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
Exelon Corporation and Subsidiary Companies
General
On October 20, 2000, Exelon Corporation (Exelon) became the parent corporation
for each of PECO Energy Company (PECO) and Commonwealth Edison Company (ComEd)
as a result of the completion of the transactions contemplated by an Agreement
and Plan of Exchange and Merger, as amended, among PECO, Unicom Corporation
(Unicom) and Exelon (Merger). The Merger was accounted for using the purchase
method of accounting. Exelon's results of operations for 1999 and 2000 consist
of PECO's results of operations for 1999 and 2000 and Unicom's results of
operations after October 20, 2000.
During January 2001, Exelon undertook a restructuring to separate its
generation and other competitive businesses from its 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.
Exelon, through its subsidiaries, operates in three business segments:
- - Energy Delivery, consisting of the retail electricity distribution and
transmission businesses of ComEd in northern Illinois and PECO in
southeastern Pennsylvania and the natural gas distribution business of PECO
in the Pennsylvania counties surrounding the City of Philadelphia.
- - Generation, consisting of electric generating facilities, energy marketing
operations and equity interests in Sithe Energies, Inc. (Sithe) and AmerGen
Energy Company, LLC (AmerGen).
- - 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 21 of the Notes to Consolidated Financial Statements for further
segment information.
Results of Operations
Year Ended December 31, 2001 Compared To Year Ended December 31, 2000
Net Income and Earnings Per Share
Exelon's net income increased $842 million, or 144%, for 2001. Diluted earnings
per share increased $1.56 per share, or 54%. Income before extraordinary items
and cumulative effect of changes in accounting principles increased $850
million, or 150%, for 2001. Diluted earnings per share on the same basis
increased $1.62 per share, or 58%. 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.
Earnings Before Interest and Income Taxes
Exelon evaluates the performance of its business segments based on earnings
before interest and income taxes (EBIT). In addition to components of operating
income as shown on the consolidated statements of income, EBIT includes equity
in earnings (losses) of unconsolidated affiliates, and other income and expense
recorded in other, net, with the exception of investment income. Operating
revenues, operating expenses, depreciation and amortization and other income and
expenses for each business segment in the following analyses include
intercompany transactions, which are eliminated in the consolidated Exelon
financial statements.
1
The October 20, 2000 acquisition of Unicom, and the January 1, 2001
corporate restructuring, significantly impacted Exelon's results of operations.
To provide a more meaningful analysis of results of operations, the EBIT
analyses by business segment below identify the portion of the EBIT 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 as well as the effect of excluding Merger-related costs from Exelon's 2000
operations. The segment results also reflect the results as if the corporate
restructuring occurred on January 1, 2000. The 2000 pro forma effects of the
Merger and restructuring were developed using estimates of various items,
including allocation of corporate overheads to business segments and
intercompany transactions.
EBIT Contribution by Business Segment
Components of Variance
--------------------------
Merger Normal
(in millions) 2001 2000 Variance Variance Operations
- -------------------------------------------------------------------------------------------------------------
Energy Delivery $ 2,623 $ 1,503 $ 1,120 $ 1,219 $ (99)
Generation 962 440 522 22 500
Enterprises (107) (140) 33 (32) 65
Corporate (22) (328) 306 286 20
- -----------------------------------------------------------------------------------------------------------
EBIT $ 3,456 $ 1,475 $ 1,981 $ 1,495 $ 486
===========================================================================================================
Energy Delivery
Components of Variance
-------------------------
Merger Normal
(in millions) 2001 2000 Variance Variance Operations
- ------------------------------------------------------------------------------------------------------------
Operating Revenue $ 10,171 $ 4,511 $ 5,660 $ 5,168 $ 492
Operating Expense and Other 6,467 2,711 3,756 3,242 514
Depreciation & Amortization 1,081 297 784 707 77
- -----------------------------------------------------------------------------------------------------------
EBIT $ 2,623 $ 1,503 $ 1,120 $ 1,219 $ (99)
===========================================================================================================
Energy Delivery's EBIT increased $1,120 million in 2001, as compared to 2000.
The Merger accounted for $1,219 million of the variance offset by a decrease in
EBIT from normal operations of $99 million. The decrease in EBIT from normal
operations reflects increased operating and maintenance expenses and regulatory
asset amortization, partially offset by improved margins on sales due to
favorable rate changes.
Energy Delivery's operating and maintenance expenses increased due to
higher administrative and general costs as a result of increased allocation of
costs previously recorded at Corporate, and $18 million for employee severance
costs associated with the Merger, partially offset by a decrease in customer
costs. Higher purchased power costs for 2001 include charges for energy losses
incurred during distribution from Generation (line loss charges), however line
loss charges were not included in the 2000 pro forma purchased power costs.
Other expenses increased $73 million due primarily to a $113 million gain
on a ComEd forward share repurchase arrangement recognized during the first
quarter of 2000, partially offset by a $38 million non-recurring loss on the
sale of Cotter Corporation, a ComEd subsidiary, recognized during the first
quarter of 2000.
Depreciation and amortization increased $77 million reflecting increased
regulatory asset amortization of $34 million consistent with regulatory
provisions, and increased depreciation expense of $43 million primarily
associated with capital additions.
Depreciation and amortization includes goodwill amortization of $126
million in 2001, which will be discontinued in 2002 upon the adoption of
Financial Accounting Standards Board (FASB) Statement of Financial Accounting
Standards (SFAS) No. 142 "Goodwill and Other Intangible Assets" (SFAS No. 142).
2
Energy Delivery's electric sales statistics are as follows:
Deliveries (in megawatthours (MWh)) 2001 2000(a) Variance
- ------------------------------------------------------------------------------------------------------------
Residential 36,459,606 35,307,675 1,151,931
Small Commercial & Industrial 37,183,693 36,506,400 677,293
Large Commercial & Industrial 36,824,787 39,663,127 (2,838,340)
Public Authorities & Electric Railroads 10,003,853 9,828,668 175,185
- ------------------------------------------------------------------------------------------------------------
Total Retail Deliveries 120,471,939 121,305,870 (833,931)
============================================================================================================
The table above includes deliveries of 16 million MWhs in 2001 to customers who
purchase energy from alternative suppliers.
Electric Revenue (in millions) 2001 2000(a) Variance
- ------------------------------------------------------------------------------------------------------------
Residential $ 3,571 $ 3,483 $ 88
Small Commercial & Industrial 2,852 2,680 172
Large Commercial & Industrial 1,933 1,796 137
Public Authorities & Electric Railroads 568 544 24
- ------------------------------------------------------------------------------------------------------------
Total Electric Retail Revenue 8,924 8,503 421
- ------------------------------------------------------------------------------------------------------------
Wholesale and Miscellaneous Revenue 593 643 (50)
- ------------------------------------------------------------------------------------------------------------
Total Electric Revenue $ 9,517 $ 9,146 $ 371
============================================================================================================
<FN>
(a) Includes the operations of ComEd as if the Merger occurred on January 1, 2000.
</FN>
The changes in electric retail revenues for 2001, as compared to 2000, as if the
Merger occurred on January 1, 2000, are attributable to the following:
(in millions) Variance
- ------------------------------------------------------------------------------------------------------------
Rate Changes $ 217
Customer Choice 131
Weather 98
Revenue Taxes (88)
Other Effects 63
- ------------------------------------------------------------------------------------------------------------
Electric Retail Revenue $ 421
============================================================================================================
- - 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.
- - Customer Choice. ComEd non-residential customers and all PECO customers
have the choice to purchase energy from other suppliers. This choice
generally does not impact kWh deliveries, but affects revenue collected
from customers related to energy supplied by Energy Delivery. The favorable
customer choice effect is attributable to increased revenues of $276
million from customers in Pennsylvania selecting or returning to PECO as
their electric generation supplier, partially offset by a decrease in
revenues of $145 million from customers in Illinois electing to purchase
energy from an alternative retail electric supplier (ARES) or the power
purchase option (PPO), under which customers can purchase power from ComEd
at a market-based rate. Exelon continues to collect delivery charges from
these customers.
- - Weather. The demand for electricity and gas services is impacted by weather
conditions. Very warm weather in summer months and very cold weather in
other months is referred to as "favorable weather conditions", because
these weather conditions result in increased sales of electricity and gas.
Conversely, mild weather reduces demand. Although weather was moderate in
2001, the weather impact was favorable compared to the prior year as a
result of warmer summer weather offset in part by warmer winter weather in
2001, primarily in the ComEd service territory.
3
- - Revenue taxes. The change in revenue taxes represents a change in
presentation of certain revenue taxes from operating revenue and tax
expense to collections recorded as liabilities resulting from Illinois
legislation. This change in presentation does not affect income.
- - Other Effects. A strong housing construction market in Chicago has
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 Federal Energy Regulatory
Commission (FERC) ruling.
Energy Delivery's gas sales statistics are as follows:
2001 2000 Variance
- -----------------------------------------------------------------------------------------------------------
Deliveries in million cubic feet (mmcf) 81,528 91,686 (10,158)
Revenue (in millions) $654 $532 $122
- -----------------------------------------------------------------------------------------------------------
The changes in gas revenue for 2001, as compared to 2000, are as follows:
(in millions) Variance
- -----------------------------------------------------------------------------------------------------------
Price $ 174
Weather (38)
Volume (14)
- -----------------------------------------------------------------------------------------------------------
Gas Revenue $ 122
===========================================================================================================
- - Price. The favorable variance in price is attributable to an adjustment of
the purchased gas cost recovery by the Pennsylvania Public Utility
Commission (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.
- - Weather. The unfavorable weather impact is attributable to warmer
temperatures in the non-summer months of 2001 than in 2000 in the PECO
service territory. Heating degree days decreased 12% in 2001 compared to
2000.
- - Volume. Exclusive of weather impacts, lower delivery volume affected
revenue by $14 million compared to 2000. Total mmcf sales to retail
customers decreased 11% compared to 2000, primarily as a result of slower
economic conditions in 2001 offset by customer growth.
Generation
Components of Variance
--------------------------
Merger Normal
(in millions) 2001 2000 Variance Variance Operations
- ------------------------------------------------------------------------------------------------------------
Operating Revenue $ 7,048 $ 3,316 $ 3,732 $ 2,772 $960
Operating Expense and Other 5,804 2,750 3,054 2,667 387
Depreciation & Amortization 282 126 156 83 73
- ------------------------------------------------------------------------------------------------------------
EBIT $ 962 $ 440 $ 522 $ 22 $500
============================================================================================================
4
Generation's EBIT increased $522 million for 2001 compared to 2000. The Merger
accounted for $22 million of the variance. The remaining $500 million increase
resulted primarily from higher margins on market and affiliate wholesale energy
sales, coupled with decreased operating costs at the nuclear plants, partially
offset by additional depreciation and amortization. During the first five months
of 2001, Generation benefited from increases in wholesale market prices,
particularly in the Pennsylvania-New Jersey-Maryland control area and
Mid-America Interconnected Network regions. The increase in wholesale market
prices was primarily driven by significant increases in fossil fuel prices. The
large concentration of nuclear generation in the Generation portfolio allowed
Exelon to capture the higher prices in the wholesale market for sales to
non-affiliates with minimal increase in fuel prices. Generation revenues for
2001 include charges to affiliates for line losses. Line loss charges were not
included in pro forma 2000 revenue. Generation also benefited from higher
nuclear plant output due to increased capacity factors during 2001. Energy
marketing activities positively impacted 2001 results. Mark-to-market gains were
$16 million and $14 million on non-trading and trading energy contracts,
respectively, offset by realized trading losses of $6 million. Lower operating
costs are attributable to reductions in the number of employees and fewer
nuclear outages in 2001 than in 2000, which offset the effect of increases in
reserves related to litigation of $30 million. In addition, Generation's EBIT
benefited from an increase in equity in earnings of AmerGen and Sithe of $90
million in 2001 compared to the prior year period as a result of acquisitions in
2000. The increase in depreciation and amortization expense primarily reflects
an increase in decommissioning expense of $140 million reflecting the
discontinuance of regulatory accounting practices for certain nuclear generating
stations, partially offset by a $90 million reduction in depreciation and
decommissioning expense attributable to the extension of estimated service lives
of Generation's generating plants.
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 $12.79 per MWh for
2001, compared to $14.65 per MWh for 2000.
Enterprises
Components of Variance
---------------------------
Merger Normal
(in millions) 2001 2000 Variance Variance Operations
- -----------------------------------------------------------------------------------------------------------
Operating Revenue $ 2,292 $ 1,395 $ 897 $ 467 $ 430
Operating Expense and Other 2,330 1,500 830 491 339
Depreciation & Amortization 69 35 34 8 26
- -----------------------------------------------------------------------------------------------------------
EBIT $ (107) $ (140) $ 33 $ (32) $ 65
===========================================================================================================
Enterprises' EBIT increased $33 million for 2001 compared to 2000. Normal
operations contributed $65 million of the variance, which was partially offset
by a $32 million reduction attributable to the Merger. The increase in EBIT from
normal operations primarily reflects $27 million of net realized gains on
investments, $23 million from lower net losses in communications joint ventures,
$21 million of reduced losses on the sale of assets, and $15 million primarily
from improved margins and reduced operating expenses of retail energy sales in
Pennsylvania. These increases were partially offset by $13 million of net
writedowns on investments.
5
Enterprises' revenues increased $897 million for 2001 compared to 2000.
Normal operations contributed $430 million and the Merger added $467 million.
Operating revenues attributable to normal operations increased $574 million as a
result of acquisitions by its services businesses. Additionally, revenues
increased by $26 million as a result of increased operations at Exelon Services.
These increases were partially offset by $166 million lower revenues primarily
attributable to reduced operations of retail energy sales in Pennsylvania.
Enterprises' operating and other expenses increased $830 million for 2001
compared to 2000. Normal operations contributed $339 million and the Merger
added $491 million. Operating expenses from normal operations included $554
million as a result of acquisitions made by its services businesses.
Additionally, operating and other expenses increased by $32 million from
increased operations at Exelon Services and $13 million due to net writedowns on
investments. These increases were partially offset by $193 million from lower
expense primarily attributable to reduced operations of retail energy sales in
Pennsylvania, $27 million from net realized gains on investments, $23 million
from lower net losses in communications joint ventures, and $21 million of
reduced losses on the sale of assets.
Enterprises' depreciation and amortization expense increased primarily as a
result of goodwill amortization related to acquisitions made by its services
businesses.
Depreciation and amortization includes goodwill amortization of $24 million
in 2001, which will be discontinued in 2002 upon the adoption of SFAS No. 142.
Enterprises' investments are weighted towards investments in the
communication industry, which continues to be adversely impacted by the
significant downturn in the communications market.
Other Components of Net Income
Interest Charges Interest charges consist of interest expense and distributions
on preferred securities of subsidiaries. Interest charges increased $524
million, or 83%, for 2001. The increase was primarily attributable to $438
million from the effects of the Merger, $70 million related to borrowings by
Exelon to finance the Merger cash consideration and the December 2000 investment
in Sithe as well as additional interest of $16 million as a result of the
issuance of transition bonds in May 2000 to securitize a portion of PECO's
stranded cost recovery.
Investment Income Investment income is recorded in Other, Net on the
Consolidated Statements of Income, but is excluded from EBIT. Investment income
decreased by $17 million due to net realized losses of $60 million on the
nuclear decommissioning trust funds for the nuclear stations formerly owned by
ComEd, offset by increased income of $43 million, primarily reflecting a full
year of investment income from the former Unicom companies, as well as money
market interest and interest on the loan to Sithe recorded at Generation in
2001.
Income Taxes Income taxes increased by $590 million in 2001 as compared to 2000,
$541 million of which is due to higher pretax income and $49 million due to a
higher effective income tax rate. The increase in income taxes reflects
additional pretax income of $1,440 million, of which $1,044 million is
attributable to the Merger. The effective income tax rate was 39.7% for 2001 as
compared to 37.6% for 2000. The increase in the effective income tax rate was
primarily attributable to goodwill amortization associated with the Merger which
is not deductible for tax purposes, a higher effective state income tax rate due
to operations in Illinois subsequent to the Merger, reduced impact of investment
tax credit amortization and a favorable annual tax return adjustment recorded in
2001.
Extraordinary Items In 2000, Exelon incurred extraordinary charges aggregating
$6 million ($4 million, net of tax) related to prepayment premiums and the
write-off of unamortized deferred financing costs associated with the early
retirement of debt with a portion of the proceeds from the securitization of
PECO's stranded cost recovery in May 2000.
Cumulative Effect of Changes in Accounting Principles On January 1, 2001, Exelon
adopted SFAS No. 133 "Accounting for Derivative Instruments and Hedging
Activities" (SFAS No. 133), as amended, resulting in a benefit of $20 million
($12 million, net of income taxes). On January 1, 2000, Exelon recorded a
benefit of $40 million ($24 million, net of income taxes) representing the
cumulative effect of a change in accounting method for nuclear outage costs by
PECO in conjunction with the synchronization of accounting policies in
connection with the Merger.
6
Year Ended December 31, 2000 Compared To Year Ended December 31, 1999
Net Income and Earnings Per Share
Exelon's net income increased $16 million, or 3% in 2000. Diluted earnings per
share were consistent with the prior year period. Income before extraordinary
items and cumulative effect of a change in accounting principle, decreased $41
million, or 7% in 2000. Diluted earnings per share on the same basis were
consistent with the prior period. Earnings per share increased less than net
income because of an increase in the weighted average shares of common stock
outstanding as a result of the issuance of common stock in connection with the
Merger, partially offset by the repurchase of common stock with the proceeds
from PECO's March 1999 and May 2000 stranded cost recovery securitizations.
Earnings Before Interest and Income Taxes To provide a more meaningful analysis
of results of operations, the EBIT analyses by business segment below identify
the portion of the EBIT 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 the former Unicom companies' results for the
period after the Merger on October 20, 2000 as well as the effect of excluding
Merger-related costs from Exelon's 2000 operations. The 2000 and 1999 results
also reflect the corporate restructuring as if it had occurred on January 1,
1999. The 2000 pro forma effects of the Merger and restructuring were developed
using estimates of various items, including allocation of corporate overheads to
business segments and intercompany transactions.
EBIT Contribution by Business Segment
Components of Variance
---------------------------
Merger Normal
(in millions) 2000 1999 Variance Variance Operations
- -----------------------------------------------------------------------------------------------------------
Energy Delivery $ 1,503 $ 1,372 $ 131 $ 297 $ (166)
Generation 440 379 61 34 27
Enterprises (140) (212) 72 (4) 76
Corporate (328) (194) (134) (272) 138
- -----------------------------------------------------------------------------------------------------------
Total $ 1,475 $ 1,345 $ 130 $ 55 $ 75
===========================================================================================================
Energy Delivery
Components of Variance
---------------------------
Merger Normal
(in millions) 2000 1999 Variance Variance Operations
- -----------------------------------------------------------------------------------------------------------
Operating Revenue $ 4,511 $ 3,265 $ 1,246 $ 1,138 $ 108
Operating Expense and Other 2,711 1,785 926 739 187
Depreciation & Amortization 297 108 189 102 87
- -----------------------------------------------------------------------------------------------------------
EBIT $ 1,503 $ 1,372 $ 131 $ 297 $ (166)
===========================================================================================================
Energy Delivery's EBIT increased $131 million in 2000, as compared to 1999. The
Merger accounted for $297 million of the variance offset by a decrease in EBIT
from normal operations of $166 million. The decrease in EBIT from normal
operations reflects increased operating and maintenance expenses and regulatory
asset amortization which more than offset the increase in revenue. The increase
in revenue from normal operations is attributable to improved margins on sales
due to customers in Pennsylvania selecting PECO as their electric generation
supplier and rate adjustments partially offset by lower summer volume.
Energy Delivery's operating expenses and other increased due to higher
administrative and general costs as a result of increased allocation of costs
previously recorded at Corporate, partially offset by a nonrecurring capital
stock credit related to a 1999 adjustment associated with the impact of PECO's
1997 restructuring charge.
Depreciation and amortization increased $87 million primarily reflecting
increased regulatory asset amortization consistent with regulatory orders.
7
Generation
Components of Variance
---------------------------
Merger Normal
(in millions) 2000 1999 Variance Variance Operations
- -----------------------------------------------------------------------------------------------------------
Operating Revenue $ 3,316 $ 2,411 $ 905 $ 590 $ 315
Operating Expense and Other 2,750 1,907 843 528 315
Depreciation & Amortization 126 125 1 28 (27)
- -----------------------------------------------------------------------------------------------------------
EBIT $ 440 $ 379 $ 61 $ 34 $ 27
===========================================================================================================
Generation's EBIT increased $61 million for 2000 compared to 1999. The Merger
accounted for $34 million of the variance. The remaining $27 million increase
resulted primarily from higher margins on market and affiliate wholesale energy
sales and from the abandonment of two information systems implementations in
1999 and a $15 million write-off in 1999 of the investment in a cogeneration
facility in connection with the settlement of litigation. In addition,
Generation's EBIT also benefited from an increase in equity in earnings of
AmerGen of $4 million in 2000 compared to the prior year period. Effective with
the acquisition of Clinton Nuclear Power Station (Clinton) by AmerGen, the
management agreement for Clinton was terminated, resulting in lower revenues of
$99 million and lower operation and maintenance expense of $70 million.
Generation's nuclear fleet, including AmerGen, performed at a weighted
average capacity factor of 93.8% for 2000. Generation's nuclear fleet production
costs for 2000 were $14.65 per MWh.
Enterprises
Components of Variance
---------------------------
Merger Normal
(in millions) 2000 1999 Variance Variance Operations
- -----------------------------------------------------------------------------------------------------------
Operating Revenue $ 1,395 $ 644 $ 751 $ 277 $ 474
Operating Expense and Other 1,500 852 648 278 370
Depreciation & Amortization 35 4 31 3 28
- -----------------------------------------------------------------------------------------------------------
EBIT $ (140) $ (212) $ 72 $ (4) $ 76
===========================================================================================================
Enterprises' EBIT increased $72 million for 2000 compared to 1999. Normal
operations contributed $76 million of the variance, which was partially offset
by a $4 million reduction attributable to the Merger. The increase in EBIT from
normal operations primarily reflects a reduction in losses from retail energy
sales partially offset by writedowns on communications investments and losses in
communications joint ventures.
Enterprises' revenues increased $751 million for 2000 compared to 1999.
Normal operations contributed $474 million and the Merger added $277 million.
Operating revenues attributable to normal operations increased $530 million as a
result of thirteen infrastructure services company acquisitions in 2000 and
1999, partially offset by reduced retail energy sales.
Enterprises' operating and other expenses increased $648 million for 2000
compared to 1999. Normal operations contributed $370 million and the Merger
added $278 million. Increased operating expenses from normal operations
primarily related to the thirteen infrastructure services company acquisitions
and to writedowns on communication investments and losses in communications
joint ventures, partially offset by reduced retail energy sales.
Enterprises' depreciation and amortization expense increased primarily as a
result of goodwill amortization related to its infrastructure services
businesses acquisitions.
Other Components of Net Income
Interest Charges Interest charges increased $203 million, or 47%, to $632
million in 2000. The increase was primarily attributable to $156 million from
the operations of Unicom since the Merger and interest of $104 million on the
transition bonds issued to securitize PECO's stranded cost recovery, partially
offset by $77 million of lower interest charges as a result of the reduction of
PECO's long-term debt with the proceeds from the securitization.
8
Investment Income Investment income is recorded in Other, Net on the
Consolidated Statements of Income, but is excluded from EBIT. Investment income
increased by $12 million to $64 million in 2000, primarily reflecting the
effects of the Merger.
Income Taxes The effective tax rate was 37.6% in 2000 as compared to 37.1% in
1999.
Extraordinary Items In 2000, Exelon incurred extraordinary charges aggregating
$6 million ($4 million, net of tax) related to prepayment premiums and the
write-off of unamortized deferred financing costs associated with the early
retirement of debt with a portion of the proceeds from the securitization of
PECO's stranded cost recovery in May 2000.
In 1999, Exelon incurred extraordinary charges aggregating $62 million ($37
million, net of tax) related to prepayment premiums and the write-off of
unamortized debt costs associated with the repayment and refinancing of debt.
Cumulative Effect of a Change in Accounting Principle In 2000, Exelon recorded a
benefit of $40 million ($24 million, net of income taxes) representing the
cumulative effect of a change in accounting method for nuclear outage costs by
PECO in conjunction with the synchronization of accounting policies in
connection with the Merger.
Liquidity and Capital Resources
Exelon's capital resources are primarily provided by internally generated cash
flows from operations and, to the extent necessary, external financing including
the issuance of commercial paper. Exelon's access to external financing at
reasonable terms is dependent on the credit ratings of Exelon and its
subsidiaries and the general business condition of Exelon and the industry.
Exelon's businesses are capital intensive. Capital resources are used primarily
to fund Exelon's capital requirements, including construction, investments in
new and existing ventures, repayments of maturing debt and preferred securities
of subsidiaries and payment of common stock dividends. Any potential future
acquisitions could require external financing, including the issuance by Exelon
of common stock.
Cash Flows from Operating Activities
Cash flows provided by operations for 2001 were $3.6 billion, approximately
two-thirds of which were provided by Energy Delivery and one-third of which was
provided by Generation. Enterprises' cash flows from operations were immaterial
to Exelon in 2001. Energy Delivery's cash flow from operating activities
primarily results from sales of electricity and gas to a stable and diverse base
of retail customers at fixed prices. Energy Delivery's future cash flows will
depend upon the ability to achieve cost savings in operations, 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. Generation's future
cash flow from operating activities will depend upon future demand and market
prices for energy and the ability to continue to produce and supply power at
competitive costs. Although the amounts may vary from period to period as a
result of the uncertainties inherent in business, Exelon expects that Energy
Delivery and Generation will continue to provide a reliable and steady source of
internal cash flow from operations for the foreseeable future.
9
Cash Flows from Investing Activities
Cash flows used in investing activities for 2001 were $2.4 billion, primarily
for capital expenditures of $2.0 billion. Capital expenditures by business
segment for 2001 and projected amounts for 2002 are as follows:
(in millions) 2001 2002
- -----------------------------------------------------------------------------------------------------------
Energy Delivery $ 1,133 $ 1,060
Generation 803 1,089
Enterprises 70 114
Corporate and Other 35 27
- -----------------------------------------------------------------------------------------------------------
Subtotal $ 2,041 $ 2,290
TXU Acquisition -- 443
- -----------------------------------------------------------------------------------------------------------
Total Capital Expenditures and TXU Acquisition $ 2,041 $ 2,733
===========================================================================================================
Energy Delivery's estimated capital expenditures for 2002 reflect the
continuation of efforts to further improve the reliability of its distribution
system in the Chicago region. Approximately 36% of the budgeted 2002
expenditures are for growth and the remainder for additions to or upgrades of
existing facilities. Exelon anticipates that Energy Delivery will obtain
financing, when necessary, through borrowings, the issuance of preferred
securities, or capital contributions from Exelon.
Approximately 75% of Generation's estimated capital expenditures for 2002
are for additions to and upgrades of existing facilities (including nuclear
refueling outages), nuclear fuel and increases in capacity at existing plants.
Capital expenditures are projected to increase in 2002 as compared to 2001 due
to higher nuclear fuel expenditures, growth and an increase in the number of
planned refueling outages, during which significant maintenance work is
performed. Eleven nuclear refueling outages, including AmerGen, are planned for
2002, compared to six during 2001. Total capital expenditures for nuclear
refueling outages are expected to increase in 2002 over 2001 by $24 million.
Exelon has committed to provide AmerGen with capital contributions equivalent to
50% of the purchase price of any acquisitions AmerGen makes in 2002. Exelon
anticipates that Generation's capital expenditures will be funded by internally
generated funds, Generation borrowings or capital contributions from Exelon. In
addition to the 2002 capital expenditures of $1.1 billion, Generation expects to
close the purchase of two natural-gas and oil-fired plants from TXU Corp. (TXU)
in the first quarter of 2002. The $443 million purchase is expected to be funded
with available cash and commercial paper.
Enterprises' capital expenditures were $70 million in 2001. Enterprises'
estimated capital expenditures for 2002 are approximately $114 million,
primarily for additions to or upgrades of existing facilities. All of
Enterprises' investments are expected to be funded by capital contributions or
borrowings from Exelon.
Exelon's total estimated capital expenditures in 2002 are approximately
$2.7 billion including the acquisition of the TXU generating stations. Exelon's
proposed capital expenditures and other investments are subject to periodic
review and revision to reflect changes in economic conditions and other factors.
Cash Flows from Financing Activities
Cash flows used in financing activities were $1.3 billion in 2001 primarily
attributable to debt service and payments of dividends on common stock. Debt
financing activities during 2001 were as follows:
- - Exelon Corporation - Retired a $1.2 billion term loan with proceeds from
$500 million and $700 million senior unsecured note issuances at Exelon and
Generation, respectively.
- - Energy Delivery - Refinanced $805 million in PECO transition bonds, retired
$340 million of ComEd transitional trust notes and early retired $196
million in First Mortgage Bonds with available cash.
- - Generation - Issued $121 million of pollution control bonds to refinance an
equivalent amount originally issued by PECO and issued $700 million of
senior unsecured notes.
10
The 2001 common stock dividend payments of $583 million cover the period from
October 20, 2000, the date of the Merger, through November 15, 2001. On January
29, 2002, the Board of Directors of Exelon declared a quarterly dividend of
$0.44 per share of Exelon's common stock. This increase of $0.07 per share
annually, will result in an annual dividend rate of $1.76 per share. The new
dividend rate reflects Exelon's vertically integrated business portfolio and its
focus on total return to shareholders. The new dividend rate represents about a
50% payout of the expected 2002 earnings per share from Exelon's regulated
electricity delivery businesses. Exelon intends to grow the dividend to about a
60% payout of earnings from regulated operations based on cash flow and earnings
growth prospects for Energy Delivery. The payment of future dividends is subject
to approval and declaration by the Board of Directors each quarter.
Credit Issues
Exelon meets its short-term liquidity requirements primarily through the
issuance of commercial paper by Exelon, ComEd and PECO. Exelon, along with
ComEd, PECO and Generation, entered into a $1.5 billion unsecured revolving
credit facility with a group of banks. Generation currently cannot borrow under
the credit agreement until it has delivered audited financial statements to the
banks, which is expected to occur in the first quarter of 2002. This credit
facility is used principally to support the commercial paper program of Exelon,
ComEd and PECO.
At December 31, 2001, Exelon had outstanding $360 million of notes payable
consisting principally of commercial paper. For 2001, the average interest rate
on notes payable was approximately 2.63%. Certain of the credit agreements to
which Exelon, ComEd, PECO and Generation are parties require each of them to
maintain a debt to total capitalization ratio of 65% or less, excluding
securitization debt (and for PECO, excluding the receivable from parent recorded
in PECO's shareholders' equity). At December 31, 2001, the debt to total
capitalization ratios on that basis for Exelon, ComEd, PECO and Generation were
47%, 45%, 38% and 26%, respectively.
Exelon and its subsidiaries' access to the capital markets, including the
commercial paper market, and their financing costs in those markets are
dependent on their respective securities ratings. None of Exelon's or its
subsidiaries' borrowings are subject to default or prepayment as a result of a
downgrading of securities ratings although such a downgrading could increase
interest charges under Exelon's bank credit facility. Exelon and its
subsidiaries from time to time enter into interest rate swap and other
derivatives that require the maintenance of investment grade ratings. Failure to
maintain investment grade ratings would allow the counterparty to terminate the
derivative and settle the transaction on a net present value basis.
Exelon has obtained an order from the Securities and Exchange Commission
(SEC) under the Public Utility Holding Company Act of 1935 (PUHCA) authorizing
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, 2001, $3.0 billion of financing authority
is available under the SEC order. Exelon requested, and the SEC reserved
jurisdiction over, an additional $4 billion in financing authorization. Exelon
agreed to limit its short-term debt outstanding to $3 billion of the $4 billion
total financing authority. Exelon has asked the SEC to eliminate the short-term
debt restriction. The SEC order also authorized Exelon to issue guarantees of up
to $4.5 billion outstanding at any one time. At December 31, 2001, Exelon had
provided $1.4 billion of guarantees. See Contractual Obligations and Commercial
Commitments in this section. The SEC order requires Exelon to maintain a ratio
of common equity to total capitalization (including securitization debt) on and
after June 30, 2002 of not less than 30%. At December 31, 2001, Exelon's common
equity to total capitalization was 35%.
Under PUHCA and the Federal Power Act, Exelon, ComEd, PECO and Generation
can pay dividends only from retained or current earnings. However, the SEC order
granted permission to Exelon and ComEd to pay up to $500 million in dividends
out of additional paid-in capital, provided that Exelon agreed not to 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, 2001, Exelon had
retained earnings of $1.2 billion, which includes ComEd retained earnings of
$257 million, PECO retained earnings of $270 million and Generation retained
earnings of $471 million. Exelon is 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). Exelon requested, and the SEC reserved
jurisdiction over, an additional $1.5 billion in EWGs and FUCOs.
During 2001, Exelon loaned Sithe $150 million, which was repaid by Sithe in
December of 2001 from the proceeds of a bank borrowing. In connection with that
bank borrowing, Exelon provided the lenders with a support letter confirming its
investment in Sithe and Exelon's agreement to maintain a positive net worth of
Sithe. Sithe's net worth is expected to remain positive for the forseeable
future and accordingly this agreement is not reflected in the following
Contractual
11
Obligations and Commercial Commitments discussion. This agreement does not
guarantee any debt or obligation of Sithe. During 2001, Sithe paid Exelon $2
million in interest on the loan.
Contractual Obligations and Commercial Commitments
Exelon's contractual obligations as of December 31, 2001 representing cash
obligations that are considered to be firm commitments are as follows:
Payment due within
---------------------------------------- Due after
(in millions) Total 1 Year 2-3 Years 4-5 Years 5 Years
- ------------------------------------------------------------------------------------------------------------
Long-Term Debt $ 14,411 $ 1,406 $ 2,287 $ 2,576 $ 8,142
Short-Term Debt 360 360 -- -- --
Operating Leases 990 82 152 128 628
Purchase Obligations 12,192 1,695 3,173 1,346 5,978
Spent Nuclear Fuel Obligation 843 -- -- -- 843
Acquisition of TXU Generating
Stations 443 443 -- -- --
- ------------------------------------------------------------------------------------------------------------
Total Contractual Obligations $ 29,239 $ 3,986 $ 5,612 $ 4,050 $15,591
============================================================================================================
For additional information about
- long-term debt see Note 14 of the Notes to Consolidated Financial
Statements
- short-term debt see Note 13 of the Notes to Consolidated Financial
Statements
- operating leases see Note 20 of the Notes to Consolidated Financial
Statements
- purchase obligations see Note 20 of the Notes to Consolidated Financial
Statements
- the TXU acquisition see Note 20 of the Notes to Consolidated Financial
Statements
- the spent nuclear fuel obligation see Note 12 of the Notes to
Consolidated Financial Statements
Exelon has an obligation to decommission its nuclear power plants. Exelon's
current estimate of decommissioning costs for its owned nuclear plants is $7.2
billion in current year (2002) dollars. Nuclear decommissioning activity occurs
primarily after the plants retirement and is currently estimated to begin in
2045. At December 31, 2001 the decommissioning liability, which is recorded over
the life of the plant, recorded in Accumulated Depreciation and Deferred Credits
and Other Liabilities on Exelon's Consolidated Balance Sheets was $2.7 billion
and $1.3 billion, respectively. In order to fund future decommissioning costs,
Exelon held $3.2 billion of investments in trust funds which are included as
Investments in Exelon's Consolidated Balance Sheets and include net unrealized
and realized gains.
Exelon's commercial commitments as of December 31, 2001 representing
commitments triggered by future events, including obligations to make payment on
behalf of other parties as well as financing arrangements to secure obligations
of Exelon, are as follows:
Expiration within
--------------------------------------- After
(in millions) Total 1 Year 2-3 Years 4-5 Years 5 Years
- ------------------------------------------------------------------------------------------------------------
Available Lines of Credit (a) $ 1,500 $ 1,500 $ -- $ -- $ --
Letters of Credit (non-debt) (b) 38 37 1 -- --
Letters of Credit (Long-Term Debt) (c) 427 122 305 -- --
Insured Long-Term Debt (d) 154 -- 154 -- --
Guarantees (e) 1,410 218 310 -- 882
- ------------------------------------------------------------------------------------------------------------
Total Commercial Commitments $ 3,529 $ 1,877 $ 770 $ -- $ 882
============================================================================================================
<FN>
(a) Lines of Credit - Exelon, along with ComEd, PECO, and Generation, maintain a $1.5 billion 364-day
credit facility to support commercial paper issuances. At December 31, 2001, there are no borrowings
against the credit facility. Additionally, at December 31, 2001, there was $360 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 - Provide support for lines of credit, performance contracts, surety bonds, energy marketing
contracts, nuclear insurance, and leases as required by third parties.
</FN>
12
Off Balance Sheet Obligations
Generation owns 49.9% of the outstanding common stock of Sithe and has an
option, beginning on December 18, 2002, to purchase the remaining common stock
outstanding (Remaining Interest) in Sithe. The purchase option expires on
December 18, 2005. In addition, the Sithe stockholders who own in the aggregate
the Remaining Interest have the right to require Generation to purchase the
Remaining Interest (Put Rights) during the same period in which Generation can
exercise its purchase option. At the end of this exercise period, if Generation
has not exercised its purchase option and the other Sithe stockholders have not
exercised their Put Rights, Generation will have an additional one-time option
to purchase shares from the other stockholders in Sithe to bring Generation's
ownership in Sithe from the current 49.9% to 50.1% of Sithe's total outstanding
common stock.
If Generation exercises its option to acquire the Remaining Interest, or if
all the other Sithe stockholders exercise their Put Rights, the purchase price
for 70% of the Remaining Interest will be set at fair market value subject to a
floor of $430 million and a ceiling of $650 million. The balance of the
Remaining Interest will be valued at fair market value without being subject to
floor or ceiling prices. In either instance, interest shall accrue from the
beginning of the exercise period.
If Generation increases its ownership in Sithe to 50.1% or more, Sithe will
become a consolidated subsidiary and Exelon's financial results will include
Sithe's financial results from the date of purchase. At December 31, 2001, Sithe
had total assets of $4.2 billion and long-term debt of $2.3 billion, including
$2.1 billion of non-recourse project debt, and excluding $107 million of
non-recourse project debt associated with Sithe's equity investments. For the
year ended December 31, 2001 Sithe had revenues of $1 billion. As of December
31, 2001 Exelon had a $725 million equity investment in Sithe.
Additionally, the debt on the books of Exelon's unconsolidated equity
investments and joint ventures is not reflected on Exelon's Consolidated Balance
Sheets. Total investee debt, including the debt of Sithe described in the
preceding paragraph, is currently estimated to be $2.4 billion ($1.2 billion
based on Exelon's ownership interest of the investments).
Generation and British Energy, Generation's joint venture partner in
AmerGen, have each agreed to provide up to $100 million to AmerGen at any time
for operating expenses.
Other Factors
In 2001, Exelon adopted a cash balance pension plan. All management and electing
union employees who joined Exelon or one of its participating subsidiaries
during 2001 became participants in the plan. Management employees who were
active participants in Exelon's previous qualified defined benefit plans at
December 31, 2000 and are employed by Exelon on January 1, 2002 will be given a
choice to convert 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 which may result in increased
cash requirements from pension plan assets. Exelon may be required to increase
future funding to the pension plan as a result of these increased cash
requirements.
Due to the performance of the United States debt and equity markets in
2001, the value of assets held in trusts to satisfy the obligations of pension
and postretirement benefit plans and the eventual nuclear generating station
decommissioning has decreased. Also, as a result of the Merger and corporate
restructuring, there was a larger than average number of employees taking
advantage of retirement benefits in 2001. These factors may also result in
additional future funding requirements of the pension and postretirement benefit
plans. Contributions to the nuclear decommissioning trust funds of $112 million
offset net losses of $109 million, resulting in a 2% increase in the
decommissioning trust funds balance at December 31, 2001 compared to December
31, 2000. Exelon believes that the amounts being recovered from customers
through electric rates along with the earnings on the trust funds will be
sufficient to fund its decommissioning obligations. For additional information
about nuclear decommissioning see Notes 1 and 12 of the Notes to Consolidated
Financial Statements.
13
Quantitative and Qualitative Disclosures About Market Risk
Exelon is exposed to market risks associated with commodity price, credit,
interest rates and equity prices. The inherent risk in market sensitive
instruments and positions is the potential loss arising from adverse changes in
commodity prices, counterparty credit, interest rates and equity security
prices. Exelon's corporate Risk Management Committee (RMC) sets forth risk
management philosophy and objectives through a corporate policy, 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 Exelon's 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 Exelon's 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
basis. Trading activities and non-trading marketing activities include the
purchase and sale of electric capacity and energy and fossil fuels, including
oil, gas and coal. The availability and prices of energy and energy-related
commodities are subject to fluctuations due to factors such as weather,
environmental policies, changes in supply and demand, state and federal
regulatory policies and other events.
Marketing (non-trading) activities To the extent Exelon's generation supply,
(either owned or contracted) is in excess of its obligations to customers,
including ComEd and PECO's retail load, that available electricity is sold into
the wholesale markets. To reduce price risk caused by market fluctuations,
Exelon enters into derivative contracts, including forwards, futures, swaps, and
options with approved counterparties to hedge Exelon's anticipated exposures.
Market price risk exposure is the risk of a change in the value of unhedged
positions. Exelon expects to maintain a minimum 80% hedge ratio in 2002 for its
energy marketing portfolio. This hedge ratio represents the percentage of
Exelon's 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. Absent any opportunistic efforts to mitigate market price
exposure, the estimated market price exposure for the non-trading portfolio
associated with a ten percent reduction in the average around-the-clock market
price of electricity is an approximate $100 million decrease in net income, or
approximately $0.30 per share. This sensitivity, which is consistent with prior
guidance, assumes an 80% hedge ratio, and that price changes occur evenly
throughout the year and across all markets. The sensitivity also assumes a
static portfolio. Exelon expects to actively manage its portfolio to mitigate
the market price exposure. Actual results could differ depending on the specific
timing of, and markets affected by, the price changes, as well as future changes
in Exelon's portfolio.
Trading activities Exelon began to use financial contracts for trading purposes
in the second quarter of 2001. The trading activities were entered into as a
complement to Exelon's energy marketing portfolio and represent a very limited
portion of Exelon's overall energy marketing activities. For example, the limit
on open positions in electricity for any forward month represents less than 5%
of the owned and contracted supply of electricity. The trading portfolio is
planned to grow modestly in 2002, subject to stringent risk management limits
and policies, including volume, stop-loss and value-at-risk limits to manage
exposure to market risk. A value-at-risk (VAR) model is used to assess the
market risk associated with financial derivative instruments entered into for
trading purposes. VAR represents the potential gains or losses for instruments
or portfolios due to changes in market factors, for a specified time period and
confidence level. The measured VAR as of December 31, 2001, using a Monte Carlo
model with a 95% confidence level and assuming a one-day time horizon was
approximately $800,000. The measured VAR represents an estimate of the potential
change in value of Exelon's portfolio of trading related financial derivative
instruments. These estimates, however, are not necessarily indicative of actual
results, which may differ due to the fact that actual market rate fluctuations
may differ from forecasted fluctuations and due to the fact that the portfolio
may change over the holding period.
14
Exelon's energy contracts are accounted for under SFAS No. 133. Most
non-trading contracts qualify for a normal purchases and normal sales exception.
Those that do not are recorded as assets or liabilities on the balance sheet at
fair value. Changes in the fair value of qualifying hedge contracts are recorded
in Other Comprehensive Income, 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.
Outlined below is a summary of the changes in fair value for those contracts
included as assets and liabilities in the Consolidated Balance Sheet for the
year ended December 31, 2001:
(in millions) Non-trading Trading
- -------------------------------------------------------------------------------------------------------------
Fair value of contracts outstanding as of January 1, 2001
(reflects the adoption of SFAS No. 133) $ (7) $ -
Change in fair value during 2001:
Contracts settled during year 87 7
Mark-to-market gain/(loss) (2) 7
- ------------------------------------------------------------------------------------------------------------
Total change in fair value 85 14
- ------------------------------------------------------------------------------------------------------------
Fair value of contracts outstanding at December 31, 2001 $ 78 $ 14
============================================================================================================
The total change in fair value during 2001 is reflected in the 2001 financial
statements as follows:
Non-trading Trading
- ------------------------------------------------------------------------------------------------------------
Mark-to-market gain/(loss) on non-qualifying hedge contracts or
hedge ineffectiveness reflected in earnings $ 16 $ 14
Mark-to-market gain/(loss) on hedge contracts reflected in
Other Comprehensive Income 69 --
- ------------------------------------------------------------------------------------------------------------
Total change in fair value $ 85 $ 14
============================================================================================================
The majority of Exelon's contracts are non-exchange traded contracts valued
using prices provided by external sources, which primarily represent 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 Exelon believes 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 represent 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 and other valuation techniques. The fair values in each category
reflect the level of forward prices and volatility factors as of December 31,
2001 and may change as a result of future changes in these factors. The
maturities of the net energy trading and non-trading assets and sources of fair
value as of December 31, 2001 are as follows:
Maturities within
------------------------------------ Total Fair
(in millions) 1 Year 2-3 Years 4-5 Years Value
- -------------------------------------------------------------------------------------------------------------
Non-trading:
Actively quoted prices $ -- $ -- $ -- $ --
Prices provided by other external sources 36 50 -- 86
Prices based on model or other valuation methods (4) 2 (6) (8)
- ------------------------------------------------------------------------------------------------------------
Total $ 32 $ 52 $ (6) $ 78
============================================================================================================
Trading:
Actively quoted prices $ -- $ -- $ -- $ --
Prices provided by other external sources 10 4 -- 14
Prices based on model or other valuation methods -- -- -- --
- ------------------------------------------------------------------------------------------------------------
Total $ 10 $ 4 $ -- $ 14
============================================================================================================
15
Management uses its best estimates to determine the fair value of commodity and
derivative contracts it holds and sells. These estimates consider various
factors including closing exchange and over-the-counter price quotations, time
value, volatility factors, and credit exposure. However, it is possible 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.
Credit Risk
ComEd and PECO are each obligated to provide service to all electric customers
within their respective franchised territories. As a result, ComEd and PECO each
have a broad customer base. For the year ended December 31, 2001, ComEd's ten
largest customers represented approximately 3% of its retail electric revenues
and PECO's ten largest customers represented approximately 10% of its retail
electric revenues. Credit risk for Energy Delivery is managed by each company's
credit and collection policies, which are consistent with state regulatory
requirements.
Generation has credit risk associated with counterparty performance which
includes but is not limited to the risk of financial default or slow payment.
Counterparty credit risk is managed through established policies, including
establishing 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 master netting
agreements with the majority of its large counterparties, which reduce exposure
to risk by providing for the offset of amounts payable to the counterparty
against the counterparty receivables.
Generation participates in the five established, real-time energy markets,
which are administered by independent system operators (ISOs): Pennsylvania, New
Jersey, Maryland, LLC (PJM), which is in the Mid-Atlantic Area Council region:
New England and New York, which are both in the Northeast Power Coordinating
Council region, California, which is in the Western Systems Coordinating Council
region and Texas, which is administered by the Electric Reliability Council of
Texas. Approximately one-half of Generation's transactions, on a megawatthour
basis, were made in these markets. In these areas, power is traded through
bilateral agreements between buyers and sellers and on the spot markets which
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 ISO's 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 Exelon's financial condition, results of
operations or net cash flows.
Exelon's balance sheet includes a $427 million net investment in a direct
financing lease as of December 31, 2001. 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 $1,065
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.
Interest Rate Risk
Exelon uses a combination of fixed rate and variable rate debt to reduce
interest rate exposure. Interest rate swaps may be used to adjust exposure when
deemed appropriate based upon market conditions. Exelon also utilizes
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 maintain the lowest cost of capital. As of December 31, 2001, a hypothetical
10% increase in the interest rates associated with variable rate debt would
result in an $1 million decrease in pre-tax earnings for 2002.
Exelon has 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 and with a $235 million fixed-rate
obligation of ComEd. In December 2001, Exelon entered into forward-starting
interest rate swaps, with an aggregate notional amount of $250 million in
anticipation of the issuance of debt at ComEd in the first quarter of 2002. At
December 31, 2001, these interest rate swaps had an aggregate fair market value
exposure of $21 million based on the present value difference between the
contract and market rates at December 31, 2001.
16
The aggregate fair value exposure of the interest rate swaps that would
have resulted from a hypothetical 50 basis point decrease in the spot yield at
December 31, 2001 is estimated to be $34 million. If these derivative
instruments had been terminated at December 31, 2001, this estimated fair value
represents the amount that would be paid by Exelon to the counterparties.
The aggregate fair value exposure of the interest rate swaps that would
have resulted from a hypothetical 50 basis point increase in the spot yield at
December 31, 2001 is estimated to be $11 million. If these derivative
instruments had been terminated at December 31, 2001, this estimated fair value
represents the amount to be paid by Exelon to the counterparties.
Equity Price Risk
Exelon maintains trust funds, as required by the Nuclear Regulatory Commission
(NRC), to fund certain costs of decommissioning its nuclear plants. As of
December 31, 2001, these funds are reflected at fair value on Exelon's
Consolidated Balance Sheets. The mix of securities is designed to provide
returns to be used to fund decommissioning and to compensate for inflationary
increases in decommissioning costs. However, the equity securities in the trusts
are exposed to price fluctuations in equity markets, and the value of fixed
rate, fixed income securities are exposed to changes in interest rates. Exelon
actively monitors the investment performance and periodically reviews asset
allocation in accordance with Exelon's nuclear decommissioning trust fund
investment policy. A hypothetical 10% increase in interest rates and decrease in
equity prices would result in a $204 million reduction in the fair value of the
trust assets.
Critical Accounting Policies
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
reported amounts of assets and liabilities in the financial statements. The
following areas represent those that management believes are particularly
important to the financial statements and that require the use of estimates and
assumptions to describe matters that are inherently uncertain:
Accounting for Derivative Instruments
Exelon uses derivative financial instruments primarily to manage its commodity
price and interest rate risks. Derivative financial instruments are accounted
for under SFAS No. 133. Accounting for derivatives continues to evolve through
guidance issued by the Derivatives Implementation Group (DIG) of the Financial
Accounting Standards Board. To the extent that changes by the DIG modify current
guidance, including the normal purchases and normal sales determination, the
accounting treatment for derivatives may change.
Energy Contracts To manage its utilization of generation supply (including owned
and contracted assets), Exelon enters into contracts to purchase or sell
electricity, fossil fuels, and ancillary products such as transmission rights
and congestion credits, and emission allowances. These energy marketing
contracts are considered derivatives under SFAS 133 unless a determination is
made that they qualify for a SFAS No. 133 normal purchases and normal sales
exclusion. If the exclusion applies, those contracts are not marked-to-market
and are not reflected in the financial statements until delivery occurs.
The availability of the normal purchases and normal sales exclusion to
specific contracts is based on a determination that excess generation is
available for a forward sale and similarly a determination that at certain times
generation supply will be insufficient to serve load. This determination is
based on internal models that forecast customer demand and generation supply.
The 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. The critical assumptions used in the determination of normal purchases
and normal sales are consistent with assumptions used in the general corporate
planning process.
17
Energy contracts that are considered derivatives may be eligible for
designation as hedges. If a contract is designated as a hedge, the change in its
market value is generally deferred as a component of other comprehensive income
until the transaction it is hedging is completed. Conversely, the change in the
market value of derivatives not designated as hedges is recorded in current
period earnings. To qualify as a cash flow hedge, 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. The effectiveness of an energy contract
designated as a hedge is determined by internal models that measure the
statistical correlation between the derivative and the associated hedged item.
When external quoted market prices are not available, Exelon utilizes the
Black model, a standard industry valuation model to determine the fair value of
energy derivative contracts marked to market. The valuation model uses
volatility assumptions relating to future energy prices based on specific energy
markets and utilizes externally available forward market price curves.
Interest Rate Derivatives Exelon utilizes derivatives to manage its exposure to
fluctuation in interest rates related to outstanding variable rate debt
instruments and planned future debt issuances as well as exposure to changes in
the fair value of outstanding debt that is planned for early retirement. Hedge
accounting is used for all interest rate derivatives to date based on the
probability of the transaction and the expected highly effective nature of the
hedging relationship between the interest rate swap contract and the interest
payment or changes in fair value of the hedged debt. Dealer quotes are available
for all of Exelon's interest rate swap agreement derivatives.
Regulatory Assets and Liabilities
Regulatory assets represent incurred costs that have been deferred because they
are probable of future recovery in customer rates. Regulatory liabilities
represent previous collections from customers to fund costs which have not yet
been incurred.
Both ComEd and PECO are currently subject to rate freezes that limit the
opportunity to recover increased costs and the costs of new investment in
facilities through rates during the rate freeze period. Current rates include
the recovery of Exelon's existing regulatory assets. Exelon continually assesses
whether the regulatory assets are probable of future recovery by considering
factors such as applicable regulatory environment changes, recent rate orders to
other regulated entities in the same jurisdiction, and the status of any pending
or potential deregulation legislation. If future recovery of costs ceases to be
probable the assets would be required to be recognized in current period
earnings.
Nuclear Decommissioning
Exelon's current estimate of its nuclear facilities' decommissioning cost is
$7.2 billion in current year (2002) dollars. Calculating this estimate involves
significant assumptions with respect to the expected increases in
decommissioning costs relative to general inflation rates, changes in the
regulatory environment or regulatory requirements, and the timing of
decommissioning. The estimated service life of the nuclear station is also a
significant assumption because decommissioning costs are generally recognized
over the life of the generating station. Cost estimates for decommissioning
Exelon's nuclear facilities have been prepared by an independent engineering
firm and reflect currently existing regulatory requirements and available
technology. Nuclear station service lives, over which the decommissioning costs
are recognized, were extended by 20 years in 2001. The life extension is subject
to NRC approval of an extension of existing NRC operating licenses, which
generally are 40 years. The obligation for decommissioning currently operating
plants is recorded in accumulated depreciation consistent with industry
practice. As discussed in New Accounting Pronouncements, this accounting will be
affected by the adoption of SFAS No. 143, "Asset Retirement Obligations" (SFAS
No. 143) effective January 1, 2003. See Notes 1 and 12 of the Notes to the
Consolidated Financial Statements for further information regarding the
accounting for decommissioning.
18
Unbilled Energy Revenues
Revenues related to the sale of energy are generally recorded when service is
rendered or energy is delivered to customers. However, the determination of the
energy sales to individual customers is based on the reading of their meters
which are read on a systematic basis throughout the month. At the end of each
month, amounts of energy delivered to customers since the date of the last meter
reading are estimated and the corresponding unbilled revenue is estimated. This
unbilled revenue is estimated each month based on daily generation volumes,
estimated customer usage by class, line losses and applicable customer rates
based on regression analyses reflecting significant historical trends and
experience. Customer accounts receivable as of December 31, 2001 include
unbilled energy revenues of $361 million.
Contract Accounting
Enterprises recognizes contract revenue and profits on certain long-term
fixed-price contracts by the percentage-of-completion method of accounting. In
determining the amount of revenue to recognize Exelon is required to estimate
the total costs and profits expected to be recorded under the contract over its
contract term, and the recoverability of costs related to change orders. Changes
in these estimates could result in the recognition of differences in earnings.
Environmental Costs
As of December 31, 2001 Exelon had accrued liabilities of $156 million for
environmental investigation and remediation costs. The liabilities are based
upon estimates with respect to the number of sites for which Exelon will be
responsible, the scope and cost of work to be performed at each site, the
portion of costs that will be shared with other parties and the timing of the
remediation work. Where timing and amounts of expenditures can be reliably
estimated, amounts are discounted. Where timing and amounts cannot be reliably
estimated, a range is estimated and the low end of the range is recognized on an
undiscounted basis. Estimates can be affected by factors including future
changes in technology, changes in regulations or requirements of local
governmental authorities and actual costs of disposal.
Outlook
Changes in the Utility Industry
The electric utility industry in the United States remains in transition. It is
moving from a fully regulated industry, consisting primarily of integrated
companies combining generation, transmission and distribution, to competitive
wholesale generation markets with continuing regulation of transmission and
distribution. The transition has resulted in substantial disposition of
generating assets by formerly integrated companies, the creation of separate,
and in some cases, stand alone, generating companies and consolidation. During
2001, however, the pace of transition slowed. This slowdown was due primarily to
public and governmental reactions to issues associated with deregulation efforts
in California and the collapse of the wholesale electricity market in
California.
At the Federal level, the FERC remains committed to the development of
wholesale generation markets. Although its proposal for the development of large
regional transmission organizations (RTOs) to facilitate markets has been
delayed, it is planning an initiative to standardize wholesale markets in the
United States. At the state level, concerns raised by the California experiences
have stalled new retail competition initiatives and slowed the separation of
generation from regulated transmission and distribution assets.
Exelon believes that the transition in the electric utility industry will
continue, albeit at a slower pace than previously, particularly at the state
level. This slower transition will be reflected in reduced industry
consolidation in the near term and reduced disaggregation of regulated to
unregulated services. These uncertainties may limit opportunities for Exelon to
pursue its plans to expand its generation portfolio.
Exelon also believes that competition for electric generation services has
created new risks and uncertainties in the industry. Some of these risks were
clearly illustrated in California - the risks of inadequate generation, having
load obligations without owning generation, and price volatility. The situation
in California also illustrated the need for additional infrastructure to support
competitive markets. The uncertainties include future prices of generation
services in both the
19
wholesale and retail markets, supply and demand volatility, and changes in
customer profiles that may impact margins on various electric service offerings.
These uncertainties create additional risk for participants in the industry,
including Exelon, and may result in increased volatility in operating results
from year to year.
Energy Delivery
Exelon believes that its energy delivery business will provide a significant and
steady source of earnings for investment in growth opportunities. Exelon's
primary goals for its energy delivery companies, ComEd and PECO, are to deliver
reliable service, to improve customer service and to sustain productive
regulatory relationships. Achieving these goals is expected to maximize the
value of Exelon's energy delivery assets.
Under restructuring regulations adopted at the Federal and state levels,
the role of electric utilities in the supply and delivery of energy is changing.
Energy Delivery continues to be obligated to provide reliable delivery systems
under cost-based rates. It remains obligated, as a provider of last resort, to
supply generation service during the transition period to a competitive supply
marketplace to customers who do not or cannot choose an alternate supplier.
Retail competition for generation services has resulted in reduced revenues from
regulated rates and the sale of increasing amounts of energy at market-based
rates.
Energy Delivery's revenues will be affected by rate reductions and rate
freezes currently in effect at ComEd and PECO. The rate freezes limit Energy
Delivery's ability to recover increased expenses and the costs of investments in
new transmission and distribution facilities through rates. As a result, Energy
Delivery's future results of operations will be dependent on its ability:
- - to deliver electricity and, in the case of PECO, gas, to its customers
cost-effectively, particularly in light of the current caps on rates and
ComEd capital expenditure requirements,
- - to realize cost savings from the Merger and synergies to offset increased
costs on new investments and inflation while its delivery rates are capped
and,
- - to manage its provider of last resort responsibilities.
ComEd's results of operations will be affected by a legislatively mandated
5% residential base rate reduction that became effective in October 2001, a base
rate freeze that will remain generally effective until at least January 1, 2005
and the collection of transition charges through at least 2006. PECO's results
of operations will be affected by 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 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.
ComEd's obligations to make capital expenditures, combined with the rate
freeze, could affect its earnings during the rate freeze period. ComEd is
obligated to make capital expenditures with respect to its transmission and
distribution system, including defined projects within the City of Chicago
(City) as a result of a settlement agreement with the City and at least $2
billion during the period 1999 through 2004 on transmission and distribution
facilities outside of the City as a result of Illinois legislation. Given
ComEd's commitments to improve the reliability of its transmission and
distribution system, ComEd expects that its capital expenditures will exceed
depreciation on its rate base assets through at least 2002. The base rate freeze
will generally preclude rate recovery on and of those investments prior to
January 1, 2005. Unless ComEd can offset the additional carrying costs against
cost savings, its return on investment may be reduced during the period of the
rate freeze and until rate increases are approved authorizing a return of and on
this new investment.
PECO's results will be affected by annual increases in amortization of its
stranded cost recovery through 2010. PECO has been authorized to recover
stranded costs of $5.3 billion ($4.9 billion of unamortized costs at December
31, 2001) over a twelve-year period ending December 31, 2010 with a return on
the unamortized balance of 10.75%. In 2001, revenue attributable to stranded
cost recovery was $797 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 2001 was $271 million and will
increase to $879 million by 2010.
A substantial portion of Energy Delivery's customers have the right to
choose their electricity suppliers. All of ComEd's non-residential customers
have this right, and all of its residential customers will have this right as of
May 1, 2002. All of PECO's retail customers have this right. At December 31,
2001, approximately 21% of ComEd's small commercial and
20
industrial load, and 42% of its large commercial and industrial load were
purchasing their electric energy from an alternative electric supplier or chose
the purchase power option, and approximately 28% of PECO's residential load, 6%
of its small commercial and industrial load and 5% of its large commercial and
industrial load were purchasing generation service from an alternate supplier.
Provider of last resort (POLR) obligations refer to the obligation of a
utility to provide generation services (i.e., power and energy) to those
customers who do not take service from an alternative generation supplier or who
choose to come back to the utility after taking service from an alternative
supplier. Because the choice lies with the customer, these obligations make it
difficult for the utility to predict and plan for the level of customers and
associated energy demand. If these obligations remain unchanged, the utility
could be required to maintain reserves sufficient to serve 100% of the service
territory load at a tariffed rate on the chance that customers who switched to
new suppliers decide to come back to the utility as a "last resort" option. A
significant over or under estimation of such reserves may cause commodity price
risks for suppliers. Both ComEd and PECO have entered into long-term agreements
with Generation to procure their power needs and achieve some certainty during
the next several years with respect to these obligations. ComEd's agreement
allows it to obtain sufficient power at fixed rates. PECO's agreement allows it
to obtain sufficient power at the rates it is allowed to charge to serve
customers who do not choose alternate generation suppliers.
In Illinois, utilities are required to offer bundled rates frozen at levels
established prior to restructuring legislation until January 2005. The provider
of last resort issue requires resolution in the near term, as the answer will
affect pricing, competitive market development and planning by utilities,
alternate suppliers and customers. ComEd has made an informal proposal,
regarding its future provider of last resort obligations. The proposal seeks to
balance the desire for a reliable supply of electricity at a reasonable price
with more price certainty for smaller customers, such as residential customers,
while continuing to develop a functioning competitive wholesale market for
generation services. The proposal offers large customers a default power and
energy offering at spot market rates, thereby freeing the utility from
maintaining a long-term portfolio and making that capacity available to
alternative suppliers. The proposal affords certainty of supply for large
customers, but not price certainty. Recognizing that small customers may not yet
have the same competitive options as large customers, the proposal offers small
customers both supply and price certainty, protecting those customers from
market volatility. The proposal would require regulatory action in order to
become effective, and no assurance can be provided as to the timing of such
action or the ultimate result of such action.
PECO's rates for generation services are generally capped through December
2010. Accordingly, the provider of last resort issue for PECO also requires
resolution, but in a longer timeframe.
Transmission. Energy Delivery provides wholesale transmission service under
rates established by FERC. FERC has used its regulation of transmission to
encourage competition for wholesale generation services and the development of
regional structures to facilitate regional wholesale markets. In December 1999,
FERC issued Order No. 2000 (Order 2000) requiring jurisdictional utilities to
file a proposal to form a regional transmission organization (RTO) or,
alternatively, to describe efforts to participate in or work toward
participating in an RTO or explain why they were not participating in an RTO.
Order 2000 is generally designed to separate the governance and operation of the
transmission system from generation companies and other market participants.
In response to Order 2000, ComEd and several other utilities filed a
business plan in August 2001 with FERC describing the creation of Alliance
Transmission Company, LLC (Alliance Transco or Alliance) as an independent,
for-profit transmission company. In connection with the process leading to the
FERC filing, ComEd issued a non-binding declaration of intent to divest to
Alliance Transco transmission facilities having a gross book value in excess of
$1 billion. In a related action, ComEd entered into a non-binding memorandum of
understanding with National Grid USA (National Grid), the proposed manager of
Alliance Transco, setting forth general principles relating to the divestiture
and Alliance Transco as a basis for further discussion.
On December 20, 2001, FERC issued several orders relating to RTOs operating
in the Midwest. In those orders, FERC, among other things, approved Midwest
Independent Transmission System Operator, Inc. (MISO) as an RTO and found that
Alliance Transco lacked sufficient scope to be a stand-alone RTO. FERC also
directed the Alliance participants to explore with the MISO how the
21
participants' business plan can be accommodated with the MISO operational
framework and dismissed the business plan filed in August 2001 by the Alliance
participants. In addition, FERC determined that National Grid is not a market
participant within the meaning of Order 2000 and, thus, is eligible to become
the managing member of Alliance Transco if that entity is formed. FERC further
directed the Alliance participants to file a statement of their plans to join an
RTO, including timeframes, within 60 days. As a result of the FERC orders,
representatives of ComEd and the other Alliance participants are exploring
various RTO participation options and are meeting with representatives of MISO
to explore how the Alliance Transco may operate under the MISO.
The Alliance participants, including ComEd, filed their discussions with
MISO at the FERC in February 2002, noting progress as to some issues, but also
noted negotiations were ongoing. The Alliance participants also noted that they
were exploring the possibility of filing their business plan within an RTO other
than MISO.
PECO provides regional transmission service pursuant to a regional
open-access transmission tariff filed by it and the other transmission owners
who are members of PJM. PJM is a power pool that integrates, through central
dispatch, the generation and transmission operations of its member companies
across a 50,000 square mile territory. Under the PJM tariff, transmission
service is provided on a region-wide, open-access basis using the transmission
facilities of the PJM members at rates based on the costs of transmission
service. PJM's Office of Interconnection is the ISO for PJM (PJM ISO) and is
responsible for operation of the PJM control area and administration of the PJM
open-access transmission tariff. PECO and the other transmission owners in PJM
have turned over control of their transmission facilities to the PJM ISO. The
PJM ISO and the transmission owners who are members of PJM, including PECO, have
filed with FERC for approval of PJM as an RTO. FERC has conditionally approved
the PJM RTO.
Generation
Exelon believes that its generation and energy marketing business will be the
primary growth vehicle in the near term. Exelon's generation strategy is to
develop a national generation portfolio with fuel and dispatch diversity, to
recognize the cost savings and operational benefits of owning and operating
substantial generating capacity and to optimize the value of Exelon's low-cost
generating capacity through energy marketing expertise.
Generation competes nationally in the wholesale electric generation markets
on the basis of price and service offerings, utilizing its generation portfolio
to assure customers of energy deliverability. Generation's generating capacity
is primarily located in the Midwest, Mid-Atlantic and Northeast regions.
Generation owns a 50% interest in AmerGen and a 49.9% interest in Sithe.
Generation has agreed to supply ComEd and PECO with their respective load
requirements for customers through 2006 and 2010, respectively. Longer term,
ComEd and PECO supply requirements will be significantly impacted by the
resolution of their POLR obligations and the extent of retail customer
switching. Generation's future results will be impacted by these uncertainties
and in turn, their impact on power purchase agreements with others, including
Midwest Generation. Generation has also contracted with Exelon Energy, the
competitive retail energy services subsidiary of Enterprises, to meet its load
requirements pursuant to its competitive retail generation sales agreements. In
addition, Generation has contracts to sell energy and capacity to third parties.
To the extent that Generation's resources exceed its contractual commitments, it
markets these resources on a short-term basis or sells them in the spot market.
Generation's future results of operations are dependent upon its ability to
operate its generating facilities efficiently to meet its contractual
commitments and to sell energy services in the wholesale markets. A substantial
portion of Generation's capacity, including all of the nuclear capacity, is base
load generation designed to operate for extended periods of time at low marginal
costs. Nuclear generation is currently the most cost effective way for
Generation to meet its commitments for sales to Energy Delivery and other
utilities. During 2001, the nuclear generating fleet, including AmerGen operated
at a 94.4% weighted average capacity factor. To cost effectively meet its
long-term commitments to provide energy, including its commitment to meet the
provider of last resort load obligations of ComEd and PECO, Generation must
consistently operate its nuclear generating facilities at high capacity factors.
Generation's planned nuclear capacity factor for 2002 is 91%. Failure to achieve
this capacity level would require Generation to contract or purchase in the spot
market more expensive energy to meet these commitments. Because of Generation's
reliance on nuclear facilities, any changes in regulations by the NRC requiring
additional investments or resulting in increased operating or decommissioning
costs of nuclear generating units could adversely affect Generation.
22
The operating results of Generation depend on its level of sales and, for
market sales, on the price of electricity, which is subject to significant
volatility. Sales and market prices both depend on the demand for electricity.
Consequently, operating results are expected to be stronger in the first and
third quarters of each year when the winter and summer peak demand periods
occur. Additionally, Generation's results of operations are impacted by
refueling outages of its nuclear units, which reduce the generating availability
of its nuclear units, as well as increasing maintenance and capital
expenditures. The number of refueling outages, including AmerGen, is expected to
increase to eleven in 2002 from six in 2001. Maintenance and capital
expenditures are expected to increase by $80 million and $24 million,
respectively in 2002 as compared to 2001 as a result of the additional nuclear
refueling outages.
Generation intends to continue to grow its generation portfolio through
asset acquisitions, development of new plants, innovative application of
technology, joint ventures and long-term contracts. New investments in
generation, whether purchased or developed, are dependent on the future success
of both the bilateral and spot energy wholesale markets, which are newly created
and continuing to develop. Regardless of the approach, Generation intends to
remain disciplined in its opportunities to expand its generation portfolio,
including its evaluation of the potential return on investments as well as the
risks of investments.
Generation's wholesale marketing unit, Power Team, uses Generation's
generation portfolio, transmission rights and expertise to ensure delivery of
generation to wholesale customers under long-term and short-term contracts.
Power Team is responsible for supplying the load requirements of ComEd and PECO
and markets the remaining energy in the wholesale markets. Power Team also buys
and sells power in the wholesale markets. Trading activities were initiated in
2001 and represent a small portion of Power Team's activity. As of December 31,
2001, trading activities accounted for less than 1% of Generation's EBIT.
Trading activities are expected to increase modestly in 2002 and trading
activity growth will be dependent on the continued development of the wholesale
energy markets and Power Team's ability to manage trading and credit risks in
those markets. The spot markets also involve the credit risks of market
participants purchasing energy, which Generation may not be able to manage or
hedge. Generation uses financial trading, primarily to complement the marketing
of its generation portfolio. Generation intends to manage the risk of these
activities through a mix of long-term and short-term supply obligations and
through the use of established policies, procedures and trading limits.
Financial trading, together with the effects of SFAS No. 133, may cause
volatility in Exelon's future results of operations.
Generation has entered into purchase power agreements (PPAs) dated December
18, 2001 and November 22, 1999 with AmerGen. Under the 2001 PPA, Exelon has
agreed to purchase from AmerGen all the energy from Unit No. 1 at Three Mile
Island Nuclear Station after December 31, 2001 through December 31, 2014. Under
the 1999 PPA, Generation has agreed to purchase from AmerGen all of the residual
energy from Clinton through December 31, 2002. Currently, the residual output
approximates 25% of the total output of Clinton. In 2001, the amount of power
purchased from AmerGen recorded in Fuel and Purchased Power in the Consolidated
Statements of Income was $57 million.
In addition, under a service agreement dated March 1, 1999, Generation
provides AmerGen with certain operation and support services to the nuclear
facilities owned by AmerGen. This service agreement has an indefinite term and
may be terminated by Generation or by AmerGen on 90 days' notice. Generation is
compensated for these services in an amount agreed to in the work order but not
less than the higher of fully allocated costs for performing the services or the
market price. The amount charged to AmerGen for these services in 2001 was $80
million.
Enterprises
Enterprises consists primarily of the infrastructure services business of
InfraSource, Inc. (InfraSource), the energy services business of Exelon
Services, Inc., the competitive retail energy sales business of Exelon Energy,
Inc., 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. InfraSource,
formerly Exelon Infrastructure Services, Inc. (EIS), was renamed effective
November 15, 2001 in order to effectively unite all of the EIS companies under
one brand name. Enterprises' results of operations will be affected by its
ability:
- - to integrate various acquired businesses in the infrastructure services
business so as to realize synergies and cost savings, and
- - to rationalize certain investments either by improving margins or, in
appropriate cases, by disposition to third parties.
23
The results of InfraSource's infrastructure services business and Exelon
Services' energy services business are dependent on demand for outsourced
construction and maintenance services. That demand has been driven in the past
by the restructuring of the electric utility industry and growth of the
communications, cable and internet industries. Slowdown in that restructuring
and the current condition of the communications, cable and internet industries
means that results will be driven by efforts to manage costs and achieve
synergies.
Exelon Energy's competitive retail energy sales business is dependent upon
continued deregulation of retail electric and gas markets and its ability to
obtain supplies of electricity and gas at competitive prices in the wholesale
market. The low margin nature of the business makes it important to achieve
concentrations of customers with higher volumes so as to manage costs.
Enterprises' investments are weighted toward the communications industry,
but also include companies in energy services and retail services, including
e-commerce. Investments in the communications industries have included joint
ventures with established companies. Investments in other areas have generally
been in new entrepreneurial companies with technologies and applications for the
deregulating energy marketplace. Enterprises continually monitors the
performance and potential of its investments and evaluates opportunities to sell
existing investments and to make new investments. In the past, Exelon has been
required to write-off or write-down certain investments. The sale, write-down,
or write-off of investments may increase the volatility of earnings. The
adoption of SFAS No. 142 is expected to result in an impairment of Enterprises'
goodwill which will be recorded in the first quarter of 2002. See New Accounting
Pronouncements.
Other Factors
Inflation affects Exelon through increased operating costs and increased capital
costs for electric plant. As a result of the rate caps imposed under the
legislation in Illinois and Pennsylvania and price pressures due to competition,
Exelon may not be able to pass the costs of inflation through to customers.
In 2001, Exelon made several changes to its pension plans and
postretirement benefit plans including consolidating the former Unicom and PECO
plans into Exelon plans. Also, a cash balance pension plan was adopted to cover
essentially all management and electing union employees hired on or after
January 1, 2001. Management employees who were active participants in the former
Unicom and PECO pension plans on December 31, 2000 and remain employed by Exelon
on January 1, 2002, will have the opportunity to continue to participate in the
pension plan or to transfer to the cash balance plan. Exelon also adopted an
amendment to the former Unicom postretirement medical benefit plan that changed
the eligibility requirement of the plan to cover employees taking their pensions
with ten years of service after age 45 rather than ten years of service and
having attained the age of 55.
Exelon's costs of providing pension and postretirement benefits to its
retirees is dependent upon a number of factors, such as the discount rate, rates
of return on plan assets, and the assumed rate of increase in health care costs.
Although Exelon's pension and postretirement expense is determined using
three-year averaging and is not as vulnerable to a single year's change in
rates, these costs are expected to increase in 2002 and beyond as the result of
the above noted plan changes along with the affects of the decline in market
value of plan assets, changes in appropriate assumed rates of return on plan
assets and discount rates, and increases in health care costs. For a discussion
of Exelon's pension and postretirement benefit plans, see Note 16 of the Notes
to Consolidated Financial Statements.
Environmental Exelon's operations have in the past and may in the future require
substantial capital expenditures in order to comply with environmental laws.
Additionally, under Federal and state environmental laws, Exelon is generally
liable for the costs of remediating environmental contamination of property now
or formerly owned by Exelon and of property contaminated by hazardous substances
generated by Exelon. Exelon owns or leases a number of real estate parcels,
including parcels on which its operations or the operations of others may have
resulted in contamination by substances that are considered hazardous under
environmental laws. Exelon has identified 72 sites where former manufactured gas
plant (MGP) activities have or may have resulted in actual site contamination.
Exelon is currently involved in a number of proceedings relating to sites where
hazardous substances have been deposited and may be subject to additional
proceedings in the future.
As of December 31, 2001 and 2000, Exelon had accrued $156 million and $172
million, respectively, for environmental investigation and remediation costs,
including $127 million and $140 million, respectively, for MGP investigation and
remediation that currently can be reasonably estimated. Exelon expects to expend
$35 million for environmental remediation
24
activities in 2002. Exelon cannot predict whether it will incur other
significant liabilities for any additional investigation and remediation costs
at these or additional sites identified by Exelon, environmental agencies or
others, or whether such costs will be recoverable from third parties.
Security Issues and Other Impacts of Terrorist Actions The events of September
11, 2001 have affected Exelon's operating procedures and costs and are expected
to affect the cost and availability of the insurance coverages that Exelon
carries. Exelon has initiated security measures to safeguard its employees and
critical operations and is actively participating in industry initiatives to
identify methods to maintain the reliability of its energy production and
delivery systems. It is expected that governmental authorities will be working
to ensure that emergency plans are in place and that critical infrastructure
vulnerabilities are addressed. The electric utility industry is proposing
security guidelines rather than government mandated standards to protect
critical infrastructures. It is not known if Federal standards will be issued to
the electric or gas industries. Exelon is evaluating enhanced security measures
at certain critical locations, enhanced response and recovery plans and
assessing longer term design changes and redundancy measures. These measures
will involve additional expense to develop and implement.
The NRC has placed all nuclear generating plants on its highest alert
status, requiring increased security measures, enhanced communication with
authorities at all levels of government and enhanced physical barriers. These
additional measures are estimated to cost between $600,000 and $900,000 annually
for each of Exelon's ten operating plants. Exelon can not predict how long the
NRC will keep nuclear plants on this status. The NRC also has undertaken an
initiative to perform a "top to bottom" review of nuclear security in light of
the September 11, 2001 events. Exelon cannot predict when the NRC review will be
completed or whether additional actions and expenditures will be required as a
result.
Exelon carries nuclear liability insurance. The Price-Anderson Act limits
the liability of nuclear reactor owners for claims arising 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.
Through its subsidiaries, Exelon carries the maximum available commercial
insurance of $200 million. The remaining $9.3 billion is provided through
mandatory participation in a financial protection pool. Exelon cannot predict
the effects on operations of the August 2002 expiration of the Price-Anderson
Act.
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. Exelon is self-insured to the extent that any
losses may exceed the amount of insurance maintained. Nuclear Electric Insurance
Limited (NEIL), a mutual insurance company to which Exelon belongs, provides
property and business interruption insurance for Exelon's nuclear operations. In
recent years, NEIL has made distributions to its members. Exelon's distribution
for 2001 is $69 million, which was recorded as a reduction to Operating and
Maintenance expense on Exelon's Consolidated Statements of Income. Due in part
to the September 11, 2001 events, Exelon cannot predict the level of future
distributions, although they are expected to be lower than recent levels.
Exelon does not carry any business interruption insurance other than the
NEIL coverage for nuclear operations. Damage to Energy Delivery's properties
could disrupt the distribution of its and Generation's product and significantly
and adversely affect results of operations. Exelon cannot predict the effects on
operations of the availability of property damage and liability coverage or any
disruptions to its delivery facilities.
For a discussion of nuclear insurance and other contingencies, see Note 20
of the Notes to Consolidated Financial Statements.
New Accounting Pronouncements
In 2001, the FASB issued SFAS No. 141, "Business Combinations" (SFAS No. 141),
SFAS No. 142, SFAS No. 143, and SFAS No. 144 "Accounting for the Impairment or
Disposal of Long-Lived Assets" (SFAS No. 144).
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. SFAS No. 141
is effective for business combinations initiated after June 30, 2001.
SFAS No. 142 establishes new accounting and reporting standards for
goodwill and intangible assets. Exelon adopted SFAS No. 142 as of January 1,
2002. Under SFAS No. 142, effective January 1, 2002, goodwill recorded by Exelon
is no longer subject to amortization. After January 1, 2002, goodwill will be
subject to an assessment for impairment using a two-step fair value
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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 first step compares the fair value of a reporting unit to its carrying
amount, including goodwill. If the carrying amount of the reporting unit exceeds
its fair value, the second step is performed. The second step compares the
carrying amount of the goodwill to the fair value of the goodwill. If the fair
value of goodwill is less than the carrying amount, an impairment loss would be
reported as a reduction to goodwill and a charge to operating expense, except at
the transition date, when the loss would be reflected as a cumulative effect of
a change in accounting principle. As of December 31, 2001, Exelon's Consolidated
Balance Sheets reflected approximately $5.3 billion in goodwill net of
accumulated amortization, including $4.9 billion of net goodwill related to the
merger of Unicom and PECO recorded on ComEd's Consolidated Balance Sheets, with
the remainder related to Enterprises. Annual amortization of goodwill related to
the Merger and to Enterprises of $126 million and $24 million, respectively, was
discontinued upon adoption of SFAS No. 142. Exelon has completed the first step
of the transitional impairment analysis which indicated that the ComEd goodwill
is not impaired but that an impairment exists with respect to the Enterprises
goodwill. The second step of the analysis, which will compare the fair value of
the Enterprises goodwill to the $433 million carrying value at December 31, 2001
has not yet been completed. The second step analysis is expected to be
completed, and the transitional impairment loss recognized, in the first quarter
of 2002 as a Cumulative Effect of a Change in Accounting Principle.
SFAS No. 143 provides accounting requirements for retirement obligations
associated with tangible long-lived assets. Exelon expects to 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
Exelon's nuclear generating plants. Currently, Exelon records the obligation for
decommissioning ratably over the lives of the plants. The January 1, 2003
adoption of this standard will require a cumulative effect adjustment effective
the date of adoption to adjust plant assets and decommissioning liabilities to
the values they would have been had this standard been employed from the
in-service dates of the plants.
The effect of this cumulative adjustment will be to increase the
decommissioning liability to reflect a full decommissioning obligation in
current year dollars. Additionally, the standard will require the accrual of an
asset related to the full amount of the decommissioning obligation, which will
be amortized over the remaining lives of the plants. The difference between the
asset recognized and the liability recorded upon adoption of the standard will
be charged to earnings and recognized as a cumulative effect, net of expected
regulatory recovery. The decommissioning liability to be recorded represents an
obligation for the future decommissioning of the plants, and as a result
interest expense will be accrued on this liability until such time as the
obligation is satisfied.
Exelon is in the process of evaluating the impact of SFAS No. 143 on its
financial statements, and cannot determine the ultimate impact of adoption at
this time, however the cumulative effect could be material to Exelon's earnings.
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 currently recognized as decommissioning expense, 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 could result in an
increase in expense.
SFAS No. 144 establishes accounting and reporting standards for both the
impairment and disposal of long-lived assets. This statement is effective for
fiscal years beginning after December 15, 2001 and provisions of this statement
are generally applied prospectively. Exelon is in the process of evaluating the
impact of SFAS No. 144 on its financial statements, and does not expect the
impact to be material.
Forward-Looking Statements
Except for the historical information contained herein, 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 discussed herein as well as those listed in Note 20 of
the Notes to Consolidated Financial Statements and other factors discussed in
Exelon's filings with the SEC. Readers are cautioned not to place undue reliance
on these forward-looking statements, which speak only as of the date of this
Report. Exelon undertakes no obligation to publicly release any revision to
these forward-looking statements to reflect events or circumstances after the
date of this Report.
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