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.
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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.
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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
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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
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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,
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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
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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.
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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.
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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.
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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.
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Effective management of capital projects is important to our business.
Energy Delivery's business is capital intensive and requires
significant investments in energy transmission and distribution
facilities, and in other internal infrastructure projects.
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:
59
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.
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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.
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The following table provides detail on changes in Generation's
mark-to-market net asset or liability balance sheet position from January 1,
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