UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
February 21, 2003
(Date of earliest
event reported)
Commission File Name of Registrant; State of Incorporation; Address of IRS Employer
Number Principal Executive Offices; and Telephone Number Identification Number
- --------------------- ---------------------------------------------------------- ------------------------
1-16169 EXELON CORPORATION 23-2990190
(a Pennsylvania corporation)
10 South Dearborn Street - 37th Floor
P.O. Box 805379
Chicago, Illinois 60680-5379
(312) 394-7398
Item 5. Other Events
The purpose of the Current Report is to file certain financial information
regarding Exelon Corporation and Subsidiary Companies. Such financial
information is set forth in the exhibits to this Current Report.
Item 7. Financial Statements and Exhibits
(c) Exhibits.
23 Consent of the Independent Public Accountants
99-1 Selected Financial Data
99-2 Market for Registrant's Common Equity and Related Stockholder Matters
99-3 Management's Discussion and Analysis of Financial Condition and Results of
Operations
99-4 Financial Statements and Supplementary Data
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned hereunto duly authorized.
EXELON CORPORATION
/S/ Robert S. Shapard
----------------------------------
Robert S. Shapard
Executive Vice President and Chief
Financial Officer
February 21, 2003
Exhibit 23
Consent of the Independent Accountants
CONSENT OF INDEPENDENT ACCOUNTANTS
----------------------------------
We hereby consent to the incorporation by reference in the Registration
Statements on Form S-3 (File Nos. 333-57640 and 333-84446), on Form S-4 (File
No. 333-37082) and on Form S-8 (File Nos. 333-61390 and 333-49780) of Exelon
Corporation and Subsidiary Companies of our report dated January 29, 2003,
except for Note 23 for which the date is February 20, 2003, relating to the
financial statements, which appears in this Current Report on Form 8-K dated
February 21, 2003.
PricewaterhouseCoopers LLP
February 21, 2003
Exhibit 99-1
Exelon Corporation and Subsidiary Companies Selected Financial Data
Summary of Earnings and Financial Condition
Exelon Corporation and Subsidiary Companies
For the Years Ended December 31,
--------------------------------------------------------------------
in millions, except for per share data 2002 2001 2000 (a) 1999 1998
- -------------------------------------------------------------------------------------------------------------------
Statement of Income Data:
Operating Revenues $ 14,955 $ 14,918 $ 7,499 $ 5,478 $ 5,325
Operating Income 3,299 3,362 1,527 1,373 1,268
Income before Cumulative Effect of
Changes in Accounting Principles 1,670 1,416 562 570 500
Cumulative Effect of Changes in
Accounting Principles
(net of income taxes) (230) 12 24 -- --
- ------------------------------------------------------------------------------------------------------------------
Net Income $ 1,440 $ 1,428 $ 586 $ 570 $ 500
- ------------------------------------------------------------------------------------------------------------------
Earnings per Common Share (Diluted):
Income Before Cumulative Effect of
Changes in Accounting Principles $ 5.15 $ 4.39 $ 2.75 $ 2.89 $ 2.23
Cumulative Effect of Changes in
Accounting Principles
(net of income taxes) (0.71) 0.04 0.12 -- --
- ------------------------------------------------------------------------------------------------------------------
Net Income $ 4.44 $ 4.43 $ 2.87 $ 2.89 $ 2.23
- ------------------------------------------------------------------------------------------------------------------
Dividends per Common Share $ 1.76 $ 1.82 $ 0.91 $ 1.00 $ 1.00
- ------------------------------------------------------------------------------------------------------------------
Average Shares of Common Stock
Outstanding - Diluted 325 322 204 197 224
- ------------------------------------------------------------------------------------------------------------------
December 31,
--------------------------------------------------------------------
2002 2001 2000 (a) 1999 1998
- ------------------------------------------------------------------------------------------------------------------
Balance Sheet Data:
Current Assets $ 4,118 $ 3,735 $ 4,151 $ 1,221 $ 582
Property, Plant and Equipment, net 17,134 13,791 12,936 5,004 4,804
Deferred Debits and Other Assets 16,226 17,218 17,699 6,862 6,662
- ------------------------------------------------------------------------------------------------------------------
Total Assets $ 37,478 $ 34,744 $ 34,786 $ 13,087 $ 12,048
- ------------------------------------------------------------------------------------------------------------------
Current Liabilities $ 5,974 $ 4,370 $ 4,993 $ 1,286 $ 1,735
Long-Term Debt 13,127 12,879 12,958 5,969 2,920
Deferred Credits and Other Liabilities 9,963 8,749 8,959 3,726 3,756
Minority Interest 77 31 31 12 --
Preferred Securities of Subsidiaries 595 613 630 321 579
Shareholders' Equity 7,742 8,102 7,215 1,773 3,058
- ------------------------------------------------------------------------------------------------------------------
Total Liabilities and
Shareholders' Equity $ 37,478 $ 34,744 $ 34,786 $ 13,087 $ 12,048
- ------------------------------------------------------------------------------------------------------------------
(a) Reflects the effects of the Unicom Merger (October 20, 2000).
1
Exhibit 99-2
Exelon Corporation and Subisidiary Companies Market for Registrant's Common
Equity and Related Stockholder Matters
Exelon Corporation's (Exelon) common stock is listed on the New York Stock
Exchange. The following table sets forth the high and low sales prices, closing
prices and dividends for Exelon's common stock for 2002 and 2001 on a per share
basis.
2002 2001
Fourth Third Second First Fourth Third Second First
Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter
- -------------------------------------------------------------------------------------------------------------------
High Price $ 53.06 $ 52.83 $ 56.99 $ 53.88 $ 48.69 $ 67.65 $ 70.26 $ 69.75
Low Price 42.38 37.85 50.10 45.90 39.65 38.75 62.10 53.60
Close 52.77 47.50 52.30 52.97 47.88 44.60 64.12 65.60
Dividends 0.44 0.44 0.44 0.44 0.43 0.42 0.42 0.55 (a)
- -------------------------------------------------------------------------------------------------------------------
(a) The first quarter dividend in 2001 was a pro rata dividend. Unicom and PECO
each paid their shareholders pro rata, per diem dividends from their last
regular dividend dates through October 19, 2000. The first quarter covered
the 119-day period from the date of the Merger, through the February 15,
2001 record date.
Exelon had 180,059 shareholders of common stock of record as of January 31,
2003.
Exhibit 99-3
Exelon Corporation and Subsidiary Companies Management's Discussion and Analysis
of Financial Condition and Results of Operations
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
(Dollars in millions, unless otherwise noted)
General Business
On October 20, 2000, Exelon Corporation (Exelon or we) became the
parent corporation for PECO Energy Company (PECO) and Commonwealth Edison
Company (ComEd) as a result of a merger among PECO, Unicom Corporation (Unicom),
the former parent company of ComEd, and Exelon (Merger). The Merger was
accounted for using the purchase method of accounting with PECO as the acquiring
company. Accordingly, our results of operations for 2000 consist of PECO's
results of operations for 2000 and Unicom's results of operations after October
20, 2000.
During January 2001, we undertook a restructuring to separate our
generation and other competitive businesses from our regulated energy delivery
business at ComEd and PECO. As part of the restructuring, the generation-related
operations and assets and liabilities of ComEd were transferred to Exelon
Generation Company, LLC (Generation). Also, as part of the restructuring, the
non-regulated operations and related assets and liabilities of PECO,
representing PECO's generation and enterprises business segments, were
transferred to Generation and Exelon Enterprises Company, LLC (Enterprises),
respectively. Additionally, certain operations and assets and liabilities of
ComEd and PECO were transferred to Exelon Business Services Company (BSC). BSC
provides Exelon and its subsidiaries financial, human resource, legal,
information technology, supply management and corporate governance services.
Exelon, a registered public utility holding company, through its
subsidiaries, now operates in three business segments:
o Energy Delivery, whose businesses include the regulated sale of
electricity and distribution and transmission services by ComEd in
northern Illinois and PECO in southeastern Pennsylvania and the sale
of natural gas and distribution services by PECO in the Pennsylvania
counties surrounding the City of Philadelphia.
o Generation, consisting of the owned and contracted for electric
generating facilities, energy marketing operations, and equity
interests in Sithe Energies, Inc. (Sithe) and AmerGen Energy Company,
LLC (AmerGen).
o Enterprises, consisting of competitive retail energy sales, energy and
infrastructure services, communications and other investments
(weighted towards the communications, energy services and retail
services industries).
See Note 20 of the Notes to Consolidated Financial Statements for further
segment information.
2
Goals and Strategies
Our vision is to build exceptional value - by becoming the best and
most consistently profitable electricity and gas company in the United States.
To implement our vision, we must
Live up to our commitments
o Keep the lights on.
o Perform safely - especially in nuclear operations.
o Constantly improve our environmental performance.
o Act honorably and treat everyone with respect, decency and
integrity.
o Continue building a high performance culture that reflects the
diversity of our communities.
o Report our results, opportunities and problems honestly and
reliably.
Perform at world-class levels
o Relentlessly pursue greater productivity, quality and innovation.
o Understand the relationships among our businesses and optimize
the whole.
o Promote and implement policies that build effective markets.
o Adapt rapidly to changing markets, politics, economics and
technology to meet our customers' needs.
o Maximize the earnings and cash flow from our assets and
businesses and sell those that do not meet our goals.
Invest in our consolidating industry
o Develop strategies based on learning from past successes and
failures.
o Implement systems and best practices that can be applied to
future acquisitions.
o Prioritize acquisition opportunities based on synergies from
scale, scope, generation and delivery integration, and our
ability to profitably satisfy provider of last resort (POLR) and
other regulatory obligations.
o Make acquisitions that will best employ our limited investment
resources to produce the most consistent cash flow and earnings
accretion.
o Return earnings to shareholders when higher returns are not
available from acquisition opportunities.
The first component of our strategy is to "live up to our commitments."
As such, we will continue to make investments in our businesses to provide
reliable services at fair prices. The second component of our vision is to
"perform at world class levels," which includes our plan to develop a more
fundamental and durable productivity improvement program to expand on 2002's
Cost Management Initiative. Our process, The Exelon Way, is designed to create
value and strengthen our competitive position by improving processes,
productivity and cash flow. Our third major corporate goal is to "invest in our
consolidating industry." To further our strategy, each of the business segments
has formulated its own plans to achieve our corporate goals.
Energy Delivery. Energy Delivery focuses on providing reliable and
affordable services to customers. ComEd and PECO continue to make improvements
to their delivery systems to minimize the frequency and duration of service
interruptions, while working more efficiently to lower their costs. We believe
that ComEd and PECO will continue to provide a significant and steady source of
earnings and cash flows over the next several years.
3
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. Power Team is the unit
within Generation that manages the output of Generation's assets and energy
sales to reduce the volatility of Generation's earnings and cash flows. 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.
Enterprises. Enterprises is focused on operating its investments with
the goal of maximizing its earnings and cash flow. Enterprises is not currently
contemplating any acquisitions. Enterprises expects to divest itself of
businesses that are not consistent with our strategic direction. This does not
necessarily mean that an immediate exit will be arranged, but rather we may
retain businesses for a period of time if we believe that this course of action
will strengthen their value.
Business Outlook and the Challenges in Managing Our Business
We face a number of challenges in achieving our vision and keeping our
commitments to our customers and our investors; however, there are three
principal areas on which we focus our attention. First, our financial
performance is significantly affected by the availability and utilization of our
generation facilities. As the largest U.S. nuclear generator, we face
operational and regulatory risks that, if not managed diligently, could have
significant adverse consequences. Second, our results of operations are directly
affected by wholesale energy prices. Energy prices are driven by demand factors
such as weather and economic conditions in our service territories. They are
also driven by supply factors and the regions where we operate currently have
excess capacity. Over the last several years, wholesale prices of electricity
have generally been low. The possibility of continued low wholesale prices,
coupled with a continued economic recessionary trend, could adversely affect our
business. Finally, our business may be significantly impacted by the end of
ComEd's regulatory transition period in 2006. By existing law, after 2006, ComEd
will not collect competitive transition charges (CTCs) from customers who elect
to receive generation services from alternative energy suppliers including the
ComEd Power Purchase Option (PPO). Additionally, the current bundled rate
structure may be reset in a regulatory proceeding. It is difficult to predict
the outcome of a potential regulatory proceeding to establish rates for 2007 and
thereafter, nor is it possible to predict what changes may occur to the
restructuring law in Illinois; however, we are undertaking various efforts to
mitigate the 2007 challenge.
These and other challenges affecting our businesses are described
below. There are several factors, such as weather, economic activity and
regulatory actions that affect Energy Delivery, Generation and Enterprises 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.
Energy Delivery
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 Illinois Commerce Commission
(ICC) and PECO is regulated by the Pennsylvania Public Utility
Commission (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 Federal
Energy Regulatory Commission (FERC), which regulates their transmission
rates, certain other aspects of their businesses and, for PECO, gas
pipelines. The
4
regulations adopted by these state and Federal agencies affect the
manner in which we do business, our ability to undertake specified
actions and the costs of our operations.
We are involved in a number of 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. 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 grant some certainty to all
parties to the proceedings as to rates and energy costs.
o ComEd Delivery Services Rate Case
ComEd is authorized to charge customers who purchase
electricity from an alternative supplier for the use of its
distribution system to deliver that electricity. These
delivery service rates are set through proceedings before the
ICC based upon, among other things, the operating costs
associated with ComEd's distribution system and the capital
investment that ComEd has made in its distribution system. In
April 2002, the ICC issued an interim order that set delivery
rates for ComEd's residential customers. The interim order was
subject to an audit of test year (2000) expenditures,
including capital expenditures. In October 2002, the ICC
received the report on the audit of the test year expenditures
by a consulting firm engaged by the ICC to perform the audit.
The consulting firm recommended certain additional
disallowances to test year expenditures and rate base levels.
ComEd does not expect any change in delivery service rates to
have a significant impact on results of operations in 2003.
However, the estimated potential investment write-off, before
income taxes, could be up to approximately $100 million if the
ICC ultimately determines that all or some portion of ComEd's
distribution plant is not recoverable through rates. In 2002,
ComEd recorded a charge to earnings, before income taxes, of
$12 million representing the estimated minimum probable
exposure. ComEd is in negotiations with several parties to
resolve the delivery service case.
We must maintain the availability and reliability of Energy Delivery's
delivery systems to meet customer expectations.
Each year increases in both customers and the demand for energy
requires 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. 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.
We must manage Energy Delivery's costs due to the rate and equity
return limitations imposed on Energy Delivery's revenues.
Rate freezes and caps in effect at ComEd and PECO currently limit
Energy Delivery's ability to recover increased expenses and the costs
of investments in new transmission and distribution
5
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 to offset increased infrastructure investments and
inflation.
o Rate limitations
ComEd is subject to a legislatively mandated rate freeze on
bundled retail rates that will remain effective until January
1, 2007. PECO is subject to agreed-upon rate reductions of
$200 million, in aggregate, for the period 2002 through 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 as a result of
settlements previously reached with the PUC.
o 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
2003 through 2006.
Energy Delivery has and will lose energy customers to other generation
service providers, although it continues to provide delivery services
and may have an obligation to provide generation service to those
customers.
o 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 can choose to purchase their generation supply from
alternative suppliers. If customers do not choose an
alternative generation supplier or take service under ComEd's
PPO, ComEd and PECO are each currently generally obligated to
provide generation and delivery service to customers in their
service territories at fixed rates, or in some instances,
market-derived rates. In addition, customers who choose 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 supplier. To the
extent that customers leave traditional bundled tariffs and
select a different generation provider, Energy Delivery's
revenues are likely to decline.
At December 31, 2002, based on sales of energy, approximately
27% of ComEd's small commercial and industrial (C&I) load and
61% of its large C&I load were purchasing their generation
service from an alternative generation supplier or had chosen
ComEd's PPO, a market-based price for energy. There are
currently no certified alternative suppliers for the
residential market in ComEd's service territory. Also, at
December 31,
6
2002, approximately 10% of PECO's small C&I load, 7% of its
large C&I load and 21% of its residential load were purchasing
their generation service from an alternative electric
generation supplier.
PECO's Electric Restructuring Settlement established market
share thresholds (MST) for residential and commercial
customers such that if, on January 1, 2003, 50% of PECO's
residential and commercial customers (by number of customers
for residential and small commercial classes, and by load for
large commercial classes) are not obtaining generation service
from alternative generation suppliers, then non-shopping
customers, up to the MSTs level, will be randomly assigned to
alternative generation suppliers. The assigned customers have
the right, at any time, to return to PECO or to switch to
another supplier.
The number of customers choosing 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. As
a result of the right of customer choice of generation
suppliers, we anticipate that our revenues and gross margins
could vary.
Energy Delivery continues to serve as the provider of last resort
for energy for all customers in its service territories.
ComEd and PECO are required to make available generation service
to all retail customers in their service territories, including
customers that have taken energy from an alternative generation
supplier. ComEd and PECO customers can "switch," that is, they can
choose an alternative generation supplier and then return to us
and then go back to an alternative supplier, and so on, within
limits. Because customers can switch, planning for Energy Delivery
has a higher level of uncertainty than that traditionally
experienced due to weather and the economy. In order to mitigate
this risk with regard to our large commercial and industrial
customers, on July 19, 2002, ComEd filed a request with the ICC to
revise its POLR obligation in Illinois to be the back-up energy
supplier to certain businesses. ComEd is seeking permission from
the ICC to limit the availability by June 2006 of Rate 6L for 370
of its largest energy customers. 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 megawatts (MWs). Our
request affects a total of approximately 2,500 MWs. On November
14, 2002, the ICC allowed our request to go into effect as of June
2003. Energy Delivery has no obligation to purchase power reserves
to cover the load served by others. Presently, we manage the POLR
obligation through full requirements contracts with Generation,
under which Generation supplies ComEd's and PECO's power
requirements. Because of the ability of customers to switch
generation suppliers, there is uncertainty regarding the amount of
Energy Delivery load that Generation must prepare for. This
uncertainty increases Generation's costs. As a result, and in
connection with our July 2002 ICC request, we are discussing the
POLR obligation issue with a number of parties including those who
were parties to our rate request.
Energy Delivery's long-term power purchase agreements provide a partial
hedge to its customers' demand.
Because the bundled rates Energy Delivery charges its customers are
frozen or capped for several years, as mentioned previously in the
"Rate limitations" section, its ability to recover increased costs with
increases in rates charged to these customers is limited. Therefore, to
effectively
7
manage its obligation to provide power to meet its customers' demand,
Energy Delivery has established power supply agreements with Generation
that reduce exposure to the volatility of market prices through 2006.
Market prices relative to Energy Delivery's bundled rates still
influence switching behavior among retail customers.
Our business may be significantly impacted by the end of the ComEd
regulatory transition period in 2006, and to a lesser extent, the end
of the PECO regulatory transition period in 2010.
Illinois electric utilities are allowed to collect CTCs from customers
who choose an alternative supplier of electric generation service or
choose a utility's 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 competitive price of delivered
energy (the sum of generation service at competitive 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. Under current law, ComEd will no longer collect CTCs at
the end of 2006.
In 2001, ComEd collected $110 million of CTC revenue, while in 2002,
CTC revenue collected increased to $306 million due to the change in
the competitive price of delivered electricity, primarily due to lower
wholesale prices and more customers choosing alternative energy
suppliers or the ComEd PPO. Based on increasing mitigation factors and
our assumptions about the competitive price of delivered energy and
customers' choice of electric suppliers, we estimate that CTC revenue
will be approximately $250 to $300 million annually by 2006. In
addition, the CTC is dependent on the ICC's determination of the market
price of electricity. In a proceeding before the ICC, various market
participants, including alternative providers and large customers, have
proposed modifications to the method for determining the market price
that, if accepted, could have the effect of reducing the CTC. Under the
current restructuring statute, in 2007 this revenue will likely drop to
zero. Through 2006, ComEd will continue to have a bundled service
obligation, particularly to residential and small commercial customers.
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. Much like the CTC collections, this revenue
stream is authorized by the legislature through the transition period.
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.
During informal workshops sponsored by a member of the Illinois General
Assembly, various market participants and interested parties made
proposals which, if adopted, could have the effect of reducing the CTC.
In order to address post-transition uncertainty, we are constantly
working with Illinois state and business community leadership to
facilitate the development of a competitive electricity market while
providing system reliability. This is particularly important as ComEd's
costs to provide electricity to bundled residential and small
commercial customers are capped by law at 110% of market. 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. To offset CTC revenue loss after 2006, we are
pursuing measures that would provide greater productivity, quality and
innovation in our work practices across Exelon.
8
Our ability to make successful acquisition(s) and the recovery of
wholesale power prices over the next several years will affect our
ability to successfully manage this situation. Currently, it is
difficult to predict the outcome of a potential regulatory proceeding
to establish rates after 2006. We believe that no one factor will solve
these challenges, but that a combination of the components currently
being worked on, together with other things that we will do over the
next four years, will address these challenges.
In Pennsylvania, as a mechanism for utilities to recover their allowed
stranded costs, the Pennsylvania Electricity Generation Customer Choice
and Competition Act (Competition Act) provides for the imposition and
collection of non-bypassable CTCs on customers' bills. CTCs are
assessed to and collected from all retail customers who have been
assigned stranded cost responsibility and access the utilities'
transmission and distribution systems. As the CTCs are based on access
to the utility's transmission and distribution system, they will be
assessed regardless of whether such customer purchases electricity from
the utility or an alternative electric generation supplier. The
Competition Act provides, however, that the utility'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 ($4.6 billion of unamortized costs at December 31, 2002) over a
twelve-year period ending December 31, 2010, with a return on the
unamortized balance of 10.75%. PECO's recovery of stranded costs is
based on the level of transition charges established in the settlement
of PECO's restructuring case and the projected annual retail sales in
PECO's service territory. Recovery of transition charges for stranded
costs and PECO's allowed return on its recovery of stranded costs are
included in revenues. In 2002, revenue attributable to stranded cost
recovery was $850 million and is scheduled to increase to $932 million
by 2010, the final year of stranded cost recovery. Amortization of
PECO's stranded cost recovery, which is a regulatory asset, is included
in depreciation and amortization. The amortization expense for 2002 was
$308 million and will increase to $879 million by 2010. Thus, PECO's
results will be adversely affected over the remaining period ending
December 31, 2010 by the reduction in the unamortized balance of
stranded costs and therefore the return received on that unamortized
balance.
9
Our ability to successfully manage the end of the transition period may
affect our capital structure.
ComEd has approximately $4.9 billion of goodwill recorded at December
31, 2002. This goodwill was recognized and recorded in connection with
the Merger. Under Generally Accepted Accounting Principles (GAAP), the
goodwill will remain at its recorded amount unless it is determined to
be impaired, which is based upon an analysis of ComEd's cash flows. If
an impairment is determined at ComEd, the amount of the impaired
goodwill will be written-off and expensed at ComEd. However, a goodwill
impairment charge at ComEd may not affect Exelon's results of
operations. Exelon's goodwill impairment test would include assessing
the cash flows of the entire Energy Delivery business segment (a single
Reporting Unit, which includes PECO, as defined under current
accounting guidance), not just ComEd's cash flows. Presently, ComEd has
sufficient cash flows to support the recorded amount of goodwill and
thus, no impairment has been recorded. For a further discussion on this
subject, see the Asset Impairment discussion in Critical Accounting
Estimates. ComEd's cash flows include CTCs, which will cease at the end
of 2006, unless there is a legislative or regulatory change and
collections from traditional bundled customers at tariffed rates.
Absent another source of revenues to replace the loss of the CTC
revenue, all or a portion of the goodwill may become impaired. ComEd
currently believes that there are a number of alternatives that could
provide cash flows to support the goodwill. Under current regulations,
a significant goodwill impairment may restrict ComEd's ability to pay
dividends (see Credit Issues in Liquidity and Capital Resources). We
are pursuing various solutions to address ComEd's ability to pay
dividends if a significant goodwill impairment exists. However, based
on Illinois legislation, goodwill impairments are excluded from
determining whether or not the earnings cap amount has been met or
exceeded (see Energy Delivery - Equity Return Limitations).
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 bring power in 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 use of energy. Sales growth on an
annual basis is expected to be 1.5% and 0.6% in ComEd's and PECO's
service territories, respectively. In the long-term, output growth for
electricity is expected to be 1.2% per year for Energy Delivery.
However, there is continued economic uncertainty. Recessionary economic
conditions, and the associated reduced economic activity, may adversely
affect our results of operations.
Our business is affected by the restructuring of the energy industry.
10
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 and the more recently 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.
o Regional Transmission Organizations / Standard Market Design
To facilitate wholesale competition in the electric industry,
FERC has required jurisdictional utilities to provide open
access to their transmission systems. To foster the
development of large regional wholesale markets, FERC issued
Order 2000, encouraging the development of regional
transmission organizations (RTOs) and the elimination of trade
barriers between regions. FERC has also proposed rulemakings
to mandate a standard market design (SMD) for the wholesale
markets. Order 2000 and the proposed SMD rule contemplate that
the jurisdictional transmission owners in a region will turn
over operating authority over their transmission facilities to
an RTO or other independent entity for the purpose of
providing open transmission access. As a result, the
independent entity will become the provider of the
transmission service and the transmission owners will recover
their revenue requirements through the independent entity. The
transmission owners will remain responsible for maintaining
and physically operating their transmission facilities. The
SMD rulemaking 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 implement a
financially-based system for dealing with congestion on
transmission lines known as "locational marginal pricing"
(LMP). FERC has also issued proposals to encourage RTO
development, independent control of the transmission grid and
expansion of the transmission grid by providing enhanced
returns on equity for transmission assets.
PECO is a member of PJM Interconnection, LLC (PJM), an
approved RTO operating in the Mid-Atlantic region. ComEd,
along with other Midwestern utilities, joined PJM in a
westward expansion of PJM. ComEd is expected to turn over
control of its transmission assets to PJM later this year and
recover its current transmission revenues through the PJM
open-access transmission tariff.
FERC Order 2000 has not led to the rapid development of RTOs
and FERC has not yet finalized its SMD proposal, due in part
to substantial opposition by some state regulators and other
governmental officials. We support both of these proposals 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 for their load, the
ability of ComEd and PECO to cost effectively serve their POLR
load obligation will depend on the development of such
markets.
11
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.
Energy Delivery continues to make significant capital expenditures to
improve the reliability of its transmission and distribution systems in
order to provide a high level of service to its customers. Energy
Delivery expects that its capital expenditures will continue 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 (see Energy
Delivery - Rate and Equity Return Limitations above).
Generation
Our Generation business operates a fleet of generating assets and
markets the output of a portfolio of supply, which includes 100% owned assets,
co-owned facilities and purchased power. As discussed previously, Generation has
entered into long-term power purchase agreements with ComEd and PECO. The
majority of Generation's portfolio is used to provide power under these
agreements. To the extent the portfolio is not needed to supply power to ComEd
or PECO, their output is sold on the wholesale market. Generation's ability to
grow is dependent upon its ability to cost-effectively meet ComEd's and PECO's
load requirements, to manage its power portfolio and to effectively handle the
changes in the wholesale power markets.
Our financial performance may be affected by liabilities arising from
our ownership and operation of nuclear facilities.
The ownership and operation of nuclear facilities involve certain
risks, including: mechanical or structural problems; inadequacy or
lapses in maintenance protocols; the impairment of reactor operation
and safety systems due to human error; the costs of storage, handling
and disposal of nuclear material; and uncertainties with respect to the
technological and financial aspects of decommissioning nuclear
facilities at the end of their useful lives. The following are among
the more significant of these risks:
o Operational risk
Operations at any nuclear generation plant could degrade to
the point where we would have to shut down the plant. If this
were to happen, the process of identifying and correcting the
causes of the operational downgrade to return the plant to
operation could require significant time and expense,
resulting in both lost revenue and increased fuel and
purchased power expense to meet our supply commitments. For
plants operated by us but not wholly owned by us, we could
incur liabilities to the co-owners. We may choose to close a
plant rather than incur substantial costs to restart the
plant.
o Nuclear accident risk
Although the safety record of nuclear reactors 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 may include loss of life and
property damage. Any resulting liability from a nuclear
accident could exceed our insurance coverages and
significantly affect our results of operations or financial
position. See
12
Note 19 of Notes to the Consolidated Financial Statements for
further discussion of nuclear insurance.
o Nuclear regulation
The Nuclear Regulatory Commission (NRC) may modify, suspend or
revoke licenses and impose civil penalties for failure to
comply with the Atomic Energy Act, the regulations under it or
the terms of the licenses of nuclear facilities. Changes in
regulations by the NRC that require a substantial increase in
capital expenditures or that result in increased operating or
decommissioning costs could adversely affect our results of
operations or financial condition. Events at nuclear plants
owned by others, as well as those owned by us, may initiate
such actions. Additional security requirements could also be
imposed.
o Plant life extensions
In 2001, Generation extended the estimated lives of certain
nuclear stations. This change in estimate reflects the current
and planned applications to the NRC to renew the operating
licenses of Generation's nuclear stations. These applications
for renewal, if approved by the NRC, will allow Generation to
operate these plants for an additional 20 years longer than
originally authorized. Nuclear station service life extensions
are subject to NRC approval of an extension of existing NRC
operating licenses, which are generally 40 years. We continue
to fully believe that any such applications for renewal of
operating licenses will be approved. However, if the NRC does
not extend our operating licenses for our nuclear stations,
our results of operations could be adversely affected by
increased depreciation rates and accelerated future
decommissioning payments.
Generation's financial performance is affected in large measure by the
availability and use of its nuclear generation capacity.
o Nuclear capacity factors
Generation 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 marginal costs due to
low variable fuel costs. Consequently, to be successful,
Generation must consistently operate its nuclear generating
facilities at high capacity factors. Generation's nuclear
fleet performed at a 92.7% capacity factor (which represents
the percentage of the total maximum energy that could be
produced if facilities were operating full-time year round) in
2002 and is targeted to operate at a 94.2% capacity factor in
2003. In calculating capacity factors, Generation's nuclear
fleet includes the AmerGen plants and excludes the Salem
generation facility, which is operated by Public Service
Enterprise Group Incorporated (PSE&G). Lower capacity factors
would increase our 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 its obligations to
Energy Delivery and other committed third-party sales. These
sources generally are at a higher cost than Generation
otherwise would have incurred to generate energy from its
nuclear stations.
o Refueling outage scheduling at nuclear plants affects
availability and costs
Outages at nuclear stations to replenish fuel require the
station to be "turned off."
13
Refueling outages are planned to occur once every 18 to 24
months and currently average approximately 22 days in
duration. We have significantly decreased the length of
refueling outages in recent years. However, when refueling
outages last longer than anticipated or we experience
unplanned outages, we face lower margins due to higher energy
replacement costs and/or lower energy sales. Each twenty-day
outage, depending on the capacity of the station, will
decrease the total nuclear annual capacity factor between 0.1%
and 0.4%. The number of refueling outages, including AmerGen,
will decrease to eight in 2003 from eleven in 2002.
Maintenance and capital expenditures are expected to decrease
by approximately $45 million and $10 million, respectively, in
2003 as compared to 2002 as a result of fewer nuclear
refueling outages.
Generation is directly affected by wholesale energy prices.
Generation sells energy in the wholesale markets after meeting its
contractual commitments to Energy Delivery and other parties. These
sales expose Generation to the risks of rising and falling prices in
those markets, and cash flows may vary accordingly. The amount of
generation capacity that is exposed to the volatility of market prices
depends inversely on the level of demand in the Energy Delivery
companies.
The wholesale prices of electricity have generally been lower than
historical levels over the last few years. A continued trend of low
wholesale electricity prices could negatively affect our overall
results of operations. Factors that affect wholesale energy prices
include the overall demand for energy, fossil fuel costs and excess
capacity within the industry.
o Demand for energy
An increased demand for energy will normally cause energy
prices to increase; however, if this increase in demand drives
an incremental increase in supply, energy prices may be less
affected. The demand for energy is directly affected by
weather conditions and economic conditions in our service
territories.
o Weather conditions
Generation's operations are affected by weather,
which affects demand for electricity as well as
operating conditions. We manage our business based
upon normal weather assumptions. To the extent that
weather is warmer in the summer or colder in the
winter than we assumed, Generation may require
greater resources to meet its contractual
requirements to Energy Delivery. Extreme summer
conditions or storms may affect the availability of
generation capacity and transmission, limiting
Generation's ability to send power to where it is
sold. These conditions, which may not have been fully
anticipated, may adversely affect us 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 does incorporate contingencies into its
planning for extreme weather conditions, including
reserving capacity to meet summer loads at levels
representative of warmer than normal weather
conditions.
o Economic conditions
Economic conditions and activity in Energy Delivery's
service territories directly affect the demand for
electricity and gas. Changes in economic conditions
and
14
activity in Energy Delivery's service territories and
in other parts of the United States can affect the
level of operations required in our generating
facilities as well as the prevailing prices of
electricity and gas in the wholesale markets in which
we do business.
o Fossil fuel costs
At any given time, the open market wholesale price of
electricity is affected by the cost of supplying one more unit
of electricity to the market at that time. 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 gas plus the spark spread, the cost to
convert gas to electricity. Therefore, changes in the cost of
gas may impact the open market wholesale price of electricity.
o Excess capacity
In addition to being affected by demand factors such as
weather, the economy, and fossil fuel costs, energy prices are
also impacted by the amount of supply available in a region.
In the markets where we sell power, there has been a
significant increase in the number of new power plants coming
on-line which has driven down power prices over the last few
years. In fact, an "excess supply" problem currently exists in
many parts of the country. A key factor for Exelon's future
earnings is the timing of a return to more normal levels in
the supply-demand balance within the regions where we operate.
The scope and scale of our nuclear generation resources provide a cost
advantage in meeting our contractual commitments and enable us to sell
power in the wholesale markets.
The generation assets transferred to Generation by ComEd and PECO
during the 2001 restructuring, the generating plants acquired in 2002
and Generation's investments in Sithe and AmerGen provide a critical
mass of generation capacity and a leadership position in energy
wholesale markets. Generation's resources, including AmerGen, include
interest in 11 nuclear generation stations, consisting of 19 units,
which generated 125,916 GWhs, or more than half of our total supply in
2002. As the largest generator of nuclear power in the United States,
we can take advantage of our 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.
15
Our financial performance will be affected by our ability to
effectively operate and integrate the assets of Sithe New England into
our business and to market the output.
In November 2002, Generation acquired the generating assets of Sithe
New England Holdings, LLC (Sithe New England). The Sithe New England
assets, now known as the Exelon New England Holdings assets, include
2,421 MWs of gas-fired combined facilities under construction and
several operating generating facilities, which together with the assets
under construction total 4,066 MWs of capacity. The facilities under
construction (Mystic 8, Mystic 9, and Fore River) are currently in the
final stages of construction and testing. We anticipate commercial
operation dates during the second quarter of 2003. These projects have
experienced delays in construction and any further delays could
adversely affect our results. See further discussion of the Sithe
Boston Generation Project Debt in Liquidity and Capital Resources. With
the continued low wholesale energy prices, we anticipate that the
effects of the Sithe New England acquisition will be dilutive to
earnings by approximately $125 million in 2003.
Power Team has not fully committed the output from these facilities
into the New England markets. As such, the uncommitted capacity of the
Exelon New England Holdings assets is subject to the fluctuations in
market demand and market prices.
Substantially all of the natural gas requirements for Mystic 8 and
Mystic 9 will be supplied through a twenty-year natural gas contract
that became effective on December 1, 2002 with Distrigas of
Massachusetts, LLC (Distrigas). The Distrigas facilities consist of a
liquefied natural gas (LNG) import terminal located adjacent to the
Mystic station. We are anticipating an additional pipeline gas supply
arrangement to supplement LNG supplies to be in service by early 2005.
In the interim, any disruption in LNG supplies to the Distrigas
facilities could restrict the operating abilities of Mystic 8 and
Mystic 9.
The interaction between our Energy Delivery and Generation businesses
provide us a partial hedge.
The price of power purchased and sold in the open wholesale energy
markets can vary significantly in response to market conditions. Both
ComEd and PECO have entered into long-term agreements for the next
several years with Generation to procure the power at fixed rates
needed to meet the demand of their customers. The amounts provided to
affiliates 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 to serve ComEd and PECO
customers is not exposed to the price uncertainty of the open wholesale
energy market. Consequently, we have limited our earnings exposure to
the volatility of the wholesale energy market to the energy generated
beyond the ComEd and PECO requirements, as well as any other contracted
longer term obligations. Generally, between 60% and 70% of our
generation serves ComEd and PECO customers. We expect such levels to
decrease to between 55% and 60% as a result of activating the acquired
Sithe New England plants, which are currently under construction. One
of the responsibilities of Power Team is to establish a hedging
strategy, incorporating the load obligations of Energy Delivery, to
minimize the contracted volatility of our earnings and cash flows, and
to maximize the value of economic generation in excess of that needed
to serve ComEd and PECO requirements.
Our financial performance depends on our ability to respond to
competition in the energy industry.
16
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. As a
result, the energy generation business is currently suffering from over
capacity in certain parts of the country, which reduces wholesale
energy prices. As discussed above, we are well positioned because
Generation has entered into agreements for the next several years with
ComEd and PECO to sell the power needed to meet the demand of their
customers. These agreements provide a mechanism to enhance stability in
our earnings and limit our exposure to the negative effects of
wholesale markets.
The commencement of commercial operation of new generating facilities
in the regional markets where we have facilities or contracts for
power, such as the Midwest, Mid-Atlantic, Northeast and South
(including certain sections of Texas), would likely decrease wholesale
power market prices in those regions, which could have a negative
effect on our business and results of operations.
Our financial performance may be affected by the marketing, trading and
risk management activities of Power Team.
Generation's wholesale marketing unit, Power Team,
o uses our energy generation portfolio, transmission rights and its
power marketing expertise to manage delivery of energy to
wholesale customers, including Energy Delivery, under long-term
and short-term contracts,
o participates in the wholesale energy market to hedge our open
energy (power and fossil fuels) positions,
o manages commodity and counterparty credit risks through the use
of documented risk and credit policies, and
o uses its energy market expertise to engage in trading activities
for speculative purposes on a limited basis.
Power Team has substantial experience in energy markets, generation
dispatch and the requirements for the physical delivery of power. Power
Team may buy power to meet the energy demand of its customers,
including Energy Delivery. These purchases may be made for more than
the energy demanded by Power Team's customers. Power Team then sells
this open position, along with our generating capacity not used to meet
our customer demand, in the wholesale energy market.
Power Team began proprietary trading activities in 2001, but this
activity accounts for a small portion of Power Team's efforts. In 2002,
proprietary trading activities resulted in an $18 million after-tax
reduction in our earnings. We will continue proprietary trading
activities but in a more limited capacity given the current lack of
liquidity of power markets and reduced number of creditworthy
counterparties.
Power Team has managed to avoid the recent managerial problems
experienced in the energy trading industry through the strict adherence
to prudent risk management practices. However, the recent failures of
energy companies and their related energy trading practices over the
last year have diminished the size and depth of the wholesale energy
market. We cannot predict how this will affect our trading operations
in the future.
17
We depend on counterparties fulfilling their obligations.
Our trading, marketing and contracting operations are exposed to the
risk that counterparties, which owe us money or energy as a result of
market transactions, will not perform their obligations. In order to
evaluate the viability of our counterparties, we have implemented
credit risk management procedures designed to mitigate the risks
associated with these transactions. Energy supplied by third-party
generators, including AmerGen and Sithe, under long-term agreements
represents a significant portion of Generation's overall capacity.
These third-party generators face operational risks such as those that
Generation faces, and their ability to perform also depends on their
financial condition. In the event the counterparties to these
arrangements fail to perform, we might be forced to honor the
underlying commitment at then-current market prices and incur
additional losses, to the extent of amounts, if any, already paid to
the counterparties. 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. 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.
See the Credit Risk section in the Quantitative and Qualitative
Disclosures about Market Risk for further discussions on specific
credit risk matters such as our potential counterparty exposures,
including Dynegy Inc. (Dynegy).
Generation's business is also affected by the restructuring of the
energy industry.
o Regional Transmission Organizations / Standard Market Design
Generation is dependent on wholesale energy markets and open
transmission access and rights by which we deliver power to
our wholesale customers, including ComEd and PECO. We use the
wholesale regional energy markets to sell power that we do not
need to satisfy our long-term contractual obligations, to meet
long-term obligations not provided by our own resources, and
to take advantage of price opportunities.
Wholesale spot markets have only been implemented in certain
areas of the country and each market has unique features that
may create trading barriers between the markets. Although FERC
has proposed initiatives, including Order 2000 and the
proposed SMD rule, to encourage the development of large
regional, uniform markets and to eliminate trade barriers,
these initiatives have not yet led to the development of such
markets all across the country. PJM's market strongly
resembles FERC's proposal, and both the New England
Independent System Operator (NE-ISO) and the New York
Independent System operator (NYISO) are implementing market
reforms. We strongly encourage the development of standardized
energy markets and support 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.
18
Approximately 26% of our generation resources are located in
the region encompassed by PJM. If the PJM market is expanded
to the Midwest, 82% of our current assets will be located
within the expanded market. The PJM market has been the most
successful and liquid regional market and is largely
consistent with the standard market design proposed by FERC.
Our future results of operations may be impacted by the
successful expansion of that market to the Midwest and the
implementation of any market changes mandated by FERC.
o Provider of Last Resort
As noted, Energy Delivery has a POLR obligation that it has
largely assigned to Generation through the full requirements
contracts that it has with Generation. Currently both ComEd
and PECO have entered into purchase power agreements (PPAs)
with Generation to provide 100% of their respective energy
requirements. ComEd's PPA with Generation is for 100% of its
required load through 2004 at fixed prices, and in 2005 and
2006 it equals 100% of the output of ComEd's former nuclear
plants, now owned by Generation at market based prices. PECO's
PPA with Generation is a full load requirements contract
through 2010. We intend to revise the PPA between ComEd and
Generation to be a full requirements contract in 2005 and
2006. Additionally, the PPAs between Generation, ComEd and
PECO may be extended beyond their current expiration dates.
ComEd and PECO continue to work on resolution of the POLR
issues with their respective state regulatory commissions and
other market participants.
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. As mentioned previously, as part of Generation's recent
acquisition of the assets of Sithe New England, Generation is in the
process of completing the construction of three high-efficiency
generating facilities with projected capacity of 2,421 MWs of energy.
The inability to effectively manage the capital projects, such as the
Sithe New England facilities, could adversely affect our results from
operations.
Enterprises
Enterprises' results of operations may be affected by its ability to
strategically divest itself of 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 the transactions. In addition, the amounts that Enterprises may
realize from a divestiture are subject to fluctuating market conditions
that may contribute to pricing and other terms that are materially
different than expected and could result in a loss on the sale. Timing
of any divestitures may positively or negatively affect our results of
operations as we expect certain businesses to be profitable going
forward.
Enterprises may incur further impairments of its investments.
Enterprises wrote down $41 million of investments in 2002 when certain
events occurred, such as competitors' technological advancement,
accelerated distributions of public holdings at a loss, lack of
achievability of financial results versus plan and limited access to
capital markets. At
19
December 31, 2002, Enterprises held $128 million of investments. These
types of events, or others, could continue to occur in 2003, which
could result in additional impairment charges.
Enterprises' results of operations may be affected by its ability to
manage its projects.
Enterprises consists of many businesses that utilize long-term
fixed-price contracts. At the beginning of the contract, we estimate
the total costs and profits of the contract; if the actual costs vary
significantly form the estimates, our results of operations will be
adversely impacted. Along with our ability to execute, results may be
impacted by economic conditions, weather conditions and the regulatory
environment.
Capital Markets / Financing Environment
In order to expand our operations and to meet the needs of our current
and future customers, we invest in our businesses. Our ability to finance our
businesses and other necessary expenditures is affected by the capital intensive
nature of our operations and our current and future credit ratings. The capital
markets also affect our decommissioning trust funds and benefit plan assets. Our
financing needs will be dependent on our strategic direction of acquiring
integrated utilities and generation facilities, and our ability to dispose of
unprofitable businesses that do not advance our goals. Further discussions on
our liquidity position can be found in the Liquidity and Capital Resources
section.
Our ability to grow our business is affected by our ability to finance
capital projects.
Our businesses require considerable capital resources. When necessary,
we secure funds from external sources by issuing commercial paper and,
as required, long-term debt securities. We actively manage our exposure
to changes in interest rates through interest-rate swap transactions
and our balance of fixed- and floating-rate instruments. We currently
anticipate primarily using internally generated cash flows and
short-term financing through commercial paper to fund our operations as
well as long-term external financing sources to fund capital
requirements as the needs and opportunities arise. Our ability to
arrange debt financing, to refinance current maturities and early
retirements of debt, and the costs of issuing new debt are dependent
on:
o credit availability from banks and other financial institutions,
o maintenance of acceptable credit ratings (see Our Credit Ratings
below),
o investor confidence in us,
o investor confidence in other regional wholesale power markets, o
general economic and capital market conditions,
o the success of current projects, and o the perceived quality of
new projects.
20
Our credit ratings influence our ability to raise capital.
Our businesses have investment grade ratings and have been successful
in raising capital, which has been used to further our business
initiatives. Also, from time to time, we enter into energy commodity
and other contracts that require the maintenance of investment grade
ratings. Failure to maintain investment grade ratings would require us
to incur higher financing costs and would allow, but not in most
instances require, counterparties to energy commodity contracts to
terminate the contracts and settle the transaction. Also, the failure
to maintain investment grade ratings would restrict our access to the
wholesale energy markets.
Equity market performance affects our decommissioning trust funds and
benefit plan asset values.
The sharp decline in the equity markets since the third quarter of 2000
has reduced the value of the assets held in trusts to satisfy the
obligations of pension and postretirement benefit plans and the
eventual nuclear generation station decommissioning requirements. If
the markets continue to decline, we may have higher funding
requirements and pension and other postretirement benefit expense. We
will continue to manage the assets in the pension and postretirement
benefit plans and nuclear decommissioning trusts in order to achieve
the best return possible in conjunction with our overall risk
management practices and diversified approach to investment. Please
refer to the Critical Accounting Estimates section that more fully
describes the quantitative financial statement effects of changes in
the equity markets on the nuclear decommissioning trust funds and
benefit plan assets.
Our results of operations can be affected by inflation.
Inflation affects us through increased operating costs and increased
capital costs for electric plant. As a result of the rate freezes and
caps imposed under the legislation in Illinois and Pennsylvania and
price pressures due to competition, we may not be able to pass the
costs of inflation through to customers.
Other
We may incur substantial cost 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
Generation's 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 and site remediation and clean-up. Remediation activities
associated with manufactured gas plant operations conducted by
predecessor companies will be one source 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.
21
As of December 31, 2002, our reserve for environmental investigation
and remediation costs was $156 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.
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 the Public Utility Holding Company Act (PUHCA) of 1935 as a
result of our ownership of ComEd and PECO. That regulation affects our
ability to:
o diversify, by generally restricting our investments to
traditional electric and gas utility businesses and related
businesses;
o issue securities, by requiring the prior approval of the SEC
or for ComEd and PECO, requiring the approval of state
regulatory commissions; and
o 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 our ability to manage costs
for security and liability insurance.
o Security
We do not fully know the impact that future terrorist attacks
or threats of terrorism may have on our industry in general
and on us in particular. The events of September 11, 2001 have
affected our operating procedures and costs. We have initiated
security measures to safeguard our employees and critical
operations and are actively participating in industry
initiatives to identify methods to maintain the reliability of
our energy production and delivery systems. We have met or
exceeded all security measures mandated by the NRC for nuclear
plants after the September 11, 2001 terrorist attacks. These
security measures resulted in increased costs in 2002 of $19
million, of which approximately $10 million was capitalized.
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.
In connection with the events of September 11, 2001, the
electric and gas industries have also developed additional
security guidelines. The electric industry, through the North
American Electric Reliability Council (NERC), developed
physical security guidelines, which were accepted by the U.S.
Department of Energy. In 2003, FERC is expected to issue
minimum 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
22
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.
o Nuclear liability insurance
The Price-Anderson Act limits the liability of nuclear reactor
owners for claims that could arise from a single incident. The
current limit is $9.5 billion and is subject to change to
account for the effects of inflation and changes in the number
of licensed reactors. As required by the Price-Anderson Act,
we carry nuclear liability insurance in the maximum available
amount (currently $300 million per site). Claims exceeding
that amount are covered through mandatory participation in a
financial protection pool. The Price-Anderson Act expired on
August 1, 2002, but existing facilities, such as those owned
and operated by Generation, remain covered. The U.S. Congress
has extended the provisions of the Price-Anderson Act related
to commercial facilities through 2003. The extension was
passed as part of the Consolidated Appropriations Resolution,
2003, which will be presented to the President of the United
States for his signature. The extension would affect
facilities obtaining NRC operating licenses in 2003. Existing
facilities are unaffected by the extension.
o Other insurance
In addition to nuclear liability insurance, Exelon also
carries property damage and liability insurance for its
properties and operations. As a result of significant changes
in the insurance marketplace, due in part to the September 11,
2001 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 terrorists 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 2002 was $40 million, which was recorded as a
reduction to Operating and Maintenance expense on our
Consolidated Statements of Income. Due in part to the
September 11, 2001 events and the results in the stock market
over the last two years, we cannot predict the level of future
distributions.
The possibility of attack or war may adversely affect our results of
operations, future growth and ability to raise capital.
Any military strikes or sustained military campaign may affect our
operations in unpredictable ways, such as further changes in insurance
markets, increased security measures and disruptions of fuel supplies
and markets, particularly oil and LNG. Just the possibility that
infrastructure facilities, such as electric generation, transmission
and distribution facilities, would be direct targets of, or indirect
casualties of, an act of terror or war may affect our operations. War
and the possibility of war may have an adverse effect on the economy in
general. A lower level of economic activity might result in a decline
in energy consumption, which may adversely affect our revenues or
restrict our future growth. Instability in the financial markets as a
result of war may affect our ability to raise capital.
The introduction of new technologies could increase competition within
our markets.
23
While demand for electricity is generally increasing throughout the
United States, the rate of construction and development of new, more
efficient, electric generation 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 affect on our
results of operations or financial condition.
Results of Operations
Year Ended December 31, 2002 Compared To Year Ended December 31, 2001
Net Income and Earnings Per Share
Net income for 2002 increased $12 million compared to 2001. Diluted
earnings per common share were $4.44 and $4.43 for 2002 and 2001, respectively.
Net income for 2002 reflects a $230 million charge for the cumulative effect of
changes in accounting principles as a result of the adoption of Financial
Accounting Standards Board (FASB) Statement of Financial Accounting Standards
(SFAS) No. 142, "Goodwill and Other Intangible Assets" (SFAS No. 142), while net
income for 2001 reflects $12 million of 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 4
of the Notes to Consolidated Financial Statements for further information
regarding the adoption of SFAS No. 142 and SFAS No. 133.
Income Before Cumulative Effect of Changes in Accounting Principles in
2002 increased $254 million, or 18%, compared to 2001. Diluted earnings per
common share on the same basis increased $0.76 per share, or 17%. The increase
reflects Enterprises' sale of its interest in AT&T Wireless, a 2.6% increase in
retail sales due to a warmer-than-usual summer, an extension of the estimated
service lives of generating stations, the discontinuation of goodwill
amortization as of January 1, 2002 pursuant to SFAS No. 142, lower interest
expense, and reduced depreciation expense resulting from lower depreciation
rates at Energy Delivery. The increase was partially offset by lower wholesale
energy prices, increased nuclear refueling outage costs, the write-down of
certain investments at Enterprises, employee severance costs, and other factors
described below.
Results of Operations by Business Segment
All comparisons presented under this heading are comparisons of
operating results and other statistical information for 2002 to operating
results and other statistical information for 2001. These results 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%
- -------------------------------------------------------------------------------------------------
24
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 consists of our regulated energy delivery operations
conducted by ComEd and PECO.
ComEd is engaged principally in the purchase, transmission,
distribution and sale of electricity to a diverse base of residential,
commercial, industrial and wholesale customers in northern Illinois. ComEd is a
public utility under the Illinois Public Utilities Act and is subject to
extensive regulation by the ICC as to rates, the issuance of securities and
certain other aspects of ComEd's operations. ComEd is also subject to regulation
by 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 as of December 31,
2002. The service territory includes the City of Chicago, an area of about 225
square miles with an estimated population of three million. ComEd had
approximately 3.6 million customers at December 31, 2002.
PECO is engaged principally in the purchase, transmission,
distribution and sale of electricity to residential, commercial and industrial
customers and in the purchase, distribution and sale of natural gas to
residential, commercial and industrial customers. PECO is a public utility under
the Pennsylvania Public Utility Code and is subject to extensive regulation by
the 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 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 3.8
million, including 1.5 million in the City of Philadelphia. Natural gas service
is supplied in an approximate 2,100 square mile area in southeastern
Pennsylvania adjacent to Philadelphia, with a population of approximately 2.3
million. PECO delivers electricity to approximately 1.5 million customers and
natural gas to approximately 450,000 customers.
Energy Delivery 2002 2001 Variance % Change
- -------------------------------------------------------------------------------------------------------------------
Operating Revenues $ 10,457 $10,171 $ 286 2.8%
Revenue, net of Purchased Power & Fuel Expense 5,855 5,699 156 2.7%
Operating Income 2,860 2,593 267 10.3%
Income Before Income Taxes 2,033 1,725 308 17.9%
Net Income 1,268 1,022 246 24.1%
- -------------------------------------------------------------------------------------------------------------------
The changes in Energy Delivery's revenue, net of purchased power and
fuel expense, for 2002 compared to 2001, included the following:
25
o increases in weather normalized volumes of $171 million as a result of
increases in the number of customers and additional average usage per
customer, primarily residential customers,
o positive weather impacts of $84 million, primarily the results of
warmer than usual summer weather,
o changes in customer rates resulting in a $54 million decrease to
revenue, net of purchased power and fuel expense,
o favorable changes due to customer choice of $30 million, including
customers returning to PECO as their energy supplier, or ComEd's
customers electing to purchase energy from alternative energy
suppliers or electing ComEd's PPO, under which non-residential
customers can purchase power from ComEd at a market-based rate,
o increases in PJM ancillary charges of $41 million, which decreased
revenue, net of purchased power and fuel expense,
o an $18 million increase in 2002 purchased power expense for ComEd due
to an increase in the weighted average on-peak/off-peak cost of
electricity,
o a 2001 reversal of a reserve for revenue refunds of $15 million
related to certain ComEd municipal customers as a result of a
favorable FERC ruling, and
o an increase in revenue, net of purchased power and fuel related to a
settlement of CTCs by a large customer of PECO in the amount of $11
million in 2001.
The changes in operating income for 2002 compared to 2001, included the
following:
o reduction in amortization expense of $126 million as a result of the
discontinuance of goodwill amortization upon the adoption of SFAS No.
142 on January 1, 2002,
o additional gross receipts tax expense of $72 million related to
additional revenues and an increase in the gross receipt tax rate on
electric revenue effective January 1, 2002 (gross receipts taxes are
recorded in Revenues and Taxes Other Than Income and have no impact on
net income),
o reduction in depreciation expense of $48 million due to the impact of
lower depreciation rates at ComEd effective July 1, 2002,
o increased depreciation expense in 2002 of $34 million due to higher
plant in service balances,
o increase in regulatory asset amortization of $30 million in 2002,
primarily attributable to additional amortization of PECO's CTCs,
o reduction in 2002 in the allowance for uncollectible accounts related
to a change in accounting estimate of $28 million,
o higher corporate allocations, pension and postretirement benefit
costs, and executive severance costs totaling $22 million in 2002, and
o lower employee severance costs at PECO of $18 million in 2001
associated with the Merger.
The changes in income before income taxes for 2002 compared to 2001,
included the following:
o a decrease in interest expense of $119 million primarily attributable
to less outstanding debt and refinancing of existing debt at lower
interest rates,
o lower interest income of $74 million resulting from lower interest
rates which is primarily attributable to a note receivable from Unicom
Investments, Inc., an Exelon subsidiary, and
o the establishment of a reserve of $12 million in 2002 for a probable
plant disallowance resulting from an audit performed in conjunction
with ComEd's delivery service rate case.
Energy Delivery's effective income tax rate was 37.6% for 2002,
compared to 40.8% for 2001. This 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.
26
Energy Delivery Operating Statistics and Revenue Detail
Energy Delivery's electric sales statistics and revenue detail are as
follows:
Retail Deliveries - (in gigawatthours (GWhs))(1) 2002 2001 Variance % Change
- -------------------------------------------------------------------------------------------------------------------
Bundled Deliveries (2)
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 (3)
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%
- -----------------------------------------------------------------------------------------------------
(1) One gigawatthour is the equivalent of one million kilowatthours (kWh).
(2) Bundled service reflects deliveries to customers taking electric service
under tariffed rates, which include the cost of energy and the delivery
cost of the transmission and the distribution of the energy. PECO's
tariffed rates also include a CTC. See Note 6 of the Notes to Consolidated
Financial Statements for a discussion of CTC.
(3) Unbundled service reflects customers electing to receive electric
generation service from an alternative energy supplier or ComEd's PPO. See
Note 5 of the Notes to Consolidated Financial Statements for further
discussion of ComEd's PPO.
27
Electric Revenue 2002 2001 Variance % Change
- -------------------------------------------------------------------------------------------------------------------
Bundled Revenues (1)
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 (2)
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 Only)
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 (3) 581 594 (13) (2.2%)
- -----------------------------------------------------------------------------------------------------
Total Electric Revenue $ 9,908 $ 9,517 $ 391 4.1%
- -----------------------------------------------------------------------------------------------------
(1) 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.
(2) 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.
(3) Wholesale and miscellaneous revenues include transmission revenue, sales to
municipalities and other wholesale energy sales.
n.m. - not meaningful
The differences in 2002 electric retail revenues as compared to 2001
were attributable to the following:
Variance
- ---------------------------------------------------------------------
Volume $ 224
Weather 151
Customer Choice 95
Rate Changes (54)
Other Effects (12)
- ---------------------------------------------------------------------
Electric Retail Revenue $ 404
- ---------------------------------------------------------------------
o Volume. Revenues from higher delivery volume, exclusive of the effect of
weather, increased due to an increased number of customers and increased
usage per customer, primarily residential.
o Weather. The weather impact was favorable in 2002 compared to 2001 as a
result of warmer summer weather in ComEd and PECO service territories.
Cooling degree days in the ComEd and PECO service territories were 29%
higher and 15% higher, respectively, in 2002 as compared to 2001.
28
Heating degree days in the ComEd and PECO service territories were 3%
higher and 1% higher, respectively, in 2002 as compared to 2001.
o Customer Choice. All ComEd and PECO customers have the choice to purchase
energy from other suppliers. This affects revenues from the sale of energy
but not revenue from the delivery of electricity since ComEd and PECO
continue to deliver electricity that is purchased from other suppliers. As
of December 31, 2002, 13% of energy delivered to Energy Delivery's
customers was provided by alternative electric suppliers. On May 1, 2002,
all ComEd residential customers became eligible to choose their supplier of
electricity; however, as of December 31, 2002, no alternative electric
supplier had sought approval from the ICC and no electric utilities had
chosen to enter the ComEd residential market for the supply of electricity.
The increase in electric retail revenues includes increased revenues of
$226 million from customers in Pennsylvania who selected or returned to
PECO as their electric supplier. The increase was partially offset by a
decrease in revenues of $131 million from customers in Illinois electing to
purchase energy from an alternative retail electric supplier (ARES) or
ComEd's PPO.
o Rate Changes. The decrease in revenues attributable to rate changes
reflects $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 rate effective January 1, 2002 and the expiration of a 6%
reduction in PECO's rates during the first quarter of 2001.
o Other Effects. The primary other item impacting revenues in 2002 was an $11
million settlement of CTCs by a large PECO customer in the first quarter of
2001.
The reduction in wholesale revenue is primarily attributable to the
expiration of wholesale contracts that ComEd had entered into to support the
open access program in Illinois and the fact that wholesale revenues for 2001
included a reversal of a $15 million reserve for customer refunds because of a
favorable FERC ruling in 2001. The decrease in wholesale revenue was partially
offset by a $12 million reimbursement from Generation relating to third-party
energy reconciliations.
Energy Delivery's gas sales statistics and revenue detail were as
follows:
2002 2001 Variance
- ----------------------------------------------------------------------------------------
Deliveries in millions of cubic feet (mmcf) 85,545 81,528 4,017
Revenue $549 $654 $(105)
- ----------------------------------------------------------------------------------------
The changes in gas revenue for 2002 as compared to 2001, were as
follows:
Variance
- ------------------------------------------------------------------------
Rate Changes $ (108)
Weather 2
Volume 1
- ------------------------------------------------------------------------
Gas Revenue $ (105)
- ------------------------------------------------------------------------
o Rate Changes. The unfavorable variance in rates is attributable to an
adjustment of the purchased gas cost recovery by the PUC in December 2001.
The average rate per mmcf in 2002 was 20% lower than it was in 2001. PECO's
gas rates are subject to periodic adjustments by the PUC and are designed
to recover from or refund to customers the difference between actual cost
of purchased gas and the amount included in base rates and increases or
decreases in certain state taxes not recovered in base rates. Effective
December 1, 2002, the PUC approved a reduction in the purchased gas
adjustment of 4.5%.
29
o Weather. The weather impact was favorable, as a result of colder weather in
2002, as compared to 2001. Heating degree-days in PECO's service territory
increased 1% in 2002 compared to 2001.
o Volume. Exclusive of weather impacts, higher delivery volume increased
revenue by $1 million in 2002 compared to 2001. Total deliveries to
customers increased 5% in 2002 compared to 2001, primarily as a result of
customer growth and higher transportation volumes.
Results of Operations - Generation
Generation is one of the largest competitive electric generation
companies in the United States, as measured by owned and controlled MWs.
Generation combines its large generation fleet with an experienced wholesale
power marketing operation. During 2002, Generation acquired the generating
assets of Sithe New England as well as two generating stations from TXU Corp.
Including those acquisitions, Generation directly owns generation assets in the
Northeast, Mid-Atlantic, Midwest and Texas regions with a net capacity of 26,762
MWs including 14,547 MWs of nuclear capacity, and also controls another 13,900
MWs of capacity in the Midwest, Southeast and South Central regions through
long-term contracts.
In addition to its owned generation facilities, Generation owns a 49.9%
interest in Sithe with a call option, that first became available in December
2002, to purchase the remaining 50.1% interest (see further discussion in
Liquidity and Capital Resources). Sithe develops, owns and operates 22
generation facilities in North America. Currently, Sithe has a total generating
capacity of 1,321 MWs in operation and 230 MWs under construction. Generation
also owns a 50% interest in AmerGen, a joint venture with British Energy plc.
AmerGen owns three nuclear stations with total generation capacity of 2,481 MWs.
Generation's wholesale marketing unit, Power Team, a major wholesale
marketer of energy, uses Generation's energy generation portfolio, transmission
rights and expertise to ensure delivery of energy to Generation's wholesale
customers under long-term and short-term contracts, including the load
requirements of ComEd and PECO. Power Team markets any remaining energy in the
wholesale and spot markets.
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%
Revenue, net of Purchased Power & Fuel Expense 2,605 2,831 (226) (8.0%)
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%)
- -------------------------------------------------------------------------------------------------------------------
The changes in Generation's revenue, net of purchased power and fuel
expense, for 2002 compared to 2001, included the following:
o lower margins on market sales attributable to lower average market
energy prices,
30
o increased net trading portfolio losses of $36 million due to lower
trading margins primarily resulting from lower purchased power and
transmission costs, together with lower wholesale market prices,
o weather-related increases in sales to affiliates,
o lower average supply costs, and
o increased market sales volumes.
The changes in operating income for 2002 compared to 2001, included the
following:
o costs incurred for five additional refueling outages of $80 million,
o higher allocated corporate costs, including executive severance,
o increase in 2002 in the allowance for uncollectible accounts related
to a change in accounting estimate of $6 million,
o decrease in depreciation and decommissioning expense of $42 million
reflecting the extension by Generation in 2001 of the estimated
service lives of its generating stations,
o additional depreciation expense of $32 million on generating plants
placed in service, including two generating plants that were acquired
in April 2002 and a peaking facility placed in service in July 2002,
o costs related to additional security measures of $9 million,
o reduction in Generation's severance accrual of $10 million,
o decrease in expenses of $8 million related to fewer employees, and
o cost reductions related to the Cost Management Initiative.
The changes in income before income taxes for 2002 compared to 2001,
included the following:
o improved decommissioning trust investment income during 2002 to $58
million, compared to losses of $60 million in 2001, and
o net decrease in interest expense due to:
o increased long-term debt resulting in a $21 million increase and
o reduction in the variable interest rate on the spent nuclear fuel
obligation resulting in a decrease of $19 million.
Generation's effective income tax rate was 35.9% for 2002 compared to 39.0%
for 2001. This decrease was primarily attributable to tax-exempt interest
deductions in 2002 and other tax benefits recorded in 2002.
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. 141 "Business Combinations" (SFAS No. 141)
and SFAS No. 142, and income of $12 million, net of income taxes, recorded in
2001 related to the adoption of SFAS No. 133. See Note 4 of the Notes to
Consolidated Financial Statements for further discussion of these effects.
31
Generation Operating Statistics
Generation's sales and the supply of these sales, excluding the trading
portfolio, were as follows:
Sales (in GWhs) 2002 2001 % Change
- -------------------------------------------------------------------------------------------------------------------
Energy Delivery 118,473 116,917 1.3%
Exelon Energy 5,502 6,876 (20.0%)
Market Sales 83,565 72,333 15.5%
- -------------------------------------------------------------------------------------------------
Total Sales 207,540 196,126 5.8%
- -------------------------------------------------------------------------------------------------
Supply of Sales (in GWhs) 2002 2001 % Change
- -------------------------------------------------------------------------------------------------------------------
Nuclear Generation (1) 115,854 116,839 (0.8%)
Purchases - non-trading portfolio (2) 78,710 67,942 15.8%
Fossil and Hydro Generation 12,976 11,345 14.4%
- -------------------------------------------------------------------------------------------------
Total Supply 207,540 196,126 5.8%
- -------------------------------------------------------------------------------------------------
(1) Excluding AmerGen.
(2) Including purchased power agreements with AmerGen.
Trading volume of 69,933 GWhs and 5,754 GWhs for 2002 and 2001,
respectively, is not included in the table above.
32
Generation's average margin and other operating data for 2002 and 2001 were
as follows:
($/MWh)(1) 2002 2001 % Change
- -------------------------------------------------------------------------------------------------------------------
Average Revenue
Energy Delivery $ 33.48 $ 32.55 2.9%
Exelon Energy 44.87 41.53 8.0%
Market Sales 30.75 37.00 (16.9%)
Total - excluding the trading portfolio 32.68 34.51 (5.3%)
Average Supply Cost (2) - excluding trading portfolio $ 20.14 $ 20.26 (0.6%)
Average Margin - excluding the trading portfolio $ 12.54 $ 14.25 (12.0%)
- -------------------------------------------------------------------------------------------------------------------
(1) One megawatthour (MWh) is the equivalent of one thousand kWhs.
(2) Average supply cost includes purchased power and fuel costs.
2002 2001
- -------------------------------------------------------------------------------------------------------------------
Nuclear fleet capacity factor (1) 92.7% 94.4%
Nuclear fleet production cost per MWh (1) $ 13.00 $ 12.78
Average purchased power cost for wholesale operations per MWh $ 41.83 $ 45.94
- -------------------------------------------------------------------------------------------------------------------
(1) Including AmerGen and excluding Salem.
The factors below contributed to the overall reduction in Generation's
average margin for 2002.
Generation's GWh deliveries increased 5.8% in 2002 primarily due to
favorable weather conditions, which increased demand for Energy Delivery and
increased market sales attributable to the increased supply from acquired
generation and power uprates at existing facilities, slightly offset by a
decrease in sales to Exelon Energy, Enterprises' retail energy unit, due to
lower demand in the eastern energy markets.
Generation's supply mix changed due to:
o 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,
o decreased nuclear generation due to an increase in the number of
refueling outages during 2002, slightly offset by power uprates,
o increased Fossil and Hydro net generation due to the effect of 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 account for an increase of 2,500 GWhs, and
strong waterflows which increased the hydro output by 400 GWhs, and
o 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:
o increased weighted average on and off peak prices per MWh for supply
agreements with ComEd,
o higher contracted prices from Exelon Energy, impacted by lower actual
volumes to those customers, and
o lower market prices.
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
33
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 consists primarily of the infrastructure services business of
InfraSource, Inc. (InfraSource), the energy services business of Exelon
Services, Inc. (Exelon Services), the competitive retail energy sales business
of Exelon Energy, the district cooling business of Exelon Thermal Technologies,
Inc., communications joint ventures and other investments weighted towards the
communications, energy services and retail services industries.
Enterprises 2002 2001 Variance % Change
- -------------------------------------------------------------------------------------------------------------------
Operating Revenues $2,033 $2,292 $ (259) (11.3%)
Operating Income (Loss) (14) (77) 63 81.8%
Income (Loss) Before Income Taxes and Cumulative Effect
of Changes in Accounting Principles 134 (128) 262 n.m.
Income (Loss) Before Cumulative Effect of Changes in
Accounting Principles 65 (85) 150 176.5%
Net Income (Loss) (178) (85) (93) (109.4%)
- -------------------------------------------------------------------------------------------------------------------
n.m. - not meaningful
The changes in Enterprises' operating income (loss) for 2002 compared to
2001, included the following:
o lower revenues of $65 million from Exelon Services as a result of
reduced construction projects offset by lower construction costs of
$51 million,
o reductions in administrative expenses of $28 million primarily
resulting from the Cost Management Initiative,
o reduction of amortization expense of $23 million as result of the
discontinuance of goodwill amortization upon the adoption of SFAS No.
142 on January 1, 2002,
o accelerated depreciation of assets relating to Exelon Energy's
discontinuance of retail sales in the PJM region of $7 million,
o higher gross margins at Exelon Energy of $28 million, which reflect
discontinuing retail sales in the PJM region and improved gas and
electricity margins. Energy revenue reductions of $170 million were
more than offset by decreases in related cost of $198 million, which
included a favorable mark-to-market adjustment of $16 million, and
o higher gross margins at InfraSource of $7 million consisting of:
o higher infrastructure and construction services revenues of
$97 million from an increase in the electric line of
business offset by higher infrastructure and construction
costs of $53 million, and
o lower revenues of $117 million as a result of the continued
decline of the telecommunications industry and related
reduction in construction services offset by lower
construction costs of $80 million.
The changes in income (loss) before income taxes for 2002 compared to 2001,
included the following:
o a pre-tax gain of $198 million recorded on the AT&T Wireless sale,
o lower interest expense of $23 million due to pay down of debt from
proceeds of the AT&T Wireless sale,
o higher equity in earnings of unconsolidated affiliates of $16 million
resulting from the discontinuance of losses on AT&T Wireless as a
result of its sale,
34
o write-down of communications investments of $27 million, energy
related investment write-downs of $14 million, and a net write-down of
other assets of $4 million in 2002 offset by $12 million loss from net
write-downs of communications investments, a $1 million loss from an
energy related investment, and a net write-down of other assets of $2
million in 2001,
o equity in earnings from a communications joint venture of $9 million
primarily relating to its recovery of trade receivables previously
considered uncollectible, and
o lower interest income of $7 million.
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.
The cumulative effect of a change in accounting principle recorded in 2002
due to the adoption of SFAS No. 142 reduced net income by $243 million, net of
income taxes. See Note 4 of the Notes to Consolidated Financial Statements.
Year Ended December 31, 2001 Compared to Year Ended December 31, 2000
On October 20, 2000, we became the parent corporation of PECO and ComEd as
a result of the Merger. Our results of operations for 2000 consist of PECO's
results for the entire year and ComEd's results from October 20, 2000 to the end
of the year.
Net Income and Earnings Per Share
Our net income for 2001 increased $842 million, or 144%, compared to 2000.
Diluted earnings per share increased $1.56 per share, or 54%. Income before the
cumulative effect of changes in accounting principles increased $854 million, or
152%, for 2001. Diluted earnings per share on the same basis increased $1.64 per
share, or 60%. Earnings per share increased less than net income as a result of
an increase in the weighted average shares of common stock outstanding from the
issuance of common stock in connection with the Merger, partially offset by the
repurchase of common stock with the proceeds from PECO's May 2000 stranded cost
recovery securitization.
Results of Operations by Business Segment
The remaining sections under this heading, "Year Ended December 31, 2001
Compared To Year Ended December 31, 2000," present the operating results for
each of our business segments for 2001. All comparisons presented under this
heading are comparisons of operating results and other statistical information
for 2001 to operating results and other statistical information for 2000. These
results reflect intercompany transactions, which are eliminated in our
consolidated financial statements.
The October 20, 2000 acquisition of Unicom, and the January 1, 2001
corporate restructuring, significantly impacted our results of operations. To
provide a more meaningful analysis of results of operations, the business
comparisons below identify the portion of the variance that is attributable to
Unicom's results of operations and the portion of the variance that results from
normal operations attributable to changes in components of the underlying
operations of Exelon. The merger variance represents Unicom results for 2000
prior to the October 20, 2000 acquisition date, the effect of excluding
Merger-related costs from Exelon's 2000 operations and an adjustment to reflect
results as if the corporate restructuring occurred on January 1, 2000. The 2000
pro forma effects of the Merger and
35
restructuring were developed using estimates of various items, including
allocations of corporate overheads to business segments and intercompany
transactions.
Income (Loss) Before the Cumulative Effect of Changes in Accounting Principles by Business Segment
Components of Variance
----------------------
Merger Normal
2001 2000 Variance Variance Operations
- -------------------------------------------------------------------------------------------------------------------
Energy Delivery $ 1,022 $ 587 $ 435 $ 598 $ (163)
Generation 512 260 252 (1) 253
Enterprises (85) (94) 9 (31) 40
Corporate (33) (191) 158 115 43
- -------------------------------------------------------------------------------------------------------------------
Total $ 1,416 $ 562 $ 854 $ 681 $ 173
- -------------------------------------------------------------------------------------------------------------------
Net Income (Loss) by Business Segment
Components of Variance
-----------------------
Merger Normal
2001 2000 Variance Variance Operations
- -------------------------------------------------------------------------------------------------------------------
Energy Delivery $ 1,022 $ 587 $ 435 $ 598 $ (163)
Generation 524 260 264 (1) 265
Enterprises (85) (94) 9 (31) 40
Corporate (33) (167) 134 115 19
- -------------------------------------------------------------------------------------------------------------------
Total $ 1,428 $ 586 $ 842 $ 681 $ 161
- -------------------------------------------------------------------------------------------------------------------
Results of Operations - Energy Delivery
Components of Variance
----------------------
Merger Normal
Energy Delivery 2001 2000 Variance Variance Operations
- -------------------------------------------------------------------------------------------------------------------
Operating Revenues $ 10,171 $ 4,511 $ 5,660 $ 5,168 $ 492
Revenue, net of Purchased Power
& Fuel Expense 5,699 2,725 2,974 2,966 8
Operating Income 2,593 1,502 1,091 1,132 (41)
Income Before Income Taxes 1,725 1,008 717 919 (202)
Net Income 1,022 587 435 598 (163)
- -------------------------------------------------------------------------------------------------------------------
Energy Delivery's revenue net of purchased power and fuel expense, in 2001
was comparable to that for 2000.
The changes in Energy Delivery's operating income for 2001 compared to
2000, included the following:
o increased depreciation expense of $43 million, primarily associated
with capital additions,
o increased regulatory asset amortization of $34 million, primarily
attributable to additional amortization of PECO's CTCs,
o higher administrative and general costs as a result of increased
allocation of costs previously recorded at a corporate level, and
o higher employee severance costs of $18 million in 2001 associated with
the Merger.
The changes in income before income taxes for 2001 compared to 2000,
included the following:
36
o reduction of $115 million in intercompany interest income in 2001 from
Unicom Investments, Inc.,
o gain of $113 million on a forward share repurchase arrangement
recognized during the first quarter of 2000,
o lower interest expense due to reductions in the amount of debt
outstanding as well as lower interest rates due to debt refinancing,
o non-recurring loss of $38 million on the sale of Cotter Corporation, a
ComEd subsidiary, recognized during the first quarter of 2000, and
o additional interest on Transition Bonds issued to securitize PECO's
stranded cost recovery.
The effective income tax rate was 40.8% for 2001 compared to 41.8% for
2000. This decrease in the effective tax rate was primarily attributable to a
reduction in state income tax.
Energy Delivery's electric sales statistics are as follows:
Retail Deliveries - (GWhs) 2001 2000 (1) Variance % Change
- -------------------------------------------------------------------------------------------------------------------
Bundled Deliveries (2)
Residential 33,355 33,322 33 0.1%
Commercial & Industrial 29,433 28,752 681 2.4%
Large Commercial & Industrial 23,265 23,639 (374) (1.6%)
Public Authorities & Electric Railroads 8,645 8,143 502 6.2%
- -----------------------------------------------------------------------------------------------------
Total Bundled Deliveries 94,698 93,856 842 0.9%
- -----------------------------------------------------------------------------------------------------
Unbundled Deliveries (3)
Alternative Energy Suppliers
- ----------------------------
Residential 3,105 1,986 1,119 56.3%
Small Commercial & Industrial 4,471 6,322 (1,851) (29.3%)
Large Commercial & Industrial 7,810 13,211 (5,401) (40.9%)
Public Authorities & Electric Railroads 372 598 (226) (37.8%)
- -----------------------------------------------------------------------------------------------------
15,758 22,117 (6,359) (28.8%)
- -----------------------------------------------------------------------------------------------------
PPO (ComEd Only)
- ----------------
Small Commercial & Industrial 3,279 1,433 1,846 128.8%
Large Commercial & Industrial 5,750 2,813 2,937 104.4%
Public Authorities & Electric Railroads 987 1,087 (100) (9.2%)
- -----------------------------------------------------------------------------------------------------
10,016 5,333 4,683 87.8%
- -----------------------------------------------------------------------------------------------------
Total Unbundled Deliveries 25,774 27,450 (1,676) (6.1%)
- -----------------------------------------------------------------------------------------------------
Total Retail Deliveries 120,472 121,306 (834) (0.7%)
- -----------------------------------------------------------------------------------------------------
(1) Includes the operations of ComEd as if the Merger occurred on January 1,
2000.
(2) Bundled service reflects deliveries to customers taking electric service
under tariffed rates, which include the cost of energy and the delivery
cost of the transmission and the distribution of the energy. PECO's
tariffed rates also include a CTC. See Note 6 of the Notes to Consolidated
Financial Statements for a discussion of CTCs.
(3) Unbundled service reflects customers electing to receive electric
generation service from an alternative energy supplier or ComEd's PPO. See
Note 5 of the Notes to Consolidated Financial Statements for further
discussion of ComEd's PPO.
37
Electric Revenue 2001 2000 (1) Variance % Change
- -------------------------------------------------------------------------------------------------------------------
Bundled Revenues (2)
Residential $ 3,336 $ 3,348 $ (12) (0.4%)
Small Commercial & Industrial 2,503 2,371 132 5.6%
Large Commercial & Industrial 1,452 1,343 109 8.1%
Public Authorities & Electric Railroads 502 471 31 6.6%
- -----------------------------------------------------------------------------------------------------
Total Bundled Revenues 7,793 7,533 260 3.5%
- -----------------------------------------------------------------------------------------------------
Unbundled Revenues (3)
Alternative Energy Suppliers
- ----------------------------
Residential 235 135 100 74.1%
Small Commercial & Industrial 129 216 (87) (40.3%)
Large Commercial & Industrial 138 295 (157) (53.2%)
Public Authorities & Electric Railroads 6 18 (12) (66.7%)
- -----------------------------------------------------------------------------------------------------
508 664 (156) (23.5%)
- -----------------------------------------------------------------------------------------------------
PPO (ComEd Only)
- ----------------
Small Commercial & Industrial 220 92 128 139.1%
Large Commercial & Industrial 343 158 185 117.1%
Public Authorities & Electric Railroads 59 56 3 5.4%
- -----------------------------------------------------------------------------------------------------
622 306 316 103.3%
- -----------------------------------------------------------------------------------------------------
Total Unbundled Revenues 1,130 970 160 16.5%
- -----------------------------------------------------------------------------------------------------
Total Electric Retail Revenues 8,923 8,503 420 4.9%
- -----------------------------------------------------------------------------------------------------
Wholesale and Miscellaneous Revenue (4) 594 644 (50) (7.8%)
- -----------------------------------------------------------------------------------------------------
Total Electric Revenue $ 9,517 $ 9,147 $ 370 4.0%
- -----------------------------------------------------------------------------------------------------
(1) Includes the operations of ComEd as if the Merger occurred on January 1,
2000. Total revenues for Energy Delivery recorded in 2000 were $4.5
billion.
(2) 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.
(3) 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.
(4) Wholesale and miscellaneous revenues include sales to alternative energy
suppliers, transmission revenue, sales to municipalities and other
wholesale energy sales.
The changes in electric retail revenues for 2001, as compared to 2000, as
if the Merger occurred on January 1, 2000, were attributable to the following:
Variance
- -------------------------------------------------------------------------------
Rate Changes $ 217
Customer Choice 131
Weather 98
Revenue Taxes (88)
Other Effects 62
- -------------------------------------------------------------------------------
Electric Retail Revenue $ 420
- -------------------------------------------------------------------------------
o Rate Changes. The increase in revenues attributable to rate changes
reflects the expiration of a 6% reduction in PECO's electric rates in
effect for 2000 related to PECO's restructuring settlement, partially
offset by a $60 million PECO rate reduction in effect for 2001, and a 5%
ComEd residential rate reduction, effective October 1, 2001, required by
the Illinois restructuring legislation.
38
o Customer Choice. All PECO and all ComEd non-residential customers had the
choice to purchase energy from other suppliers throughout 2001. The
increase in electric retail revenues included increased revenues of $276
million from customers in Pennsylvania who selected or returned to PECO as
their electric generation supplier. This was partially offset by a decrease
in revenues of $145 million from customers in Illinois electing to purchase
energy from an ARES or from ComEd, under the PPO.
o Weather. The weather impact was favorable compared to 2000 as a result of
warmer summer weather conditions, although the favorable summer weather
conditions were partially offset by unfavorable winter weather conditions,
primarily in the ComEd service territory.
o Revenue Taxes. The change in revenue taxes represents a change in
presentation of certain revenue taxes for ComEd from operating revenue and
tax expense to collections recorded as liabilities resulting from Illinois
legislation. This change in presentation does not affect income.
o Other Effects. A strong housing construction market in Chicago contributed
to residential and small commercial and industrial customer volume growth,
partially offset by the unfavorable impact of a slower economy on large
commercial and industrial customers.
The reduction in Wholesale and Miscellaneous revenues in 2001, as compared
to 2000, reflects lower off-system sales due to the expiration of wholesale
contracts that were offered by ComEd from June 2000 to May 2001 to support the
open access program in Illinois, partially offset by increased transmission
service revenue and the reversal of a $15 million reserve for revenue refunds to
ComEd's municipal customers as a result of a favorable FERC ruling.
Energy Delivery's gas sales statistics were as follows:
2001 2000 Variance
- ---------------------------------------------------------------------------
Deliveries in mmcf 81,528 91,686 (10,158)
Revenue $654 $532 $122
- ---------------------------------------------------------------------------
The changes in gas revenue for 2001, as compared to 2000, were as follows:
Variance
- -----------------------------------------------------------------------------
Price $ 174
Weather (38)
Volume (14)
- -----------------------------------------------------------------------------
Gas Revenue $ 122
- -----------------------------------------------------------------------------
o Rate Changes. The favorable variance in price is attributable to an
adjustment of the purchased gas cost recovery by the PUC, effective in
December 2000. The average price per million cubic feet for all customers
for 2001 was 39% higher than 2000. PECO's gas rates are subject to periodic
adjustments by the PUC designed to recover or refund the difference between
actual cost of purchased gas and the amount included in base rates and to
recover or refund increases or decreases in certain state taxes not
recovered in base rates.
o Weather. The unfavorable weather impact is attributable to warmer winter
weather conditions in the PECO service territory. Heating degree days
decreased 12% in 2001 compared to 2000.
o Volume. Exclusive of weather impacts, lower delivery volume affected
revenue by $14 million compared to 2000. Total volume of sales to retail
customers decreased 11% compared to 2000, primarily as a result of slower
economic conditions in 2001 offset by customer growth.
39
Results of Operations - Generation
Components of Variance
----------------------
Merger Normal
Generation 2001 2000 Variance Variance Operations
- -------------------------------------------------------------------------------------------------------------------
Operating Revenues $ 6,826 $ 3,274 $ 3,552 $ 2,772 $ 780
Revenue, net of Purchased Power &
Fuel Expense 2,831 1,428 1,403 1,082 321
Operating Income 872 441 431 23 408
Income Before Income Taxes 839 420 419 (10) 429
Income Before Cumulative Effect of Changes
in Accounting Principles 512 260 252 (1) 253
Net Income 524 260 264 (1) 265
- -------------------------------------------------------------------------------------------------------------------
The changes in Generation's revenue, net of purchased power and fuel
expense, for 2001 compared to 2000, included the following:
o increases in wholesale market prices during the first five months
of 2001, particularly in the PJM and Mid-America Interconnected
Network regions, which were primarily driven by significant
increases in fossil fuel prices,
o higher revenues in 2001 due to the inclusion of charges to
affiliates for line losses which were not included in pro forma
2000 revenue,
o mark-to-market gains of $16 million and $14 million on
non-trading and trading energy contracts, respectively, offset by
realized trading losses of $6 million in 2001, and
o higher nuclear plant output due to increased capacity factors
during 2001.
The large concentration of nuclear generation in Generation's portfolio
allowed it to capture higher margins in the wholesale market for sales to
non-affiliates due to minimal increases in fuel costs.
The changes in operating income for 2001 compared to 2000, included the
following:
o reductions in the number of employees,
o fewer nuclear outages in 2001 than in 2000,
o increased decommissioning expense of $140 million reflecting the
discontinuance of regulatory accounting practices for certain
nuclear generating stations,
o net realized losses on decommissioning trust investments during
2001 of $60 million, and
o additional reserves related to litigation of $30 million.
Other items decreasing net income were an increase in equity in earnings of
AmerGen and Sithe of $90 million as a result of acquisitions in 2000 and a
reduction in depreciation and decommissioning expense of $90 million
attributable to the extension of estimated service lives of Generation's
generating plants.
The effective income tax rate was 39.0% for 2001 compared to 38.1% for
2000. This increase in the effective tax rate was primarily attributable to the
change in the amortization of investment tax credits. The investment tax credit
amortization period was extended as a result of 2001 plant life extensions.
The cumulative effect of a change in accounting principle recorded in 2001
was income of $12 million, net of income taxes, related to the adoption of SFAS
No. 133.
40
For 2001, Generation's sales were 201,879 GWhs, approximately 60% of which
were to affiliates. Supply sources were as follows:
- ------------------------------------------------------------------------------
Nuclear units 54%
Purchases 37%
Fossil and hydro units 3%
Generation investments 6%
- ------------------------------------------------------------------------------
Total 100%
- ------------------------------------------------------------------------------
Generation's nuclear fleet, including AmerGen, performed at a weighted
average capacity factor of 94.4% for 2001 compared to 93.8% in 2000.
Generation's nuclear fleet's production costs, including AmerGen, were $12.78
per MWh for 2001, compared to $14.64 per MWh for 2000.
Results of Operations - Enterprises
Components of Variance
----------------------
Merger Normal
Enterprises 2001 2000 Variance Variance Operations
- -------------------------------------------------------------------------------------------------------------------
Operating Revenues $ 2,292 $ 1,395 $ 897 $ 467 $ 430
Operating Income (Loss) (77) (78) 1 (10) 11
Income (Loss) Before Income Taxes (128) (146) 18 (52) 70
Net Income (Loss) (85) (94) 9 (31) 40
- -------------------------------------------------------------------------------------------------------------------
The changes in Enterprises' operating income (loss) for 2001 compared
to 2000, included the following:
o Exelon Energy discontinuing retail sales in the PJM region, which
resulted in lower power costs of $193 million offset by lower
retail energy sales of $166 million,
o acquisitions by Exelon Services and InfraSource resulted in
increased infrastructure and construction revenues of $574
million offset by increased related costs of $554 million,
o increased depreciation and amortization expense of $26 million as
a result of goodwill amortization related to acquisitions made by
Exelon Services and InfraSource, and
o higher construction costs of $32 million from Exelon Services as
a result of increased construction projects offset by higher
construction revenues of $26 million.
The changes in income (loss) before income taxes for 2001 compared to 2000,
included the following:
o net realized gains on investments of $27 million,
o higher equity in earnings of unconsolidated affiliates of $23
million from lower net losses in communications joint ventures,
o reduced losses of $21 million from sale of assets in 2000, and
o net write-downs on investments of $13 million.
The effective income tax rate was 33.6% for 2001 compared to 35.6% for
2000. This decrease in the effective tax rate was primarily attributable to
higher book write-downs of investments in 2001, which were not deductible for
income tax purposes.
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's and
41
Generation's operations. 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 a $1.5 billion
revolving credit facility which we currently utilize to support our commercial
paper program. See the Credit Issues section of Liquidity and Capital Resources
for further discussion. We primarily use our capital resources to fund our
capital requirements, including construction, investments in new and existing
ventures, to repay maturing debt and to pay common stock dividends. Future
acquisitions that we may undertake may require external financing, which might
include our issuing common stock.
Cash Flows from Operating Activities
Cash flows provided by 2002 operations were consistent with 2001 at $3.6
billion. Energy Delivery and Generation provided approximately 70% and 30%,
respectively, of the 2002 cash flows, while Enterprises' contribution was not
significant. 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 and are weighted toward the third quarter. Energy Delivery's future
cash flows will depend upon the ability to achieve operating cost reductions and
the impact of the economy, weather and customer choice 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 prices. Although the amounts
may vary from period to period as a result of the uncertainties inherent in
business, we expect that Energy Delivery and Generation will continue to provide
a reliable and steady source of internal cash flow from operations for the
foreseeable future. In the fourth quarter of 2002, we made a discretionary
tax-deductible pension plan contribution of $150 million funded by ComEd,
Generation and BSC. We also expect to make a discretionary plan contribution in
2003 of $300 million to $350 million.
Cash Flows from Investing Activities
Cash flows used in investing activities for 2002 were $2.5 billion, of which
$2.2 billion was used for capital expenditures, compared to $2.4 billion in
2001, of which $2.1 billion was used for capital expenditures. Investing
activities in 2002 also includes $445 million for the acquisition of generating
plants.
Capital expenditures by business segment for 2002 and projected amounts for
2003 are as follows:
2002 2003
- -------------------------------------------------------------------------------------------------------------------
Energy Delivery $ 1,041 $ 989
Generation 990 963
Enterprises 44 26
Corporate and Other 75 32
- -------------------------------------------------------------------------------------------------------------------
Subtotal 2,150 2,010
Acquisition of Generating Plants 445 --
- -------------------------------------------------------------------------------------------------------------------
Total Capital Expenditures and Acquisition of Generating Plants $ 2,595 $ 2,010
- -------------------------------------------------------------------------------------------------------------------
Energy Delivery's estimated capital expenditures for 2003 reflect the
continuation of efforts to improve the reliability of its distribution system.
Approximately 35% of the budgeted 2003 expenditures are for growth and the
remainder are for additions to or upgrades of existing facilities. We anticipate
that
42
Energy Delivery will obtain financing, when necessary, through borrowings,
the issuance by PECO or ComEd, or both, of preferred securities or capital
contributions made by us.
Generation purchased two natural-gas and oil-fired generating plants from
TXU on April 25, 2002. The $443 million purchase was funded with commercial
paper, which Exelon issued and Generation is repaying from cash flows from
operations. The balance of Generation short-term borrowings at December 31, 2002
attributable to the TXU purchase was approximately $70 million. Investing
activities also include a $2 million use of cash for the November 1, 2002
purchase of Sithe New England. The $2 million use is net of $12 million of cash
acquired. The remainder of the purchase was financed with a $534 million note to
Sithe. In 2002, Generation agreed to make a loan to AmerGen of up to $100
million, at an interest rate of one-month LIBOR plus 2.25%, and with a maturity
date of July 1, 2003. As of December 31, 2002, the balance of the loan to
AmerGen was $35 million.
We project that Generation's capital expenditures in 2003 will be lower
than they were in 2002, 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. Eight nuclear refueling outages are planned for
2003, compared to 11 during 2002. We project that the total capital expenditures
for nuclear refueling outages will decrease in 2003 over 2002 by $10 million.
Generation has agreed to make capital contributions to AmerGen of 50% of the
purchase price of any acquisitions that AmerGen makes. We anticipate that
Generation's capital expenditures will be funded by internally generated funds,
Generation's borrowings or capital contributions from us.
Enterprises' capital expenditures were $44 million in 2002. Enterprises'
capital expenditures for 2002 were primarily for additions to or upgrades of
existing facilities. On April 1, 2002, Enterprises sold its 49% interest in AT&T
Wireless for $285 million in cash.
We project that Enterprises' capital expenditures for 2003 will be
approximately $26 million, primarily for additions to or upgrades of existing
facilities. We anticipate that all of Enterprises' capital expenditures will be
funded by internally generated funds, capital contributions or borrowings from
us.
Our total estimated capital expenditures in 2003 are approximately $2.0
billion. Internally generated cash flow is expected to meet capital requirements
excluding acquisitions. Our proposed capital expenditures and other investments
are subject to periodic review and revision to reflect changes in economic
conditions and other factors.
Cash Flows from Financing Activities
Cash flows used in financing activities were $1.1 billion in 2002, as
compared to $1.3 billion in 2001, due to lower dividend payments, a contribution
from a minority interest, and increased employee stock purchase plan activity.
The primary components of 2002 financing activity are as follows:
o ComEd issued $700 million of First Mortgage Bonds and pollution
control bonds to redeem $700 million of First Mortgage Bonds and
pollution control bonds. ComEd also paid at maturity $500 million of
First Mortgage Bonds and other long-term debt, retired $340 million of
transitional trust notes and had net issuances of $123 million of
commercial paper.
o PECO issued $225 million of First and Refunding Mortgage Bonds. The
proceeds of these bonds were used to repay commercial paper that it
used to pay at maturity $222 million of First and Refunding Mortgage
Bonds. PECO made principal payments of $326 million on transition
bonds and net issuances of $200 million of commercial paper.
43
On January 22, 2003, ComEd issued $350 million of 3.70% First Mortgage
Bonds, due on February 1, 2008 and $350 million of 5.875% First Mortgage Bonds,
due on February 1, 2033. These bond proceeds were used to refinance long-term
debt that had been retired during the third and fourth quarters of 2002.
The 2001 common stock dividend payments of $583 million cover the period
from October 20, 2000, the date of the Merger, through the end of 2001. The 2002
cash dividend payments on common stock were $563 million. On January 28, 2003,
our Board of Directors declared a quarterly dividend of $0.46 per share
representing an annual dividend rate of $1.84 per share, which is an increase of
$0.08 per share over 2002. We intend to grow our dividend over time at a rate of
approximately 4% to 5%, commensurate with long-term earnings growth. The payment
of future dividends is subject to approval and declaration by the Board of
Directors each quarter.
Financing activities in 2002 exclude the non-cash issuance of a $534
million note to Sithe for the November 1, 2002 acquisition of Sithe New England
and approximately $1.0 billion of Sithe New England long-term debt, which is
reflected in our Consolidated Balance Sheets as of December 31, 2002.
Credit Issues
We meet our short-term liquidity requirements primarily through the
issuance of commercial paper by the Exelon corporate holding company (Exelon
Corporate) and by ComEd, PECO and Generation. Exelon Corporate participates,
along with ComEd, PECO and Generation, in a $1.5 billion unsecured 364-day
revolving credit facility with a group of banks. The credit facility that became
effective on November 22, 2002, includes a term-out option that allows any
outstanding borrowings at the end of the revolving credit period to be repaid on
November 21, 2004. Exelon Corporate may increase or decrease the sublimits of
each of the participants upon written notification to the banks. As of December
31, 2002, Exelon Corporate's sublimit was $900 million, ComEd's was $200
million, PECO's was $400 million and there was no sublimit for Generation. The
credit facility is used principally to support the commercial paper programs of
Exelon Corporate, ComEd, PECO and Generation. At December 31, 2002, our
Consolidated Balance Sheet reflects the $948 million of commercial paper
outstanding, of which $267 million was classified as long-term debt.
For 2002, the average interest rate on notes payable was approximately
1.88%. Certain of the credit agreements to which Exelon Corporate, ComEd, PECO
and Generation are parties require them to maintain a 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 attributed to
securitization debt, certain changes in working capital, distributions on
preferred securities of subsidiaries and in the case of Exelon Corporate and
Generation, interest on Sithe New England's debt. Exelon Corporate is measured
at the Exelon consolidated level. The following table summarizes the threshold
reflected in the credit agreement that the ratio cannot be less than for the
twelve-month period ended December 31, 2002:
Credit Agreement Threshold
- ------------------------------------------------------------------------------
Exelon Corporate 2.65 to 1
ComEd 2.25 to 2
PECO 2.25 to 1
Generation 3.25 to 1
- ------------------------------------------------------------------------------
At December 31, 2002, we were in compliance with the credit agreement
thresholds.
44
At December 31, 2002, our capital structure consisted of 60% of long-term
debt, 32% common equity, 5% notes payable and 3% preferred securities of
subsidiaries. Total debt included $6.2 billion of securitization debt
constituting obligations of certain consolidated special purpose entities,
representing 26% of capitalization. These consolidated special purpose entities
were created for the sole purpose of issuing debt obligations to securitize
intangible transition property and CTC's of Energy Delivery. Shareholders'
equity was reduced by $1 billion in 2002 due to the recording of a minimum
pension liability.
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 utility-money pool. Participation in the
money pool is subject to authorization by Exelon's corporate treasurer. ComEd
and its subsidiary, Commonwealth Edison Company of Indiana, Inc., PECO,
Generation and BSC may participate in the money pool as lenders and borrowers,
and Exelon Corporate as a lender. Contributions to and permitted borrowings from
the money pool are based on whether the contributions and borrowings result in
economic benefits to all the participants. Interest on borrowings is based on
short-term market rates of interest, or, if from an external source, specific
borrowing rates. There were no material money pool transactions in 2002.
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. None of our borrowings are 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
$1.5 billion credit facility, and certain other credit facilities. From time to
time, we enter into energy commodity and other contracts that require the
maintenance of investment grade ratings. Failure to maintain investment grade
ratings would allow counterparties to certain energy commodity contracts to
terminate the contracts and settle the transactions on a net present value
basis. The following table shows our securities ratings at December 31, 2002:
Securities Moody's Investors Standard & Poors Fitch Investors
Service Corporation 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
PECO Senior secured debt A2 A A
Commercial paper P1 A2 F1
Generation Senior unsecured debt Baa1 A- BBB+
Commercial paper P2 A2 F2
- ----------------------------------------------------------------------------------------------------------------------
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.
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 billion. As of December 31, 2002, there was $1.8 billion of financing
authority remaining under the SEC order. Our request for an additional $4
billion in financing authorization is pending with the SEC. The current order
limits our short-term debt outstanding to $3 billion of the $4 billion total
financing authority. Our request that the short-term debt sub-limit restriction
be eliminated is pending with the SEC. The SEC order also authorized us to issue
45
guarantees of up to $4.5 billion outstanding at any one time. At December 31,
2002, Exelon had provided $1.5 billion of guarantees. See Contractual
Obligations, Commercial Commitments and Off Balance Sheet Obligations 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) on and after June 30, 2002 of not less than 30%. Exelon
expects that it will maintain a common equity ratio of at least 30%.
Under PUHCA, Exelon, ComEd, PECO and Generation can pay dividends only from
retained, undistributed or current earnings. However, the SEC order granted
permission to ComEd, and to us, to the extent we receive dividends from ComEd
paid from ComEd additional paid-in-capital, to pay up to $500 million in
dividends out of additional paid-in capital, although Exelon may not pay
dividends out of paid-in capital after December 31, 2002 if its common equity is
less than 30% of its total capitalization. At December 31, 2002, Exelon had
retained earnings of $2.0 billion, including ComEd's retained earnings of $577
million, PECO's retained earnings of $401 million and Generation's undistributed
earnings of $924 million. We are also limited by order of the SEC under PUHCA to
an aggregate investment of $4 billion in exempt wholesale generators (EWGs) and
foreign utility companies (FUCOs). At December 31, 2002, we had invested $2.1
billion in EWGs, leaving $1.9 billion of investment authority under the order.
Our request for an additional $1.5 billion in EWG investment authorization is
pending with the SEC.
During 2001, we loaned $150 million to Sithe. Sithe paid $2 million in
interest on this loan and fully repaid the principal balance in December of 2001
from the proceeds of a bank borrowing. In connection with a bank borrowing by
Sithe, we provided the lenders with a support letter confirming our investment
in Sithe and agreeing to maintain a positive net worth in Sithe. We expect that
Sithe's net worth will remain positive for the foreseeable future and,
accordingly, this agreement is not reflected in the following Contractual
Obligations, Commercial Commitments and Off Balance Sheet Obligations
discussion. This agreement does not guarantee any debt or obligation of Sithe.
Contractual Obligations, Commercial Commitments and Off Balance Sheet
Obligations
Our contractual obligations as of December 31, 2002 representing cash
obligations that we consider to be firm commitments are as follows:
Payment due within
-------------------------------------------------------
Due 2008
Total 2003 2004-2005 2006-2007 and beyond
- -------------------------------------------------------------------------------------------------------------------
Long-Term Debt $ 14,595 $ 1,669 $ 2,275 $ 2,445 $ 8,206
Notes Payable 681 681 -- -- --
Short-Term Note to Sithe 534 534 -- -- --
Operating Leases 895 77 117 103 598
Purchase Obligations 14,729 2,677 2,987 1,856 7,209
Spent Nuclear Fuel Obligation 858 -- -- -- 858
Obligation to Minority Shareholders 54 3 6 6 39
- -------------------------------------------------------------------------------------------------------------------
Total Contractual Obligations $ 32,346 $ 5,641 $ 5,385 $ 4,410 $ 16,910
- -------------------------------------------------------------------------------------------------------------------
For additional information about:
o long-term debt see Note 13 of the Notes to Consolidated Financial
Statements
o notes payable see Note 12 of the Notes to Consolidated Financial Statements
o short-term note to Sithe see Note 3 of the Notes to Consolidated Financial
Statements
o operating leases see Note 19 of the Notes to Consolidated Financial
Statements
o purchase obligations see Note 19 of the Notes to Consolidated Financial
Statements
o the spent nuclear fuel obligation see Note 11 of the Notes to Consolidated
Financial Statements
46
o the obligation to minority shareholders see Note 19 of the Notes to
Consolidated Financial Statements
We have a long-term supply agreement through December 2022 with Distrigas
to guarantee physical gas supply to our New England generating units. Under the
agreement, prices are indexed to New England gas markets.
Generation has an obligation to decommission its nuclear power plants. Our
current estimate of decommissioning costs for the nuclear plants owned by
Generation is $7.4 billion in current year (2003) dollars. Nuclear
decommissioning activity occurs primarily after a plant is retired. Based on the
extended license lives of our nuclear plants, we will begin decommissioning our
plants from 2014 through 2056, with expenditures primarily occurring when our
operating plants are decommissioned, during the period from 2029 through 2056.
At December 31, 2002, the decommissioning liability, which is recognized over
the life of the plant, was recorded in our Consolidated Balance Sheets as
Accumulated Depreciation and Deferred Credits and Other Liabilities in the
amounts of $2.8 billion and $1.4 billion, respectively. To fund future
decommissioning costs, Generation held $3.1 billion of investments in trust
funds, including net unrealized gains and losses, at December 31, 2002.
Our commercial commitments as of December 31, 2002, representing
commitments not recorded on the balance sheet but potentially triggered by
future events, including obligations to make payment on behalf of other parties
and financing arrangements to secure our obligations, are as follows:
Expiration within
--------------------------------------------------------------
2008
Total 2003 2004-2005 2006-2007 and beyond
- -------------------------------------------------------------------------------------------------------------------
Credit Facility (a) $ 1,500 $ 1,500 $ -- $ -- $ --
Letters of Credit (non-debt) (b) 111 106 5 -- --
Letters of Credit (Long-Term Debt) (c) 456 305 151 -- --
Insured Long-Term Debt (d) 254 -- -- -- 254
Guarantees of Letters of Credit (e) 226 226 -- -- --
Performance Guarantees (f) 101 -- -- -- 101
Surety Bonds (g) 521 329 57 4 131
Energy Marketing Contract
Guarantees (h) 124 114 10 -- --
Nuclear Insurance Guarantees (i) 1,380 -- -- -- 1,380
Lease Guarantees (j) 13 -- -- 2 11
Preferred Securities (k) 128 -- -- -- 128
Sithe New England Equity Guarantee (l) 38 38 -- -- --
Guarantees of Long-Term Debt (m) 41 2 -- -- 39
- -------------------------------------------------------------------------------------------------------------------
Total Commercial Commitments $ 4,893 $ 2,620 $ 223 $ 6 $ 2,044
- -------------------------------------------------------------------------------------------------------------------
(a) Credit Facility - Exelon, along with ComEd, PECO, and Generation, maintain a
$1.5 billion 364-day credit facility to support commercial paper issuances.
At December 31, 2002, there were no borrowings against the credit facility.
Additionally, at December 31, 2002, there was $948 million of commercial
paper outstanding.
(b) Letters of Credit (non-debt) - Exelon and certain of its subsidiaries
maintain non-debt letters of credit to provide credit support for certain
transactions as requested by third parties.
(c) Letters of Credit (Long-Term Debt) - Direct-pay letters of credit issued in
connection with variable-rate debt in order to provide liquidity in the
event that it is not possible to remarket all of the debt as required
following specific events, including changes in the basis of determining the
interest rate on the debt.
(d) Insured Long-Term Debt - Borrowings that have been credit-enhanced through
the purchase of insurance coverage equal to the amount of principal
outstanding plus interest.
(e) Guarantees of letters of credit - Guarantees issued to provide support for
letters of credit as required by third parties. These guarantees could be
called upon only in the event of non-payment by a subsidiary.
(f) Performance Guarantees - Guarantees issued to ensure execution under
specific contracts.
(g) Surety Bonds - Guarantees issued related to contract and commercial surety
bonds, excluding bid bonds.
(h) Energy Marketing Contract Guarantees - Guarantees issued to ensure
performance under energy commodity contracts.
47
(i) Nuclear Insurance Guarantees - Guarantees of nuclear insurance required
under the Price-Anderson Act. $1.1 billion of this total exposure is exempt
from the $4.5 billion PUHCA guarantee limit by SEC rule.
(j) Lease Guarantees - Guarantees issued to ensure payments on building leases.
(k) Preferred Securities - Guarantees issued to guarantee the preferred
securities of the subsidiary trusts of PECO. See Note 16 of the Notes to
Consolidated Financial Statements for further information.
(l) Sithe New England Equity Guarantee - See Note 3 of the Notes to Consolidated
Financial Statements for further information on the $38 million guarantee.
After construction of the SBG facilities is complete, Exelon could be
required to guarantee up to an additional $42 million in order to ensure
that the SBG facilities have adequate funds available for potential outage
and other operating costs and requirements.
(m) Guarantees of Long-Term Debt - Issued to guarantee payment of subsidiary
debt.
Sithe Boston Generation Project Debt. We participate in a $1.25 billion
credit facility, most of which is available to finance the construction projects
of Sithe Boston Generating, LLC (the SBG Facility). The outstanding balance of
this facility at December 31, 2002 was $1.0 billion. The SBG Facility provides
that if these construction projects are not completed by June 12, 2003, the SBG
Facility lenders will have the right, but will not be required, to, among other
things, declare all amounts then outstanding under the SBG Facility and the
interest rate swap agreements to be due. Generation believes that the
construction projects will be substantially complete by May 31, 2003, but that
all of the approvals required under the SBG Facility may not be issued by that
date. Generation is currently evaluating whether the requirements of the SBG
Facility relating to the construction projects can be satisfied by June 12,
2003. In the event that the requirements are not expected to be satisfied by
June 12, 2003, Generation will contact the SBG Facility lenders concerning an
amendment or waiver of these provisions of the SBG Facility. Generation
currently expects that arrangements for such an amendment or waiver, if
necessary, can be successfully negotiated with the SBG Facility lenders.
Unconsolidated Equity Investments. Generation is a 49.9% owner of Sithe and
accounts for the investment as an unconsolidated equity investment. The Sithe
New England purchase did not affect the accounting for Sithe as an equity
investment. Separate from the Sithe New England transaction, Generation is
subject to a Put and Call Agreement (PCA) that gives Generation the right to
purchase (Call) the remaining 50.1% of Sithe, and gives the other Sithe
shareholders the right to sell (Put) their interest to Generation. If the Put
option is exercised, Generation has the obligation to complete the purchase. At
the end of this exercise period, which is December 2005, if Generation has not
exercised its Call option and the other stockholders have not exercised their
Put rights, Generation will have an additional one-time option to purchase
shares from the other stockholders to bring Generation's ownership in Sithe from
the current 49.9% to 50.1% of Sithe's total outstanding common stock.
The PCA originally provided that the Put and Call options became
exercisable as of December 18, 2002 and expired in December 2005. However, upon
Apollo Energy, LLC's (Apollo) purchase of Vivendi's 34.2% ownership and Sithe
management's 1% share, Apollo agreed to delay the effective date of its Put
right until June 1, 2003 and, if certain conditions are met, until September 1,
2003. There are also certain events that could trigger Apollo's Put right
becoming effective prior to June 1, 2003 including Exelon being downgraded below
investment grade by Standard and Poor's Rating Group or Moody's Investors
Service, Inc., a stock purchase agreement between Exelon and Apollo being
executed and subsequently terminated, or the occurrence of any event of default,
other than a change of control, under certain Exelon or Apollo credit
agreements. Depending on the triggering event, the put price of approximately
$460 million, growing at a market rate of interest, needs to be funded within 18
or 30 days of the Put being exercised. There have been no changes to the Put and
Call terms with respect to Marubeni's remaining 14.9% interest.
The delay in the effective date of Apollo's Put right allows us to explore
a further restructuring of our investment in Sithe. We are continuing
discussions with Apollo and Marubeni regarding restructuring alternatives that
are designed in part to resolve our ownership limitations of Sithe's qualifying
facilities. We would hope to implement any additional restructuring of our Sithe
investment in
48
2003. If we are unsuccessful in restructuring the Sithe transaction, we will
proceed to implement measures to address the ownership of the qualified
facilities as well as divest non-strategic assets, for which the financial
outcome is uncertain.
If Generation exercises its option to acquire the remaining outstanding
common stock in Sithe, or if all the other stockholders exercise their Put
Rights, the purchase price for Apollo's 35.2% interest will be approximately
$460 million, growing at a market rate of interest. The additional 14.9%
interest will be valued at fair market value subject to a floor of $141 million
and a ceiling of $290 million.
If Generation increases its ownership in Sithe to 50.1% or more, Sithe may
become a consolidated subsidiary and our financial results may include Sithe's
financial results from the date of purchase. At December 31, 2002, Sithe had
total assets of $2.6 billion and total debt of $1.3 billion. This $1.3 billion
includes $624 million of subsidiary debt incurred primarily to finance the
construction of six new generating facilities, $461 million of subordinated
debt, $103 million of line of credit borrowings, $43 million of current portion
of long-term debt and capital leases, $30 million of capital leases, and
excludes $453 million of non-recourse project debt associated with Sithe's
equity investments. For the year ended December 31, 2002, Sithe had revenues of
$1.0 billion. As of December 31, 2002, Generation had a $478 million equity
investment in Sithe.
Additionally, the debt on the books of our unconsolidated equity
investments and joint ventures is not reflected on our Consolidated Balance
Sheets. We estimate that this debt, including the $1.3 billion of Sithe's debt
described in the preceding paragraph, totals approximately $1.3 billion and that
our portion of that amount, based on our ownership interest in the investments,
is approximately $673 million.
Generation's equity investment in AmerGen was $160 million and $95 million
at December 31, 2002 and 2001, respectively. Generation and British Energy plc
(British Energy), Generation's joint venture partner in AmerGen, have each
agreed to provide up to $100 million to AmerGen at any time that the Management
Committee of AmerGen determines that, in order to protect the public health and
safety and/or to comply with NRC requirements, these funds are necessary to meet
ongoing operating expenses or to safely maintain any AmerGen plant. The current
financial condition of British Energy has been the focus of media attention
recently. We cannot predict the ability of British Energy to provide funds to
AmerGen. However, we do not believe this will impact AmerGen's ability to
conduct its business.
PECO Accounts Receivable Agreement. PECO is party to an agreement with a
financial institution under which it can sell 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, 2002, PECO had sold a $225
million interest in accounts receivable, consisting of an $164 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 $61 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, 2002
and 2001, PECO met this requirement.
Insurance Coverage. We carry property damage, decontamination and premature
decommissioning insurance for each station loss resulting from damage to its
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
49
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 Estimates
The preparation of financial statements in conformity with Generally
Accepted Accounting Principles 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 estimates and assumptions with its Accounting and
Disclosure Governance Committee on a regular basis and provides periodic updates
to the Audit Committee of the Board of Directors on management decisions.
Management believes that the following areas require significant management
judgment in making estimates and assumptions to describe matters that are
inherently uncertain and that may change in subsequent periods.
Accounting for Derivative Instruments
We use derivative financial instruments primarily to manage commodity price
and interest rate risks. In connection with our Risk Management Policy (RMP),
we:
o use financial derivatives to manage our exposure to interest rate
fluctuations related to our variable rate debt instruments, changes in
interest rates related to planned future debt issuances prior to their
actual issuance and changes in the fair value of outstanding debt
which we are planning to retire early,
o enter into derivatives to manage the physical and financial risks
associated with our energy supply and load obligations, and
o enter into energy related derivatives for trading or speculative
purposes.
Our derivative activities are subject to the management, direction, and
control of our Risk Management Committee (RMC). The RMC sets forth risk
management philosophy and objectives, and establishes procedures for control,
valuation, counterparty credit approval, and the monitoring and reporting of our
activities in derivative markets and the performance of our derivative
contracts.
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 account for derivative financial instruments under SFAS No. 133. To the
extent that changes in SFAS No. 133 modify current guidance, including the
standards for determining whether contracts can be accounted for as normal
purchases and normal sales, the accounting treatment for derivatives may change.
We are required under SFAS No. 133 to record derivative instruments at fair
value. Depending on the designation of the derivative, the fair value is either
recorded in the income statement or as a component of other comprehensive income
in shareholders' equity (OCI). 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
50
the fair value internally using the Bloomberg swap valuation tool. This tool
uses the most recent market inputs and a widely accepted valuation methodology.
During 2002, Generation recognized unrealized and realized net gains of $6
million and $20 million, respectively, relating to mark-to-market adjustments of
certain non-trading power purchase and sale contracts pursuant to SFAS No. 133
and unrealized and realized net losses aggregating $9 million and $20 million,
respectively, relating to mark-to-market adjustments of derivative instruments
entered into for trading purposes.
Hedge Accounting. As part of our energy marketing business, we enter into
contracts to purchase or sell electricity, gas and ancillary products such as
transmission rights, congestion credits and emission allowances, using contracts
that are considered derivatives under SFAS No. 133. Certain of these derivatives
qualify as hedge transactions.
A derivative instrument can be designated as a hedge of the fair value of a
recognized asset or liability or of an unrecognized firm commitment (fair value
hedge) or a hedge of a forecasted transaction or the variability of cash flows
to be received or paid related to a recognized asset or liability (cash flow
hedge). To qualify for hedge accounting, the fair value changes in the
derivative must be expected to offset 80%-120% of the changes in fair value or
cash flows of the hedged item. Changes in the fair value of a derivative that is
designated and qualifies as a fair value hedge and is highly effective, along
with the gain or loss on the hedged asset or liability that is attributable to
the hedged risk, are recorded in earnings. Changes in the fair value of a
derivative that is designated as and qualifies as a cash flow hedge and is
highly effective, are recorded in OCI, until earnings are affected by the
variability of cash flows being hedged. Exelon continually assesses these cash
flow hedges to determine if they continue to be effective and that the
forecasted future transaction is probable. At the point in time that 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.
Energy Contracts. We enter into contracts designated as cash flow hedges in
which we manage the variability of our cash flows related to the purchase or
sale of energy. At the initiation of the contract the contract is identified as
a cash flow hedge, which requires us to determine whether the contract is in
accordance with our RMP, that the forecasted future transaction is probable, and
that 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 an energy contract
designated as a hedge. An example of a contract that would qualify for hedge
accounting would be a forward over-the-counter sales contract used to hedge an
expected sale of generation exposed to market prices.
Interest Rate Derivative Instruments. We enter into interest rate swap
contracts related to variable rate debt in order to convert the variable
interest payments into fixed interest payments to manage the variability of cash
flows. Additionally, we enter into forward starting interest rate swaps in order
to lock in an interest rate at a future date in anticipation of a future debt
issuance to manage the variability of changes in interest rates between the date
of the decision to issue and the actual date of issue.
We also enter into interest rate swap contracts related to fixed rate debt
in order to maintain our targeted percentage of variable rate debt.
51
The fair value of derivatives generally reflects the estimated amounts that
we would receive or pay to terminate the contracts at the balance sheet date,
thereby taking into account the current unrealized gains or losses of open
contracts.
Normal Purchases and Normal Sales Exemption. As part of our energy
marketing business, we enter into contracts to purchase or sell electricity, gas
and ancillary products such as transmission rights, congestion credits and
emission allowances using contracts that are considered derivatives under SFAS
No. 133. The majority of these contracts, however, qualify for the normal
purchases and normal sales SFAS No. 133 exemption from mark-to-market accounting
treatment as they are for the purchase and sale of energy to meet the
requirements of our customers. These contracts include short-term and long-term
commitments to purchase and sell energy and energy related products in the
retail and wholesale markets with the intent and ability to deliver or take
delivery in quantities we expect to use or sell over a reasonable period in the
normal course of business.
These contracts are reflected in the financial statements at the lower of
cost or market, on a portfolio basis, using the accrual method of accounting. We
did not have any loss contracts as of December 31, 2002. Under these contracts
we recognize any gains or losses when the underlying physical transaction
affects earnings. At the initiation of the contract, we make a determination as
to whether or not the contract meets the criteria as a normal purchase or normal
sale. An example of an energy contract that would qualify for the normal sale
exemption would include a forward sale contract under which we expect to supply
the full requirements of the counterparty. An example of a contract that would
qualify for the normal purchase exemption would be an energy capacity contract
that we enter into to satisfy the needs of our customer base, either retail or
wholesale.
The availability of the normal purchases and normal sales exemption to
specific contracts is based on a determination that at certain times excess
generation is available for a forward sale and, similarly, a determination that
at certain times generation supply will be insufficient to serve our load. The
determination of the ability and intent to deliver or take delivery is based on
internal models that forecast customer demand and electricity 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 contracts
being considered differently under SFAS No. 133 and the potential requirement of
mark-to-market accounting.
Proprietary Trading. As part of our energy trading operation, we enter into
contracts to buy and sell energy for trading purposes. These contracts are
recognized on the balance sheet at fair value and changes in the fair value are
recognized through earnings. All proprietary trading activity is recorded net in
revenue. Trading activities are a very small portion of Exelon's overall power
marketing activities. The trading portfolio is subject to stringent risk
management limits and policies, including volumetric and depression limits to
manage exposure to market risk, as prescribed by the RMC.
Non-Trading Contracts. To manage our commodity risk exposure and meet our
load requirements, we have also entered into non-trading contracts that do not
meet the definition in SFAS No. 133 of a normal purchase or normal sale or meet
the requirements for hedge accounting treatment. These non-trading contracts are
marked-to-market when the underlying item affects earnings with the gains and
losses recorded in Purchased Power and Fuel expense. Non-trading contracts are
subject to stringent risk management limits and policies, as prescribed by the
RMC.
Although we use derivative instruments to assist in managing commodity
price and interest rate risks, we can still experience earnings volatility from
period to period because of the risks associated with marketing and trading
electricity and other energy-related products.
52
Regulatory Assets and Liabilities
Energy Delivery's operating subsidiaries, ComEd and PECO, are regulated by
their respective state regulatory commissions as well as by FERC. The regulators
in Illinois and Pennsylvania, as well as FERC, use cost-based rate structures to
determine the rates we will charge customers. In establishing cost-based rates,
the ICC and the PUC may consider the capital requirements and working capital
needs to operate the distribution and transmission business, determine the
operating cost levels that can be passed on to customers and provide for a
reasonable return to our shareholders. In their determination of rates, the ICC
and PUC may include allowable costs in periods other than the periods in which
an unregulated entity would record the costs in the income statement. These
costs are accounted for as either a regulatory asset or liability. 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. Regulatory assets and
liabilities are accounted for under SFAS No. 71, "Accounting for the Effects of
Certain Types of Regulation" (SFAS No. 71). Use of SFAS No. 71 is applicable to
our utility operations that meet the following criteria: the operations are
subject to third-party regulation of rates; the rates are cost-based; and the
assumption that all costs will be recoverable from customers through rates is
appropriate and reasonable. If a separable portion of our business no longer
meets these criteria, we are required to eliminate the financial statement
effects of regulation for that part of our business.
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. Current
rates include the recovery of our existing regulatory assets.
The most significant regulatory assets we have recorded are:
o Competitive Transition Charges: These charges represent PECO's
stranded costs that the PUC determined would be allowed to be
recoverable through regulated rates. These costs are related to the
deregulation of the generation portion of the electric utility
business in Pennsylvania. The unamortized balance of the CTC of $4.6
billion and $4.9 billion as of December 31, 2002 and 2001,
respectively, was recorded on our Consolidated Balance Sheets. The CTC
includes Intangible Transition Property sold to PECO Energy Transition
Trust, a wholly owned subsidiary of PECO, in connection with the
securitization of PECO's stranded cost recovery. These charges are
being amortized through December 31, 2010 with a rate of return on the
unamortized balance of 10.75%.
o Recoverable Transition Costs: These charges, related to the recovery
of ComEd's former generating plants, are amortized based on the
expected return on equity of ComEd in any given year. At December 31,
2002 and 2001, we had $175 million and $277 million, respectively, in
recoverable transition costs recorded in our Consolidated Balance
Sheets. ComEd expects to fully recover and amortize these charges by
the end of 2006, but may increase or decrease its annual amortization
to maintain its earnings within the earnings cap provisions
established by Illinois legislation. See Note 5 of the Notes to
Consolidated Financial Statements for discussion of recoverable
transition cost amortization.
o Recoverable Deferred Income Taxes: These costs represent the
difference between the method in which the regulator allows for the
recovery of income taxes and how income taxes would be recorded by
unregulated entities. These recoverable deferred income taxes,
recorded in compliance with SFAS No. 109 "Accounting for Income
Taxes," include the deferred tax effects associated principally with
liberalized depreciation accounted for in accordance with the
ratemaking policies of the ICC and PUC, as well as the revenue impacts
thereon, and assume continued recovery of these costs in future
53
rates. At December 31, 2002 and 2001, we had $661 million and $701
million, respectively, in recoverable deferred income taxes recorded
in our Consolidated Balance Sheets.
o Nuclear Decommissioning Costs for Retired Plants: These costs
represent the amount of future nuclear decommissioning costs related
to the retired former ComEd plants which are being recovered through
rates. At December 31, 2002 and 2001, we had $248 million and $310
million, respectively, in nuclear decommissioning costs for retired
plants recorded in our Consolidated Balance Sheets. These costs will
be recovered in rates and amortized on a straight-line basis to
earnings by the end of 2006.
For each regulatory jurisdiction where we conduct business, we continually
assess whether the regulatory assets continue to meet the criteria for probable
future recovery. 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. If future recovery of costs ceases to be probable, the assets
and liabilities would be recognized in current period earnings. A write-off of
regulatory assets could impact our ability to pay dividends under PUHCA.
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.
Nuclear Decommissioning
We currently have direct ownership interests in 16 active nuclear
generating units and four retired nuclear generating units. In addition, we own
a 50% equity interest in AmerGen, which operates three active nuclear generating
units.
In connection with the operation of our nuclear units, the NRC requires us
to decommission these facilities after their NRC operating license lives end,
generally 40 years from the date of initial operation. We have, however,
requested or are in the process of requesting the extension of these license
lives for several nuclear generating stations. The decommissioning of a nuclear
generating station involves the decontamination of structures and components,
the removal of high-level and low-level radioactive materials from the site for
disposal at a licensed facility and for certain stations, the restoration of the
station sites to a natural state. We estimate that, once started,
decommissioning of a site can generally be completed in 10 years. Based on the
projected extended license lives of our nuclear plants, we will begin
decommissioning our plants from 2014 through 2056, with expenditures primarily
occurring when our operating plants are decommissioned, during the period from
2029 through 2056.
We currently recover certain decommissioning costs in regulated rates. The
amounts recovered are deposited in trust accounts and invested for funding of
future decommissioning costs for active and inactive generating units. As part
of our 2001 restructuring, the generation-related assets and liabilities of
ComEd and PECO were transferred to Generation. The accounting for our receipt of
decommissioning collections and recognition of decommissioning liabilities
varies between the plants that were previously owned by ComEd or by PECO prior
to restructuring.
We account for the current period's cost of decommissioning related to
generating plants previously owned by PECO by following regulatory accounting
principles and recording a charge to depreciation expense and a corresponding
liability in accumulated depreciation concurrent with decommissioning
collections from rate payers. Our regulatory accounting principles for the
generating
54
stations previously owned by ComEd were discontinued when those stations were
transferred to Generation. Those stations included both operating and retired
units. For operating units, the difference between the current cost
decommissioning estimate and the decommissioning liability recorded in
accumulated depreciation is amortized to depreciation expense on a straight-line
basis over the remaining lives. For retired units, the current cost
decommissioning estimate is recorded in deferred credits and other liabilities
and accreted to depreciation expense.
Under regulatory accounting principles, gains and losses on marketable
securities held in the nuclear decommissioning trust funds are reported in
accumulated depreciation. After regulatory accounting principles are
discontinued, unrealized gains and losses on marketable securities held in the
nuclear decommissioning trust funds are reported in accumulated other
comprehensive income. Realized gains and losses on decommissioning trust funds
are reflected in other income and deductions in our Consolidated Statements of
Income. Due to the sharp declines in the equity market since the third quarter
of 2000, the value of our nuclear decommissioning trust funds has also
decreased. In 2002, contributions to these trust funds of $112 million were
offset by net realized and unrealized losses of $224 million, resulting in a 4%
decrease in the trust funds' balance at December 31, 2002 compared to December
31, 2001. We believe that the amounts that ComEd and PECO are recovering from
customers through electric rates, along with the earnings on the trust funds,
will be sufficient to fund our decommissioning obligations.
Cost estimates for decommissioning our nuclear facilities have been
prepared by an independent engineering firm and reflect currently existing
regulatory requirements and available technology. Our current estimate of our
nuclear facilities' decommissioning cost is $7.4 billion in current year (2003)
dollars. Calculating this estimate involves significant assumptions about the
expected increases in decommissioning costs relative to general inflation rates,
changes in the regulatory environment or regulatory requirements, and the timing
of decommissioning. Significant changes in these assumptions could materially
affect the liabilities and future costs related to decommissioning recorded in
our Consolidated Financial Statements.
The estimated service life of the nuclear station is also a significant
assumption because decommissioning and depreciation costs are generally
recognized over the life of the generating station. In 2001, we extended nuclear
station service lives, over which the decommissioning costs are recognized, by
20 years. Effective April 1, 2001, we extended the estimated service lives by 20
years for three nuclear stations. Effective July 1, 2001, we extended the
estimated service lives by 20 years for the remainder of Exelon's operating
nuclear stations. These changes were based on engineering and economic
feasibility studies we performed considering, among other things, future capital
and maintenance expenditures at these plants. The service life extension is
subject to NRC approval of an extension of existing NRC operating licenses. As a
result of the change, net income for 2002 and 2001 increased approximately $132
million ($79 million, net of income taxes) and approximately $90 million ($54
million, net income taxes), respectively. Although we consider the service life
extension authorization to be probable, if the extensions were denied, our
results of operations would be adversely impacted by increased depreciation
rates and accelerated future decommissioning payments.
SFAS No. 143. The accounting for our nuclear decommissioning obligation
will be affected by the adoption of SFAS No. 143, "Asset Retirement Obligations"
(SFAS No. 143) effective January 1, 2003. SFAS No. 143 provides accounting
requirements for retirement obligations associated with tangible long-lived
assets. Retirement obligations associated with long-lived assets included within
the scope of SFAS No. 143 are those for which there is a legal obligation under
existing or enacted law, statute, written or oral contract or by legal
construction under the doctrine of promissory estoppel.
The effect of this cumulative adjustment on nuclear decommissioning will be
to change the
55
decommissioning liability to reflect the fair value of the decommissioning
obligation at the balance sheet date. Additionally, SFAS No. 143 will require
the recording of an asset related to the decommissioning obligation, which will
be amortized over the remaining lives of the plants. The net difference, between
the asset recognized and the adjustment to the decommissioning liability
recorded upon adoption of SFAS No. 143, will be charged to earnings and
recognized as a cumulative effect of a change in accounting principle, net of
expected regulatory recovery and net of taxes. The decommissioning liability
will then represent the fair value of the obligation for the future
decommissioning of the plants and, as a result, accretion expense will be
accrued on this liability until the obligation is satisfied.
As noted above, we currently record the obligation for decommissioning
ratably over the lives of the plants. We are currently in the process of
evaluating the impact of adopting SFAS No. 143 on our financial condition. Based
on the current information and the credit-adjusted risk-free rate, we estimate
the increase in 2003 non-cash expense to impact earnings before the cumulative
effect of a change in accounting principle for the adoption of SFAS No. 143 by
approximately $24 million, after income taxes. Additionally, the adoption of
SFAS No. 143 is expected to result in a large, non-cash, one-time cumulative
effect of a change in accounting principle gain of at least $1.5 billion, after
income taxes. The $1.5 billion gain and the $24 million charge includes our
share of the impact of the SFAS No. 143 adoption related to AmerGen's nuclear
plants. These impacts are based on our current interpretation of SFAS No. 143
and are subject to continued refinement based on the finalization of assumptions
and interpretation at the time of adopting the standard, including the
determination of the credit-adjusted risk-free rate. Under SFAS No. 143, the
fair value of the nuclear decommissioning obligation will continue to be
adjusted on an ongoing basis as these model input factors change.
In accordance with SFAS No. 143, we used a probabilistic cash flow model
with multiple scenarios in order to determine the fair value of the
decommissioning obligation. SFAS No. 143 also stipulates that fair value
represent the amount a third party would receive for assuming all of an entity's
obligation. Key assumptions used in our determination of fair value as defined
in SFAS No. 143 include:
o decommissioning cost studies prepared by a third party
- these decommissioning studies represent a marketplace assessment
of costs and the timing of retirement activities validated by
comparison to current decommissioning projects and other third
party estimates
o annual cost escalation studies to determine escalation factors based
on inflation indices used in decommissioning cost studies for the
following major categories:
- labor,
- equipment and materials,
- energy,
- other (taxes, insurance, fees, etc.), and
- low-level radioactive waste disposal costs.
o use of probabilistic cash flow models to measure the fair value
including:
- the probability of various cost levels, and
- the probability of various timing scenarios incorporating the
factors of current license lives and life extension and the
timing of DOE acceptance for disposal of our spent nuclear fuel.
Under the Nuclear Waste Policy Act of 1982 (NWPA), the U.S. Department of
Energy (DOE) is responsible for the selection and development of repositories
for, and the disposal of, spent nuclear fuel and high-level radioactive waste
(SNF). As required by the NWPA, ComEd and PECO, each signed a contract with the
DOE (Standard Contract) to provide for disposal of SNF from their respective
nuclear generating stations. The NWPA and the Standard Contract required the DOE
to begin taking possession of SNF generated by nuclear generating units by no
later than January 31, 1998. The DOE, however,
56
failed to meet that deadline and its performance will be significantly delayed.
The DOE currently estimates it will open a SNF facility in 2010. This extended
delay requires us to retain possession of the SNF, thus increasing
decommissioning costs including the operation and maintenance of facilities to
store SNF until the DOE removes it from our sites.
The NRC regulatory guidance suggests that decommissioning cost studies be
updated every five years. Most of our studies were prepared in 1995 and 1996 and
are in the process of being updated. Although no significant changes in
decommissioning technologies have occurred since the studies were performed, and
annual cost escalation studies are performed to determine the escalation factor
applied to the base year cost study, changes in these cost studies could have a
material impact on the fair value of the nuclear decommissioning obligation. The
final determination of the cumulative effect of a change in accounting principle
is also in part a function of the credit-adjusted risk-free rate at the time of
the adoption of the standard. Additionally, although over the life of the plant,
the charges to earnings for the depreciation of the asset and the interest on
the liability will be equal to the amounts that would have been recognized as
decommissioning expense under the current accounting, the timing of those
charges will change and in the near-term period subsequent to adoption, the
depreciation of the asset and the interest on the liability are expected to
result in an increase in expense.
Asset Impairments
Long-Lived Assets and Investments. SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets" (SFAS No. 144), establishes
accounting and reporting standards for both the impairment and disposal of
long-lived assets. SFAS No. 144 continues the FASB requirements that:
o an impairment loss be recognized if the carrying amount of an asset is
not recoverable from its undiscounted cash flows, and
o the impairment loss be measured as the difference between the carrying
amount and the fair value of the asset.
Accounting Principles Board Opinion No. 18, "The Equity Method of Accounting for
Investment in Common Stock," requires that an impairment loss be recognized for
an investment if the investment declines in fair value below its amortized cost
basis, and this decline is judged to be other-than-temporary.
We continually monitor our investments and businesses and the markets in
which these businesses operate in order to determine events that may trigger an
impairment. We have tested our businesses and investments for recoverability
whenever events or changes in circumstances indicate that their carrying amounts
may not be recoverable. Such triggering events may include a current expectation
that there is a likelihood of 50% or greater that a long-lived asset will be
sold, competitors' technological advancement, accelerated distributions of
public holdings at a loss, lack of achievability of financial results versus
plan, limited access to capital, or the loss of a major customer, among others.
The analysis of impairment for long-lived and intangible assets is subject to an
undiscounted cash flow analysis that requires significant assumptions.
In 2002, we did not identify factors through our review process that
indicated potential impairment of property, plant and equipment or other
long-lived assets with the exception of investments at our Enterprises business
unit. Enterprises wrote down $41 million of investments in 2002 when we
discovered certain triggering events, such as those described above.
Goodwill. Under SFAS No. 142, goodwill is also subject to an assessment for
impairment using a two-step fair value based test, the first step of which must
be performed at least annually, or more frequently if events or circumstances
indicate that goodwill might be impaired. The reporting units of Exelon that
were determined to have had goodwill allocated to them were Energy Delivery,
Exelon's
57
infrastructure services business (InfraSource), the energy services business
(Exelon Services) and the competitive retail energy sales business (Exelon
Energy). All of Energy Delivery's goodwill is at ComEd. If an impairment is
determined at ComEd, the amount of the impaired goodwill will be written-off and
expensed at ComEd. However, under current accounting guidance, a goodwill
impairment charge at ComEd may not affect Exelon's results of operations.
Exelon's goodwill impairment test would include assessing the cash flows of the
entire Energy Delivery business segment (a single Reporting Unit, which includes
PECO, as defined under current accounting guidance), not just ComEd's cash
flows.
We performed the first step of the SFAS No. 142 impairment analysis,
comparing the fair value of a reporting unit to its carrying amount, including
goodwill, as of January 1, 2002, upon adoption of SFAS No. 142. That first step
indicated no impairment of ComEd's goodwill but showed an impairment of the
goodwill recorded in Enterprises' reporting units. In performing the Step I
tests as prescribed in SFAS No. 142, ComEd and Enterprises determined that
discounted cash flow models would provide the most appropriate measure to
determine Step I fair value. Consistent with the guidance in SFAS No. 142, ComEd
and Enterprises prepared multiple scenario discounted cash flow models in order
to determine the value for Step I of SFAS No. 142. These models use multiple
assumptions including revenue growth rates, general expense escalation rates,
allowed return on equity, a risk-adjusted discount rate and long-term earnings
multiples of comparable companies. In addition to the above-noted assumptions,
ComEd's model included varying assumptions regarding:
o The timing of future rate case filings to establish new rates for
bundled service after the then scheduled 2004 expiration of the rate
freeze period, which has subsequently been extended to 2006 by
Illinois law. Rate changes were assumed to occur at various points in
2005 through 2007 in the different scenarios.
o The cash flow impact of the expiration of the rate freeze and the
resolution of uncertainties regarding future commodity risk at the
expiration of the current purchase power agreements, the resolution of
ComEd's POLR obligation and various other risks and uncertainties.
The results of the Step I analysis for ComEd showed a weighted average
probabilistic valuation of the multiple scenario discounted cash flows in excess
of ComEd's book carrying amount, including goodwill, at December 31, 2001. Since
the Step I calculated fair value was in excess of book value, we could conclude
that ComEd's goodwill of $4.9 billion was not impaired. The results of the Step
I analysis for Enterprises, however, calculated weighted average probabilistic
valuations of the multiple scenario discounted cash flows of less than the book
carrying value, including goodwill, of InfraSource, Exelon Services and Exelon
Energy. The second step of the analysis, which compared the fair value of each
of Enterprises' reporting units' goodwill to the carrying value at December 31,
2001, indicated a total goodwill impairment of $357 million ($243 million, net
of income taxes and minority interest). The impairment was recorded as a
cumulative effect of a change in accounting principle in the first quarter of
2002. Enterprises' goodwill balance was $76 million at December 31, 2002.
As required by SFAS No. 142, Exelon performed the annual update of ComEd's
and Enterprises' goodwill impairment analyses using a November 1, 2002
measurement date. These valuations determined the Step I calculated fair value
of both ComEd and the Enterprises' units to be in excess of their respective
book values at November 1, 2002. Since the Step I calculated fair value was in
excess of book value, we concluded that goodwill was not impaired. Again, the
probabilistic discounted cash flows model used in these analyses included the
significant assumptions noted above. Rate changes were assumed to occur at
various points in 2007 through 2009 in the different scenarios for ComEd based
on the June 2002 extension of the rate freeze.
Modifications to any of the assumptions discussed above, particularly
changes in discount rates, long-term earnings multiples of comparable companies
used to determine terminal values, and the
58
expected results of rate proceedings, could result in a future impairment of
goodwill. Actual results as well as market conditions in upcoming periods will
impact the probabilities of scenarios used in the models. If the estimates of
future cash flows in both the ComEd and Enterprises models had been 10% lower,
respectively, those discounted cash flows would still have been greater than the
carrying values of ComEd and Enterprises, respectively. As we were not required
to perform a Step II analysis at the November 1, 2002 measurement date for
either ComEd or Enterprises, a dollar amount for any potential impairment has
not been determined. Because goodwill represents approximately 85% of ComEd's
common equity, a potential future impairment of goodwill could significantly
impact ComEd's ability to pay dividends to Exelon under PUHCA. The Illinois
legislation provides that reductions to ComEd's common equity resulting from
goodwill impairments will not impact ComEd's earnings cap calculation through
2006.
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. 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.
In accordance with SFAS No. 87, "Employers' Accounting for Pensions" (SFAS No.
87) and SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other
than Pensions" (SFAS No. 106) the impact of changes in these factors on pension
and other postretirement welfare benefit obligations is generally recognized
over the expected remaining service life of the employees rather than
immediately recognized in the income statement.
In selecting the expected rate of return on plan assets, we considered
historical and expected returns for the types of investments the plans hold. Our
pension trust assets have lost $581 million, and $265 million, and gained $173
million in 2002, 2001 and 2000, respectively. The long-term expected rate of
return on plan assets (EROA) assumption used in calculating pension cost was
9.5% at January 1, 2002, 2001 and 2000. We generally maintain 60% of our plan
assets in equity securities and 40% of our plan assets in fixed-income
securities. Each quarter we review the actual asset allocations and follow a
rebalancing procedure in order to remain within an allowable range of these
targeted percentages. Based on our asset allocation and long-term historical
returns for both equity and fixed-income securities, we set our EROA at 9.0% as
of January 1, 2003 in order to calculate 2003 pension cost. Our other
postretirement benefit assets have lost $125 million, $14 million and $7 million
in 2002, 2001 and 2000, respectively. The EROA assumption used in calculating
the other postretirement benefit obligation was 8.8% at January 1, 2002, 2001
and 2000, respectively. We will use an EROA assumption of 8.4% as of January 1,
2003 in order to calculate the 2003 other postretirement benefit costs. 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.
We use the Moody's Aa Corporate Bond Index as a basis in selecting the
discount rate. As described in Note 15 of the Notes to Consolidated Financial
Statements, we set the assumed discount rate at 7.35% and 6.75% at December 31,
2001 and 2002, respectively, in our estimate of pension expense and other
postretirement benefit costs.
The following table illustrates the effect of changing the major
actuarial assumptions discussed above:
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Impact on
Projected Benefit Impact on Impact on
Obligation at Pension Liability at 2003
Change in Actuarial Assumption December 31, 2002 December 31, 2002 Pension Cost
- -------------------------------------------------------------------------------------------------------------------
Pension Benefits
Decrease Discount Rate by 0.5% $ 336 $ 336 $ 8
Decrease Rate of Return on Plan Assets by 0.5% -- -- 32
- -------------------------------------------------------------------------------------------------------------------
Impact on Impact on
Other Postretirement Postretirement Impact on 2003
Benefit Obligation Benefit Liability Postretirement
Change in Actuarial Assumption at December 31, 2002 at December 31, 2002 Benefit Cost
- -------------------------------------------------------------------------------------------------------------------
Postretirement Benefits
Decrease Discount Rate by 0.5% $ 152 $ -- $ 18
Decrease Rate of Return on Plan Assets by 0.5% -- -- 6
- -------------------------------------------------------------------------------------------------------------------
The assumptions are reviewed at the beginning of each year during our
annual review process. The impact of assumption changes are reflected in the
recorded pension amounts consistent with assumption changes as they occur. As
these assumptions change from period to period, recorded pension amounts and
funding requirements could also change.
Our pension and other postretirement benefit plans have unrecognized losses
of $2.1 billion and $0.8 billion, respectively, at December 31, 2002. This
unrecognized loss primarily represents the difference between the expected
return on plan assets and the actual return on plan assets that has not yet been
recognized in pension or other postretirement benefit expense. We generally
amortize these unrecognized (gains)/losses over five years; however, the annual
amortization amounts vary based on actuarial determinations. Recognition of an
unrecognized loss will result in increased net periodic pension cost going
forward.
Primarily as a result of sharp declines in the equity markets since the
third quarter of 2000, we recognized an additional minimum liability of $1.0
billion, net of income taxes, and an intangible asset of $211 million as
prescribed by SFAS No. 87 in the fourth quarter of 2002. The liability was
recorded as a reduction to shareholders' equity, and the equity will be restored
to the balance sheet in future periods when the fair value of plan assets
exceeds the accumulated benefit obligation. The recording of this additional
minimum liability did not affect net income or cash flow in 2002 or compliance
with debt covenants; however, pension cost and cash funding requirements could
increase in future years without a substantial recovery in the equity markets.
Our defined benefit pension plans currently meet the minimum funding
requirements of the Employment Retirement Income Security Act of 1974 without
any additional funding; however, we made a discretionary tax-deductible plan
contribution of $150 million in the fourth quarter of 2002 funded by ComEd,
Generation and BSC. We also expect to make a discretionary tax-deductible plan
contribution in 2003 of $300 million to $350 million.
Approximately $93 million was included in operating and maintenance expense
in 2002 for the cost of our pension and postretirement benefit plans, exclusive
of the 2002 charges for employee severance programs. Although the 2003 increase
in pension and postretirement benefit cost will depend on market conditions, our
estimate is that expense will increase by approximately $125 million in 2003
from 2002 expense levels as the result of the effects of the decline in market
value of plan assets in 2002, the decline in discount rate and increases in
health care costs.
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In 2001, we adopted a cash balance pension plan. All management and
electing union employees who were hired by us after 2001 became participants in
the plan. Approximately 4,700 management employees who were active participants
in our previous qualified defined benefit plans at December 31, 2000 and
remained employed by us on January 1, 2002 elected to transfer to the cash
balance plan. Participants in the cash balance plan, unlike participants in the
other defined benefit plans, may request a lump-sum cash payment upon employee
termination. This may result in increased cash requirements from pension plan
assets, which may increase future funding to the pension plan.
Stock-Based Compensation Plans
We maintain a Long-Term Incentive Plan (LTIP) for certain full-time
salaried employees and previously maintained a broad-based incentive program for
certain other employees. The types of long-term incentive awards that have been
granted under the LTIP are non-qualified options to purchase shares of our
common stock and common stock awards. The exercise price of the stock options is
equal to the fair market value of the underlying stock on the date of option
grant. Options granted under the LTIP and the broad-based incentive program
become exercisable upon attainment of a target share value and/or time. All
options expire 10 years from the date of grant.
At December 31, 2002, there were 13,000,000 options authorized for issuance
under the LTIP and 2,000,000 options authorized under the broad-based incentive
program. We currently follow the disclosure-only provisions of SFAS No. 123,
"Accounting for Stock-Based Compensation" (SFAS No. 123). If we elected to
account for our stock-based compensation plans based on SFAS No. 123, we would
have recognized compensation expense of $33 million, $26 million and $25
million, for 2002, 2001 and 2000, respectively.
We use an independent actuarial firm to calculate the fair value of the
options and to assist in the development of amounts required to be disclosed
under SFAS No. 123. The key assumptions used in this determination of fair value
are the expected volatility of the stock price, based on historical information;
the expected life of the options, based on the vesting period and expiration
date of the options; the estimated dividend yield, based on historical
information adjusted for material known future changes; and the risk-free
interest rate, based on the yield of a United States Treasury Strip available on
the date of the grant and expiring at the approximate end of the option's term.
Changes in these assumptions could have resulted in material changes in the
amounts disclosed under SFAS No. 123 in Notes 1 and 17 of the Notes to
Consolidated Financial Statements.
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Business Combinations
In the three year period ended December 31, 2002, we have completed several
business combinations and asset acquisitions. We adopted SFAS No. 141 as of
January 1, 2002. SFAS No. 141 is effective for business combinations initiated
after June 30, 2001. SFAS No. 141 requires that all business combinations be
accounted for under the purchase method of accounting and establishes criteria
for the separate recognition of intangible assets acquired in business
combinations. Under the purchase method of accounting, purchased assets and
liabilities must be recorded at their fair value. If a quoted fair value is not
readily available for the majority of assets and liabilities exchanged, the
determination of this fair value requires the use of significant judgment, both
by management and outside experts engaged to assist in this determination
process. Changes in the assumptions made in determining the fair values could
have resulted in material changes in the amounts disclosed in Note 3 of the
Notes to Consolidated Financial Statements. There would also be an impact on our
financial results. If the fair value of property, plant and equipment acquired
in a business combination would have been higher, and an amount allocated to
goodwill in the business combination lower, depreciation expense would have been
higher. Conversely, if the fair value of property, plant and equipment acquired
in a business combination would have been lower, and an amount allocated to
goodwill in the business combination higher, depreciation expense would have
been lower. For example, if the $2 billion fair value of the generating plants
acquired in the Merger was estimated to be 1% higher, then annual depreciation
expense would be less than $1 million higher and goodwill amortization, which
ceased in 2002, would have been less than $1 million lower annually.
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 the 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 volume, estimated customer usage by class, estimated losses of
energy during delivery to customers (line loss) and applicable customer rates.
Customer accounts receivable as of December 31, 2002 include unbilled energy
revenues of $442 million. 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.
Long-Term Contract Accounting
Enterprises recognizes contract revenue and profits on certain long-term
fixed-price contracts by the percentage-of-completion method of accounting. As
contract work is completed, the corresponding percentage of total estimated
profit on the contract is recognized in the Consolidated Statements of Income.
In determining the amount of revenue to recognize, we are required to estimate,
at the beginning of the contract, the total costs and profits expected to be
recorded under the contract over its contract term, and, on an on-going basis,
the recoverability of costs related to change orders. Changes in these estimates
could result in the recognition of differences in earnings. At December 31,
2002, Current Assets included $70 million of costs and earnings in excess of
billings on uncompleted contracts and Current Liabilities included $44 million
of billings and earnings in excess of costs on uncompleted contracts.
Environmental Costs
As of December 31, 2002, we had accrued liabilities of $156 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
62
timing and costs of expenditures can be reliably estimated, amounts are
discounted. These amounts represent $97 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 $59 million of the
accrued liabilities total above. Estimates can be affected by the factors noted
above as well as by changes in technology and changes in 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 philosophy 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 and officers from each of the business units. The RMC reports to the
board of directors on the scope of our derivative 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 and energy and fossil fuels,
including oil, gas, coal and emission allowances. The availability and prices of
energy and energy-related commodities are subject to fluctuations due to factors
such as weather, governmental environmental policies, changes in supply and
demand, state and federal regulatory policies and other events.
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 4 years. We have an estimated 90% hedge ratio in
2003 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. The
hedge ratio is not fixed and will vary from time to time depending upon market
conditions, demand and volatility and 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
an approximately $37 million decrease in net income, or approximately $0.11 per
share. This sensitivity assumes a 90% hedge ratio and that price changes occur
evenly throughout the year and across all markets. The sensitivity also assumes
a static portfolio. 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.
63
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 and 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 1% of our owned and
contracted supply of electricity. The trading portfolio is subject to stringent
risk management limits and policies, including volume, stop-loss and
value-at-risk limits.
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 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 table describes the drivers of our energy trading and
marketing business and gross margin included in the income statement for the
year ended December 31, 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 this table 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).
Normal Operations and Proprietary
Hedging Activities (a) 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/(Losses) 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 $ 2,634 $ (29) $ 2,605 (b)
- -------------------------------------------------------------------------------------------------------------------
(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 18 of the Notes to Consolidated Financial Statements
for further information.
64
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, 2002. It indicates the drivers behind changes in the
balance sheet amounts. This table will incorporate 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 Proprietary
Hedging Activities 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)
- -------------------------------------------------------------------------------------------------------------------
The following table details the balance sheet classification of the
Mark-to-Market Energy Contract Net Assets recorded as of December 31, 2002:
Normal Operations and Proprietary
Hedging Activities 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)
- -------------------------------------------------------------------------------------------------------------------
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, by region and by 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, 2002 and may change as a result of changes in these factors.
Management uses its best estimates to determine the fair
65
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 assets, 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 generate or require cash.
Maturities within
----------------------------------------------
2008 and Total Fair
2003 2004 2005 2006 2007 Beyond Value
- -------------------------------------------------------------------------------------------------------------------
Normal Operations, qualifying cash flow hedge contracts (1):
Prices provided by other external sources $(124) $ (48) $ (9) $ (5) $ -- $ -- $ (186)
- -------------------------------------------------------------------------------------------------------------------
Total $(124) $ (48) $ (9) $ (5) $ -- $ -- $ (186)
- -------------------------------------------------------------------------------------------------------------------
Normal Operations, other derivative contracts (2):
Actively quoted prices $ 26 $ 4 $ -- $ -- $ -- $ -- $ 30
Prices provided by other external sources -- 3 2 2 -- -- 7
Prices based on model or other valuation methods 7 (11) (4) (9) (2) -- (19)
- -------------------------------------------------------------------------------------------------------------------
Total $ 33 $ (4) $ (2)$ (7) $ (2) $ -- $ 18
- -------------------------------------------------------------------------------------------------------------------
Proprietary Trading, other derivative contracts (3):
Actively quoted prices $ (4) $ -- $ -- $ -- $ -- $ -- $ (4)
Prices provided by other external sources 6 (3) -- -- -- -- 3
Prices based on model or other valuation methods 5 1 -- -- -- -- 6
- -------------------------------------------------------------------------------------------------------------------
Total $ 7 $ (2) $ -- $ -- $ -- $ -- $ 5
- -------------------------------------------------------------------------------------------------------------------
Average tenor of proprietary trading portfolio (4) 1.5 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 its 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.
The table below provides details of effective cash flow hedges under SFAS
No. 133 included in the balance sheet as of December 31, 2002. The data in the
table gives an indication of the magnitude of SFAS No. 133 hedges we have in
place, however, given that under SFAS No. 133 not all hedges are recorded in
OCI, the table does not provide an all-encompassing picture of our hedges. The
table also includes a roll-forward of Accumulated Other Comprehensive Income
related to cash flow hedges for the year ended 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.
66
Total Cash Flow Hedge Other Comprehensive Income Activity,
Net of Income Tax
---------------------------------------------------------
Power Team
Normal Operations and Interest Rate and Total Cash
Hedging Activities Other Hedges (1) Flow Hedges
- -------------------------------------------------------------------------------------------------------------------
Accumulated OCI, January 1, 2002 $ 47 $ (25) $ 22
Changes in Fair Value (128) (51) (179)
Reclassifications from OCI to Net Income (33) (9) (42)
- -------------------------------------------------------------------------------------------------------------------
Accumulated OCI Derivative Gain/(Loss)
at December 31, 2002 $ (114) $ (85) $ (199)
- -------------------------------------------------------------------------------------------------------------------
(1) Includes interest rate hedges at Generation, ComEd and PECO, as well as
energy commodity hedges at Enterprises.
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, 2002.
67
Proprietary
Trading VaR
- ------------------------------------------------------------------------------
95% Confidence Level, One-Day Holding Period, One-Tailed
Period End $ 0.2
Average for the Period 1.4
High 5.0
Low 0.2
95% Confidence Level, Ten-Day Holding Period, Two-Tailed
Period End $ 0.3
Average for the Period 1.5
High 5.3
Low 0.1
99% Confidence Level, One-Day Holding Period, Two-Tailed
Period End $ 0.9
Average for the Period 4.6
High 16.7
Low 0.4
- ------------------------------------------------------------------------------
Credit Risk
Credit risk for Energy Delivery is managed by each of ComEd's and PECO's
credit and collection policies, 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, 2002, ComEd's ten largest customers represented
approximately 3% of its retail electric revenues and PECO's ten largest
customers represented approximately 8% of its retail electric 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 table provides information on Generation's credit exposure,
net of collateral, as of December 31, 2002. It further delineates that exposure
by the credit rating of the counterparties and provides 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 table below do not include sales to Generation's affiliates
or exposure through Independent System Operators (ISOs) which are discussed
below.
68
Total Number Of Net Exposure Of
Exposure Counterparties Counterparties
Before Credit Credit Net Greater than 10% Greater than 10%
Rating Collateral Collateral Exposure of Net Exposure of Net Exposure
- -------------------------------------------------------------------------------------------------------------------
Investment Grade $ 156 $ -- $ 156 2 $ 71
Split Rating -- -- -- -- --
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
- -------------------------------------------------------------------------------------------------------------------
Maturity of Credit Risk Exposure
--------------------------------
Exposure Total Exposure
Less than Greater than Before Credit
Rating 2 Years 2-5 Years 5 Years Collateral
- -------------------------------------------------------------------------------------------------------------------
Investment Grade $ 117 $ 39 $ -- $ 156
Split Rating -- -- -- --
Non-Investment Grade 17 -- -- 17
No External Ratings
Internally Rated - Investment Grade 27 -- -- 27
Internally Rated - Non-Investment Grade 4 -- -- 4
- -------------------------------------------------------------------------------------------------------------------
Total $ 165 $ 39 $ -- $ 204
- -------------------------------------------------------------------------------------------------------------------
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. As of December 31, 2002,
Generation had a net receivable from Dynegy of approximately $3 million and,
consistent with the terms of the existing credit arrangement, has received
collateral in support of this receivable. Generation also has credit risk
associated with Dynegy through Generation's equity investment in Sithe. Sithe is
a 60% owner of the Independence generating station, a 1,040-MW gas-fired
qualified facility that has an energy-only long-term tolling agreement with
Dynegy, with a related financial swap arrangement. As of December 31, 2002,
Sithe had recognized an asset on its balance sheet related to the fair market
value of the financial swap agreement with Dynegy that is marked-to-market under
the terms of SFAS No. 133. If Dynegy is unable to fulfill the terms of this
agreement, Sithe would be required to impair this financial swap asset. We
estimate, as a 49.9% owner of Sithe, that the impairment would result in an
after-tax reduction of our equity earnings of approximately $10 million.
In addition to the impairment of the financial swap asset, if Dynegy were
unable to fulfill its obligations under the financial swap agreement and the
tolling agreement, we would likely incur a further impairment associated with
the Independence plant. Depending upon the timing of Dynegy's failure to fulfill
its obligations and the outcome of any restructuring initiatives, we could
realize an after-tax charge of between $0 and $130 million. In the event of a
sale of our investment in Sithe to a third party, proceeds from the sale could
be negatively impacted by approximately $100 million, or approximately $65
million net of income taxes.
Additionally, the future economic value of AmerGen's purchased power
arrangement with Illinois Power Company, a subsidiary of Dynegy, could be
impacted by events related to Dynegy's financial condition.
Generation participates in the following established, real-time energy
markets, which are administered by ISOs: PJM, New England ISO, New York ISO,
California ISO, Midwest ISO, Inc., Southwest Power Pool, Inc. and Texas, which
is administered by the Electric Reliability Council of
69
Texas. In these areas, power is traded through bilateral agreements between
buyers and sellers and on the spot markets that are operated by the ISOs. In
areas where there is no spot market, electricity is purchased and sold solely
through bilateral agreements. For sales into the spot markets administered by
the ISOs, the ISO maintains financial assurance policies that are established
and enforced by those administrators. The credit policies of the ISOs may under
certain circumstances require that losses arising from the default of one member
on spot market transactions be shared by the remaining participants.
Non-performance or non-payment by a major counterparty could result in a
material adverse impact on our financial condition, results of operations or net
cash flows.
Our consolidated balance sheet includes a $445 million net investment in a
direct financing lease as of December 31, 2002. The investment in direct
financing leases represents future minimum lease payments due at the end of the
thirty-year life of the lease of $1,492 million, less unearned income of $1,047
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 this direct financing
lease.
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, 2002, a hypothetical 10%
increase in the interest rates associated with variable rate debt would result
in a $5 million decrease in pre-tax earnings for 2003.
We have entered into fixed to floating interest rate swaps in order to
maintain our targeted percentage of variable rate debt, associated with ComEd's
debt issuances in the aggregate amount of $485 million. At December 31, 2002,
these interest rate swaps, designated as fair value hedges, had a fair market
value of $41 million based on the present value difference between the contract
and market rates at December 31, 2002. If we had not had the fair value hedges
in place at ComEd, we would have recognized an additional $14 million in
interest expense in 2002.
During 2002 and 2001, ComEd entered into forward-starting interest rate
swaps, with an aggregate notional amount of $830 million and $250 million,
respectively, in anticipation of the issuance of debt. In connection with bond
issuances in 2002, ComEd settled forward-starting interest rate swaps in the
aggregate notional amount of $450 million, resulting in a $10 million pre-tax
loss recorded as a regulatory asset, which is being amortized over the life of
the related debt in interest expense. At December 31, 2002, ComEd had $630
million of forward-starting interest rate swaps outstanding. These interest rate
swaps, designated as cash flow hedges, had a fair market value exposure of $52
million at December 31, 2002. As it remained probable that the debt issuances,
the forecasted future transactions these swaps were hedging, would occur,
although the issuances had been delayed, we continued to account for these
interest rate swap transactions as hedges. In connection with ComEd's January
22, 2003 issuance of $700 million in First Mortgage Bonds, we settled swaps, in
the aggregate notional amount of $550 million, for a payment of $43 million,
which will be recorded as a regulatory asset and amortized over the life of the
debt issuance.
During 2002, PECO entered into forward-starting interest rate swaps, with
an aggregate notional amount of $200 million, in anticipation of the issuance of
debt at PECO. These interest rate swaps were designated as cash flow hedges. In
connection with bond issuances in 2002, PECO settled these forward-
70
starting interest rate swaps resulting in a $5 million pre-tax loss recorded in
OCI, which is being amortized over the life of the related debt.
PECO also had entered into 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. At December 31, 2002, these interest
rate swaps had an aggregate fair market value exposure of $22 million.
PECO also has interest rate swaps in place to satisfy counterparty credit
requirements in regards to the floating rate series of transition bonds which
are mirror swaps of each other. These swaps are not designated as cash flow
hedges, therefore, they are required to be marked-to-market if there is a
difference in their values. Since these swaps are offsetting each other, a
mark-to-market adjustment is not expected to occur.
Under the terms of the Sithe Boston Generation, LLC (SBG) project debt
facility, SBG is required to effectively fix the interest rate on 50% of
borrowings under the facility through its maturity in 2007. As of December 31,
2002, we have entered into interest rate swap agreements which have effectively
fixed the interest rate on $861 million of notional principal, or 83% of
borrowings outstanding at December 31, 2002. The fair market value exposure of
these swaps, designated as cash flow hedges, is $92 million.
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, 2002 is estimated to be $49 million.
If the derivative instruments had been terminated at December 31, 2002, 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, 2002 is estimated to be $33 million.
If the derivative instruments had been terminated at December 31, 2002, this
estimated fair value represents the amount the counterparties would pay us.
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, 2002 is estimated to be $200 million.
If the derivative instruments had been terminated at December 31, 2002, 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, 2002 is estimated to be $132 million.
If the derivative instruments had been terminated at December 31, 2002, this
estimated fair value represents the amount we would pay to the counterparties.
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, 2002, 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 $172 million reduction in the fair value of the
trust assets. See Defined Benefit Pension and Other Postretirement Welfare
Benefits in the Critical
71
Accounting Estimates section for information regarding the pension and other
postretirement benefit trust assets.
New Accounting Pronouncements
In 2001, the FASB issued SFAS No. 143. SFAS No. 143 provides accounting
requirements for retirement obligations associated with tangible long-lived
assets. We will adopt SFAS No. 143 on January 1, 2003. Retirement obligations
associated with long-lived assets included within the scope of SFAS No. 143 are
those for which there is a legal obligation to settle under existing or enacted
law, statute, written or oral contract or by legal construction under the
doctrine of promissory estoppel. Adoption of SFAS No. 143 will change the
accounting for the decommissioning of our nuclear generating plants as well as
certain other long-lived assets. We are in the process of evaluating the impact
of adopting SFAS No. 143 on our financial condition.
As it relates to nuclear decommissioning, the effect of a cumulative
adjustment will be to decrease the decommissioning liability to reflect the fair
value of the decommissioning obligation at the balance sheet date. Additionally,
SFAS No. 143 will require the recognition of an asset related to the
decommissioning obligation, which will be amortized over the remaining lives of
the plants. The net difference, between the asset recognized and the change in
the liability to reflect fair value recorded upon adoption of SFAS No. 143, will
be recorded in earnings and recognized as a cumulative effect of a change in
accounting principle, net of expected regulatory recovery and income taxes. The
decommissioning liability will then represent an obligation for the future
decommissioning of the plants and, as a result, accretion expense will be
accrued on this liability until the obligation is satisfied.
Currently, Generation records the obligation for decommissioning ratably
over the lives of the plants. Based on the current information and the
credit-adjusted risk-free rate, we estimate the increase in 2003 non-cash
expense to impact earnings before the cumulative effect of a change in
accounting principle for the adoption of SFAS No. 143 by approximately $24
million, after income taxes. Additionally, the adoption of SFAS No. 143 is
expected to result in a large, non-cash, one-time cumulative effect of a change
in accounting principle gain of at least $1.5 billion, after income taxes. The
$1.5 billion gain and the $24 million charge includes our share of the impact of
the SFAS No. 143 adoption related to AmerGen's nuclear plants. These impacts are
based on our current interpretation of SFAS No. 143 and are subject to continued
refinement based on the finalization of assumptions and interpretation at the
time of adopting the standard, including the determination of the
credit-adjusted risk-free rate. Under SFAS No. 143, the fair value of the
nuclear decommissioning obligation will continue to be adjusted on an ongoing
basis as these model input factors change.
The final determination of the 2003 earnings impact and the cumulative
effect of adopting SFAS No. 143 is in part a function of the credit adjusted
risk-free rate at the time of the adoption of SFAS No. 143. Additionally,
although over the life of the plant the charges to earnings for the depreciation
of the asset and the interest on the liability will be equal to the amounts that
would have been recognized as decommissioning expense under current accounting,
the timing of those charges will change and in the near-term period subsequent
to adoption, the depreciation of the asset and the interest on the liability is
expected to result in an increase in expense.
In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities" (SFAS No. 146). SFAS No. 146
requires that the liability for costs associated with exit or disposal
activities be recognized when incurred, rather than at the date of a commitment
to an exit or disposal plan. SFAS No. 146 is to be applied prospectively to exit
or disposal activities initiated after December 31, 2002.
In November 2002, the FASB released FASB Interpretation No. (FIN) 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others" (FIN No. 45), providing for
expanded disclosures and recognition of a liability for the fair value of the
obligation undertaken by the guarantor. Under FIN No. 45, guarantors are
required to
72
disclose the nature of the guarantee, the maximum amount of potential future
payments, the carrying amount of the liability and the nature and amount of
recourse provisions or available collateral that would be recoverable by the
guarantor. As of December 31, 2002, we have adopted disclosure requirements
under FIN No. 45, which were effective for financial statements for periods
ended after December 15, 2002. The recognition and measurement provisions of FIN
No. 45 are effective, on a prospective basis, for guarantees issued or modified
after December 31, 2002.
In January 2003, the FASB issued FIN No. 46, "Consolidation of Variable
Interest Entities" (FIN No. 46). FIN No. 46 addresses consolidating certain
variable interest entities and applies immediately to variable interest entities
created after January 31, 2003. The impact, if any, of adopting FIN 46 on our
consolidated financial position, results of operations and cash flows, has not
been fully determined.
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.
73
Exhibit 99-4
Exelon Corporation and Subsidiary Companies Financial Statements and
Supplementary Data
Report of Independent Accountants
To the Shareholders and
Board of Directors of
Exelon Corporation:
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of income, cash flows and changes in shareholders'
equity and comprehensive income present fairly, in all material respects, the
financial position of Exelon Corporation and Subsidiary Companies (Exelon) at
December 31, 2002 and December 31, 2001, and the results of their operations and
their cash flows for each of the three years in the period ended December 31,
2002 in conformity with accounting principles generally accepted in the United
States of America. These financial statements are the responsibility of Exelon's
management; our responsibility is to express an opinion on these financial
statements based on our audits. We conducted our audits of these statements in
accordance with auditing standards generally accepted in the United States of
America, which require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
As discussed in Note 2 to the consolidated financial statements, Exelon acquired
Unicom Corporation on October 20, 2000 in a business combination accounted for
under the purchase method of accounting. The results of Unicom Corporation are
included in the consolidated financial statements since the acquisition date.
As discussed in Note 4 to the consolidated financial statements, Exelon changed
its method of accounting for nuclear outage costs in 2000.
As discussed in Note 1 to the consolidated financial statements, Exelon changed
its method of accounting for derivative instruments and hedging activities
effective January 1, 2001.
As discussed in Note 4 to the consolidated financial statements, Exelon changed
its method of accounting for goodwill effective January 1, 2002.
Chicago, Illinois
January 29, 2003, except for Note 23 for which the date is February 20, 2003.
74
Exelon Corporation and Subsidiary Companies
Consolidated Statements of Income
For the Years Ended December 31,
------------------------------------------------
in millions, except per share data 2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
Operating Revenues $ 14,955 $ 14,918 $ 7,499
Operating Expenses
Purchased Power 3,262 3,156 1,620
Purchased Power from Unconsolidated Affiliate 273 57 52
Fuel 1,727 1,877 934
Operating and Maintenance 4,345 4,394 2,310
Merger-Related Costs -- -- 276
Depreciation and Amortization 1,340 1,449 458
Taxes Other Than Income 709 623 322
- -------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 11,656 11,556 5,972
- -------------------------------------------------------------------------------------------------------------------
Operating Income 3,299 3,362 1,527
- -------------------------------------------------------------------------------------------------------------------
Other Income and Deductions
Interest Expense, net of amounts capitalized (966) (1,107) (614)
Distributions on Preferred Securities of Subsidiaries (45) (49) (24)
Equity in Earnings (Losses) of Unconsolidated Affiliates, net 80 62 (41)
Other, Net 300 79 53
- -------------------------------------------------------------------------------------------------------------------
Total Other Income and Deductions (631) (1,015) (626)
- -------------------------------------------------------------------------------------------------------------------
Income Before Income Taxes and the
Cumulative Effect of Changes in Accounting Principles 2,668 2,347 901
Income Taxes 998 931 339
- -------------------------------------------------------------------------------------------------------------------
Income Before Cumulative Effect
of Changes in Accounting Principles 1,670 1,416 562
Cumulative Effect of Changes in Accounting Principles (net of income taxes of
$(90), $8 and $16 in 2002, 2001 and 2000,
respectively) (230) 12 24
- -------------------------------------------------------------------------------------------------------------------
Net Income $ 1,440 $ 1,428 $ 586
- -------------------------------------------------------------------------------------------------------------------
Average Shares of Common Stock Outstanding
Basic 322 320 202
Diluted 325 322 204
- -------------------------------------------------------------------------------------------------------------------
Earnings Per Common Share - Basic:
Income Before Cumulative
Effect of Changes in Accounting Principles $ 5.18 $ 4.42 $ 2.79
Cumulative Effect of Changes in Accounting Principles (0.71) 0.04 0.12
- -------------------------------------------------------------------------------------------------------------------
Net Income $ 4.47 $ 4.46 $ 2.91
- -------------------------------------------------------------------------------------------------------------------
Earnings Per Common Share - Diluted:
Income Before Cumulative
Effect of Changes in Accounting Principles $ 5.15 $ 4.39 $ 2.75
Cumulative Effect of Changes in Accounting Principles (0.71) 0.04 0.12
- -------------------------------------------------------------------------------------------------------------------
Net Income $ 4.44 $ 4.43 $ 2.87
- -------------------------------------------------------------------------------------------------------------------
Dividends Per Common Share $ 1.76 $ 1.82 $ 0.91
- -------------------------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements
75
Exelon Corporation and Subsidiary Companies
Consolidated Statements of Cash Flows For the Years Ended December 31,
-------------------------------------------
in millions 2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
Cash Flows from Operating Activities
Net Income $ 1,440 $ 1,428 $ 586
Adjustments to reconcile Net Income to Net
Cash Flows provided by Operating Activities:
Depreciation and Amortization, including nuclear fuel 1,701 1,834 607
Cumulative Effects of Changes in Accounting
Principles (net of income taxes) 230 (12) (24)
Provision for Uncollectible Accounts 129 145 89
Net Gain on Sale of Investments (199) -- --
Deferred Income Taxes 278 (68) 193
Merger-Related Costs -- -- 276
Employee Severance Costs -- 46 --
Deferred Energy Costs 25 29 (79)
Equity in (Earnings) Losses of Unconsolidated Affiliates, net (80) (62) 41
Write-down of Investments 41 36 --
Net Realized Losses on Nuclear
Decommissioning Trust Funds 32 127 --
Other Operating Activities 12 (16) (165)
Changes in Working Capital:
Accounts Receivable (448) 318 (445)
Repurchase of Accounts Receivable -- -- (50)
Inventories (37) (33) 49
Accounts Payable, Accrued Expenses & Other Current Liabilities 470 (190) (2)
Other Current Assets 20 33 20
- -------------------------------------------------------------------------------------------------------------------
Net Cash Flows provided by Operating Activities 3,614 3,615 1,096
- -------------------------------------------------------------------------------------------------------------------
Cash Flows from Investing Activities
Capital Expenditures (2,150) (2,088) (752)
Acquisitions of Generating Plants (445) -- --
Unicom Merger Consideration -- -- (507)
Proceeds from Direct Financing Leases -- -- 1,228
Investment in Sithe Energies, Inc. -- -- (704)
Enterprises Acquisitions, net of cash acquired -- (30) (245)
Proceeds from the Sale of Investments 287 -- --
Proceeds from Nuclear Decommissioning Trust Funds 1,612 1,624 265
Investment in Nuclear Decommissioning Trust Funds (1,824) (1,863) (380)
Note Receivable from Unconsolidated Affiliate (35) -- --
Other Investing Activities 17 (35) (108)
- -------------------------------------------------------------------------------------------------------------------
Net Cash Flows used in Investing Activities (2,538) (2,392) (1,203)
- -------------------------------------------------------------------------------------------------------------------
Cash Flows from Financing Activities
Issuance of Long-Term Debt 1,223 2,270 1,021
Common Stock Repurchases -- -- (501)
Retirement of Long-Term Debt (2,134) (1,860) (665)
Change in Short-Term Debt 321 (1,013) 10
Redemption of Preferred Securities of Subsidiaries (18) (17) (19)
Dividends Paid on Common Stock (563) (583) (157)
Change in Restricted Cash (24) (58) (140)
Proceeds from Employee Stock Plans 78 39 67
Contribution from Minority Interest of Consolidated Subsidiary 43 -- --
Other Financing Activities (18) (42) (11)
- -------------------------------------------------------------------------------------------------------------------
Net Cash Flows used in Financing Activities (1,092) (1,264) (395)
- -------------------------------------------------------------------------------------------------------------------
Decrease in Cash and Cash Equivalents (16) (41) (502)
Cash and Cash Equivalents at beginning of period 485 526 54
Cash Acquired in Unicom Merger -- -- 974
- -------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at end of period $ 469 $ 485 $ 526
- -------------------------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements
76
Exelon Corporation and Subsidiary Companies
Consolidated Balance Sheets
December 31,
-------------------------------------
in millions 2002 2001
- -------------------------------------------------------------------------------------------------------------------
Assets
Current Assets
Cash and Cash Equivalents $ 469 $ 485
Restricted Cash 396 372
Accounts Receivable, net
Customer 2,095 1,687
Other 265 381
Receivable from Unconsolidated Affiliate 32 44
Inventories, at average cost
Fossil Fuel 218 222
Materials and Supplies 306 249
Deferred Income Taxes 6 23
Other 331 272
- -------------------------------------------------------------------------------------------------------------------
Total Current Assets 4,118 3,735
- -------------------------------------------------------------------------------------------------------------------
Property, Plant and Equipment, net 17,134 13,791
Deferred Debits and Other Assets
Regulatory Assets 5,938 6,423
Nuclear Decommissioning Trust Funds 3,053 3,165
Investments 1,393 1,623
Goodwill, net 4,992 5,335
Other 850 672
- -------------------------------------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 16,226 17,218
- -------------------------------------------------------------------------------------------------------------------
Total Assets $ 37,478 $ 34,744
- -------------------------------------------------------------------------------------------------------------------
Liabilities and Shareholders' Equity
Current Liabilities
Notes Payable $ 681 $ 360
Note Payable to Unconsolidated Affiliate 534 --
Long-Term Debt Due Within One Year 1,402 1,406
Accounts Payable 1,563 964
Accrued Expenses 1,311 1,135
Other 483 505
- -------------------------------------------------------------------------------------------------------------------
Total Current Liabilities 5,974 4,370
- -------------------------------------------------------------------------------------------------------------------
Long-Term Debt 13,127 12,879
Deferred Credits and Other Liabilities
Deferred Income Taxes 3,702 4,362
Unamortized Investment Tax Credits 301 316
Nuclear Decommissioning Liability for Retired Plants 1,395 1,353
Pension Obligation 1,959 334
Non-Pension Postretirement Benefits Obligation 877 847
Spent Nuclear Fuel Obligation 858 843
Other 871 694
- -------------------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 9,963 8,749
- -------------------------------------------------------------------------------------------------------------------
Commitments and Contingencies
Minority Interest of Consolidated Subsidiaries 77 31
Preferred Securities of Subsidiaries 595 613
Shareholders' Equity
Common Stock 7,059 6,961
Deferred Compensation (1) (2)
Retained Earnings 2,042 1,169
Accumulated Other Comprehensive Income (Loss) (1,358) (26)
- -------------------------------------------------------------------------------------------------------------------
Total Shareholders' Equity 7,742 8,102
- -------------------------------------------------------------------------------------------------------------------
Total Liabilities and Shareholders' Equity $ 37,478 $ 34,744
- -------------------------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements
77
Exelon Corporation and Subsidiary Companies
Consolidated Statements of Changes in Shareholders' Equity
Accumulated
Other Total
Dollars in millions, Common Deferred Retained Treasury Comprehensive Shareholders'
shares in thousands Shares Stock Compensation Earnings Shares Income (Loss) Equity
- --------------------------------------------------------------------------------------------------------------------
Balance, December 31, 1999 225,354 $ 3,577 $ (3) $ (100) $ (1,705) $ 4 $ 1,773
Net Income -- -- 586 -- -- 586
Long-Term Incentive Plan Activity 563 75 (9) -- 7 -- 73
Shares Issued to Acquire Unicom 147,963 5,310 -- -- -- -- 5,310
Merger Consideration-Stock Options 111 -- -- -- -- 111
Amortization of Deferred Compensation -- 5 -- -- -- 5
Common Stock Dividends Declared -- -- (157) -- -- (157)
Common Stock Repurchases -- -- (5) (496) -- (501)
Stock Option Exercises -- -- -- 19 -- 19
Cancellation of Treasury Shares (54,875) (2,175) -- -- 2,175 -- --
Other Comprehensive Income (Loss),
net of income taxes of $(1) -- -- -- -- (4) (4)
- --------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2000 319,005 $ 6,898 $ (7) $ 324 $ -- $ -- $ 7,215
Net Income -- -- 1,428 -- -- 1,428
Long-Term Incentive Plan Activity 1,864 55 -- -- -- -- 55
Employee Stock Purchase Plan Issuances 138 6 -- -- -- -- 6
Merger Consideration-Stock Options 2 -- -- -- -- 2
Amortization of Deferred Compensation -- 5 -- -- -- 5
Common Stock Dividends Declared -- -- (583) -- -- (583)
Reclassified Net Unrealized Losses on
Marketable Securities, net of income
taxes of $(22) -- -- -- -- (23) (23)
Other Comprehensive Income (Loss),
net of income taxes of $(7) -- -- -- -- (3) (3)
- --------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2001 321,007 $ 6,961 $ (2) $ 1,169 $ -- $ (26) $ 8,102
Net Income -- -- 1,440 -- -- 1,440
Long-Term Incentive Plan Activity 2,049 87 -- -- -- -- 87
Employee Stock Purchase Plan Issuances 257 11 -- -- -- -- 11
Amortization of Deferred Compensation -- 1 -- -- -- 1
Common Stock Dividends Declared -- -- (567) -- -- (567)
Other Comprehensive Income (Loss),
net of income taxes of $(850) -- -- -- -- (1,332) (1,332)
- --------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2002 323,313 $ 7,059 $ (1) $ 2,042 $ -- $ (1,358) $ 7,742
- --------------------------------------------------------------------------------------------------------------------
Exelon Corporation and Subsidiary Companies
Consolidated Statements of Comprehensive Income
For the Years Ended December 31,
--------------------------------------
in millions 2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
Net Income $ 1,440 $ 1,428 $ 586
Other Comprehensive Income (Loss)
Minimum Pension Liability, net of income taxes of $(597) (1,007) -- --
SFAS No. 133 Transition Adjustment, net
of income taxes of $32 -- 44 --
Cash Flow Hedge Fair Value Adjustment, net of income taxes of $(132)
and $17, respectively (199) 22 --
Foreign Currency Translation Adjustment,
net of income taxes of $0 -- (1) --
Unrealized Gain (Loss) on Marketable
Securities, net of income taxes of $(116), $(40) and $(1), respectively (119) (41) (4)
Interest in Other Comprehensive Income (Loss) of Unconsolidated Affiliates,
net of income taxes of $(5) and $(16), respectively (7) (27) --
- -------------------------------------------------------------------------------------------------------------------
Total Other Comprehensive Income (Loss) (1,332) (3) (4)
- -------------------------------------------------------------------------------------------------------------------
Total Comprehensive Income $ 108 $ 1,425 $ 582
- -------------------------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements
78
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Exelon Corporation and Subsidiary Companies
(Dollars in millions, except per share data unless otherwise noted)
1. Significant Accounting Policies
Description of Business
Exelon Corporation (Exelon) is a utility services holding company formed as
a result of the merger of Unicom Corporation (Unicom), the former parent company
of Commonwealth Edison Company (ComEd), and PECO Energy Company (PECO) (Merger)
(see Note 2 - Merger). Exelon is engaged, through its subsidiaries, in the
energy delivery, wholesale generation and the enterprises businesses discussed
below (see Note 20 - Segment Information). The Energy Delivery segment's
businesses include the sale of electricity and distribution and transmission
services by ComEd in northern Illinois and PECO in southeastern Pennsylvania and
the sale of natural gas and distribution services by PECO in the Pennsylvania
counties surrounding the City of Philadelphia. The wholesale generation business
consists of the electric generating facilities and energy marketing operations
of Exelon Generation Company, LLC (Generation) and Generation's interests in
Sithe Energies, Inc. (Sithe) and AmerGen Energy Company, LLC (AmerGen). Exelon
Enterprises Company, LLC (Enterprises) includes energy and infrastructure
services, competitive retail energy sales, communications joint ventures and
other investments weighted towards the communications, energy services and
retail services industries.
Basis of Presentation
The consolidated financial statements of Exelon include the accounts of its
majority-owned subsidiaries after the elimination of intercompany transactions.
Investments and joint ventures in which a 20% to 50% interest is owned and a
significant influence is exerted are accounted for under the equity method of
accounting. The proportionate interests in jointly owned electric utility plants
are consolidated. Investments in which less than a 20% interest is owned are
primarily accounted for under the cost method of accounting. Exelon owns 100% of
all significant consolidated subsidiaries, either directly or indirectly, except
for ComEd of which Exelon owns more than 99%, InfraSource Inc. (InfraSource) of
which Exelon owns 95% and Southeast Chicago Energy Project, LLC of which Exelon
owns 70% through Generation. Exelon has reflected the third-party interests in
the above majority owned investments as minority interests in its Consolidated
Statements of Cash Flows, Consolidated Balance Sheets and in Other, Net on the
Consolidated Statements of Income. Accounting policies for regulated operations
are in accordance with those prescribed by the regulatory authorities having
jurisdiction, principally the Illinois Commerce Commission (ICC), the
Pennsylvania Public Utility Commission (PUC), the Federal Energy Regulatory
Commission (FERC) and the Securities and Exchange Commission (SEC) under the
Public Utility Holding Company Act of 1935 (PUHCA). On October 20, 2000, Exelon
became the parent of PECO through a share exchange and Unicom was merged into
Exelon. As a result of these transactions, Unicom ceased to exist and Exelon
became the parent of ComEd and PECO (see Note 2 - Merger). For accounting
purposes, PECO was deemed the acquiror in the Merger. Accordingly, the financial
statements of Exelon for the periods presented prior to October 20, 2000
represent the historical financial statements of PECO and for the periods from
October 20, 2000 include the operations acquired from Unicom.
Accounting for the Effects of Regulation
Exelon accounts for all of its regulated electric and gas operations in
accordance with the Financial Accounting Standards Board (FASB) Statement of
Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of
Certain Types of Regulation," (SFAS No. 71) requiring Exelon to record in its
financial statements the effects of rate regulation. Use of SFAS No. 71 is
applicable to the utility operations of Exelon that meet the following criteria:
(1) third-party regulation of rates; (2) cost-based rates; and (3) a reasonable
assumption that all costs will be recoverable from customers through
79
rates. Exelon believes that it is probable that currently recorded regulatory
assets will be recovered. If a separable portion of Exelon's business no longer
meets the provisions of SFAS No. 71, Exelon is required to eliminate the
financial statement effects of regulation for that portion.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles (GAAP) requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates. Areas in
which significant estimates have been made include, but are not limited to, the
accounting for derivatives, nuclear decommissioning liabilities, asset
impairment analyses, environmental costs and pension costs.
Revenues
Operating revenues are generally recorded as service is rendered or energy
is delivered to customers. At the end of each month, Exelon accrues an estimate
for the unbilled amount of energy delivered or services provided to its electric
and gas customers (see Note 8 - Accounts Receivable). Exelon recognizes contract
revenues and profits on certain long-term fixed-price contracts from its
services businesses under the percentage-of-completion method of accounting
based on costs incurred as a percentage of estimated total costs of individual
contracts. Premiums received and paid on option contracts and swap arrangements
are amortized to revenue and expense over the life of the contracts. Certain of
these contracts are considered derivative instruments and are recorded at fair
value with subsequent changes in fair value recognized as revenues and expenses
unless hedge accounting is applied. Commodity derivatives used for trading
purposes are accounted for using the mark-to-market method. Under this
methodology, these derivatives are adjusted to fair value, and the unrealized
gains and losses are recognized in current period income.
Long-Term Contract Accounting
Enterprises recognizes contract revenue and profits on certain long-term
fixed-price contracts by the percentage-of-completion method of accounting. In
determining the amount of revenue to recognize, Exelon is required to estimate
the total costs and profits expected to be recorded under the contract over its
contract term, and the recoverability of costs related to change orders. Changes
in these estimates could result in the recognition of differences in earnings.
At December 31, 2002 and 2001, Current Assets includes $70 million and $77
million, respectively, of Costs and Earnings in Excess of Billings on
uncompleted contracts and Current Liabilities includes $44 million and $56
million, respectively, of Billings and Earnings in Excess of Costs on
uncompleted contracts.
At December 31, 2002 and 2001, Accounts Receivable includes $49 million and
$46 million, respectively, of contract retention. This amount represents revenue
recognized on costs incurred that is not yet billable until final completion of
the project and acceptance by the customer. In applying the
percentage-of-completion accounting method, the collection of these estimated
revenues is deemed probable.
Purchased Gas Adjustment Clause
PECO's natural gas rates are subject to a fuel adjustment clause designed
to recover or refund the difference between the actual cost of purchased gas and
the amount included in base rates. Differences between the amounts billed to
customers and the actual costs recoverable are deferred and recovered or
refunded in future periods by means of prospective quarterly adjustments to
rates.
Nuclear Fuel
80
The cost of nuclear fuel is capitalized and charged to fuel expense using the
unit of production method. Estimated costs of nuclear fuel storage and disposal
at operating plants are charged to fuel expense as the related fuel is consumed.
Stock-Based Compensation
Exelon uses the disclosure-only provisions of SFAS No. 123, "Accounting for
Stock-Based Compensation" (SFAS No. 123). See Note 17 - Common Stock for further
discussion of these plans. The table below shows the effect on net income and
earnings per share had Exelon elected to account for its stock-based
compensation plans using the fair value method under SFAS No. 123 for the years
ended December 31, 2002, 2001 and 2000:
2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
Net income - as reported $ 1,440 $ 1,428 $ 586
Deduct: Total stock-based compensation expense
determined under fair value based method for all
awards, net of income taxes 33 26 25
- -------------------------------------------------------------------------------------------------------------------
Pro forma net income $ 1,407 $ 1,402 $ 561
- -------------------------------------------------------------------------------------------------------------------
Earnings per share:
Basic - as reported $ 4.47 $ 4.46 $ 2.91
Basic - pro forma $ 4.36 $ 4.38 $ 2.77
Diluted - as reported $ 4.44 $ 4.43 $ 2.87
Diluted - pro forma $ 4.33 $ 4.35 $ 2.75
- -------------------------------------------------------------------------------------------------------------------
Income Taxes
Deferred Federal and state income taxes are provided on all significant
temporary differences between book basis and tax basis of assets and
liabilities. Investment tax credits previously utilized for income tax purposes
have been deferred on the Consolidated Balance Sheets and are recognized in book
income over the life of the related property. Exelon and its subsidiaries file a
consolidated Federal income tax return. Income taxes are allocated to each of
Exelon's subsidiaries within the consolidated group based on the separate return
method. Exelon estimates its income tax valuation allowance by assessing which
deferred tax assets are more likely than not to be recovered in the future (see
Note 14 - Income Taxes).
Gains and Losses on Reacquired Debt
Recoverable gains and losses on reacquired debt related to regulated
operations are deferred and amortized to interest expense over the period
consistent with rate recovery for ratemaking purposes. Gains and losses on other
debt are recognized in Exelon's Consolidated Statements of Income as incurred
(see Note 6 - Supplemental Financial Information).
Comprehensive Income
Comprehensive income includes all changes in equity during a period except
those resulting from investments by and distributions to shareholders.
Comprehensive income is reflected in the Consolidated Statements of Changes in
Shareholders' Equity and the Consolidated Statements of Comprehensive Income.
Cash and Cash Equivalents
Exelon considers all temporary cash investments purchased with an original
maturity of three months or less to be cash equivalents.
81
Restricted Cash
Restricted cash reflects escrowed cash to be applied to the principal and
interest payment on the transition bonds and transitional trust notes.
Marketable Securities
Marketable securities are classified as available-for-sale securities and
are reported at fair value, with the unrealized gains and losses, net of tax,
reported in other comprehensive income. Under regulatory accounting practices,
unrealized gains and losses on marketable securities held in the nuclear
decommissioning trust funds are reported in accumulated depreciation for
operating units and as a reduction of regulatory assets for retired units. If
regulatory accounting practices are not applicable, unrealized gains and losses
on marketable securities held in the nuclear decommissioning trust funds are
reported in accumulated other comprehensive income. At December 31, 2002 and
2001, Exelon had no held-to-maturity or trading securities.
Property, Plant and Equipment
Property, plant and equipment is recorded at cost. Exelon evaluates the
carrying value of property, plant and equipment and other long-term assets based
upon current and anticipated undiscounted cash flows, and recognizes an
impairment when it is probable that such estimated cash flows will be less than
the carrying value of the asset. Measurement of the amount of impairment, if
any, is based upon the difference between the carrying value and fair value. The
cost of maintenance, repairs and minor replacements of property is charged to
maintenance expense as incurred.
Upon retirement, the cost of regulated property plus removal costs less
salvage value is charged to accumulated depreciation by the regulated
subsidiaries in accordance with regulatory practices. For unregulated property,
the cost and accumulated depreciation of property, plant and equipment retired
or otherwise disposed of are removed from the related accounts and included in
the determination of the gain or loss on disposition.
Depreciation, Amortization and Decommissioning
Depreciation is provided over the estimated service lives of property,
plant and equipment on a straight-line basis. Annual depreciation provisions for
financial reporting purposes, expressed as a percentage of average service life
for each asset category, are presented in the table below. See Note 4 - Adoption
of New Accounting Pronouncements and Accounting Changes for information on
service life extensions for certain nuclear generating stations and Energy
Delivery's change in depreciation rates.
Asset Category 2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
Electric-Transmission and Distribution 3.11% 3.97% 4.16%
Electric-Generation 3.65% 3.11% 5.02%
Gas 2.13% 2.34% 2.39%
Common - Gas and Electric 6.40% 6.26% 5.09%
Other Property and Equipment 7.88% 9.53% 8.11%
- -------------------------------------------------------------------------------------------------------------------
Amortization of regulatory assets is provided over the recovery period
specified in the related regulatory agreement. Goodwill associated with the
Merger was amortized on a straight-line basis over 40 years in 2001 and 2000.
Goodwill associated with other acquisitions was amortized over periods from 10
to 20 years in 2001 and 2000. Accumulated amortization of goodwill was $185
million and $35 million at December 31, 2001 and 2000, respectively. Effective
January 1, 2002, under SFAS No. 142 "Goodwill and Other Intangible Assets" (SFAS
No. 142), goodwill recorded by Exelon is no longer subject to amortization but
is subject to an annual impairment test (see Note 4 - Adoption of New Accounting
Pronouncements and Accounting Changes).
Exelon currently recovers costs for decommissioning its nuclear generating
stations, excluding AmerGen, through regulated rates. The amounts recovered from
customers are deposited in trust
82
accounts and invested for funding of future costs for operating and retired
nuclear generating stations. The majority of the eventual work to decommission
Exelon's nuclear generating stations will occur after 2029.
Exelon accounts for the current period's cost of decommissioning related to
generating plants previously owned by PECO following common regulatory
accounting practices by recording a charge to depreciation expense and a
corresponding liability in accumulated depreciation concurrently with
decommissioning collections. Financial activity of the decommissioning trust
(e.g., investment income and realized and unrealized gains and losses on trust
investments) is reflected in Nuclear Decommissioning Trust Funds in Exelon's
Consolidated Balance Sheets with a corresponding offset recorded to the
liability in accumulated depreciation. Under common regulatory practices, the
deposit of funds into the decommissioning trust accounts plus the financial
activity reflected in Nuclear Decommissioning Trust Funds in Exelon's
Consolidated Balance Sheets will, over time, establish a corresponding liability
in accumulated depreciation reflecting the cost to decommission the nuclear
generating stations previously owned by PECO. Exelon will adopt SFAS No. 143,
"Asset Retirement Obligations" (SFAS No. 143) as of January 1, 2003. See "New
Accounting Pronouncements" within this note for a discussion as to how this
standard will change the accounting for nuclear decommissioning costs.
Regulatory accounting practices for the nuclear generating stations
previously owned by ComEd were discontinued as a result of an ICC order capping
ComEd's ultimate recovery of decommissioning costs. See Note 11 - Nuclear
Decommissioning and Spent Fuel Storage regarding regulatory accounting practices
for nuclear generating stations transferred by ComEd to Generation. The
difference between the current decommissioning cost estimate and the
decommissioning liability recorded in accumulated depreciation for the former
ComEd operating stations is being amortized to depreciation expense on a
straight-line basis over the remaining lives of the stations. The current
decommissioning cost estimate (adjusted annually to reflect inflation) for the
former ComEd retired units recorded in deferred credits and other liabilities is
accreted to depreciation expense. Financial activity of the decommissioning
trust related to Exelon's nuclear generating stations no longer accounted for
under common regulatory practices (e.g., investment income and realized and
unrealized gains and losses on trust investments) is reflected in Nuclear
Decommissioning Trust Funds in Exelon's Consolidated Balance Sheets with a
corresponding gain or expense recorded in Exelon's Consolidated Income Statement
or in other comprehensive income. The offset to the financial activity in the
decommissioning trust funds is summarized as follows:
o Interest income is recorded in other income and deductions,
o Realized gains and losses are recorded in other income and deductions,
o Unrealized gains and losses are recorded in other comprehensive
income, and
o Trust fund operating expenses are recorded in operation and
maintenance expense
Exelon believes that the amounts being recovered from customers through
electric rates along with the earnings on the trust funds will be sufficient to
fully fund its decommissioning obligations.
Capitalized Interest
Exelon uses SFAS No. 34, "Capitalizing Interest Costs," to calculate the
costs during construction of debt funds used to finance its non-regulated
construction projects. Exelon recorded capitalized interest of $20 million, $17
million and $2 million in 2002, 2001 and 2000, respectively.
Allowance for Funds Used During Construction (AFUDC) is the cost, during
the period of construction, of debt and equity funds used to finance
construction projects for regulated operations. AFUDC is recorded as a charge to
Construction Work in Progress and as a non-cash credit to AFUDC that is included
in Other Income and Deductions. The rates used for capitalizing AFUDC are
computed under a method prescribed by regulatory authorities (see Note 6 -
Supplemental Financial Information).
83
Capitalized Software Costs
Costs incurred during the application development stage of software
projects for software that is developed or obtained for internal use are
capitalized. At December 31, 2002, 2001 and 2000, capitalized software costs
totaled $335 million, $240 million and $285 million, respectively, net of $156
million, $85 million and $53 million of accumulated amortization, respectively.
Such capitalized amounts are amortized ratably over the expected lives of the
projects when they become operational, not to exceed ten years. Certain
capitalized software is being amortized over fifteen years pursuant to
regulatory approval.
Derivative Financial Instruments
Exelon accounts for derivative financial instruments under SFAS No. 133,
"Accounting for Derivatives and Hedging Activities" (SFAS No. 133). Under the
provisions of SFAS No. 133, all derivatives are recognized on the balance sheet
at their fair value unless they qualify for a normal purchases and normal sales
exception. Normal purchases and normal sales are contracts where physical
delivery is probable, quantities are expected to be used or sold in the normal
course of business over a reasonable period of time, and price is not tied to an
unrelated underlying derivative. Changes in the fair value of the derivative
financial instruments that do not qualify for a normal purchase and normal sales
exception are recognized in earnings unless specific hedge accounting criteria
are met. A derivative financial instrument can be designated as a hedge of the
fair value of a recognized asset or liability or of an unrecognized firm
commitment (fair value hedge), or a hedge of a forecasted transaction or the
variability of cash flows to be received or paid related to a recognized asset
or liability (cash flow hedge). Changes in the fair value of a derivative that
is highly effective as, and is designated and qualifies as, a fair value hedge,
along with the gain or loss on the hedged asset or liability that is
attributable to the hedged risk, are recorded in earnings. Changes in the fair
value of a derivative that is highly effective as, and is designated as and
qualifies as a cash flow hedge are recorded in other comprehensive income, until
earnings are affected by the variability of cash flows being hedged.
In connection with Exelon's Risk Management Policy (RMP), Exelon enters
into derivatives to manage its exposure to fluctuations in interest rates
related to its variable rate debt instruments, changes in interest rates related
to planned future debt issuances prior to their actual issuance and changes in
the fair value of outstanding debt which is planned for early retirement. As it
relates to energy transactions, Exelon utilizes derivatives to manage the
utilization of its available generating capability and provisions of wholesale
energy to its affiliates. Exelon also utilizes energy option contracts and
energy financial swap arrangements to limit the market price risk associated
with forward energy commodity contracts. Additionally, Exelon enters into
certain energy related derivatives for trading or speculative purposes.
As part of Exelon's energy marketing business, Exelon enters into contracts
to buy and sell energy to meet the requirements of its customers. These
contracts include short-term and long-term commitments to purchase and sell
energy and energy related products in the retail and wholesale markets with the
intent and ability to deliver or take delivery. While these contracts are
considered derivative financial instruments under SFAS No. 133, the majority of
these transactions have been designated as "normal purchases" or "normal sales"
and are not subject to the provisions of SFAS No. 133. Under these contracts,
Exelon recognizes gains or losses when the underlying physical transaction
affects earnings. Revenues and expenses associated with market price risk
management contracts are amortized over the terms of such contracts. Commitments
under these contracts are discussed in Note 19 - Commitments and Contingencies.
The remainder of these contracts are generally considered cash flow hedges under
SFAS No. 133. To the extent that the hedges are effective, changes in the fair
value of these contracts are recorded in other comprehensive income, until
earnings are affected by the variability of cash flows being hedged.
Additionally, during 2001, as part of the creation of Exelon's energy
trading operation, Exelon began to enter into contracts to buy and sell energy
for trading purposes subject to limits. These contracts are recognized on the
balance sheet at fair value and changes in the fair value of these derivative
financial instruments are recognized in earnings.
84
Prior to the adoption of SFAS No. 133, Exelon applied hedge accounting only
if the derivative reduced the risk of the underlying hedged item and was
designated at the inception of the hedge, with respect to the hedged item.
Exelon recognized any gains or losses on these derivatives when the underlying
physical transaction affected earnings.
Contracts entered into by Exelon to limit market risk associated with
forward energy commodity contracts are reflected in the financial statements at
the lower of cost or market using the accrual method of accounting. Under these
contracts, Exelon recognizes any gains or losses when the underlying physical
transaction affects earnings. Revenues and expenses associated with market price
risk management contracts are amortized over the terms of such contracts.
New Accounting Pronouncements
In 2001, the FASB issued SFAS No. 143, "Asset Retirement Obligations" (SFAS
No. 143). SFAS No. 143 provides accounting requirements for retirement
obligations associated with tangible long-lived assets. Exelon will adopt SFAS
No. 143 as of January 1, 2003. Retirement obligations associated with long-lived
assets included within the scope of SFAS No. 143 are those for which there is a
legal obligation to settle under existing or enacted law, statute, written or
oral contract or by legal construction under the doctrine of promissory
estoppel. Adoption of SFAS No. 143 will change the accounting for the
decommissioning of Generation's nuclear generating plants as well as certain
other long-lived assets.
As it relates to nuclear decommissioning, the effect of this cumulative
adjustment will be to decrease the decommissioning liability to reflect the fair
value of the decommissioning obligation at the balance sheet date. Additionally,
SFAS No. 143 will require the recognition of an asset related to the
decommissioning obligation, which will be amortized over the remaining lives of
the plants. The net difference, between the asset recognized and the change in
the liability to reflect fair value recorded upon adoption of SFAS No. 143, will
be recorded in earnings and recognized as a cumulative effect of a change in
accounting principle, net of expected regulatory recovery and income taxes. The
decommissioning liability will then represent an obligation for the future
decommissioning of the plants and, as a result, accretion expense will be
accrued on this liability until such time as the obligation is satisfied.
Currently, Generation records the obligation for decommissioning ratably
over the lives of the plants. Based on the current information and the
credit-adjusted risk-free rate, we estimate the increase in 2003 non-cash
expense to impact earnings before the cumulative effect of a change in
accounting principle for the adoption of SFAS No. 143 by approximately $24
million, after income taxes. Additionally, the adoption of SFAS No. 143 is
expected to result in a large, non-cash, one-time cumulative effect of a change
in accounting principle gain of at least $1.5 billion, after income taxes. The
$1.5 billion gain and the $24 million charge includes our share of the impact of
the SFAS No. 143 adoption related to AmerGen's nuclear plants. These impacts are
based on our current interpretation of SFAS No. 143 and are subject to continued
refinement based on the finalization of assumptions and interpretation at the
time of adopting the standard, including the determination of the
credit-adjusted risk-free rate. Under SFAS No. 143, the fair value of the
nuclear decommissioning obligation will continue to be adjusted on an ongoing
basis as these model input factors change.
The final determination of the 2003 earnings impact and the cumulative
effect of adopting SFAS No. 143, is in part a function of the credit adjusted
risk-free rate at the time of the adoption of SFAS No. 143. Additionally,
although over the life of the plant the charges to earnings for the depreciation
of the asset and the interest on the liability will be equal to the amounts that
would have been recognized as decommissioning expense under the current
accounting, the timing of those charges will change and in the near-term period
subsequent to adoption, the depreciation of the asset and the interest on the
liability is expected to result in an increase in expense.
85
In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities" (SFAS No. 146). SFAS No. 146
requires that the liability for costs associated with exit or disposal
activities be recognized when incurred, rather than at the date of a commitment
to an exit or disposal plan. SFAS No. 146 is to be applied prospectively to exit
or disposal activities initiated after December 31, 2002.
In November 2002, the FASB released FASB Interpretation No. (FIN) 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others" (FIN No. 45), providing for
expanded disclosures and recognition of a liability for the fair value of the
obligation undertaken by the guarantor. Under FIN No. 45, guarantors are
required to disclose the nature of the guarantee, the maximum amount of
potential future payments, the carrying amount of the liability and the nature
and amount of recourse provisions or available collateral that would be
recoverable by the guarantor. Exelon has adopted the disclosure requirements
under FIN No. 45, (see Note 19 - Commitments and Contingencies) which were
effective for financial statements for periods ended after December 15, 2002.
The recognition and measurement provisions of FIN No. 45 are effective, on a
prospective basis, for guarantees issued or modified after December 31, 2002.
In January 2003, the FASB issued FIN No. 46, "Consolidation of Variable
Interest Entities" (FIN No. 46). FIN No. 46 addresses consolidating certain
variable interest entities and applies immediately to variable interest entities
created after January 31, 2003. The impact, if any, of adopting FIN 46 on our
consolidated financial position, results of operations and cash flows, has not
been fully determined.
See Note 4 - Adoption of New Accounting Pronouncements and Accounting
Changes for discussion of the impact of new accounting pronouncements adopted by
Exelon.
Reclassifications
Certain prior year amounts have been reclassified for comparative purposes.
The reclassifications did not affect net income or shareholders' equity.
2. Merger
On October 20, 2000, Exelon became the parent corporation of PECO and ComEd
as a result of the completion of the transactions contemplated by an Agreement
and Plan of Exchange and Merger, as amended (Merger Agreement), among PECO,
Unicom and Exelon. Pursuant to the Merger Agreement, Unicom merged with and into
Exelon. In the Merger, each share of the outstanding common stock of Unicom was
converted into 0.875 shares of common stock of Exelon plus $3.00 in cash. As a
result of the Share Exchange, Exelon became the owner of all of the common stock
of PECO. As a result of the Merger, Unicom ceased to exist and its subsidiaries,
including ComEd, became subsidiaries of Exelon.
86
The Merger was accounted for using the purchase method of accounting. The
total purchase price was $6,014 million. In connection with the Merger, Exelon
issued 148 million shares of common stock in the amount of $5,310 million and
paid $507 million in cash to Unicom shareholders pursuant to the terms of the
Merger Agreement. The source of the cash consideration was borrowings under an
Exelon term loan. In addition, the Merger consideration included $113 million of
fair value of stock options and awards for certain Unicom employees and $84
million of direct acquisition costs. The cost in excess of net assets acquired
was $5,150 million as adjusted to reflect final purchase price allocations.
Exelon's results of operations include Unicom's results of operations since
October 20, 2000. The fair value of the assets acquired, including the cost in
excess of net assets acquired, and liabilities assumed in the Merger are as
follows:
- -------------------------------------------------------------------------------
Current Assets (including cash of $974) $ 2,744
Property, Plant and Equipment 7,641
Deferred Debits and Other Assets 5,535
Cost in excess of net assets acquired 5,150
Current Liabilities (2,390)
Long-Term Debt (7,419)
Deferred Credits and Other Liabilities (4,919)
Preferred Securities of Subsidiaries (328)
- -------------------------------------------------------------------------------
Total Purchase Price $ 6,014
- -------------------------------------------------------------------------------
Goodwill associated with the Merger increased by $14 million and $262
million in 2002 and 2001, respectively, as a result of the finalization of the
purchase price allocation. The adjustment resulted primarily from the after-tax
effects of the reduction of the regulatory asset for decommissioning retired
nuclear plants, as discussed in Note 11 - Nuclear Decommissioning and Spent Fuel
Storage, additional employee separation costs, the resolution of certain tax
matters and the finalization of other purchase price allocations.
Selected unaudited pro forma combined results of operations for the year
ended December 31, 2000, assuming the Merger Transaction occurred on January 1,
2000 are presented as follows:
(unaudited) 2000
- -------------------------------------------------------------------------------------------------------------------
Total revenues $ 13,531
Pro forma net income $ 1,003
Merger-related costs (net of income taxes of $147) 220
Cumulative effect of a change in accounting principle (net of income taxes of $16) 24
- -------------------------------------------------------------------------------------------------------------------
Pro forma net income before Merger-related costs
and the cumulative effect of a change in accounting principle $ 1,247
- -------------------------------------------------------------------------------------------------------------------
Pro forma net income before Merger-related costs
and the cumulative effect of a change in accounting principle
per common share (diluted) $ 3.86
- -------------------------------------------------------------------------------------------------------------------
Pro forma information assumes the issuance of transition bonds in 2000 had
occurred at the beginning of 2000. The pro forma financial information is not
necessarily indicative of the operating results that would have occurred had the
Merger been consummated as of the dates indicated, nor are they necessarily
indicative of future operating results.
87
Merger-Related Costs
In association with the Merger, Exelon recorded certain reserves for
restructuring costs. The reserves associated with PECO were charged to expense
pursuant to FASB Emerging Issues Task Force (EITF) Issue 94-3, "Liability
Recognition for Certain Employee Termination Benefits and Other Costs to Exit an
Activity (including Certain Costs Incurred in a Restructuring)"; while the
reserves associated with Unicom were recorded as part of the application of
purchase accounting and did not affect results of operations, consistent with
EITF Issue 95-3, "Recognition of Liabilities in Connection with a Purchase
Business Combination."
Merger costs charged to expense. PECO's merger-related costs charged to expense
in 2000 were $248 million, consisting of $116 million for PECO employee costs
and $132 million of direct incremental costs incurred by PECO in conjunction
with the merger transaction. Direct incremental costs represent expenses
directly associated with completing the Merger, including professional fees,
regulatory approval and settlement costs, and settlement of compensation
arrangements. Employee costs represent estimated severance costs and pension and
postretirement benefits provided under Exelon's merger separation plans for
eligible employees who were expected to be involuntarily terminated before
December 2002 due to integration activities of the merged companies. Additional
employee severance costs of $48 million, primarily related to PECO employees,
were charged to operating and maintenance expense in 2001, and a $10 million
reduction in the estimated liability related to Generation employees was
recorded in operating and maintenance expense in the first quarter of 2002.
Employee costs are being paid from Exelon's pension and postretirement benefit
plans, except for certain benefits such as outplacement services, continuation
of health care coverage and educational benefits. As of December 31, 2002, a
liability of $4 million is reflected on Exelon's consolidated balance sheet for
payment of these benefits, of which $1 million is reflected on PECO's balance
sheet and $1 million is reflected on Generation's balance sheet.
A total of 960 PECO positions were expected to be eliminated as a result of
the Merger, 274 of which related to generation, 230 of which related to PECO
energy delivery and 456 of which related to enterprises and corporate support
areas. As of December 31, 2002, 858 of the positions had been eliminated, of
which 224 related to generation, 195 related to PECO energy delivery, and 439 to
enterprises and corporate support. Of the remaining 102 positions, 58 were
eliminated as a result of normal attrition and 44 positions will not be
eliminated due to changes in certain business plans.
Additionally, in the third quarter of 2000, approximately $20 million of
closing costs and $8 million of stock compensation costs associated with Unicom
were charged to expense.
Merger costs included in purchase price allocation. The purchase price
allocation as of December 31, 2000 included a liability of $307 million for
Unicom employee costs and liabilities of approximately $39 million for estimated
costs of exiting various business activities of former Unicom activities that
were not compatible with the strategic business direction of Exelon.
88
During 2001, Exelon finalized plans for consolidation of functions,
including negotiation of an agreement with the International Brotherhood of
Electrical Workers Local 15 regarding severance benefits to union employees. In
the third quarter of 2002, Exelon reduced its reserve by $12 million due to the
elimination of identified positions through normal attrition, which did not
require payments under Exelon's merger separation plans, and a determination
that certain positions would not be eliminated by the end of 2002, as originally
planned, due to a change in certain business plans. The reduction in the reserve
was recorded as a purchase price adjustment to goodwill. In 2001 and 2002,
Exelon recorded adjustments to the purchase price allocation as follows:
Adjustments
Original ------------------ Adjusted
Estimate 2001 2002 Liabilities
- -------------------------------------------------------------------------------------------------------------------
Employee severance payments $ 128 $ 33 $ (10) $ 151 (a)
Other benefits 21 9 (2) 28 (a)
- -------------------------------------------------------------------------------------------------------------------
Employee severance payments and other benefits 149 42 (12) 179
Actuarially determined pension and postretirement costs 158 (11) -- 147 (b)
- -------------------------------------------------------------------------------------------------------------------
Total Unicom employee cost $ 307 $ 31 $ (12) $ 326
- -------------------------------------------------------------------------------------------------------------------
(a) The increase is a result of the identification in 2001 of additional
positions to be eliminated, partially offset by the 2002 elimination of
identified positions through normal attrition and changes in certain
business plans.
(b) The reduction results from lower estimated pension and postretirement
welfare benefits reflecting revised actuarial estimates.
The following table provides a reconciliation of the reserve for
employee severance and other benefits associated with the Merger:
- -------------------------------------------------------------------------------------------------------------------
Adjusted employee severance and other benefits reserve $ 179
Payments to employees in 2000 (5)
Payments to employees in 2001 (72)
Payments to employees in 2002 (74)
- -------------------------------------------------------------------------------------------------------------------
Employee severance and other benefits reserve as of December 31, 2002 (1) $ 28
- -------------------------------------------------------------------------------------------------------------------
(1) Relates to certain benefits that are being paid after 2002.
The following table provides a reconciliation of the former Unicom
positions that were expected to be eliminated as a result of the Merger:
Total
- -------------------------------------------------------------------------------------------------------------------
Estimate at October 20, 2000 2,275
2001 adjustments (a) 118
- -------------------------------------------------------------------------------------------------------------------
Total positions 2,393
- -------------------------------------------------------------------------------------------------------------------
Employees terminated in 2000 279
Employees terminated in 2001 607
Employees terminated in 2002 1,053
Normal attrition 298
Business plan changes (b) 156
- -------------------------------------------------------------------------------------------------------------------
Total positions 2,393
- -------------------------------------------------------------------------------------------------------------------
(a) The increase is a result of the identification of additional positions to
be eliminated in 2001.
(b) The reduction is due to a determination in the third quarter of 2002, that
certain positions would not be eliminated by the end of 2002 as originally
planned due to a change in certain business plans.
89
3. Acquisitions and Dispositions
Sithe New England Holdings Asset Acquisition
On November 1, 2002, Generation purchased the assets of Sithe New England
Holdings, LLC (Sithe New England), a subsidiary of Sithe, and related power
marketing operations. Sithe New England's primary assets are gas-fired
facilities currently under development. The purchase price for the Sithe New
England assets consisted of a $534 million note to Sithe, $14 million of direct
acquisition costs and an adjustment to Generation's investment in Sithe to
reflect Sithe's sale of Sithe New England to Generation. Additionally,
Generation will assume various Sithe guarantees related to an equity
contribution agreement between Sithe New England and Sithe Boston Generation,
LLC (SBG), a project subsidiary of Sithe New England. The equity contribution
agreement requires, among other things, that Sithe New England, upon the
occurrence of certain events, contribute up to $38 million of equity for the
purpose of completing the construction of two generating facilities. SBG has a
$1.25 billion credit facility (the SBG Facility) to finance the construction of
these two generating facilities. The $1.0 billion outstanding under the facility
at December 31, 2002 is reflected on Exelon's Consolidated Balance Sheet. Sithe
New England owns 4,066 megawatts (MWs) of generation capacity, consisting of
1,645 MWs in operation and 2,421 MWs under construction. Sithe New England's
generation facilities are located primarily in Massachusetts.
The allocation of purchase price to the fair value of assets acquired and
liabilities assumed in the acquisition is as follows:
- -----------------------------------------------------------------------------
Current Assets (including $12 of cash acquired) $ 82
Property, Plant and Equipment 1,889
Deferred Debits and Other Assets 62
Current Liabilities (159)
Deferred Credits and Other Liabilities (124)
Long-Term Debt (1,036)
- -----------------------------------------------------------------------------
Total Purchase Price $ 714
- -----------------------------------------------------------------------------
The SBG Facility provides that if these construction projects are not
completed by June 12, 2003, the SBG Facility lenders will have the right, but
will not be required, to, among other things, declare all amounts then
outstanding under the SBG Facility and the interest rate swap agreements to be
due. Generation believes that the construction projects will be substantially
complete by May 31, 2003, but that all of the approvals required under the SBG
Facility may not be issued by that date. Generation is currently evaluating
whether the requirements of the SBG Facility relating to the construction
projects can be satisfied by June 12, 2003. In the event that the requirements
are not expected to be satisfied by June 12, 2003, Generation will contact the
SBG Facility lenders concerning an amendment or waiver of these provisions of
the SBG Facility. Generation currently expects that arrangements for such an
amendment or waiver, if necessary, can be successfully negotiated with the SBG
Facility lenders.
See Note 19 - Commitments and Contingencies for further discussion of
Sithe.
90
Acquisition of Generating Plants from TXU
On April 25, 2002, Generation acquired two natural-gas and oil-fired plants
from TXU Corp. (TXU) for an aggregate purchase price of $443 million. The
purchase included the 893-megawatt Mountain Creek Steam Electric Station in
Dallas and the 1,441-megawatt Handley Steam Electric Station in Fort Worth. The
transaction included a purchased power agreement for TXU to purchase power
during the months of May through September from 2002 through 2006. During the
periods covered by the purchased power agreement, TXU will make fixed capacity
payments, variable expense payments, and will provide fuel to Exelon in return
for exclusive rights to the energy and capacity of the generation plants.
Substantially all of the purchase price has been allocated to property, plant
and equipment.
Sale of AT&T Wireless
On April 1, 2002, Enterprises sold its 49% interest in AT&T Wireless PCS of
Philadelphia, LLC to a subsidiary of AT&T Wireless Services for $285 million in
cash. Enterprises recorded an after-tax gain of $116 million in Other Income and
Deductions on Exelon's Consolidated Statements of Income on its $84 million
investment, which had been reflected in Deferred Debits and Other Assets on
Exelon's Consolidated Balance Sheets.
InfraSource Acquisitions
In 2001, Exelon's infrastructure services business (InfraSource), acquired
the assets of a utility service contracting company for an aggregate purchase
price of approximately $31 million. The acquisition was accounted for using the
purchase method of accounting. The excess of purchase price over the fair value
of net assets acquired was $19 million. The allocation of purchase price to the
fair value of assets acquired and liabilities assumed in the acquisition is as
follows:
- ------------------------------------------------------------------------------
Current Assets (including cash acquired of $1) $ 11
Property, Plant and Equipment 11
Cost in excess of net assets acquired 19
Current Liabilities (10)
- ------------------------------------------------------------------------------
Total $ 31
- ------------------------------------------------------------------------------
AmerGen Energy Company, LLC
In August 2000, AmerGen, a joint venture with British Energy, Inc., a
wholly owned subsidiary of British Energy plc, (British Energy), completed the
purchase of Oyster Creek Nuclear Generating Facility (Oyster Creek) from GPU,
Inc. (GPU) for $10 million. Under the terms of the purchase agreement, GPU
agreed to fund outage costs of $89 million, including the cost of fuel, for a
refueling outage that occurred in 2000. AmerGen is repaying these costs to GPU
in equal annual installments through 2009. In addition, AmerGen assumed full
responsibility for the ultimate decommissioning of Oyster Creek. At the closing
of the sale, GPU provided funding for the decommissioning trust of $440 million.
In conjunction with this acquisition, AmerGen has received a fully funded
decommissioning trust fund which has been computed assuming the anticipated
costs to appropriately decommission Oyster Creek discounted to net present value
using the NRC's mandated rate of 2%. AmerGen believes that the amount of the
trust fund and investment earnings thereon will be sufficient to meet its
decommissioning obligation. GPU is purchasing the electricity generated by
Oyster Creek pursuant to a three-year power purchase agreement.
4. Adoption of New Accounting Pronouncements and Accounting Changes
SFAS No. 141 and SFAS No. 142
91
In 2001, FASB issued SFAS No. 141, "Business Combinations" (SFAS No. 141),
which requires that all business combinations be accounted for under the
purchase method of accounting and establishes criteria for the separate
recognition of intangible assets acquired in business combinations. SFAS No. 141
became effective for business combinations initiated after June 30, 2001. In
addition, SFAS No. 141 required that unamortized negative goodwill related to
pre-July 1, 2001 purchases be recognized as a change in accounting principle
concurrent with the adoption of SFAS No. 142, "Goodwill and Other Intangible
Assets" (SFAS No. 142). At December 31, 2001, AmerGen, an equity-method investee
of Generation, had $43 million of negative goodwill, net of accumulated
amortization, recorded on its balance sheet. Upon AmerGen's adoption of SFAS No.
141 in January 2002, Generation recognized its proportionate share of income of
$22 million ($13 million, net of income taxes) as a cumulative effect of a
change in accounting principle.
Exelon adopted SFAS No. 142 as of January 1, 2002. SFAS No. 142 establishes
new accounting and reporting standards for goodwill and intangible assets. Other
than goodwill, Exelon does not have significant other intangible assets recorded
on its consolidated balance sheets. Under SFAS No. 142, goodwill is no longer
subject to amortization; however, goodwill is subject to an assessment for
impairment using a two-step fair value based test. The first step must be
performed at least annually, or more frequently if events or circumstances
indicate that goodwill might be impaired and compares the fair value of a
reporting unit to its carrying amount, including goodwill. If the carrying
amount of the reporting unit exceeds its fair value, the second step is
performed. The second step compares the carrying amount of the goodwill to the
fair value of the goodwill. If the fair value of goodwill is less than the
carrying amount, an impairment loss is reported as a reduction to goodwill and a
charge to operating expense, except at the transition date, when the loss is
reflected as a cumulative effect of a change in accounting principle.
As of December 31, 2001, Exelon's Consolidated Balance Sheets reflected
approximately $5.3 billion in goodwill net of accumulated amortization,
including $4.9 billion of net goodwill related to the Merger recorded on ComEd's
Consolidated Balance Sheets, with the remainder related to Enterprises. The
first step of the transitional impairment analysis indicated that ComEd's
goodwill was not impaired but that an impairment did exist with respect to
goodwill recorded in Enterprises' reporting units. InfraSource, the energy
services business (Exelon Services) and the competitive retail energy sales
business (Exelon Energy) were determined to be those reporting units of
Enterprises that had goodwill allocated to them. The second step of the
analysis, which compared the fair value of each of Enterprises' reporting units'
goodwill to the carrying value at December 31, 2001, indicated a total goodwill
impairment of $357 million ($243 million, net of income taxes and minority
interest). The fair value of the Enterprises' reporting units was determined
using discounted cash flow models reflecting the expected range of future cash
flow outcomes related to each of the Enterprises reporting units over the life
of the investment. These cash flows were discounted to 2002 using a
risk-adjusted discount rate. The impairment was recorded as a cumulative effect
of a change in accounting principle in the first quarter of 2002.
The changes in the carrying amount of goodwill by reportable segment (see
Note 20 - Segment Information) for the year ended December 31, 2002 are as
follows:
Energy
Delivery Enterprises Total
- -------------------------------------------------------------------------------------------------------------------
Balance as of January 1, 2002 $ 4,902 $ 433 $ 5,335
Impairment losses -- (357) (357)
Resolution of certain tax matters 21 -- 21
Merger severance adjustment (7) -- (7)
- -------------------------------------------------------------------------------------------------------------------
Balance as of December 31, 2002 $ 4,916 $ 76 $ 4,992
- -------------------------------------------------------------------------------------------------------------------
The December 31, 2002, Energy Delivery goodwill relates to ComEd and the
remaining Enterprises goodwill relates to the InfraSource and Exelon Services
reporting units. Consistent with
92
SFAS No. 142, the remaining goodwill will be reviewed for impairment on an
annual basis, or more frequently if significant events occur that could indicate
an impairment exists. ComEd and Enterprises performed an impairment review in
the fourth quarter of 2002. Such review was consistent with the review conducted
related to the implementation of SFAS No. 142, which required estimates of
numerous items with varying degrees of uncertainty, such as discount rates,
terminal value earnings multiples, future revenue levels and estimated future
expenditure levels for ComEd and Enterprises; load growth and the resolution of
future rate proceedings for ComEd; and customer base and construction back logs
for Enterprises. These valuations determined the Step I calculated fair value of
both ComEd and the Enterprises' units to be in excess of their respective book
values at November 1, 2002. Significant changes from the assumptions used in the
impairment review could possibly result in a future impairment loss. Illinois
legislation provides that reductions to ComEd's common equity resulting from
goodwill impairments will not impact ComEd's earnings through 2006 under the
earnings provisions of the legislation. See Note 5 - Regulatory Issues for
further discussion of ComEd's earnings provisions.
The components of the net transitional impairment loss recognized in the
first quarter of 2002 as a cumulative effect of a change in accounting principle
are as follows:
- -------------------------------------------------------------------------------------------------------------------
Enterprises goodwill impairment (net of income taxes of $103) $ (254)
Minority interest (net of income taxes of $4) 11
Elimination of AmerGen negative goodwill (net of income taxes of $9) 13
- -------------------------------------------------------------------------------------------------------------------
Total cumulative effect of a change in accounting principle $ (230)
- -------------------------------------------------------------------------------------------------------------------
The following tables set forth Exelon's net income and earnings per common
share for 2002, 2001, and 2000 adjusted to exclude 2001 and 2000 amortization
expense related to goodwill that is no longer being amortized.
2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
Reported income before cumulative effect
of changes in accounting principles $ 1,670 $ 1,416 $ 562
Cumulative effect of changes in accounting principles (230) 12 24
- -------------------------------------------------------------------------------------------------------------------
Reported net income 1,440 1,428 586
Goodwill amortization -- 155 34
- -------------------------------------------------------------------------------------------------------------------
Adjusted net income $ 1,440 $ 1,583 $ 620
- -------------------------------------------------------------------------------------------------------------------
Basic earnings per common share:
Reported income before cumulative effect
of changes in accounting principles $ 5.18 $ 4.42 $ 2.79
Cumulative effect of changes in accounting principles (0.71) 0.04 0.12
- -------------------------------------------------------------------------------------------------------------------
Reported net income 4.47 4.46 2.91
Goodwill amortization -- 0.48 0.17
- -------------------------------------------------------------------------------------------------------------------
Adjusted net income $ 4.47 $ 4.94 $ 3.08
- -------------------------------------------------------------------------------------------------------------------
Diluted earnings per common share:
Reported income before cumulative effect
of changes in accounting principles $ 5.15 $ 4.39 $ 2.75
Cumulative effect of changes in accounting principles (0.71) 0.04 0.12
- -------------------------------------------------------------------------------------------------------------------
Reported net income 4.44 4.43 2.87
Goodwill amortization -- 0.48 0.17
- -------------------------------------------------------------------------------------------------------------------
Adjusted net income $ 4.44 $ 4.91 $ 3.04
- -------------------------------------------------------------------------------------------------------------------
93
The cessation of the amortization of negative goodwill of AmerGen on
January 1, 2002 did not have a material impact on Exelon's reported net income
for 2002.
EITF Issue 02-3
In the third quarter of 2002, Exelon and Generation adopted the provision
of EITF Issue 02-3, "Accounting for Contracts Involved in Energy Trading and
Risk Management Activities" (EITF 02-3) issued by the FASB EITF in June 2002
that requires revenues and energy costs related to energy trading contracts to
be presented on a net basis in the income statement. Prior to the adoption,
revenues from trading activity were presented in Revenue and the energy costs
related to energy trading were presented as either Purchased Power or Fuel
expense on Exelon and Generation's Consolidated Statements of Income. For
comparative purposes, energy costs related to energy trading have been
reclassified in prior periods to revenue to conform to the net basis of
presentation required by EITF 02-3. Exelon commenced trading activities in April
2001, as such $207 million of purchased power expense and $15 million of fuel
expense, respectively, was reclassified and reflected as a reduction to revenue
for the year ended December 31, 2001.
SFAS No. 144
In September 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets" (SFAS No. 144). Exelon adopted SFAS
No. 144 on January 1, 2002. SFAS No. 144 establishes accounting and reporting
standards for both the impairment and disposal of long-lived assets. SFAS No.
144 is effective for fiscal years beginning after December 15, 2001 and its
provisions are generally applied prospectively. The adoption of SFAS No. 144 had
no effect on Exelon's reported financial position, results of operations or cash
flows.
SFAS No. 145
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements
No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections"
(SFAS No. 145). SFAS No. 145 eliminates SFAS No. 4 "Reporting Gains and Losses
from Extinguishment of Debt" and thus allows for only those gains or losses on
the extinguishment of debt that meet the criteria of extraordinary items to be
treated as such in the financial statements. SFAS No. 145 also amends Statement
of Financial Accounting Standards No. 13, "Accounting for Leases" to require
sale-leaseback accounting for certain lease modifications that have economic
effects that are similar to sale-leaseback transactions. The adoption of SFAS
No. 145 required a reclassification of the 2000 extraordinary item of $4
million, net of income taxes, to interest expense; otherwise, it had no effect
on Exelon's reported financial position or cash flows.
SFAS No. 133
SFAS No. 133 applies to all derivative instruments and requires that such
instruments be recorded on the balance sheet either as an asset or a liability
measured at their fair value through earnings, with special accounting permitted
for certain qualifying hedges. On January 1, 2001, Exelon adopted SFAS No. 133.
Generation recognized a non-cash gain of $12 million, net of income taxes, in
earnings and deferred a non-cash gain of $4 million, net of income taxes, in
accumulated other comprehensive income and PECO deferred a non-cash gain of $40
million, net of income taxes, in accumulated other comprehensive income.
Nuclear Outage Costs
During the fourth quarter of 2000, as a result of the synchronization of
accounting policies with Unicom in connection with the Merger, PECO changed its
method of accounting for nuclear outage costs to record such costs as incurred.
Previously, PECO accrued these costs over the operating unit cycle. As a result
of the change in accounting method for nuclear outage costs, PECO recorded
income of $24
94
million, net of income taxes of $16 million. The change is reported as a
cumulative effect of a change in accounting principle on the Consolidated
Statements of Income as of December 31, 2000, representing the balance of the
nuclear outage cost reserve at January 1, 2000.
SFAS No. 148
In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure - an amendment of FASB Statement No.
123" (SFAS No. 148). SFAS No. 148 provides alternative methods of transition for
a voluntary change to the fair value based method of accounting for stock-based
employee compensation and requires disclosures in both annual and interim
financial statements regarding the method of accounting for stock-based
compensation and the effect of the method on financial results. SFAS No. 148 is
effective for financial statements for fiscal years ending after December 15,
2002. As of December 31, 2002, Exelon has adopted the additional disclosure
requirements of SFAS No. 148 and continues to account for its stock-compensation
plans under the disclosure only provision of SFAS No. 123.
Changes in Accounting Estimates
Effective July 1, 2002, ComEd decreased its depreciation rates based on a
new depreciation study reflecting its significant construction program in recent
years, changes in and development of new technologies, and changes in estimated
plant service lives since the last depreciation study. The annualized reduction
in depreciation expense, based on December 31, 2001 plant balances, is estimated
to be approximately $100 million ($60 million, net of income taxes). As a result
of the change, net income for 2002 increased approximately $48 million ($29
million, net of income taxes).
Effective April 1, 2001, Generation changed its accounting estimates
related to the depreciation and decommissioning of certain generating stations.
The estimated service lives were extended by 20 years for three nuclear
stations, by periods of up to 20 years for certain fossil stations and by 50
years for a pumped storage station. Effective July 1, 2001, the estimated
service lives were extended by 20 years for the remainder of Exelon's operating
nuclear stations. These changes were based on engineering and economic
feasibility studies performed by Generation considering, among other things,
future capital and maintenance expenditures at these plants. The service life
extension is subject to Nuclear Regulatory Commission (NRC) approval of an
extension of existing NRC operating licenses, which are generally 40 years. The
estimated annualized reduction in expense from the change is $132 million ($79
million, net of income taxes).
In April 2002, ComEd changed its accounting estimate related to the
allowance for uncollectible accounts based on an independently prepared
evaluation of the risk profile of ComEd's customer accounts receivable. As a
result of the new evaluation, the allowance for uncollectible accounts reserve
was reduced by $11 million in the second quarter of 2002.
In December 2002, PECO changed its accounting estimate related to the
allowance for uncollectible accounts based on an independently prepared
evaluation of the risk profile of PECO's customer accounts receivable. As a
result of the new evaluation, the allowance for uncollectible accounts reserve
was reduced by $17 million in the fourth quarter of 2002.
In 2002, Generation increased its allowance for uncollectible accounts by
$6 million based on an independently prepared evaluation of the risk profile of
Power Team's counterparties. Power Team is the unit within Generation that
manages the output of Generation's assets and energy sales to reduce the
volatility of Generation's earnings and cash flows.
5. Regulatory Issues
ComEd
95
Delivery Service Rates. On June 1, 2001, ComEd filed with the ICC to
establish delivery service charges for residential customers in preparation for
residential customer choice, which began in May 2002. ComEd is authorized to
charge customers who purchase electricity from an alternative supplier for the
use of its distribution system to deliver that electricity. These delivery
service rates are set through proceedings before the ICC based upon, among other
things, the operating costs associated with ComEd's distribution system and the
capital investment that ComEd has made in its distribution system.
On April 1, 2002, the ICC issued an interim order in ComEd's Delivery
Services Rate Case. The interim order is subject to an audit of test year (2000)
expenditures, including capital plant expenditures, with a final order to be
issued in 2003. The order sets delivery rates for residential customers choosing
a new retail electric supplier. The new rates became effective May 1, 2002 when
residential customers became eligible to choose their supplier of electricity.
Traditional bundled rates paid by customers that retain ComEd as their
electricity supplier are not affected by this order. Bundled rates will remain
frozen through 2006, as a result of the June 6, 2002 amendments to the Illinois
Restructuring Act that extended the freeze on bundled rates for an additional
two years. Delivery service rates for non-residential customers are not affected
by the order.
In October 2002, the ICC received the report on the audit of the test year
expenditures by a consulting firm engaged by the ICC to perform the audit. The
consulting firm recommended certain additional disallowances to test year
expenditures and rate base levels. ComEd does not expect this matter to have a
significant impact on results of operations in 2003, however, the estimated
potential investment write-off, before income taxes, could be up to
approximately $100 million, if the ICC ultimately determines that all or some
portion of ComEd's distribution plant is not recoverable through rates. In 2002,
ComEd recorded a charge to earnings, before income taxes, of $12 million
representing the estimated minimum probable exposure pursuant to SFAS No. 90,
"Regulated Enterprises - Accounting for Abandonments and Disallowances of Plant
Costs an Amendment of FASB Statement No. 71." ComEd is in negotiations with
several parties to resolve the delivery service case.
Customer Choice. As of December 31, 2002, all ComEd's customers were
eligible to choose an alternative electric supplier and non-residential
customers can also elect the power purchase option (PPO) that allows the
purchase of electric energy from ComEd at market-based prices. ComEd's
residential customers became eligible to choose a new electric supplier in May
2002. However, as of December 31, 2002, no alternative supplier had sought
approval from the ICC and no electric utilities have chosen to enter the ComEd
residential market for the supply of electricity. As of December 31, 2002,
approximately 22,700 non-residential customers, representing approximately 26%
of ComEd's annual retail kilowatt-hour sales, had elected to purchase their
electric energy from an alternate electric supplier or had chosen the power
purchase option. Customers who receive energy from an alternative supplier
continue to pay a delivery charge. ComEd is unable to predict the long-term
impact of customer choice on results of operations.
Rate Reductions and Return on Common Equity Threshold. The Illinois
restructuring legislation provided a 15% residential base rate reduction
effective August 1, 1998 with an additional 5% residential base rate reduction
effective October 1, 2001. ComEd's operating revenues were reduced by
approximately $99 million and $24 million in 2002 and 2001, respectively due to
the 5% residential rate reduction. Notwithstanding the rate reductions and
subject to certain earnings tests, a rate freeze is generally in effect until at
least January 1, 2007. A utility may request a rate increase during the rate
freeze period only when necessary to ensure the utility's financial viability.
Under the Illinois legislation, if the earned return on common equity of a
utility during this period exceeds an established threshold, one-half of the
excess earnings must be refunded to customers. The threshold rate of return on
common equity is based on the Monthly Treasury Bond Long-Term Average (25 years
and above). Earnings for purposes of ComEd's threshold include ComEd's net
income calculated in accordance with GAAP and
96
reflect the amortization of regulatory assets and goodwill. As a result of the
Illinois legislation, at December 31, 2002, ComEd had a regulatory asset with an
unamortized balance of $175 million that it expects to fully recover and
amortize by the end of 2006. Consistent with the provisions of the Illinois
legislation, regulatory assets may be recovered at amounts that provide ComEd an
earned return on common equity within the Illinois legislation earnings
threshold. The earned return on common equity and the threshold return on common
equity for ComEd are each calculated on a two-year average basis. ComEd did not
trigger the earnings sharing provision in 2002, 2001 or 2000 and does not
currently expect to trigger the earnings sharing provisions in the years 2003
through 2006.
PECO
Revenue Neutral Reconciliation Adjustment. As permitted by the Pennsylvania
Electric Competition Act, the Pennsylvania Department of Revenue calculated a
2002 Revenue Neutral Reconciliation (RNR) adjustment to the gross receipts tax
rate in order to neutralize the impact of electric restructuring on its tax
revenues. In January 2002, the PUC approved the RNR adjustment to the gross
receipts tax rate collected from customers. Effective January 1, 2002, PECO
implemented the change in the gross receipts tax rate. The RNR adjustment
increases the gross receipts tax rate, which increased PECO's annual revenues
and tax obligations by approximately $50 million in 2002. The RNR adjustment was
appealed. The case was remanded to the PUC and in August 2002, the PUC ruled
that PECO is properly authorized to recover these costs. In December 2002, the
PUC approved the inclusion of the RNR factor in PECO's base rates eliminating
the need for an annual filing to obtain approval for recovery.
Customer Choice. The PUC's Final Electric Restructuring Order provided for
the phase-in of customer choice of electric generation suppliers (EGS) and as of
January 1, 2000, all customers were eligible for customer choice. The Final
Restructuring Order also established market share thresholds (MST) to promote
competition. The MST requirements provided that, if as of January 1, 2001 and
January 1, 2003, respectively, less than 35% and 50% of residential and
commercial customers were shopping, the number of customers sufficient to meet
the MST shall be randomly selected and assigned to an EGS through a
PUC-determined process. For residential and small commercial customers, the
threshold measurement is by number of customers. For large commercial customers
the measurement is by load. On January 1, 2001, the 35% MST threshold was met
for all customer classes as a result of agreements assigning customers to New
Power Company (New Power) and Green Mountain as providers of last resort default
service. During 2002, PECO experienced an increase in the number of customers
selecting or returning to PECO as their EGS and at December 31, 2002,
approximately 21% of PECO's residential load, 10% of its small commercial and
industrial load and 7% of its large commercial and industrial load were
purchasing generation from an alternative generation supplier. Customers who
purchase energy from an EGS continue to pay a delivery charge. In January 2003,
PECO submitted to the PUC an MST plan to meet the 50% threshold requirement for
its small and large commercial customer classes, which was approved on February
6, 2003. According to the approved plan, randomly assigned customers who
participated will be switched to winning MST bidders as of their respective
meter read dates. Also in February 2003, PECO filed an MST plan for the
residential customer classes which is pending PUC approval.
In February 2002, New Power notified PECO of its intent to withdraw from
providing Competitive Default Service (CDS) to approximately 180,000 residential
customers. As a result of that withdrawal, those CDS customers were returned to
PECO in the second quarter of 2002. Pursuant to a tariff filing approved by the
PUC, PECO is serving those returned customers at the discount energy rates on
generation provided for under the original New Power CDS Agreement for the
remaining term of that contract. Subsequently, in the second quarter of 2002,
New Power also advised PECO it planned to
97
withdraw from serving all of its customers in Pennsylvania, including
approximately 15,000 non-CDS PECO customers. These customers were returned to
PECO during the third quarter of 2002.
Rate Reductions and Caps. Under the Final Restructuring Order, retail
electric rates were capped at year-end 1996 levels (system-wide average of 9.96
cents/kilowatt hour (kWh)) through June 2005. The Final Restructuring Order
required PECO to reduce its retail electric rates by 8% from the 1996
system-wide average rate on January 1, 1999. This rate reduction decreased to 6%
on January 1, 2000 until January 1, 2001. The transmission and distribution rate
component was capped at a system-wide average rate of 2.98 cents/kWh through
June 30, 2005. Additionally, generation rate caps, defined as the sum of the
applicable transition charge and energy and capacity charge, will remain in
effect through 2010.
On March 16, 2000, the PUC issued an order authorizing PECO to securitize
up to an additional $1 billion of its authorized stranded costs recovery. In
accordance with the terms of that order, PECO provided its retail customers with
rate reductions of $60 million for calendar year 2001 only.
Under a comprehensive settlement agreement in connection with achieving
regulatory approval of the Merger, PECO agreed to $200 million in aggregate rate
reductions for all customers in Pennsylvania over the period January 1, 2002
through 2005 and extended the rate caps on PECO's retail electric distribution
charges through December 31, 2006.
6. Supplemental Financial Information
Supplemental Income Statement Information
For the Years Ended December 31,
------------------------------------------------
2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
Taxes Other Than Income
Utility (a) $ 412 $ 342 $ 196
Real estate 149 140 68
Payroll 98 88 41
Other 50 53 17
- -------------------------------------------------------------------------------------------------------------------
Total $ 709 $ 623 $ 322
- -------------------------------------------------------------------------------------------------------------------
Other, Net
Investment income $ 130 $ 47 $ 64
Gain (loss) on disposition of assets, net 199 4 (19)
Write-down of impaired investments (41) (36) --
AFUDC, equity and borrowed 19 18 3
Reserve for potential plant disallowance (12) -- --
Settlement of power purchase agreement -- -- 6
Other 5 46 (1)
- -------------------------------------------------------------------------------------------------------------------
Total $ 300 $ 79 $ 53
- -------------------------------------------------------------------------------------------------------------------
(a) Municipal and state utility taxes are also recorded in Revenues on Exelon's
Consolidated Statements of Income.
98
Supplemental Cash Flow Information
For the Years Ended December 31,
------------------------------------------------
2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
Cash paid during the year:
Interest (net of amount capitalized) $ 905 $ 963 $ 519
Income taxes (net of refunds) $ 614 $ 749 $ 272
Non-cash investing and financing activities:
Regulatory Asset Fair Value Adjustment $ -- $ 347 $ --
Resolution of Certain Tax Matters and Merger
Severance Adjustment 14 -- --
Purchase Accounting Estimate Adjustments -- (85) --
Issuance of Exelon Shares for Unicom -- -- 5,310
Capital Lease Obligations 52 -- --
Issuance of InfraSource Stock -- 35 14
Contribution of Land from Minority Interest of
Consolidated Subsidiary 12 -- --
Note Issued to Sithe in the
Sithe New England Acquisition 534 -- --
Depreciation and amortization:
Property, plant and equipment $ 729 $ 697 $ 325
Regulatory assets 472 445 53
Nuclear fuel 374 393 149
Decommissioning 126 144 46
Goodwill -- 155 34
- -------------------------------------------------------------------------------------------------------------------
Total Depreciation and Amortization $ 1,701 $ 1,834 $ 607
- -------------------------------------------------------------------------------------------------------------------
Supplemental Balance Sheet Information
December 31,
-----------------------------------
2002 2001
- -------------------------------------------------------------------------------------------------------------------
Investments
Investment in Sithe $ 478 $ 700
Direct financing leases 445 427
Energy services and other ventures 167 161
Investment in AmerGen 160 95
Affordable housing projects 88 98
Communication ventures 39 116
Investment in subsidiaries and joint ventures 16 26
- -------------------------------------------------------------------------------------------------------------------
Total $ 1,393 $ 1,623
- -------------------------------------------------------------------------------------------------------------------
99
Prior to the Merger, Unicom entered into a like-kind exchange transaction
pursuant to which approximately $1.6 billion was invested in passive generating
station leases with two separate entities unrelated to Exelon. The generating
stations were leased back to such entities as part of the transaction. For
financial accounting purposes, the investments are accounted for as direct
financing lease investments. Unicom Investments, Inc. holds the leasehold
interests in the generating stations in several separate bankruptcy remote,
special purpose companies it directly or indirectly wholly owns. Under the terms
of the lease agreements, Exelon received a prepayment of $1.2 billion in the
fourth quarter of 2000, which reduced the investment in the lease. The remaining
payments are payable at the end of the thirty year lease and there are no
minimum scheduled lease payments to be received over the next five years. The
components of the net investment in the direct financing leases are as follows:
December 31,
-----------------------------------
2002 2001
- -------------------------------------------------------------------------------------------------------------------
Total minimum lease payments $ 1,492 $ 1,492
Less: Unearned income 1,047 1,065
- -------------------------------------------------------------------------------------------------------------------
Net investment in direct financing leases $ 445 $ 427
- -------------------------------------------------------------------------------------------------------------------
December 31,
-----------------------------------
2002 2001
- -------------------------------------------------------------------------------------------------------------------
Regulatory Assets
Competitive transition charge $ 4,639 $ 4,947
Recoverable deferred income taxes (see Note 14) 661 701
Nuclear decommissioning costs for retired plants 248 310
Recoverable transition costs 175 277
Reacquired debt costs and interest rate swap settlements 137 112
Non-pension postretirement benefits 65 71
Compensated absences 6 5
Other 7 --
- -------------------------------------------------------------------------------------------------------------------
Long-Term Regulatory Assets 5,938 6,423
Deferred energy costs (current asset) 31 56
- -------------------------------------------------------------------------------------------------------------------
Total $ 5,969 $ 6,479
- -------------------------------------------------------------------------------------------------------------------
o Competitive Transition Charges (CTC) represent PECO's stranded costs that
the PUC determined would be allowed to be recoverable through regulated
rates. These costs are related to the deregulation of the generation
portion of the electric utility business in Pennsylvania. The unamortized
balance of the CTC of $4.6 billion and $4.9 billion as of December 31, 2002
and 2001, respectively, was recorded on our Consolidated Balance Sheets.
The CTC includes Intangible Transition Property sold to PECO Energy
Transition Trust, a wholly owned subsidiary of PECO, in connection with the
securitization of PECO's stranded cost recovery. These charges are being
amortized through December 31, 2010 with a return on the unamortized
balance of 10.75%.
o Nuclear decommissioning costs for retired plants - recovery is provided
through ComEd's current regulated rates and is expected to be fully
recovered by the end of 2006.
o Recoverable transition costs - recovery is provided for in regulated rates
pursuant to the Illinois Restructuring Act and is expected to be recovered
by the end of 2006.
o Reacquired debt costs and interest rate swap settlements - recoverable
gains and losses on reacquired debt are deferred and amortized over the
rate-regulatory period, which is over the life of the new debt issued to
finance the debt redemption. Interest rate swap settlements are deferred
and amortized over the period that the related debt is outstanding.
100
The regulatory assets related to the nuclear decommissioning costs and
deferred income taxes did not require a cash outlay of investor supplied funds;
consequently, these costs are not earning a rate of return. Recovery of the
regulatory assets for loss on reacquired debt and recoverable transition costs
is provided for through regulated revenue sources that are based on the pre-open
access cost of service. Therefore, they are earning a rate of return.
December 31,
-----------------------------------
2002 2001
- -------------------------------------------------------------------------------------------------------------------
Accrued Expenses
Taxes Accrued $ 420 $ 91
Interest Accrued 307 299
Other Accrued Expenses 584 745
- -------------------------------------------------------------------------------------------------------------------
Total $ 1,311 $ 1,135
- -------------------------------------------------------------------------------------------------------------------
7. Earnings Per Share
Diluted earnings per share are calculated by dividing net income by the
weighted average shares of common stock outstanding including shares issuable
upon exercise of stock options outstanding under Exelon's stock option plans
considered to be common stock equivalents. The following table shows the effect
of these stock options on the weighted average number of shares outstanding used
in calculating diluted earnings per share (in millions):
2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
Average Common Shares Outstanding 322 320 202
Assumed Exercise of Stock Options 3 2 2
- -------------------------------------------------------------------------------------------------------------------
Average Dilutive Common Shares Outstanding 325 322 204
- -------------------------------------------------------------------------------------------------------------------
Stock options not included in average common shares used in calculating
diluted earnings per share due to their antidilutive effect were approximately
five million, five million and 30,000 for 2002, 2001 and 2000, respectively.
8. Accounts Receivable
Accounts Receivable -- Customer at December 31, 2002 and 2001 included
unbilled operating revenues of $442 million and $438 million, respectively. The
allowance for uncollectible accounts at December 31, 2002 and 2001 was $132
million and $213 million, respectively.
PECO is party to an agreement with a financial institution under which it
can sell or finance with limited recourse an undivided interest, adjusted daily,
in up to $225 million of designated accounts receivable until November 2005. At
December 31, 2002, PECO had sold a $225 million interest in accounts receivable,
consisting of a $164 million interest in accounts receivable which PECO
accounted for as a sale under SFAS No. 140, "Accounting for Transfers and
Servicing of Financial Assets and Extinguishment of Liabilities - a Replacement
of FASB Statement No. 125," and a $61 million interest in special-agreement
accounts receivable which was accounted for as a long-term note payable (see
Note 13 - Long-Term Debt). PECO retains the servicing responsibility for these
receivables. The agreement requires PECO to maintain the $225 million interest,
which, if not met, requires cash, which would otherwise be received by PECO
under this program, to be held in escrow until the requirement is met. At
December 31, 2002 and 2001, PECO met this requirement and was not required to
make any cash deposits.
101
9. Property, Plant, and Equipment
A summary of property, plant and equipment by classification as of December
31, 2002 and 2001 is as follows:
Asset Category 2002 2001
- -------------------------------------------------------------------------------------------------------------------
Electric-Transmission and Distribution $ 10,980 $ 10,156
Electric-Generation 5,678 4,344
Gas 1,319 1,281
Common 404 399
Nuclear Fuel 3,112 2,681
Construction Work in Progress 2,783 1,294
Other Property, Plant and Equipment 1,628 1,371
- -------------------------------------------------------------------------------------------------------------------
Total Property, Plant and Equipment 25,904 21,526
Less Accumulated Depreciation (including accumulated
amortization of nuclear fuel of $2,212 and $1,838 as of
December 31, 2002 and 2001, respectively) 8,770 7,735
- -------------------------------------------------------------------------------------------------------------------
Property, Plant and Equipment, net $ 17,134 $13,791
- -------------------------------------------------------------------------------------------------------------------
10. Jointly Owned Electric Utility Plant
Exelon's undivided ownership interests in jointly owned electric plant at
December 31, 2002 and 2001 were as follows:
Production Plant
------------------------------------------------------------------------- Transmission
December 31, 2002 Peach Bottom Salem Keystone Conemaugh Quad Cities and Other Plant
- ---------------------------------------------------------------------------------------------------------------------
Operator Generation PSE&G Reliant Reliant Generation Various Co.
Participating Interest 50% 42.59% 20.99% 20.72% 75% 21 to 44%
Exelon's Share:
Plant $ 417 $ 44 $ 131 $ 214 $ 171 $ 58
Accumulated Depreciation 243 12 117 145 4 22
Construction Work
in Progress 52 36 28 1 35 --
- ---------------------------------------------------------------------------------------------------------------------
102
Production Plant
------------------------------------------------------------------------- Transmission
December 31, 2001 Peach Bottom Salem Keystone Conemaugh Quad Cities and Other Plant
- ----------------------------------------------------------------------------------------------------------------------
Operator Generation PSE&G Reliant Reliant Generation Various Co.
Participating Interest 50% 42.59% 20.99% 20.72% 75% 21 to 44%
Exelon's Share:
Plant $ 387 $ 12 $ 121 $ 193 $ 96 $ 66
Accumulated Depreciation 220 4 98 124 10 25
Construction Work
in Progress 13 53 13 12 52 1
- ---------------------------------------------------------------------------------------------------------------------
Exelon's undivided ownership interests are financed with Exelon funds and,
when placed in service, all operations are accounted for as if such
participating interests were wholly owned facilities. Direct expenses of the
jointly owned plants are included in the corresponding operating expenses on the
Consolidated Income Statements.
11. Nuclear Decommissioning and Spent Fuel Storage
Exelon has an obligation to decommission its nuclear power plants. Exelon's
current estimate of its nuclear facilities' decommissioning cost for its owned
nuclear power plants is $7.4 billion in current year (2003) dollars. Based on
the extended license lives of the nuclear plants, expenditures are expected to
occur primarily when the operating plants are decommissioned, during the period
2029 through 2056. Decommissioning costs are currently recoverable through
regulated rates. Under rates in effect through December 31, 2002, Exelon
collected approximately $102 million in 2002 from customers. At December 31,
2002, the decommissioning liability, recorded in Accumulated Depreciation and
Deferred Credits and Other Liabilities on Exelon's Consolidated Balance Sheets,
was $2.8 billion and $1.4 billion, respectively. At December 31, 2001, the
decommissioning liability, recorded in Accumulated Depreciation and Deferred
Credits and Other Liabilities on Exelon's Consolidated Balance Sheets, was $2.7
billion and $1.4 billion, respectively. In order to fund future decommissioning
costs, at December 31, 2002 and 2001, Exelon held $3.1 billion and $3.2 billion,
respectively, in trust accounts that are included as Investments in Exelon's
Consolidated Balance Sheets at their fair market value. Exelon believes that the
amounts being recovered from customers through regulated rates and earnings on
nuclear decommissioning trust funds will be sufficient to fully fund its
decommissioning obligations.
In connection with the transfer of ComEd's nuclear generating stations to
Generation, ComEd asked the ICC to approve the continued recovery of
decommissioning costs after the transfer. On December 20, 2000, the ICC issued
an order finding that the ICC has the legal authority to permit ComEd to
continue to recover decommissioning costs from customers for the six-year term
of the power purchase agreements between ComEd and Generation. Under the ICC
order, ComEd is permitted to recover $73 million per year from customers for
decommissioning for the years 2001 through 2004. In 2005 and 2006, ComEd can
recover up to $73 million annually, depending upon the portion of the output of
the former ComEd nuclear stations that ComEd purchases from Generation. Under
the ICC order, subsequent to 2006, there will be no further recoveries of
decommissioning costs from customers. The ICC order also provides that any
surplus funds after the nuclear stations are decommissioned must be refunded to
customers. The amount of recovery in the ICC order is less than the $84 million
annual amount ComEd recovered in 2000. The ICC order has been upheld on appeal
in the Illinois Appellate Court and the Illinois Supreme Court has declined to
review the Appellate Court's decision.
To account for the effects of the ICC order, in the first quarter of 2001
ComEd reduced its nuclear decommissioning regulatory asset to $372 million,
reflecting the reduction in expected probable future recoveries from customers
through 2006. The reduction in the regulatory asset in the amount of $347
million was recorded as an adjustment to the initial Merger purchase price
allocation and resulted in a corresponding increase in goodwill. Also, ComEd
recorded an obligation to Generation of approximately
103
$440 million representing ComEd's legal requirement to remit funds to Generation
for the remaining regulatory asset amount of $372 million upon collection from
customers, and for collections from customers prior to the establishment of
external decommissioning trust funds in 1989 to be remitted to Generation for
deposit into the decommissioning trusts through 2006. Unrealized gains and
losses on decommissioning trust funds (based on the market value of the assets
on the Merger date, in accordance with purchase accounting) had previously been
recorded in accumulated depreciation or regulatory assets. As a result of the
transfer of the ComEd nuclear plants to Generation and the ICC order limiting
the regulated recoveries of decommissioning costs, net unrealized losses of $23
million (net of income taxes) at that date were reclassified to accumulated
other comprehensive income. All subsequent realized gains and losses on these
decommissioning trust funds' assets are based on the cost basis of the trust
fund assets established on the Merger date and are reflected in Other Income and
Deductions in Exelon's Consolidated Statements of Income.
Nuclear decommissioning costs associated with the nuclear generating
stations formerly owned by PECO continue to be recovered currently through rates
charged by PECO to regulated customers. These amounts are remitted to Generation
as allowed by the PUC. Under an agreement effective September 2001, PECO remits
$29 million per year to Generation related to nuclear decommissioning cost
recovery.
On December 31, 2002, PECO filed with the PUC for an annual increase in its
decommissioning cost recovery of $20 million effective June 1, 2004. The filing
is consistent with provisions in the Restructuring Settlement and the Merger
Settlement which require PECO to update the cost of decommissioning every five
years. The additional amount requested is expected to be reduced as it does not
reflect pending life extensions at Peach Bottom. The approval of the life
extensions is expected by mid-2003.
Under the Nuclear Waste Policy Act of 1982 (NWPA), the U.S. Department of
Energy (DOE) is responsible for the selection and development of repositories
for, and the disposal of, spent nuclear fuel (SNF) and high-level radioactive
waste. ComEd and PECO, as required by the NWPA, each signed contracts with the
DOE (Standard Contract) to provide for disposal of SNF from their respective
nuclear generating stations. In accordance with the NWPA and the Standard
Contract, ComEd and PECO pay the DOE one mill ($.001) per kilowatt-hour of net
nuclear generation for the cost of nuclear fuel long-term storage and disposal.
This fee may be adjusted prospectively in order to ensure full cost recovery.
The NWPA and the Standard Contract required the DOE to begin taking possession
of SNF generated by nuclear generating units by no later than January 31, 1998.
The DOE, however, failed to meet that deadline and its performance will be
delayed significantly. The DOE's current estimate for opening a SNF facility is
2010. This extended delay in SNF acceptance by the DOE has led to Exelon's
adoption of dry storage at its Dresden, Quad Cities and Peach Bottom Units and
its consideration of dry storage at other units.
In July 1998, ComEd filed a complaint against the United States Government
(Government) in the United States Court of Federal Claims (Court) seeking to
recover damages caused by the DOE's failure to honor its contractual obligation
to begin disposing of SNF in January 1998. In August 2001, the Court granted
ComEd's motion for partial summary judgment for liability on ComEd's breach of
contract claim. In November 2001, the Government filed two partial summary
judgment motions relating to certain damage issues in the case as well as two
motions to dismiss claims other than ComEd's breach of contract claim. On August
30, 2002, after taking certain damages related to discovery, ComEd filed briefs
in response to the DOE's motions. The Court has postponed the time for the DOE
to file reply briefs while it entertains additional DOE discovery motions. This
litigation was assumed by Generation in the corporate restructuring.
In July 2000, PECO entered into an agreement with the DOE relating to
PECO's Peach Bottom nuclear generating unit to address the DOE's failure to
begin removal of SNF in January 1998 as required by the Standard Contract. Under
that agreement, the DOE agreed to provide PECO with credits against PECO's
future contributions to the Nuclear Waste Fund over the next ten years to
compensate PECO for SNF storage costs incurred as a result of the DOE's breach
of the contract. The agreement also provides
104
that, upon PECO's request, the DOE will take title to the SNF and the interim
storage facility at Peach Bottom provided certain conditions are met. Generation
assumed this contract in restructuring.
In November 2000, eight utilities with nuclear power plants filed a Joint
Petition for Review against the DOE with the United States Court of Appeals for
the Eleventh Circuit seeking to invalidate that portion of the agreement
providing for credits to PECO against nuclear waste fund payments on the ground
that such provision is a violation of the NWPA. PECO intervened as a defendant
in that case, and Generation assumed the claim in the 2001 corporate
restructuring. On September 24, 2002, the United States Court of Appeals for the
Eleventh Circuit ruled that the fee adjustment provision of the agreement
violates the NWPA and therefore is null and void. The Court did not hold that
the agreement as a whole is invalid. Article XVI(I) of the Amendment provides
that if any portion of the Amendment is found to be void, the DOE and Generation
agree to negotiate in good faith and attempt to reach an enforceable agreement
consistent with the spirit and purpose of this Amendment. That provision further
provides that should a major term be declared void, and the DOE and Generation
cannot reach a subsequent agreement, the entire Amendment would be rendered null
and void, the original Peach Bottom Standard Contract would remain in effect and
the parties would return to pre-Amendment status. Pursuant to Article XIV(I),
Generation has begun negotiations with the DOE and those negotiations are
ongoing. Under the agreement, Generation has received approximately $40 million
in credits against contributions to the nuclear waste fund.
In April 2001, an individual filed suit against the DOE with the United
States District Court for the Middle District of Pennsylvania seeking to
invalidate the agreement on the grounds that the DOE has violated the National
Environmental Policy Act and the Administrative Procedure Act. PECO intervened
as a defendant and moved to dismiss the complaint. Generation assumed the
defense in restructuring. On September 30, 2002, the Court granted Generation's
motion and dismissed the lawsuit on the ground that the Court did not have
jurisdiction over the matter.
The Standard Contract with the DOE also requires that PECO and ComEd pay
the DOE a one-time fee applicable to nuclear generation through April 6, 1983.
PECO's fee has been paid. Pursuant to the Standard Contract, ComEd elected to
pay the one-time fee of $277 million, with interest to the date of payment, just
prior to the first delivery of SNF to the DOE. As of December 31, 2002, the
unfunded liability for the one-time fee with interest was $858 million. The
liabilities for spent nuclear fuel disposal costs, including the one-time fee,
were transferred to Generation as part of the corporate restructuring.
12. Notes Payable
2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
Average borrowings $ 337 $ 193 $ 186
Average interest rates, computed on daily basis 1.94% 4.01% 6.62%
Maximum borrowings outstanding $ 783 $ 599 $ 500
Average interest rates, at December 31 1.88% 2.63% 7.18%
- -------------------------------------------------------------------------------------------------------------------
Exelon, ComEd, PECO and Generation entered into a $1.5 billion unsecured
revolving credit facility on November 22, 2002 with a group of banks. Under the
credit facility, each borrower may borrow up to a designated sublimit amount on
a revolving credit basis through November 20, 2003. This credit facility
includes a term-out option that allows any outstanding borrowings at the end of
the revolving credit period to be repaid on November 21, 2004. This credit
facility is used principally to support the commercial paper programs of Exelon,
ComEd, PECO and Generation. At December 31, 2002, the amount of commercial paper
outstanding was $681 million which does not include $267 million that has been
classified as long-term debt. At December 31, 2001, the amount of commercial
paper outstanding was $360 million. Interest rates on the advances under the
credit facility are based on the London Interbank Offering Rate (LIBOR) as of
the date of the advance.
105
13. Long-Term Debt
December 31,
------------------------------------------------------------
Maturity
Rates Date 2002 2001
- -------------------------------------------------------------------------------------------------------------------
Securitized Long-Term Debt
ComEd Transitional Trust Notes
Series 1998-A: 5.39%-5.74% 2003-2008 $ 2,040 $ 2,380
PETT Bonds Series 1999-A:
Fixed rates 5.63%-6.13% 2003-2008 (a) 2,426 2,577
Floating rates 1.48%-1.55% 2004-2007 (a) 274 310
PETT Bonds Series 2000-A: 7.63%-7.65% 2009 (a) 750 890
PETT Bonds Series 2001: 6.52% 2010 (a) 805 805
Other Long-Term Debt
First and Refunding Mortgage Bonds (b) (c):
Fixed rates 4.4%-9.875% 2003-2023 3,614 3,942
Floating rates 1.08%-1.41% 2012-2013 254 154
Notes payable and other 6.40%-9.20% 2003-2020 2,393 2,651
SBG Facility 6.37%(d) 2007 1,036 --
Pollution control notes:
Fixed rates 5.2%-6.95% 2007-2034 199 44
Floating rates 1.05%-1.50% 2009-2034 456 583
Notes payable - accounts receivable agreement 1.42% 2005 61 55
Sinking fund debentures 3.125%-4.75% 2004-2011 20 23
Commercial Paper (e) 1.88% (f) 2003 267 --
- -------------------------------------------------------------------------------------------------------------------
Total Long-Term Debt (g) 14,595 14,414
Unamortized debt discount and premium, net (107) (129)
Fair value hedge carrying value adjustment 41 --
Due within one year (1,402) (1,406)
- -------------------------------------------------------------------------------------------------------------------
Long-Term Debt $ 13,127 $ 12,879
- -------------------------------------------------------------------------------------------------------------------
(a) The maturity date represents the expected final payment date which is the
date when all principal and interest of the related class of transition
bonds is expected to be paid in full in accordance with the expected
amortization schedule for the applicable class. The date when all principal
and interest must be paid in full for the PETT Bonds Series 1999-A, 2000-A
and 2001-A are 2003 through 2009, 2010 and 2010, respectively. The current
portion of transition bonds is based upon the expected maturity date.
(b) Utility plant of ComEd and PECO is subject to the liens of their respective
mortgage indentures. (c) Includes first mortgage bonds issued under the
ComEd and PECO mortgage indentures securing pollution
control notes.
(d) The rate for the SBG Facility is stated as an average rate. Under the terms
of the SBG Facility, SBG is required to effectively fix the interest rate
on 50% of the borrowings under the facility through its maturity in 2007.
The SBG Facility is subject to a variable rate based on the LIBOR rate plus
a margin of 1.375%, however, through the required interest rate swaps, SBG
has effectively fixed the LIBOR component of the interest rate at 5.73% on
83% of the debt balance as of December 31, 2002.
(e) Classified as long-term at December 31, 2002 since it was refinanced with
long-term debt in January 2003.
(f) Average interest rate of commercial paper outstanding at December 31, 2002.
(g) Long-term debt maturities in the period 2003 through 2007 and thereafter
are as follows:
2003 $ 1,669
2004 962
2005 1,313
2006 1,273
2007 1,172
Thereafter 8,206
-----------------
Total $14,595
-----------------
2003 maturities include $267 million of commercial paper classified as
long-term debt (see Note 23 - Subsequent Events).
106
In 2002, ComEd issued $700 million of long-term debt primarily consisting
of the issuance of $600 million of 6.15% First Mortgage Bonds, Series 98, due
March 15, 2012 and the issuance of $100 million of Illinois Development Finance
Authority floating-rate Pollution Control Revenue Refunding Bonds, Series 2002
due April 15, 2013. In 2002, ComEd redeemed or paid at maturity $1,540 million
of long-term debt primarily consisting of the redemption of $100 million of
7.25% Illinois Development Finance Authority Pollution Control Revenue Refunding
Bonds, Series 1991 due June 1, 2011, the redemption of $200 million of 8.625%
First Mortgage Bonds, Series 81, due February 1, 2022, the redemption of $200
million of 8.5% First Mortgage Bonds, Series 84 due July 15, 2022, the payment
at maturity of $200 million of 7.375% First Mortgage Bonds, Series 85, due
September 15, 2002, the redemption of $200 million of 8.375% First Mortgage
Bonds, Series 86, due September 15, 2022, the payment at maturity of $200
million of variable rate senior notes due September 30, 2002, the payment at
maturity of $100 million of 9.17% medium-term notes due October 15, 2002, and
the retirement of $340 million in transitional trust notes.
In 2002, Generation exchanged $700 million of 6.95% Senior Notes issued in
2001 for notes which are registered under the Securities Act. ComEd exchanged
$600 million of 6.15% First Mortgage Bonds, Series 98, due March 15, 2012, for
bonds which are registered under the Securities Act. PECO exchanged $250 million
of 5.95% private placement First and Refunding Mortgage Bonds, due November 1,
2011, for bonds which are registered under the Securities Act. The exchange
bonds are identical to the outstanding bonds except for the elimination of
certain transfer restrictions and registration rights pertaining to the
outstanding bonds. ComEd, PECO and Generation did not receive any cash proceeds
from issuance of the exchange bonds.
In 2002 and 2001, ComEd entered into forward starting interest rate swaps
with an aggregate notional amount of $830 million and $250 million,
respectively, to manage interest rate exposure associated with anticipated debt
issuance. In 2002, forward starting interest rate swaps with an aggregate
notional amount of $450 million were settled with net proceeds to counterparties
of $10 million that has been deferred in regulatory assets and is being
amortized over the life of the First Mortgage Bonds as an increase to interest
expense.
In 2002 and 2001, ComEd entered into interest rate swap agreements with a
notional amount of $250 million and $235 million, respectively, to effectively
convert fixed rate debt to floating rate debt.
In 2002, PECO issued $225 million of 4.75% First and Refunding Mortgage
Bonds, due October 1, 2012. This bond issuance repaid commercial paper that was
used to pay $222 million of First and Refunding Mortgage Bonds at maturity with
a weighted average interest rate of 7.30%. In connection with the issuance of
the First and Refunding Mortgage Bonds, PECO settled forward starting interest
rate swaps in the aggregate notional amount of $200 million resulting in a $5
million pre-tax loss recorded in other comprehensive income, which is being
amortized over the expected remaining life of the related debt.
In 2001, ComEd redeemed $196 million of 9.875% First Mortgage Bonds, Series
75, due June 15, 2020 and retired $340 million in transitional trust notes.
In 2001, PECO Energy Transition Trust (PETT), a Delaware business trust and
a wholly owned subsidiary of PECO, refinanced $805 million of floating rate
Series 1999-A Transition Bonds through the issuance by PETT of fixed-rate
transition bonds (Series 2001-A Transition Bonds). The 2001-A Transition Bonds
are non-callable, fixed rate securities with an interest rate of 6.52%. The
Series 2001-A Transition Bonds have an expected final payment date of September
1, 2010 and a termination date of December 31, 2010. In connection with this
refinancing, PECO settled $318 million of forward starting interest rate swaps
resulting in a $6 million gain which is reflected in other income and deductions
due to the transaction no longer being probable. Also, in connection with this
refinancing, PECO settled a portion of the interest rate swaps and the remaining
portion of the forward starting interest rate swaps resulting in gains of $25
million, which were deferred and are being amortized over the expected remaining
lives of the related debt.
In 1999, PECO entered into treasury forwards associated with the
anticipated issuance of the Series 2000-A Transition Bonds. On May 2, 2000,
these instruments were settled with net proceeds to
107
the counterparties of $13 million that has been deferred and is being amortized
over the life of the Series 2000-A Transition Bonds as an increase to interest
expense.
In 1998, PECO entered into treasury forwards and forward starting interest
rate swaps to manage interest rate exposure associated with the anticipated
issuance of the Series 1999-A Transition Bonds. On March 18, 1999, these
instruments were settled with net proceeds of $80 million to PECO that were
deferred and are being amortized over the life of the Series 1999-A Transition
Bonds as a reduction of interest expense.
At December 31, 2002 and 2001, the aggregate unamortized net gain on the
settlement of the PECO swap transactions was $36 million and $55 million,
respectively, recorded in Other Comprehensive Income.
ComEd prepayment premiums of $24 million, and net unamortized premiums,
discounts and debt issuance expenses of $3 million, and prepayment premiums of
$39 million, offset by unamortized issuance premiums of $17 million associated
with the early retirement of debt in 2002 and 2001, respectively, have been
deferred in regulatory assets and will be amortized to interest expense over the
life of the related new debt issuance consistent with regulatory recovery. In
2000, PECO incurred charges aggregating $6 million ($4 million, net of tax) for
prepayment premiums and the write-offs of unamortized deferred financing costs
associated with the early retirement of debt that have been recorded in interest
expense.
14. Income Taxes
Income tax expense (benefit) is comprised of the following components:
For the Years Ended December 31,
-----------------------------------------------
2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
Included in operations:
Federal
Current $ 624 $ 880 $ 161
Deferred 250 (61) 163
Investment tax credit amortization (15) (14) (15)
State
Current 96 119 --
Deferred 43 7 30
- -------------------------------------------------------------------------------------------------------------------
$ 998 $ 931 $ 339
- -------------------------------------------------------------------------------------------------------------------
Included in cumulative effect of changes in accounting principles:
Federal
Deferred $ (87) $ 6 $ 13
State
Deferred (3) 2 3
- -------------------------------------------------------------------------------------------------------------------
$ (90) $ 8 $ 16
- -------------------------------------------------------------------------------------------------------------------
The effective income tax rate varies from the U.S. Federal statutory rate
principally due to the following:
108
For the Years Ended December 31,
------------------------------------------------
2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
U.S. Federal statutory rate 35.0% 35.0% 35.0%
Increase (decrease) due to:
Property basis differences (0.4) (0.2) 0.1
State income taxes, net of Federal income tax benefit 3.2 3.4 2.1
Amortization of investment tax credit (0.4) (0.5) (1.6)
Amortization of goodwill -- 1.9 0.9
Dividends on PECO Preferred Stock 0.1 0.2 0.4
Other, net (0.1) (0.1) 0.7
- -------------------------------------------------------------------------------------------------------------------
Effective income tax rate 37.4% 39.7% 37.6%
- -------------------------------------------------------------------------------------------------------------------
The tax effects of temporary differences giving rise to significant
portions of Exelon's deferred tax assets and liabilities as of December 31, 2002
and 2001 are presented below:
2002 2001
- -------------------------------------------------------------------------------------------------------------------
Deferred tax liabilities:
Plant basis difference $ 4,710 $ 4,630
Deferred gain on sale of plants 860 872
Deferred investment tax credit 212 222
Deferred debt refinancing costs 96 44
Tax deductible goodwill -- 2
Unrealized gain on derivative financial instruments -- 34
- -------------------------------------------------------------------------------------------------------------------
Total deferred tax liabilities 5,878 5,804
- -------------------------------------------------------------------------------------------------------------------
Deferred tax assets:
Decommissioning and decontamination obligations (607) (573)
Deferred pension and postretirement obligations (911) (382)
Tax deductible goodwill (95) --
Unrealized loss on derivative financial instruments (60) --
Other, net (208) (194)
- -------------------------------------------------------------------------------------------------------------------
Total deferred tax assets (1,881) (1,149)
- -------------------------------------------------------------------------------------------------------------------
Deferred income taxes (net) on the balance sheet $ 3,997 $ 4,655
- -------------------------------------------------------------------------------------------------------------------
In accordance with regulatory treatment of certain temporary differences,
Exelon has recorded a regulatory asset for recoverable deferred income taxes,
pursuant to SFAS No. 109, "Accounting for Income Taxes," of $661 million and
$701 million at December 31, 2002 and 2001, respectively. These recoverable
deferred income taxes include the deferred tax effects associated principally
with liberalized depreciation accounted for in accordance with the ratemaking
policies of the ICC and PUC, as well as the revenue impacts thereon, and assume
continued recovery of these costs in future rates.
Exelon's predecessor entities, Unicom and PECO, have years that are under
review at the audit or appeals level of the Internal Revenue Service (IRS) and
certain state authorities. These reviews by the governmental taxing authorities
are not expected to have an adverse impact on the financial condition or result
of operations at Exelon.
ComEd has taken certain tax positions, which have been disclosed to the
IRS, to defer the tax gain on the 1999 sale of its fossil generating assets. As
of December 31, 2002, a deferred tax liability of approximately $860 million
related to the fossil plant sale is reflected in Deferred Income Taxes on
Exelon's Consolidated Balance Sheets. ComEd's management believes an adequate
reserve for interest has been established in the event that such positions are
not sustained. Changes in IRS interpretations of existing tax authority or
challenges to ComEd's positions could have the impact of accelerating future
income tax payments and increasing interest expense above amounts reserved
related to the deferred tax
109
gain that becomes current. The Federal tax returns covering the period of the
1999 fossil plant sale are anticipated to be under IRS audit beginning in 2003.
Final resolution of this matter is not anticipated for several years.
As of December 31, 2002 and 2001, Exelon had recorded valuation allowances
of $13 million and $2 million, respectively.
15. Retirement Benefits
Exelon sponsors defined benefit pension plans and postretirement welfare
benefit plans applicable to essentially all ComEd, PECO, Generation and Business
Services Company (BSC) employees and certain employees of Enterprises. In 2001,
Exelon consolidated the former Unicom and PECO plans into Exelon plans.
Essentially all management employees, and electing union employees, hired on or
after January 1, 2001 participate in newly established cash balance pension
plans. Approximately 4,700 management employees who were active participants in
the former Unicom and PECO pension plans on December 31, 2000, and remained
employed by Exelon on January 1, 2002 elected to transfer to the cash balance
plan. Benefits under Exelon's pension plans generally reflect each employee's
compensation, years of service and age at retirement. Funding is based upon
actuarially determined contributions that take into account the amount
deductible for income tax purposes and the minimum contribution required under
the Employee Retirement Income Security Act of 1974, as amended. The following
tables provide a reconciliation of benefit obligations, plan assets and funded
status of the plans.
110
Pension Benefits Other Postretirement Benefits
------------------------------------------------------------
2002 2001 2002 2001
- -------------------------------------------------------------------------------------------------------------------
Change in benefit obligation:
Net benefit obligation at beginning of year $ 7,101 $ 6,695 $ 2,331 $ 2,275
Service cost 95 94 57 42
Interest cost 525 498 160 161
Plan participants' contributions -- -- 8 4
Plan amendments 120 44 -- (191)
Actuarial (gain)/loss 514 254 155 173
Curtailments/Settlements -- (38) -- --
Special accounting costs 4 48 -- 3
Gross benefits paid (505) (494) (156) (136)
- -------------------------------------------------------------------------------------------------------------------
Net benefit obligation at end of year $ 7,854 $ 7,101 $ 2,555 $ 2,331
- -------------------------------------------------------------------------------------------------------------------
Change in plan assets:
Fair value of plan assets at beginning of year $ 6,279 $ 7,000 $ 1,132 $ 1,188
Actual return on plan assets (581) (265) (125) (14)
Employer contributions 202 38 73 90
Plan participants' contributions -- -- 8 4
Gross benefits paid (505) (494) (156) (136)
- -------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of year $ 5,395 $ 6,279 $ 932 $ 1,132
- -------------------------------------------------------------------------------------------------------------------
Funded status at end of year: $ (2,459) $ (822) $ (1,623) $ (1,199)
Miscellaneous adjustment (3) -- -- --
Unrecognized net actuarial (gain)/loss 2,118 397 793 440
Unrecognized prior service cost 211 108 (149) (191)
Unrecognized net transition obligation (asset) (11) (17) 102 103
- -------------------------------------------------------------------------------------------------------------------
Net amount recognized at end of year $ (144) $ (334) $ (877) $ (847)
- -------------------------------------------------------------------------------------------------------------------
Amounts recognized in statements of financial position:
Prepaid benefit cost $ 145 $ -- $ -- $ --
Accrued benefit cost (289) (334) (877) (847)
Additional minimum liability (1,815) -- -- --
Intangible asset 211 -- -- --
Accumulated other comprehensive income 1,604 -- -- --
- -------------------------------------------------------------------------------------------------------------------
Net amount recognized at end of year $ (144) $ (334) $ (877) $ (847)
- -------------------------------------------------------------------------------------------------------------------
111
Pension Benefits Other Postretirement Benefits
-----------------------------------------------------------------------------
2002 2001 2000 2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
Weighted-average assumptions
as of December 31,
Discount rate 6.75% 7.35% 7.60% 6.75% 7.35% 7.60%
Expected return on plan assets 9.50% 9.50% 9.50% 8.80% 8.80% 8.80%
Rate of compensation increase 4.00% 4.00% 4.30% 4.00% 4.00% 4.30%
Health care cost trend on
covered charges N/A N/A N/A 8.5% 10.00% 7.00%
decreasing decreasing decreasing
to ultimate to ultimate to ultimate
trend of 4.5% trend of 4.5% trend of 5.0%
in 2008 in 2008 in 2005
- -------------------------------------------------------------------------------------------------------------------
Pension Benefits Other Postretirement Benefits
-----------------------------------------------------------------------------
2002 2001 2000 2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
Components of net periodic
benefit cost (benefit):
Service cost $ 95 $ 94 $ 39 $ 57 $ 42 $ 24
Interest cost 525 498 219 160 161 83
Expected return on assets (628) (625) (316) (93) (99) (34)
Amortization of:
Transition obligation (asset) (4) (4) (4) 10 10 12
Prior service cost 16 9 7 (37) (9) --
Actuarial (gain) loss -- (25) (26) 6 1 --
Curtailment charge (credit) -- (12) (12) -- 9 24
Settlement charge (credit) -- (9) (16) -- -- --
- -------------------------------------------------------------------------------------------------------------------
Net periodic benefit cost (benefit) $ 4 $ (74) $ (109) $ 103 $ 115 $ 109
- -------------------------------------------------------------------------------------------------------------------
Special accounting costs $ 4 $ 48 $ 217 $ -- $ 3 $ 48
- -------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------
Sensitivity of retiree welfare results
Effect of a one percentage point increase in assumed health care cost trend
on total service and interest cost components $ 33
on postretirement benefit obligation $ 302
Effect of a one percentage point decrease in assumed health care cost trend
on total service and interest cost components $ (27)
on postretirement benefit obligation $ (252)
- -------------------------------------------------------------------------------------------------------------------
Prior service cost is amortized on a straight-line basis over the average
remaining service period of employees expected to receive benefits under the
plans.
Exelon's costs of providing pension and postretirement benefit plans are
dependent upon a number of factors, such as the rates of return on pension plan
assets, discount rate, and the rate of increase in health care costs. The market
value of plan assets has been affected by sharp declines in the equity market
since the third quarter of 2000. As a result, at December 31, 2002, Exelon was
required to recognize an additional minimum liability and an intangible asset as
prescribed by SFAS No. 87 "Employers' Accounting for Pensions." The liability
was recorded as a reduction to shareholders' equity, and the equity will be
restored to the balance sheet in future periods when the fair value of plan
assets exceeds the accumulated benefit obligations. The amount of the reduction
to shareholders' equity (net of income taxes) in 2002 was $1.0 billion. The
recording of this reduction did not affect net income or cash flow in 2002 or
compliance with debt covenants.
112
Special accounting costs of $4 million in 2002 and $48 million in 2001
represent accelerated separation and enhancement benefits provided to PECO
employees expected to be terminated as a result of the Merger. Special
accounting costs in 2000 of $217 million represented PECO's accelerated
separation and enhancement benefits of $96 million and ComEd's accelerated
liability increase of $121 million inclusive of $96 million for separation
benefits and $25 million for plan enhancements.
Exelon provides certain health care and life insurance benefits for retired
employees. In 2001, Exelon adopted an amendment to the former Unicom
postretirement medical benefit plan that changed the eligibility requirement of
the plan to cover only employees who retire with 10 years of service after age
45 rather than with 10 years of service and having attained the age of 55.
Welfare benefits for active employees are provided by several insurance policies
or self-funded plans whose premiums or contributions are based upon the benefits
paid during the year.
Exelon sponsors savings plans for the majority of its employees. The plans
allow employees to contribute a portion of their pretax income in accordance
with specified guidelines. Exelon matches a percentage of the employee
contribution up to certain limits. The cost of Exelon's matching contribution to
the savings plans totaled $63 million, $57 million and $17 million in 2002, 2001
and 2000, respectively.
16. Preferred Securities of Subsidiaries
Preferred and Preference Stock
At December 31, 2002 and 2001, cumulative Preferred Stock of PECO, no par
value, consisted of 15,000,000 shares authorized and the amounts set forth
below:
December 31,
--------------------------------------------------------------------------
Current 2002 2001 2002 2001
Redemption --------------------------------------------------------------------------
Price(a) Shares Outstanding Dollar Amount
- -------------------------------------------------------------------------------------------------------------------
Series (without mandatory
redemption)
$4.68 $ 104.00 150,000 150,000 $ 15 $ 15
$4.40 112.50 274,720 274,720 27 27
$4.30 102.00 150,000 150,000 15 15
$3.80 106.00 300,000 300,000 30 30
$7.48 (b) 500,000 500,000 50 50
- -------------------------------------------------------------------------------------------------------------------
1,374,720 1,374,720 137 137
Series (with mandatory
redemption)
$6.12 (c) -- 185,400 -- 19
- -------------------------------------------------------------------------------------------------------------------
Total preferred stock 1,374,720 1,560,120 $ 137 $ 156
- -------------------------------------------------------------------------------------------------------------------
(a) Redeemable, at the option of PECO, at the indicated dollar amounts per
share, plus accrued dividends.
(b) None of the shares of this series is subject to redemption prior to April
1, 2003.
(c) PECO made the annual sinking fund payments of $18.5 million on August 1,
2002 and August 1, 2001. At December 31, 2000, shares and principal
outstanding were 370,800 and $37 million, respectively.
113
At December 31, 2002 and 2001, ComEd Preferred Stock and ComEd Preference
Stock consisted of 850,000 and 6,810,451 shares authorized, respectively, none
of which were outstanding.
Company Obligated Mandatorily Redeemable Preferred Securities
At December 31, 2002 and 2001, subsidiary trusts of PECO and ComEd had
outstanding the following preferred securities:
December 31,
----------------------------------------------------
Mandatory Distri- Liqui- 2002 2001 2002 2001
Redemption bution dation -------------------------- -------------------------
Date Rate Value Trust Securities Outstanding Dollar Amount
- -------------------------------------------------------------------------------------------------------------------
PECO Energy
Capital Trust II 2037 8.00% $ 25 2,000,000 2,000,000 $ 50 $ 50
PECO Energy
Capital Trust III 2028 7.38% 1,000 78,105 78,105 78 78
- -------------------------------------------------------------------------------------------------------------------
Total 2,078,105 2,078,105 $ 128 $ 128
- -------------------------------------------------------------------------------------------------------------------
ComEd Financing I 2035 8.48% $ 25 8,000,000 8,000,000 $ 200 $ 200
ComEd Financing II 2027 8.50% 1,000 150,000 150,000 150 150
Unamortized Discount (20) (21)
- -------------------------------------------------------------------------------------------------------------------
Total 8,150,000 8,150,000 $ 330 $ 329
- -------------------------------------------------------------------------------------------------------------------
The securities issued by the PECO trusts represent Company Obligated
Mandatorily Redeemable Preferred Securities of a Partnership (COMRPS) having a
distribution rate and liquidation value equivalent to the trust securities. The
COMRPS are the sole assets of these trusts and represent limited partnership
interests of PECO Energy Capital, L.P. (Partnership), a Delaware limited
partnership. Each holder of a trust's securities is entitled to withdraw the
corresponding number of COMRPS from the trust in exchange for the trust
securities so held. Each series of COMRPS is supported by PECO's deferrable
interest subordinated debentures, held by the Partnership, which bear interest
at rates equal to the distribution rates on the related series of COMRPS.
ComEd Financing I and ComEd Financing II are wholly owned subsidiary trusts
of ComEd. Each of ComEd trust's sole assets are subordinated deferrable interest
securities issued by ComEd bearing interest rates equivalent to the distribution
rate of the related trust security.
The preferred securities issued by each of ComEd Financing I and ComEd
Financing II have no voting privileges, except (i) for the right to approve a
merger, consolidation or other transaction involving the applicable trust that
would result in certain United States Federal income tax consequences to that
trust, (ii) with respect to certain amendments to the applicable trust
agreement, (iii) for certain voting privileges that arise upon an event of
default under the applicable trust agreement or (iv) with respect to certain
amendments to the related ComEd guarantee agreement.
The interest expense on the debentures and deferrable interest securities
is included in Distributions on Preferred Securities of Subsidiaries in the
Consolidated Statements of Income and is deductible for income tax purposes.
17. Common Stock
At December 31, 2002 and 2001, common stock without par value consisted of
600,000,000 and 600,000,000 shares authorized and 323,312,586 and 321,006,904
shares outstanding, respectively.
Stock Repurchase
In January 2000, in connection with the Merger Agreement, PECO entered into
a forward purchase agreement to purchase $500 million of its common stock from
time to time. Settlement of this forward purchase agreement was, at PECO's
election, on a physical, net share or net cash basis. In May 2000, PECO utilized
a portion of the proceeds from the securitization of its stranded cost recovery
to
114
physically settle this agreement, resulting in the repurchase of 12 million
shares of common stock for $496 million. In connection with the settlement of
this agreement, PECO received $1 million in accumulated dividends on the
repurchased shares and paid $6 million of interest.
Stock-Based Compensation Plans
Exelon maintains a Long-Term Incentive Plan (LTIP) for certain full-time
salaried employees and previously maintained a broad-based incentive program for
certain other employees. The types of long-term incentive awards that have been
granted under the LTIP are non-qualified options to purchase shares of Exelon's
common stock and common stock awards. At December 31, 2002, there were
13,000,000 options authorized for issuance under the LTIP and 2,000,000 options
authorized under the broad-based incentive program.
The exercise price of the stock options is equal to the fair market value
of the underlying stock on the date of option grant. Options granted under the
LTIP and the broad-based incentive program become exercisable upon attainment of
a target share value and/or time. All options expire 10 years from the date of
grant. Information with respect to the LTIP and the broad-based incentive
program at December 31, 2002 and changes for the three years then ended, is as
follows:
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Price Price Price
Shares (per share) Shares (per share) Shares (per share)
2002 2002 2001 2001 2000 2000
- -------------------------------------------------------------------------------------------------------------------
Balance at January 1 14,039,996 $ 43.96 15,287,859 $ 42.13 6,065,897 $ 31.91
Options granted/assumed 3,938,632 47.12 629,200 66.42 11,089,051 (a) 46.09
Options exercised (1,821,339) 33.37 (1,695,474) 34.84 (1,725,058) 31.79
Options canceled (270,299) 53.62 (181,589) 52.64 (142,031) 39.95
- -------------------------------------------------------------------------------------------------------------------
Balance at December 31 15,886,990 45.80 14,039,996 43.96 15,287,859 42.13
- -------------------------------------------------------------------------------------------------------------------
Exercisable at
December 31 10,491,184 43.96 8,006,193 38.75 4,953,942 30.04
- -------------------------------------------------------------------------------------------------------------------
Weighted average fair value
of options granted during year $ 13.62 $ 19.59 $ 16.62
- -------------------------------------------------------------------------------------------------------------------
(a) Includes 5.3 million options converted in the Merger.
The fair value of each option is estimated on the date of grant using
the Black-Scholes option-pricing model with the following weighted average
assumptions used for grants in 2002, 2001 and 2000, respectively:
2002 2001 2000
- -------------------------------------------------------------------------------
Dividend yield 3.3% 3.2% 3.6%
Expected volatility 36.8% 36.8% 36.8%
Risk-free interest rate 4.6% 4.9% 5.9%
Expected life (years) 5.0 5.0 5.0
- -------------------------------------------------------------------------------
115
At December 31, 2002, the options outstanding, based on ranges of exercise
prices, were as follows:
Options Outstanding Options Exercisable
------------------- -------------------
Weighted
Average
Remaining Weighted Weighted
Contractual Average Average
Range of Number Life Exercise Number Exercise
Exercise Prices Outstanding (years) Price Exercisable Price
- -------------------------------------------------------------------------------------------------------------------
$10.01-$20.00 560,700 6.14 $ 19.68 560,700 $ 19.68
$20.01-$30.00 926,332 4.64 25.49 926,332 25.49
$30.01-$40.00 4,668,877 7.53 37.87 4,031,683 37.76
$40.01-$50.00 4,844,505 9.39 45.61 1,419,748 42.25
$50.01-$60.00 4,265,109 8.84 59.39 3,159,481 59.47
$60.01-$70.00 621,467 9.03 67.32 393,240 67.28
- -------------------------------------------------------------------------------------------------------------------
Total 15,886,990 10,491,184
- -------------------------------------------------------------------------------------------------------------------
Exelon common stock awards under Exelon's LTIP of 316,025 shares were
issued during 2000 and 1999. Vesting for the common stock awards is over a
period not to exceed 10 years from the grant date. Compensation cost of $14
million associated with these awards is amortized to expense over the vesting
period. The related accumulated amortization of $13 million includes
amortization expense of approximately $1 million, $5 million and $5 million
during 2002, 2001 and 2000, respectively.
Exelon common share awards of 590,074, 426,794 and 159,129 shares were
granted under Exelon's LTIP and board compensation plans during 2002, 2001 and
2000, respectively. Total accumulated compensation cost of $60 million is to be
accrued to expense over the vesting period of up to 5 years from the grant date.
The related accumulated amortization of $37 million includes amortization
expense of $20 million, $11 million and $6 million during 2002, 2001 and 2000,
respectively.
In June 2001, the Board of Directors of Exelon approved the Employee Stock
Purchase Plan (ESPP). The purpose of the ESPP is to provide employees of Exelon,
and its subsidiary companies the right to purchase shares of Exelon's common
stock at below-market prices. A total of 3,000,000 shares of Exelon's common
stock have been reserved for issuance under the ESPP. Employees' purchases are
limited to no more than 125 shares per quarter and no more than $25,000 in fair
market value in any plan year. Employees purchased 257,455 and 137,648 shares of
Exelon common stock under the ESPP in 2002 and 2001, respectively.
Fund Transfer Restrictions Under PUHCA
Under PUHCA, Exelon is precluded from borrowing or receiving any extension
of credit or indemnity from its subsidiaries and can lend, but not borrow, from
Exelon's intercompany money pool. Additionally, under PUHCA, Exelon, ComEd, PECO
and Generation can pay dividends only from retained, undistributed or current
earnings. However, the SEC order granted permission to ComEd, and to Exelon to
the extent we receive dividends from ComEd paid from ComEd additional
paid-in-capital, to pay up to $500 million in dividends out of additional
paid-in capital, although Exelon may not pay dividends out of paid-in capital
after December 31, 2002 if its ratio of common equity to total capitalization is
less than 30%. At December 31, 2002, Exelon had retained earnings of $2.0
billion, which includes ComEd retained earnings of $577 million, PECO retained
earnings of $401 million and Generation undistributed earnings of $924 million.
In 2002, Exelon recorded a reduction to shareholders' equity of $1.0 billion
related to the minimum pension liability. At December 31, 2002, Exelon's common
equity to total capitalization ratio was 32%.
116
Undistributed Earnings of Equity Method Investments
At December 31, 2002, Exelon had consolidated undistributed earnings of
equity method investments of $145 million.
18. Fair Value of Financial Assets and Liabilities
The carrying amounts and fair values of Exelon's financial assets and
liabilities as of December 31, 2002 and 2001 were as follows:
2002 2001
------------------------------ ------------------------------
Carrying Carrying
Amount Fair Value Amount Fair Value
- -------------------------------------------------------------------------------------------------------------------
Non-derivatives:
Liabilities
Long-term debt (including
amounts due within one year) $ 14,529 $ 15,950 $ 14,285 $ 14,912
Preferred Securities of Subsidiaries 595 739 613 572
Derivatives:
Fixed to floating interest rate swaps 41 41 (20) (20)
Floating to fixed interest rate swaps (114) (114) -- --
Forward starting interest rate swaps (52) (52) (1) (1)
Energy derivatives (143) (143) 78 78
- -------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents, customer accounts receivable and trust accounts
for decommissioning nuclear plants are recorded at their fair value.
As of December 31, 2002 and 2001, Exelon's carrying amounts of cash and
cash equivalents and accounts receivable are representative of fair value
because of the short-term nature of these instruments. Fair values of the trust
accounts for decommissioning nuclear plants, long-term debt and preferred
securities of subsidiaries are estimated based on quoted market prices for the
same or similar issues. The fair value of Exelon's interest rate swaps and power
purchase and sale contracts is determined using quoted exchange prices, external
dealer prices, or internal valuation models which utilize assumptions of future
energy prices and available market pricing curves.
Financial instruments that potentially subject Exelon to concentrations of
credit risk consist principally of cash equivalents and customer accounts
receivable. Exelon places its cash equivalents with high-credit quality
financial institutions. Generally, such investments are in excess of the Federal
Deposit Insurance Corporation limits. Concentrations of credit risk with respect
to customer accounts receivable are limited due to Exelon's large number of
customers and, in the case of the Energy Delivery business, their dispersion
across many industries.
Exelon has entered into fixed to floating interest rate swaps in the
aggregate amount of $485 million of fixed-rate obligations of ComEd. These swaps
have been designated as fair-value hedges, as defined in SFAS No. 133 and as
such, changes in the fair value of the swap will be recorded in earnings.
However, as long as the hedges remain effective and the underlying transaction
remains probable, changes in the fair value of the swaps will be offset by
changes in the fair value of the hedged liabilities. Any change in the fair
value of the hedges as a result of ineffectiveness would be recorded immediately
in earnings. The fair market value of these swaps was $41 million at December
31, 2002.
117
Under the terms of the SBG credit facility, SBG is required to effectively
fix the interest rate on 50% of the borrowings under the facility through its
maturity in 2007. As of December 31, 2002, Generation has entered into floating
to fixed interest rate swap agreements which have effectively fixed the interest
rate on $861 million of notional principal, or 83% of borrowings outstanding at
December 31, 2002. These swaps have been designated as cash flow hedges under
SFAS No. 133, and as such, as long as the hedge remains effective and the
underlying transaction remains probable, changes in the fair value of these
swaps will be recorded in accumulated other comprehensive income (loss) until
earnings are affected by the variability of the cash flows being hedged. The
fair market value exposure of these swaps was $92 million at December 31, 2002.
Exelon has also entered into floating to fixed interest rate swaps to
manage interest rate exposure associated with the floating rate series of
transition bonds issued to securitize PECO's stranded cost recovery. These
interest rate swaps were designated as cash flow hedges. These interest rate
swaps had an aggregate fair market value exposure of $22 million at December 31,
2002.
PECO also has interest rate swaps in place to satisfy counterparty credit
requirements in regards to the floating rate series of transition bonds which
are mirror swaps of each other. These swaps are not designated as cash flow
hedges, therefore, they are required to be marked-to-market if there is a
difference in their values. Since these swaps are offsetting each other, a
mark-to-market adjustment is not expected to occur.
During 2002, PECO entered into forward starting interest rate swaps, with
an aggregate notional amount of $200 million, in anticipation of the issuance of
debt at PECO. These interest rate swaps were designated as cash flow hedges. In
connection with bond issuances in 2002, PECO settled these forward starting
interest rate swaps resulting in a $5 million pretax loss recorded in other
comprehensive income, which is being amortized over the life of the related
debt.
During 2002 and 2001, ComEd entered into forward-starting interest rate
swaps, with an aggregate notional amount of $830 million and $250 million,
respectively, in anticipation of the issuance of debt. In connection with bond
issuances in 2002, ComEd settled forward starting interest rate swaps in the
aggregate notional amount of $450 million, resulting in a $10 million pre-tax
loss recorded as a regulatory asset, which is being amortized over the life of
the related debt in interest expense. At December 31, 2002, ComEd had $630
million of forward starting interest rate swaps outstanding. These interest rate
swaps, designated as cash flow hedges, had a fair market value exposure of $52
million at December 31, 2002. As it remained probable that the debt issuances,
the forecasted future transactions these swaps were hedging, would occur,
although the issuances had been delayed, we continued to account for these
interest rate swap transactions as hedges. In connection with ComEd's January
22, 2003 issuance of $700 million in First Mortgage Bonds, ComEd settled swaps,
in the aggregate notional amount of $550 million, for a payment of $43 million,
which will be recorded as a regulatory asset and amortized over the life of the
debt issuance.
The notional amount of derivatives does not represent amounts that are
exchanged by the parties and, thus, is not a measure of Exelon's exposure. The
amounts exchanged are calculated on the basis of the notional or contract
amounts, as well as on the other terms of the derivatives, which relate to
interest rates and the volatility of these rates.
Exelon utilizes derivatives to manage the utilization of its available
generating capacity and provision of wholesale energy to its affiliates. Exelon
also utilizes energy option contracts and energy financial swap arrangements to
limit the market price risk associated with forward energy commodity
118
contracts. Additionally, Exelon enters into certain energy-related derivatives
for trading or speculative purposes.
During 2002 and 2001, Generation recognized net losses of $6 million ($4
million, net of income taxes) and gains of $16 million ($10 million, net of
income taxes), respectively, relating to mark-to-market adjustments of certain
non-trading power purchase and sale contracts pursuant to SFAS No. 133.
Mark-to-market adjustments on non-trading power purchase and sale contracts are
reported in fuel and purchased power and mark-to-market adjustments on trading
activities are reported as Operating Revenues in the Consolidated Statements of
Income. During 2002 and 2001, Generation recognized net losses aggregating $9
million ($6 million, net of income taxes) and net gains aggregating $14 million
($10 million, net of income taxes), respectively, relating to mark-to-market
adjustments on derivative instruments entered into for trading purposes. Exelon
Generation commenced financial trading in the second quarter of 2001. Gains and
losses associated with financial trading are reported as Operating Revenue in
the Consolidated Statements of Income. During 2002 and 2001, no amounts were
reclassified from accumulated other comprehensive income into earnings as a
result of forecasted energy commodity transactions no longer being probable. For
2002, no amounts were reclassified from accumulated other comprehensive income
into earnings as a result of forecasted financing transactions no longer being
probable. For 2001, a $6 million gain ($4 million, net of income taxes) was
reclassified from accumulated other comprehensive income into earnings as a
result of forecasted financing transactions no longer being probable.
Enterprises has entered into a limited number of energy commodity
derivative contracts in connection with its service of gas customers. While the
majority of these contracts qualify as normal purchases and sales or as cash
flow hedges under SFAS No. 133, $16 million was recorded as a reduction to fuel
expense as a result of contracts being marked to market in 2002. Of this $16
million, $3 million was recorded upon contract settlement and $13 million was
recorded as a change in fair value prior to contract settlement. The offset to
this $13 million was recorded as an asset on the balance sheet and it is
expected that $11 million and $2 million will reverse as fuel expense in 2003
and 2004, respectively. At December 31, 2002, there was a net asset of $20
million on the balance sheet related to Enterprises' mark-to-market contracts.
The remaining $7 million of the offset to this asset was recorded in other
comprehensive income and is expected to be reclassified to earnings within the
next twelve months. Enterprises' counterparties in these contracts are all
investment grade, with the exception of Dynegy Inc. (Dynegy), to whom
Enterprises has $2 million of exposure.
On January 1, 2001, Exelon recognized a non-cash gain of $12 million, net
of income taxes, in earnings and deferred a non-cash gain of $44 million, net of
income taxes, in accumulated other comprehensive income, a component of
shareholders' equity, to reflect the initial adoption of SFAS No. 133, as
amended. SFAS No. 133 must be applied to all derivative instruments and requires
that such instruments be recorded in the balance sheet either as an asset or a
liability measured at their fair value through earnings, with special accounting
permitted for certain qualifying hedges.
As of December 31, 2002, $102 million of deferred net losses on derivative
instruments in accumulated other comprehensive income are expected to be
reclassified to earnings during the next twelve months. Amounts in accumulated
other comprehensive income related to interest rate cash flows are reclassified
into earnings when the forecasted interest payment occurs. Amounts in
accumulated other comprehensive income related to energy commodity cash flows
are reclassified into earnings when the forecasted purchase or sale of the
energy commodity occurs. The majority of Exelon's cash flow hedges are expected
to settle within the next 4 years.
Exelon would be exposed to credit-related losses in the event of
non-performance by the counterparties that issued the derivative instruments.
The credit exposure of derivatives contracts is
119
represented by the fair value of contracts at the reporting date. Exelon's
interest rate swaps are documented under master agreements. Among other things,
these agreements provide for a maximum credit exposure for both parties.
Payments are required by the appropriate party when the maximum limit is
reached. Generation has entered into payment netting agreements or enabling
agreements that allow for payment netting with the majority of its large
counterparties, which reduce Generation's exposure to counterparty risk by
providing for the offset of amounts payable to the counterparty against amounts
receivable from the counterparty.
Exelon classifies investments in the trust accounts for decommissioning
nuclear plants as available-for-sale. The following tables show the fair values,
gross unrealized gains and losses and amortized costs bases for the securities
held in these trust accounts.
December 31, 2002
-------------------------------------------------------------------
Gross Gross
Amortized Unrealized Unrealized Estimated
Cost Gains Losses Fair Value
- -------------------------------------------------------------------------------------------------------------------
Equity securities $ 1,763 $ 72 $ (482) $ 1,353
Debt securities
Government obligations 938 62 -- 1,000
Other debt securities 698 32 (30) 700
- -------------------------------------------------------------------------------------------------------------------
Total debt securities 1,636 94 (30) 1,700
- -------------------------------------------------------------------------------------------------------------------
Total available-for-sale securities $ 3,399 $ 166 $ (512) $ 3,053
- -------------------------------------------------------------------------------------------------------------------
December 31, 2001
-------------------------------------------------------------------
Gross Gross
Amortized Unrealized Unrealized Estimated
Cost Gains Losses Fair Value
- -------------------------------------------------------------------------------------------------------------------
Equity securities $ 1,666 $ 130 $ (236) $ 1,560
Debt securities
Government obligations 882 28 (3) 907
Other debt securities 701 16 (19) 698
- -------------------------------------------------------------------------------------------------------------------
Total debt securities 1,583 44 (22) 1,605
- -------------------------------------------------------------------------------------------------------------------
Total available-for-sale securities $ 3,249 $ 174 $ (258) $ 3,165
- -------------------------------------------------------------------------------------------------------------------
Net unrealized losses of $346 million and $84 million were recognized in
Accumulated Depreciation, Regulatory Assets and Accumulated Other Comprehensive
Income in Exelon's Consolidated Balance Sheets at December 31, 2002 and 2001,
respectively.
For the Years Ended December 31
-------------------------------
2002 2001
- --------------------------------------------------------------------------------
Proceeds from sales $ 1,612 $ 1,624
Gross realized gains 56 76
Gross realized losses (86) (189)
- --------------------------------------------------------------------------------
Net realized gains of $2 million and $14 million were recognized in
Accumulated Depreciation and Regulatory Assets in Exelon's Consolidated Balance
Sheets at December 31, 2002 and 2001, respectively, and $32 million and $127
million of net realized losses were recognized in Other Income and Deductions in
Exelon's Consolidated Income Statements for 2002 and 2001, respectively. The
available-for-sale securities held at December 31, 2002 have an average maturity
of six to seven years. The cost of these securities was determined on the basis
of specific identification. See Note 11 - Nuclear
120
Decommissioning and Spent Fuel Storage for further information regarding the
nuclear decommissioning trusts.
19. Commitments and Contingencies
Capital Commitments
Exelon and British Energy, Generation's joint venture partner in AmerGen,
have each agreed to provide up to $100 million to AmerGen at any time that the
Management Committee of AmerGen determines, that in order to protect the public
health and safety and/or to comply with NRC requirements, such funds are
necessary to meet ongoing operating expenses or to safely maintain any AmerGen
plant. Although Exelon does not anticipate that AmerGen will make any
acquisitions in 2003, Exelon has committed to provide AmerGen with capital
contributions equivalent to 50% of the purchase price of any acquisitions
AmerGen makes in 2003.
Generation has a 70% interest in the Southeast Chicago Energy Project, LLC
(Southeast Chicago), which owns a peaking facility in Chicago. Southeast Chicago
is obligated to make equity distributions of $54 million over the next 20 years
to the party, which is not affiliated with Generation, that owns the remaining
30% interest. This amount reflects a return of that party's investment in
Southeast Chicago. Generation has the right to purchase, generally at a premium,
and the other party has the right to require Generation to purchase, generally
at a discount, the 30% interest in Southeast Chicago. Additionally, Generation
may be required to purchase the 30% interest upon the occurrence of certain
events, including Generation's failure to maintain an investment grade rating.
Nuclear Insurance
The Price-Anderson Act limits the liability of nuclear reactor owners for
claims that could arise from a single incident. As of January 1, 2003, the
current limit is $9.5 billion and is subject to change to account for the
effects of inflation and changes in the number of licensed reactors. Through its
subsidiaries, Exelon carries the maximum available commercial insurance of $300
million and the remaining $9.2 billion is provided through mandatory
participation in a financial protection pool. Under the Price-Anderson Act, all
nuclear reactor licensees can be assessed up to $89 million per reactor per
incident, payable at no more than $10 million per reactor per incident per year.
This assessment is subject to inflation and state premium taxes. In addition,
the U.S. Congress could impose revenue-raising measures on the nuclear industry
to pay claims. The Price-Anderson Act expired on August 1, 2002 but existing
facilities, including those owned and operated by Generation, remain covered.
The U.S. Congress has extended the provisions of the Price-Anderson Act related
to commercial facilities through 2003. The extension was passed as part of the
Consolidated Appropriations Resolution, 2003, which will be presented to the
President of the United States for his signature. The extension would affect
facilities obtaining NRC operating licenses in 2003. Existing facilities are
unaffected by the extension.
Exelon carries property damage, decontamination and premature
decommissioning insurance for each station loss resulting from damage to its
nuclear plants. In the event of an accident, insurance proceeds must first be
used for reactor stabilization and site decontamination. If the decision is made
to decommission the facility, a portion of the insurance proceeds will be
allocated to a fund, which Exelon is required by the NRC to maintain, to provide
for decommissioning the facility. Exelon is unable to predict the timing of the
availability of insurance proceeds to Exelon and the amount of such proceeds
that would be available. Under the terms of the various insurance agreements,
Exelon could be assessed up to $124 million for losses incurred at any plant
insured by the insurance companies. In the event that one or more acts of
terrorism cause accidental property damage within a twelve month period from the
first accidental property damage under one or more policies for all insureds,
the maximum recovery for all losses by all insureds will be an aggregate of $3.2
billion plus such additional amounts as the insurer may recover for all such
losses from reinsurance, indemnity, and any other source, applicable to such
losses. The $3.2 billion maximum recovery limit is not applicable, however, in
the event of a "certified act of terrorism" as defined in the Terrorism Risk
Insurance Act of 2002, as a result of government indemnity. Generally, a
"certified act of terrorism" is defined in the Terrorism Risk Insurance Act to
be any act, certified by the U.S. government, to be an act of terrorism
committed on behalf of a foreign person or interest.
Additionally, through its subsidiaries, Exelon is a member of an industry
mutual insurance company that provides replacement power cost insurance in the
event of a major accidental outage at a nuclear station. The premium for this
coverage is subject to assessment for adverse loss experience.
121
Exelon's maximum share of any assessment is $46 million per year. Recovery under
this insurance for terrorist acts is subject to the $3.2 billion aggregate limit
and secondary to the property insurance described above. This limit would also
not apply in cases of certified acts of terrorism under the Terrorism Risk
Insurance Act as described above.
In addition, Exelon participates in the American Nuclear Insurers Master
Worker Program, which provides coverage for worker tort claims filed for bodily
injury caused by a nuclear energy accident. This program was modified, effective
January 1, 1998, to provide coverage to all workers whose "nuclear-related
employment" began on or after the commencement date of reactor operations.
Exelon will not be liable for a retrospective assessment under this new policy.
However, in the event losses incurred under the small number of policies in the
old program exceed accumulated reserves, a maximum retroactive assessment of up
to $50 million could apply.
Exelon is self-insured to the extent that any losses may exceed the amount
of insurance maintained. Such losses could have a material adverse effect on
Exelon's financial condition and results of operations.
Energy Commitments
Exelon's wholesale operations include the physical delivery and marketing
of power obtained through its generation capacity, and long, intermediate and
short-term contracts. Exelon maintains a net positive supply of energy and
capacity, through ownership of generation assets and power purchase and lease
agreements, to protect it from the potential operational failure of one of its
owned or contracted power generating units. Exelon has also contracted for
access to additional generation through bilateral long-term power purchase
agreements. These agreements are firm commitments related to power generation of
specific generation plants and/or are dispatchable in nature. Exelon enters into
power purchase agreements with the objective of obtaining low-cost energy supply
sources to meet its physical delivery obligations to its customers. Exelon has
also purchased firm transmission rights to ensure that it has reliable
transmission capacity to physically move its power supplies to meet customer
delivery needs. The primary intent and business objective for the use of its
capital assets and contracts is to provide Exelon with physical power supply to
enable it to deliver energy to meet customer needs. Exelon primarily uses
financial contracts in its wholesale marketing activities for hedging purposes.
Exelon also uses financial contracts to manage the risk surrounding trading for
profit activities.
Exelon has entered into bilateral long-term contractual obligations for
sales of energy to load-serving entities, including electric utilities,
municipalities, electric cooperatives, and retail load aggregators. Exelon also
enters into contractual obligations to deliver energy to wholesale market
participants who primarily focus on the resale of energy products for delivery.
Exelon provides delivery of its energy to these customers through access to its
transmission assets or rights for firm transmission.
Generation has power purchase agreements (PPAs) with Midwest Generation,
LLC (Midwest Generation) for the purchase of capacity from its coal-fired
stations through 2004. Contracted capacity and capacity available through the
exercise of an annual option are 1,696 MWs and 3,949 MWs in 2003 and 2004,
respectively.
The agreements also provide for the option to purchase 1,084 MWs of oil and
gas-fired capacity, and 857 MWs of peaking capacity, subject to reduction.
Generation has entered into PPAs with AmerGen, under which it will purchase
all the energy from Unit No. 1 at Three Mile Island Nuclear Station after
December 31, 2001 through December 31, 2014. Under a January 1, 2003 PPA,
Generation will purchase from AmerGen all of the residual energy from the
Clinton Nuclear Power Station (Clinton), through December 31, 2003. Currently,
the residual output is approximately 31% of the total output of Clinton. In
accordance with the terms of the AmerGen partnership agreement, the 2003 PPA
will be extended through the end of the AmerGen partnership agreement in 2006.
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Exelon has a long-term supply agreement through December 2022 with
Distrigas of Massachusetts, LLC to guarantee physical gas supply to its New
England generating units. Under the agreement, prices are indexed to New England
gas markets. At December 31, 2002, Exelon had long-term commitments, relating to
the purchase and sale of energy, capacity and transmission rights from
unaffiliated utilities and others, including the Midwest Generation and AmerGen
contracts, as expressed in the following tables:
Net Capacity Power Only Power Only Purchases from Transmission Rights
Purchases (1) Sales AmerGen Non-Affiliates Purchases (2)
- -------------------------------------------------------------------------------------------------------------------
2003 $ 589 $ 2,606 $ 280 $ 1,722 $ 86
2004 639 1,181 292 768 93
2005 356 355 472 283 84
2006 328 92 472 239 3
2007 408 22 179 227 --
Thereafter 3,742 1 2,638 829 --
- -------------------------------------------------------------------------------------------------------------------
Total $ 6,062 $ 4,257 $ 4,333 $ 4,068 $ 266
- -------------------------------------------------------------------------------------------------------------------
(1) On October 2, 2002, Generation notified Midwest Generation of its exercise
of termination options under the existing Collins Generating Station
(Collins) and Peaking Unit (Peaking) Purchase Power Agreements. Generation
exercised its termination options on 1,727 MWs in 2003 and 2004. In 2003,
Generation will take 1,778 MWs of option capacity under the Collins and
Peaking Unit Agreements as well as 1,265 MWs of option capacity under the
Coal Generation Purchase Power Agreement. Net capacity purchases in 2004
include 3,474 MWs of optional capacity from Midwest Generation. Net
Capacity Purchases also include capacity sales to TXU under the purchase
power agreement entered into in connection with the purchase of two
generating plants in April 2002, which states that TXU will purchase the
plant output from May through September from 2002 through 2006. During the
periods covered by the power purchase agreement, TXU will make fixed
capacity payments and will provide fuel to Exelon in return for exclusive
rights to the energy and capacity of the generation plants. The combined
capacity of the two plants is 2,334 MWs.
(2) Transmission Rights Purchases include estimated commitments in 2004 and
2005 for additional transmission rights that will be required to fulfill
firm sales contracts.
123
Commercial Commitments
Exelon's commercial commitments as of December 31, 2002, representing
commitments not recorded on the balance sheet but potentially triggered by
future events, including obligations to make payment on behalf of other parties
and financing arrangements to secure our obligations, are as follows:
Expiration within
------------------------------------------------------------
2008
Total 2003 2004-2005 2006-2007 and beyond
- -------------------------------------------------------------------------------------------------------------------
Credit Facility (a) $ 1,500 $ 1,500 $ -- $ -- $ -
Letters of Credit (non-debt) (b) 111 106 5 -- --
Letters of Credit (Long-Term Debt) (c) 456 305 151 -- --
Insured Long-Term Debt (d) 254 -- -- -- 254
Guarantees of Letters of Credit(e) 226 226 -- -- --
Performance Guarantees (f) 101 -- -- -- 101
Surety Bonds (g) 521 329 57 4 131
Energy Marketing Contract
Guarantees (h) 124 114 10 -- --
Nuclear Insurance Guarantees (i) 1,380 -- -- -- 1,380
Lease Guarantees (j) 13 -- -- 2 11
Preferred Securities (k) 128 -- -- -- 128
Sithe New England Equity Guarantee (l) 38 38 -- -- --
Guarantees of Long-Term Debt (m) 41 2 -- -- 39
- -------------------------------------------------------------------------------------------------------------------
Total $ 4,893 $ 2,620 $ 223 $ 6 $ 2,044
- -------------------------------------------------------------------------------------------------------------------
(a) Credit Facility - Exelon, along with ComEd, PECO and Generation, maintain a
$1.5 billion 364-day credit facility to support commercial paper issuances.
At December 31, 2002, there were no borrowings against the credit facility.
Additionally, at December 31, 2002, there was $948 million of commercial
paper outstanding.
(b) Letters of Credit (non-debt) - Exelon and certain of its subsidiaries
maintain non-debt letters of credit to provide credit support for certain
transactions as requested by third parties.
(c) Letters of Credit (Long-Term Debt) - Direct-pay letters of credit issued in
connection with variable-rate debt in order to provide liquidity in the
event that it is not possible to remarket all of the debt as required
following specific events, including changes in the basis of determining
the interest rate on the debt.
(d) Insured Long-Term Debt - Borrowings that have been credit-enhanced through
the purchase of insurance coverage equal to the amount of principal
outstanding plus interest.
(e) Guarantees of letters of credit - Guarantees issued to provide support for
letters of credit as required by third parties. These guarantees could be
called upon only in the event of non-payment by a subsidiary.
(f) Performance Guarantees - Guarantees issued to ensure execution under
specific contracts.
(g) Surety Bonds - Guarantees issued related to contract and commercial surety
bonds, excluding bid bonds.
(h) Energy Marketing Contract Guarantees - Guarantees issued to ensure
performance under energy commodity contracts.
(i) Nuclear Insurance Guarantees - Guarantees of nuclear insurance required
under the Price-Anderson Act. $1.1 billion of this total exposure is exempt
from the $4.5 billion PUHCA guarantee limit by SEC rule.
(j) Lease Guarantees - Guarantees issued to ensure payments on building leases.
(k) Preferred Securities - Guarantees issued to guarantee the preferred
securities of the subsidiary trusts of PECO. See Note 16 - Preferred
Securities of Subsidiaries for further information.
(l) Sithe New England Equity Guarantee- See Note 3 - Acquisitions and
Dispositions for further information on the $38 million guarantee. After
construction of the SBG facilities is complete, Exelon could be required to
guarantee up to an additional $42 million in order to ensure that the SBG
facilities have adequate funds available for potential outage and other
operating costs and requirements.
(m) Guarantees of Long-Term Debt - Issued to guarantee payment of subsidiary
debt.
Unconsolidated Equity Investments. Generation is a 49.9% owner of Sithe and
accounts for the investment as an unconsolidated equity investment. The Sithe
New England purchase did not affect the accounting for Sithe as an equity
investment. Separate from the Sithe New England transaction, Generation is
subject to a Put and Call Agreement (PCA) that gives Generation the right to
purchase (Call) the remaining 50.1% of Sithe, and gives the other Sithe
shareholders the right to sell (Put) their interest to Generation. If the Put
option is exercised, Generation has the obligation to complete the purchase.
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The PCA originally provided that the Put and Call options became
exercisable as of December 18, 2002 and expired in December 2005. However, upon
Apollo Energy, LLC's (Apollo) purchase of Vivendi's 34.2% ownership and Sithe
management's 1% share, Apollo agreed to delay the effective date of its Put
right until June 1, 2003 and, if certain conditions are met, until September 1,
2003. There are also certain events that could trigger Apollo's Put right
becoming effective prior to June 1, 2003 including Exelon being downgraded below
investment grade by Standard and Poor's Rating Group or Moody's Investors
Service, Inc., a stock purchase agreement between Exelon and Apollo being
executed and subsequently terminated, or the occurence of any event of default,
other than a change of control, under certain Exelon or Apollo credit
agreements. Depending on the triggering event, Apollo's put price of
approximately $460 million, growing at a market rate of interest, needs to be
funded within 18 or 30 days of the Put being exercised. There have been no
changes to the Put and Call terms with respect to Marubeni's remaining 14.9%
interest.
The delay in the effective date of Apollo's Put right allows Exelon to
explore a further restructuring of our investment in Sithe. Exelon is continuing
discussions with Apollo and Marubeni regarding restructuring alternatives that
are designed in part to resolve Exelon's ownership limitations of Sithe's
qualifying facilities. Exelon would hope to implement any additional
restructuring of its Sithe investment in 2003. If Exelon is unsuccessful in
restructuring the Sithe transaction, Exelon will proceed to implement measures
to address the ownership of the qualified facilities as well as divest
non-strategic assets, for which the financial outcome is uncertain.
If Generation exercises its option to acquire the remaining outstanding
common stock in Sithe, or if all the other stockholders exercise their Put
Rights, the purchase price for Apollo's 35.2% interest will be approximately
$460 million, growing at a market rate of interest. The additional 14.9%
interest will be valued at fair market value subject to a floor of $141 million
and a ceiling of $290 million.
If Generation increases its ownership in Sithe to 50.1% or more, Sithe may
become a consolidated subsidiary and our financial results may include Sithe's
financial results from the date of purchase. At December 31, 2002, Sithe had
total assets of $2.6 billion and total debt of $1.3 billion. This $1.3 billion
includes $624 million of subsidiary debt incurred primarily to finance the
construction of six new generating facilities, $461 million of subordinated
debt, $103 million of line of credit borrowings, $43 million of the current
portion of long-term debt and capital leases, $30 million of capital leases, and
excludes $453 million of non-recourse project debt associated with Sithe's
equity investments. For the year ended December 31, 2002, Sithe had revenues of
$1.0 billion. As of December 31, 2002, Generation had a $449 million equity
investment in Sithe.
Environmental Issues
Exelon's operations have in the past and may in the future require
substantial capital expenditures in order to comply with environmental laws.
Additionally, under Federal and state environmental laws, Exelon, through its
subsidiaries, is generally liable for the costs of remediating environmental
contamination of property now or formerly owned by Exelon and of property
contaminated by hazardous substances generated by Exelon. Exelon owns or leases
a number of real estate parcels, including parcels on which its operations or
the operations of others may have resulted in contamination by substances that
are considered hazardous under environmental laws. Exelon has identified 71
sites where former manufactured gas plant (MGP) activities have or may have
resulted in actual site contamination. Exelon is currently involved in a number
of proceedings relating to sites where hazardous substances have been deposited
and may be subject to additional proceedings in the future.
As of December 31, 2002 and 2001, Exelon had accrued $156 million for
environmental investigation and remediation costs, including $125 million and
$127 million, respectively, for MGP investigation and remediation that currently
can be reasonably estimated. Included in the environmental investigation and
remediation cost obligation as of December 31, 2002 and 2001 is $97 million and
$100 million, respectively, that has been recorded on a discount basis
(reflecting discount rates of 5.0% and 5.5%, respectively). Such estimates,
reflecting the effects of a 2.5% and 3.0% inflation rate before the effects of
discounting were $138 million and $154 million at December 31, 2002 and 2001,
respectively.
125
Exelon anticipates that payments related to the discounted environmental
investigation and remediation costs, recorded on an undiscounted basis, of $76
million will be incurred for the five-year period through 2007. Exelon cannot
reasonably estimate whether it will incur other significant liabilities for
additional investigation and remediation costs at these or additional sites
identified by Exelon, environmental agencies or others, or whether such costs
will be recoverable from third parties.
Leases
Minimum future operating lease payments, including lease payments for
vehicles, real estate, computers, rail cars and office equipment, as of December
31, 2002 were:
- ---------------------------------------------------------------------------
2003 $ 77
2004 59
2005 58
2006 54
2007 49
Remaining years 598
- ---------------------------------------------------------------------------
Total minimum future lease payments $ 895
- ---------------------------------------------------------------------------
Rental expense under operating leases totaled $85 million, $75 million and
$41 million in 2002, 2001 and 2000, respectively.
Litigation
Securities Litigation. Between May 8 and June 14, 2002, several class
action lawsuits were filed in the Federal District Court in Chicago asserting
nearly identical securities law claims on behalf of purchasers of Exelon
securities between April 24, 2001 and September 27, 2001 (Class Period). The
complaints allege that Exelon violated Federal securities laws by issuing a
series of materially false and misleading statements relating to its 2001
earnings expectations during the Class Period. The court consolidated the
pending cases into one lawsuit and has appointed two lead plaintiffs as well as
lead counsel.
On October 1, 2002, the plaintiffs filed a consolidated amended complaint.
In addition to the original claims, this complaint contains allegations of new
facts and contains several new theories of liability. Exelon believes the
lawsuit is without merit and is vigorously contesting this matter.
FERC Municipal Request for Refund. Three of ComEd's wholesale municipal
customers filed a complaint and request for refund with FERC, alleging that
ComEd failed to properly adjust its rates, as provided for under the terms of
the electric service contracts with the municipal customers and to track certain
refunds made to ComEd's retail customers in the years 1992 through 1994. In the
third quarter of 1998, FERC granted the complaint and directed that refunds be
made, with interest. On April 30, 2001, FERC issued an order granting rehearing
in which it determined that its 1998 order had been erroneous and that no
refunds were due from ComEd to the municipal customers. In August 2001, each of
the three wholesale municipal customers appealed the April 30, 2001 FERC order
to the Federal circuit court, which consolidated the appeals for the purposes of
briefing and decision. The Federal circuit court has stayed the proceedings
pending settlement negotiations among the parties.
Retail Rate Law. In 1996, several developers of non-utility generating
facilities filed litigation against various Illinois officials claiming that the
enforcement against those facilities of an amendment to Illinois law removing
the entitlement of those facilities to state-subsidized payments for electricity
sold to ComEd after March 15, 1996 violated their rights under the Federal and
state constitutions. The developers also filed suit against ComEd for a
declaratory judgment that their rights under their contracts with ComEd were not
affected by the amendment. On November 25, 2002, the court granted developers'
126
motions for summary judgment. The judge also entered a permanent injunction
enjoining ComEd from refusing to pay the retail rate on the grounds of the
amendment, and Illinois from denying ComEd a tax credit on account of such
purchases. ComEd and Illinois have each appealed the ruling. ComEd believes that
it did not breach the contracts in question and that the damages claimed far
exceed any loss that any project incurred by reason of its ineligibility for the
subsidized rate. ComEd intends to prosecute its appeal and defend each case
vigorously.
Cotter Corporation Litigation. During 1989 and 1991, actions were brought
in Federal and state courts in Colorado against ComEd and its subsidiary, Cotter
Corporation (Cotter), seeking unspecified damages and injunctive relief based on
allegations that Cotter permitted radioactive and other hazardous material to be
released from its mill into areas owned or occupied by the plaintiffs, resulting
in property damage and potential adverse health effects. In 1994, a Federal jury
returned nominal dollar verdicts against Cotter on eight plaintiffs' claims in
the 1989 cases, which verdicts were upheld on appeal. The remaining claims in
the 1989 actions were settled or dismissed. In 1998, a jury verdict was rendered
against Cotter in favor of 14 of the plaintiffs in the 1991 cases, totaling
approximately $6 million in compensatory and punitive damages, interest and
medical monitoring. On appeal, the Tenth Circuit Court of Appeals reversed the
jury verdict, and remanded the case for new trial. These plaintiffs' cases were
consolidated with the remaining 26 plaintiffs' cases, which had not been tried.
The consolidated trial was completed on June 28, 2001. The jury returned a
verdict against Cotter and awarded $16 million in various damages. On November
20, 2001, the District Court entered an amended final judgment that included an
award of both pre-judgment and post-judgment interests, costs, and medical
monitoring expenses that total $43 million. In November 2000, another trial
involving a separate sub-group of 13 plaintiffs, seeking $19 million in damages
plus interest was completed in Federal District Court in Denver. The jury
awarded nominal damages of $42,500 to 11 of 13 plaintiffs, but awarded no
damages for any personal injury or health claims, other than requiring Cotter to
perform periodic medical monitoring at minimal cost. Cotter appealed these
judgments to the Tenth Circuit Court of Appeals. Cotter is vigorously contesting
the award.
On February 18, 2000, ComEd sold Cotter to an unaffiliated third party. As
part of the sale, ComEd agreed to indemnify Cotter for any liability incurred by
Cotter as a result of these actions, as well as any liability arising in
connection with the West Lake Landfill discussed in the next paragraph. In
connection with Exelon's 2001 corporate restructuring, the responsibility to
indemnify Cotter for any liability related to these matters was transferred by
ComEd to Generation.
The United States Environmental Protection Agency (EPA) has advised Cotter
that it is potentially liable in connection with radiological contamination at a
site known as the West Lake Landfill in Missouri. Cotter is alleged to have
disposed of approximately 39,000 tons of soils mixed with 8,700 tons of leached
barium sulfate at the site. Cotter, along with three other companies identified
by the EPA as potentially responsible parties (PRPs), has submitted a draft
feasibility study addressing options for remediation of the site. The PRPs are
also engaged in discussions with the State of Missouri and the EPA. The
estimated costs of remediation for the site range from $0 million to $87
million. Once a remedy is selected, it is expected that the PRPs will agree on
an allocation of responsibility for the costs. Until an agreement is reached,
Generation cannot predict its share of the costs.
Raytheon Arbitration. In March 2001, two subsidiaries of Sithe New England
Holdings (now Exelon New England Holdings) brought an action in the New York
Supreme Court against Raytheon Corporation (Raytheon) relating to its failure to
honor its guaranty with respect to the performance of the Mystic and Fore River
projects, as a result of the abandonment of the projects by the turnkey
contractor. In a related proceeding, in May 2002, Raytheon submitted claims to
the International Chamber of Commerce Court of Arbitration seeking equitable
relief and damages for alleged owner caused performance delays in connection
with the Fore River Power Plant Engineering, Procurement & Construction
Agreement (EPC Agreement). The EPC Agreement, executed by a Raytheon subsidiary
and guaranteed by Raytheon, governs the design, engineering, construction,
start-up, testing and delivery of
127
an 800-MW combined-cycle power plant in Weymouth, Massachusetts. Raytheon
recently amended its claim and now seeks 141 days of schedule relief (which
would reduce Raytheon's liquidated damage payment for late delivery by
approximately $25.4 million) and additional damages of $15.6 million. Raytheon
also has asserted a claim for loss of efficiency and productivity as a result of
an alleged constructive acceleration, for which a claim has not yet been
quantified. Generation believes the Raytheon assertions are without merit and is
vigorously contesting these claims. Hearings by the International Chamber of
Commerce Court of Arbitration with respect to liability were held in January and
February 2003. A decision on liability is expected to be issued in May 2003 and,
if necessary, additional hearings will be held on damages in May and June of
2003.
Real Estate Tax Appeals. Generation is involved in tax appeals regarding a
number of its nuclear facilities, Limerick Generating Station (Montgomery
County, PA), Peach Bottom Atomic Power Station (York County, PA), and Quad
Cities Station (Rock Island County, IL). Generation is also involved in the tax
appeal for Three Mile Island (Dauphin County, PA) through AmerGen. Generation
does not believe the outcome of these matters will have a material adverse
effect on Generation's results of operations or financial condition.
General. Exelon is involved in various other litigation matters. The
ultimate outcome of such matters, as well as the matters discussed above, while
uncertain, are not expected to have a material adverse effect on its respective
financial condition or results of operations.
Credit Contingencies
Generation is a counterparty to Dynegy in various energy transactions. In
early July 2002, the credit ratings of Dynegy were downgraded by two credit
rating agencies to below investment grade. As of December 31, 2002, Generation
had a net receivable from Dynegy of approximately $3 million, and consistent
with the terms of the existing credit arrangement, has received collateral in
support of this receivable. Generation also has credit risk associated with
Dynegy through Generation's equity investment in Sithe. Sithe is a 60% owner of
the Independence generating station, a 1,040-MW gas-fired qualified facility
that has an energy-only long-term tolling agreement with Dynegy, with a related
financial swap arrangement. As of December 31, 2002, Sithe had recognized an
asset on its balance sheet related to the fair market value of the financial
swap agreement with Dynegy that is marked-to-market under the terms of SFAS No.
133. If Dynegy is unable to fulfill the terms of this agreement, Sithe would be
required to impair this financial swap asset. We estimate, as a 49.9% owner of
Sithe, that the impairment would result in an after-tax reduction of our equity
earnings of approximately $10 million.
In addition to the impairment of the financial swap asset, if Dynegy was
unable to fulfill its obligations under the financial swap agreement and the
tolling agreement, we would likely incur a further impairment associated with
the Independence plant. Depending upon the timing of Dynegy's failure to fulfill
its obligations and the outcome of any restructuring initiatives, Exelon could
realize an after-tax charge of between $0 and $130 million. In the event of a
sale of our investment in Sithe to a third party, proceeds from the sale could
be negatively impacted by approximately $120 million, which would represent an
after-tax loss of approximately $65 million.
Additionally, the future economic value of AmerGen's purchased power
arrangement with Illinois Power, a subsidiary of Dynegy, could be impacted by
events related to Dynegy's financial condition.
128
20. Segment Information
Exelon evaluates the performance of its business segments based on Net
Income.
Energy Delivery consists of the retail electricity distribution and
transmission businesses of ComEd in northern Illinois and PECO in southeastern
Pennsylvania and the natural gas distribution business of PECO located in the
Pennsylvania counties surrounding the City of Philadelphia. Generation consists
of electric generating facilities, energy marketing operations and Exelon's
interests in Sithe and AmerGen. Enterprises consists of competitive retail
energy sales, energy and infrastructure services, communications and other
investments weighted towards the communications, energy services and retail
services industries. An analysis and reconciliation of Exelon's business segment
information to the respective information in the consolidated financial
statements are as follows:
Energy Intersegment
Delivery Generation Enterprises Corporate Eliminations Consolidated
- -------------------------------------------------------------------------------------------------------------------
Total Revenues:
2002 $ 10,457 $ 6,858 $ 2,033 $ 346 $ (4,739) $ 14,955
2001 10,171 6,826 2,292 341 (4,712) 14,918
2000 4,511 3,274 1,395 -- (1,681) 7,499
Intersegment Revenues:
2002 $ 76 $ 4,226 $ 97 $ 341 $ (4,740) $ --
2001 94 4,102 179 337 (4,712) --
2000 24 1,185 472 -- (1,681) --
Depreciation and Amortization:
2002 $ 978 $ 276 $ 55 $ 31 $ -- $ 1,340
2001 1,081 282 69 17 -- 1,449
2000 297 123 35 3 -- 458
Operating Expenses:
2002 $ 7,597 $ 6,349 $ 2,047 $ 402 $ (4,739) $ 11,656
2001 7,578 5,954 2,369 371 (4,716) 11,556
2000 (a) 3,009 2,833 1,473 324 (1,667) 5,972
Interest Expense:
2002 $ 854 $ 75 $ 14 $ 74 $ (51) $ 966
2001 973 115 37 133 (151) 1,107
2000 522 41 17 63 (29) 614
Income Taxes:
2002 $ 765 $ 217 $ 69 $ (53) $ -- $ 998
2001 703 327 (43) (56) -- 931
2000 421 160 (52) (190) -- 339
Net Income/(Loss):
2002 $ 1,268 $ 400 $ (178) $ (50) $ -- $ 1,440
2001 1,022 524 (85) (33) -- 1,428
2000 (a) 587 260 (94) (167) -- 586
Capital Expenditures:
2002 $ 1,041 $ 990 $ 44 $ 75 $ -- $ 2,150
2001 1,105 858 61 64 -- 2,088
2000 367 288 70 27 -- 752
Total Assets:
2002 $ 26,550 $ 11,007 $ 1,297 $ (1,376) $ -- $ 37,478
2001 26,365 8,145 1,743 (1,509) -- 34,744
- -------------------------------------------------------------------------------------------------------------------
(a) Includes non-recurring items of $276 million ($177 million after income
taxes) for Merger-related expenses in 2000.
129
Equity in earnings of AmerGen and Sithe of $88 million, $90 million and $4
million for 2002, 2001 and 2000, respectively, are included in Generation's Net
Income. Equity in earnings (losses) of communications joint ventures and other
investments of $3 million, $(19) million and $(45) million for 2002, 2001 and
2000, respectively, are included in Enterprises' Net Income. Equity in earnings
(losses) of affordable housing investments of $(11) million and $(9) million for
2002 and 2001, respectively, are included in Corporate's Net Income.
21. Related Party Transactions
Exelon's financial statements reflect related-party transactions with
unconsolidated affiliates as reflected in the tables below.
For the Years Ended December 31,
-----------------------------------------
2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
Purchased Power from AmerGen (1) $ 273 $ 57 $ 52
Interest Income from AmerGen (2) 2 -- --
Interest Income from Sithe (3) -- 2 --
Interest Expense to Sithe (4) 2 -- --
Services Provided to AmerGen (5) 70 80 32
Services Provided to Sithe (6) 1 -- --
Services Provided by Sithe (7) 13 -- --
- ------------------------------------------------------------------------------------------------------------------
130
December 31,
-----------------------------------
2002 2001
- --------------------------------------------------------------------------------
Net Receivable from AmerGen (1,2,3) $ 39 $ 44
Net Payable to Sithe (4,5) 7 --
Note Payable to Sithe (7) 534 --
- --------------------------------------------------------------------------------
(1) Generation has entered into PPAs dated December 18, 2001 and November 22,
1999 with AmerGen. Under the 2001 PPA, Generation has agreed to purchase
from AmerGen all the energy from Unit No. 1 at Three Mile Island Nuclear
Station from January 1, 2002 through December 31, 2014. Under the 1999 PPA,
Generation agreed to purchase from AmerGen all of the residual energy from
Clinton Nuclear Power Station (Clinton) through December 31, 2002.
Currently, the residual output is approximately 31% of the total output of
Clinton. In accordance with the terms of the AmerGen partnership agreement,
the 1999 PPA will be extended through the end of the AmerGen partnership
agreement in 2006.
(2) In February 2002, Generation entered into an agreement to loan AmerGen up
to $75 million at an interest rate equal to the 1-month London Interbank
Offering Rate plus 2.25%. In July 2002, the limit of the loan agreement was
increased to $100 million and the maturity date was extended to July 1,
2003. As of December 31 2002, the outstanding principal balance of the loan
was $35 million.
(3) In August 2001, Exelon loaned Sithe, an equity method investee of
Generation, $150 million. The note, which bore interest at the eurodollar
rate, plus 2.25%, was repaid in December 2001 with the proceeds of bank
borrowings. In connection with the bank borrowings, Exelon provided the
lenders with a support letter confirming its investment in Sithe and
Exelon's agreement to maintain a positive net worth of Sithe.
(4) Under the terms of the agreement to acquire Sithe New England dated
November 1, 2002, Generation issued a $534 million note to be paid in full
on June 18, 2003 to Sithe. The note bears interest at the rate equal to
LIBOR plus 0.875%. Interest accrued on the note as of December 31, 2002 was
$2 million.
(5) Under a service agreement dated March 1, 1999, Generation provides AmerGen
with certain operation and support services to the nuclear facilities owned
by AmerGen. This service agreement has an indefinite term and may be
terminated by Generation or AmerGen with 90 days notice. Generation is
compensated for these services in an amount agreed to in the work order,
which is not less than the higher of its fully allocated cost for
performing each service or the market price for such service.
(6) Under a service agreement dated December 18, 2000, Generation provides
certain engineering and environmental services for fossil facilities owned
by Sithe and for certain developmental projects. Generation is compensated
for these services in an amount agreed to in the work order, but not less
than the higher of fully allocated costs for performing such services or
the market price.
(7) Under a service agreement dated December 18, 2000, Sithe provides
Generation certain fuel and project development services. Sithe is
compensated for these services in the amount agreed to in the work order,
but not less than the higher of fully allocated costs for performing such
services or the market price.
22. Quarterly Data (Unaudited)
The data shown below include all reclassifications, including those
required upon the adoption of EITF 02-3, which Exelon considers necessary for a
fair presentation of such amounts:
Income Before the
Cumulative Effect of Changes
Operating Revenues Operating Income in Accounting Principles Net Income
------------------ ---------------- ------------------------ --------------
2002 2001 2002 2001 2002 2001 2002 2001
- -------------------------------------------------------------------------------------------------------------------
Quarter ended:
March 31 $ 3,357 $ 3,823 $ 605 $ 889 $ 238 $ 387 $ 8 $ 399
June 30 3,519 3,616 813 792 485 315 485 315
September 30 4,370 4,185 1,000 912 551 376 551 376
December 31 3,709 3,293 882 769 397 338 397 338
- -------------------------------------------------------------------------------------------------------------------
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Earnings per Basic Share
Average Shares Before the Cumulative Earnings per
Basic Outstanding Effect of Changes Basic Share
(in millions) in Accounting Principles Net Income
------------- ------------------------ --------------
2002 2001 2002 2001 2002 2001
- -------------------------------------------------------------------------------------------------------------------
Quarter ended:
March 31 321 320 $ 0.74 $ 1.21 $ 0.02 $ 1.25
June 30 322 321 1.50 0.98 1.50 0.98
September 30 323 321 1.71 1.17 1.71 1.17
December 31 323 321 1.23 1.05 1.23 1.05
- -------------------------------------------------------------------------------------------------------------------
Earnings per Diluted Share
Average Shares Before the Cumulative Earnings per
Diluted Outstanding Effect of Changes Diluted Share
(in millions) in Accounting Principles Net Income
------------- ------------------------ --------------
2002 2001 2002 2001 2002 2001
- -------------------------------------------------------------------------------------------------------------------
Quarter ended:
March 31 323 324 $ 0.73 $ 1.19 $ 0.02 $ 1.23
June 30 324 324 1.50 0.97 1.50 0.97
September 30 324 323 1.70 1.16 1.70 1.16
December 31 325 322 1.22 1.05 1.22 1.05
- -------------------------------------------------------------------------------------------------------------------
The following table presents the New York Stock Exchange - Composite Common
Stock Prices and dividends by quarter on a per share basis:
2002 2001
------------------------------------------ ------------------------------------------
Fourth Third Second First Fourth Third Second First
Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter
- -------------------------------------------------------------------------------------------------------------------
High Price $ 53.06 $ 52.83 $ 56.99 $ 53.88 $ 48.69 $ 67.65 $ 70.26 $ 69.75
Low Price 42.38 37.85 50.10 45.90 39.65 38.75 62.10 53.60
Close 52.77 47.50 52.30 52.97 47.88 44.60 64.12 65.60
Dividends 0.44 0.44 0.44 0.44 0.43 0.42 0.42 0.55 (a)
- -------------------------------------------------------------------------------------------------------------------
(a) The first quarter dividend in 2001 was a pro rata dividend. Unicom and PECO
each paid their shareholders pro rata, per diem dividends from their last
regular dividend dates through October 19, 2000. The first quarter covered
the 119-day period from the date of the Merger, through the February 15,
2001 record date.
23. Subsequent Events
On January 22, 2003, ComEd issued $350 million of 3.70% First Mortgage
Bonds, due on February 1, 2008 and $350 million of 5.875% First Mortgage Bonds,
due on February 1, 2033. These bond proceeds were used to refinance long-term
debt that had been retired during the third and fourth quarters of 2002. As part
of these bond issuances, ComEd settled various forward starting interest rate
swaps, for $43 million, which will be recorded as a regulatory asset and
amortized over the life of the debt issuance.
On January 31, 2003, ComEd called $236 million of its First Mortgage
Bonds at a redemption price of 103.86% of the principal amount, plus accrued
interest to the March 18, 2003 redemption date. The bonds, which carried an
interest rate of 8.375% and had a maturity date of February 15, 2023, are
expected to be refinanced with long-term debt.
On February 14, 2003, ComEd called $200 million of its Trust Preferred
securities at a redemption price of 100% of the principal amount, plus accrued
interest to the March 20, 2003 redemption date. The preferred securities, which
carried an interest rate of 8.48% and had a maturity date of September 30, 2035,
are expected to be refinanced with trust preferred securities.
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On February 20, 2003, ComEd entered into separate agreements with the City
of Chicago (City) and with Midwest Generation (Midwest Agreement). Under the
terms of the agreement with the City, ComEd will pay the City $60 million over
ten years and be relieved of a requirement, originally transferred to Midwest
Generation upon the sale of ComEd's fossil stations in 1999, to build a 500-MW
generation facility. Under the terms of the Midwest Agreement, ComEd will
receive from Midwest Generation $36 million over ten years, $22 million of which
was received on February 20, 2003, to relieve Midwest Generation's obligation
under the fossil sale agreement. Midwest Generation will also assume from the
City a Capacity Reservation Agreement which the City had entered into with
Calumet Energy Team, LLC (CET), that is effective through June 2012. ComEd will
reimburse the City for any nonperformance by Midwest Generation under the
Capacity Reservation Agreement and will pay approximately $2 million for amounts
owed to CET by the City at the time the agreement is executed. The net effect of
the settlement to ComEd will be amortized over the remaining life of the
franchise agreement with the City.
133