UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
February 28, 2002
(Date of earliest
event reported)
Commission File Name of Registrant; State of Incorporation; Address of IRS Employer
Number Principal Executive Offices; and Telephone Number Identification Number
- --------------------- --------------------------------------------------------- -------------------------
1-16169 EXELON CORPORATION 23-2990190
(a Pennsylvania corporation)
10 South Dearborn Street - 37th Floor
P.O. Box 805379
Chicago, Illinois 60680-5379
(312) 394-4321
Item 5. Other Events
The purpose of the Current Report is to file certain financial information
regarding Exelon Corporation and Subsidiary Companies. Such financial
information is set forth in the exhibits to this Current Report.
Item 7. Financial Statements and Exhibits
(c) Exhibits.
23 Consent of the Independent Public Accountants
99-1 Selected Financial Data
99-2 Market for Registrant's Common Equity and Related Stockholder Matters
99-3 Management's Discussion and Analysis of Financial Condition and
Results of Operations
99-4 Financial Statements and Supplementary Data
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned hereunto duly authorized.
EXELON CORPORATION
/S/ Ruth Ann Gillis
--------------------------
Ruth Ann Gillis
Senior Vice President and
Chief Financial Officer
February 28, 2002
Exhibit 23
CONSENT OF INDEPENDENT ACCOUNTANTS
----------------------------------
We hereby consent to the incorporation by reference in the Registration
Statement on Form S-3 (File No. 333-57640), on Form S-4 (File No. 333-37082) and
on Form S-8 (File Nos. 333-61390 and 333-49780) of Exelon Corporation and
Subsidiary Companies of our report dated January 29, 2002, except for Note 25
for which the date is March 1, 2002, relating to the financial statements, which
is included as an Exhibit in the Current Report on Form 8-K.
PricewaterhouseCoopers LLP
Chicago, Illinois
March 7, 2002
Exhibit 99-1
Exelon Corporation and Subsidiary Companies
Selected Financial Data
Selected Financial Data
For the Years Ended December 31,
---------------------------------------------------------------
in millions, except for per share data 2001 2000 (a) 1999 1998 1997
- -------------------------------------------------------------------------------------------------------------
Statement of Income Data:
Operating Revenues $ 15,140 $ 7,499 $ 5,478 $ 5,325 $ 4,601
Operating Income 3,362 1,527 1,373 1,268 1,006
Income before Extraordinary Items and
Cumulative Effect of Changes in
Accounting Principles 1,416 566 607 520 320
Extraordinary Items (net of income taxes) -- (4) (37) (20) (1,834)
Cumulative Effect of Changes in
Accounting Principles 12 24 -- -- --
Net Income (Loss) 1,428 586 570 500 (1,514)
- -------------------------------------------------------------------------------------------------------------
Earnings per Common Share (Diluted):
Income Before Extraordinary Items and
Cumulative Effect of Changes in
Accounting Principles $ 4.39 $ 2.77 $ 3.08 $ 2.32 $ 1.44
Extraordinary Items -- (0.02) (0.19) (0.09) (8.24)
Cumulative Effect of Changes in
Accounting Principles 0.04 0.12 -- -- --
- -------------------------------------------------------------------------------------------------------------
Net Income (Loss) $ 4.43 $ 2.87 $ 2.89 $ 2.23 $ (6.80)
=============================================================================================================
Dividends per Common Share $ 1.82 $ 0.91 $ 1.00 $ 1.00 $ 1.80
=============================================================================================================
Average Shares of Common Stock
Outstanding - Diluted 322 204 197 224 223
=============================================================================================================
at December 31,
---------------------------------------------------------------
2001 2000 (a) 1999 1998 1997
- -------------------------------------------------------------------------------------------------------------
Balance Sheet Data:
Current Assets $ 3,782 $ 4,151 $ 1,221 $ 582 $ 1,003
Property, Plant and Equipment, net 13,742 12,936 5,004 4,804 4,671
Deferred Debits and Other Assets 17,297 17,699 6,862 6,662 6,683
- -------------------------------------------------------------------------------------------------------------
Total Assets $ 34,821 $ 34,786 $ 13,087 $ 12,048 $ 12,357
=============================================================================================================
Current Liabilities $ 4,417 $ 4,993 $ 1,286 $ 1,735 $ 1,619
Long-Term Debt 12,876 12,958 5,969 2,920 3,853
Deferred Credits and Other Liabilities 8,685 8,990 3,738 3,756 3,576
Preferred Securities of Subsidiaries 613 630 321 579 582
Shareholders' Equity 8,230 7,215 1,773 3,058 2,727
- -------------------------------------------------------------------------------------------------------------
Total Liabilities and
Shareholders' Equity $ 34,821 $ 34,786 $ 13,087 $ 12,048 $ 12,357
=============================================================================================================
(a) Reflects the effects of the Unicom Merger (October 20, 2000).
Exhibit 99-2
Exelon Corporation and Subsidiary Companies
Market for Registrant's Common Equity and Related Stockholder Matters
Market for Registrant's Common Equity and Related Stockholder Matters
Exelon Corporation's (Exelon) common stock is listed on the New York Stock
Exchange. The following table sets forth the high and low sales prices and
closing prices for Exelon's common stock for the past two years. The information
presented in the table below prior to October 20, 2000 represents PECO Energy
Company.
2001 2000
----------------------------------------- --------------------------------------------
Fourth Third Second First Fourth Third Second First
Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter
- ----------------------------------------------------------------------------------------------------------
High Price $ 48.69 $ 67.65 $ 70.26 $ 69.75 $ 71.00 $ 61.38 $ 46.81 $ 43.69
Low Price $ 39.65 $ 38.75 $ 62.10 $ 53.60 $ 53.88 $ 40.50 $ 36.56 $ 33.00
Close $ 47.88 $ 44.60 $ 64.12 $ 65.60 $ 70.21 $ 60.58 $ 40.31 $ 36.88
Dividends $ 0.43 $ 0.42 $ 0.42 $ 0.55 (a) $ 0.16 $ 0.25 $ 0.25 $ 0.25
- ----------------------------------------------------------------------------------------------------------
(a) The first quarter dividend in 2001 was a pro rata dividend. Unicom and PECO Energy each paid their
shareholders pro rata, per diem dividends from their last regular dividend dates through October 19,
2000. The first quarter covered the 119-day period from the date of the Merger, through the February
15, 2001 record date.
Exelon had 201,269 shareholders of record of common stock as of December 31,
2001.
Securities Ratings for Exelon and its Subsidiary Companies
Standard Fitch
& Poors Investors
Securities Moody's Corporation Service, Inc.
- --------------------------------------------------------------------------------------------------
Exelon Senior unsecured debt Baa2 BBB+ BBB+
Commercial paper P2 A2 F2
ComEd Senior secured debt A3 A- A-
Senior unsecured debt Baa1 BBB+ BBB+
Commercial paper P2 A2 F2
PECO Senior secured debt A2 A A
Senior unsecured debt A3 BBB+ A-
Commercial paper P1 A2 F1
Generation Senior unsecured debt Baa1 A- BBB+
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
============================================================================================================
(a) Includes the operations of ComEd as if the Merger occurred on January 1, 2000.
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
============================================================================================================
(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.
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.
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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.
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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.
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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
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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
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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
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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.
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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
25
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.
26
Exhibit 99-4
Exelon Corporation and Subsidiary Companies
Financial Statements and Supplementary Data
To the Shareholders and Board of Directors of Exelon Corporation:
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of income, cash flows and changes in shareholders'
equity and comprehensive income present fairly, in all material respects, the
financial position of Exelon Corporation and Subsidiary Companies (Exelon) at
December 31, 2001 and December 31, 2000, and the results of their operations and
their cash flows for each of the three years in the period ended December 31,
2001 in conformity with accounting principles generally accepted in the United
States of America. These financial statements are the responsibility of Exelon's
management; our responsibility is to express an opinion on these financial
statements based on our audits. We conducted our audits of these statements in
accordance with auditing standards generally accepted in the United States of
America, which require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
As discussed in Note 2 to the consolidated financial statements, Exelon
acquired Unicom Corporation on October 20, 2000 in a business combination
accounted for under the purchase method of accounting. The results of Unicom
Corporation are included in the consolidated financial statements since the
acquisition date.
As discussed in Note 5 to the consolidated financial statements, Exelon
changed its method of accounting for nuclear outage costs in 2000. As discussed
in Note 1 to the consolidated financial statements, Exelon changed its method of
accounting for derivative instruments and hedging activities effective January
1, 2001.
/s/ PricewaterhouseCoopers LLP
Chicago, Illinois
January 29, 2002, except for Note 25 for which the date is March 1, 2002.
1
Consolidated Statements of Income
Exelon Corporation and Subsidiary Companies
For the Years Ended December 31,
-------------------------------------------
in millions, except per share data 2001 2000 1999
- ----------------------------------------------------------------------------------------------------------
Operating Revenues $ 15,140 $ 7,499 $ 5,478
Operating Expenses
Fuel and Purchased Power 5,313 2,606 2,152
Operating and Maintenance 4,393 2,310 1,454
Merger-Related Costs -- 276 --
Depreciation and Amortization 1,449 458 237
Taxes Other Than Income 623 322 262
- ----------------------------------------------------------------------------------------------------------
Total Operating Expenses 11,778 5,972 4,105
- ----------------------------------------------------------------------------------------------------------
Operating Income 3,362 1,527 1,373
- ----------------------------------------------------------------------------------------------------------
Other Income and Deductions
Interest Expense, net of amounts capitalized (1,107) (608) (396)
Distributions on Preferred Securities of Subsidiaries (49) (24) (33)
Equity in Earnings (Losses) of Unconsolidated Affiliates 62 (41) (38)
Other, Net 79 53 59
- ----------------------------------------------------------------------------------------------------------
Total Other Income and Deductions (1,015) (620) (408)
- ----------------------------------------------------------------------------------------------------------
Income Before Income Taxes, Extraordinary Items and
Cumulative Effect of Changes in Accounting
Principles 2,347 907 965
Income Taxes 931 341 358
- ----------------------------------------------------------------------------------------------------------
Income Before Extraordinary Items and Cumulative Effects
of Changes in Accounting Principles 1,416 566 607
Extraordinary Items (net of income taxes of $2, and
$25 for 2000, and 1999, respectively) -- (4) (37)
Cumulative Effect of Changes in Accounting
Principles (net of income taxes of $8 and $16 in
2001 and 2000, respectively) 12 24 --
- ----------------------------------------------------------------------------------------------------------
Net Income $ 1,428 $ 586 $ 570
==========================================================================================================
Average Shares of Common Stock Outstanding 320 202 196
==========================================================================================================
Earnings Per Common Share:
Basic:
Income Before Extraordinary Items and Cumulative
Effect of Changes in Accounting Principles $ 4.42 $ 2.81 $ 3.10
Extraordinary Items -- (0.02) (0.19)
Cumulative Effect of Changes in Accounting Principles 0.04 0.12 --
- ----------------------------------------------------------------------------------------------------------
Net Income $ 4.46 $ 2.91 $ 2.91
==========================================================================================================
Diluted:
Income Before Extraordinary Items and Cumulative
Effect of Changes in Accounting Principles $ 4.39 $ 2.77 $ 3.08
Extraordinary Items -- (0.02) (0.19)
Cumulative Effect of Changes in
Accounting Principles 0.04 0.12 --
- ----------------------------------------------------------------------------------------------------------
Net Income $ 4.43 $ 2.87 $ 2.89
==========================================================================================================
Dividends Per Common Share $ 1.82 $ 0.91 $ 1.00
==========================================================================================================
See Notes to Consolidated Financial Statements
2
Consolidated Statements of Cash Flows
Exelon Corporation and Subsidiary Companies
For the Years Ended December 31,
------------------------------------------
in millions 2001 2000 1999
- ----------------------------------------------------------------------------------------------------------
Cash Flows from Operating Activities
Net Income $ 1,428 $ 586 $ 570
Adjustments to reconcile Net Income to Net
Cash Flows provided by Operating Activities:
Depreciation and Amortization 1,834 607 358
Extraordinary Items (net of income taxes) -- 4 37
Cumulative Effects of Changes in Accounting
Principles (net of income taxes) (12) (24) --
Provision for Uncollectible Accounts 145 89 59
Deferred Income Taxes (68) 193 7
Merger-Related Costs -- 276 --
Employee Severance Costs 46 -- --
Deferred Energy Costs 29 (79) 23
Equity in (Earnings) Losses of Unconsolidated Affiliates (62) 41 38
Net Realized Losses on Nuclear
Decommissioning Trust Funds 127 -- --
Other Operating Activities 20 (169) 6
Changes in Working Capital:
Accounts Receivable 257 (445) (159)
Repurchase of Accounts Receivable -- (50) (150)
Inventories (33) 49 (43)
Accounts Payable, Accrued Expenses & Other Current Liabilities (129) (2) 149
Other Current Assets 33 20 (12)
- ----------------------------------------------------------------------------------------------------------
Net Cash Flows provided by Operating Activities 3,615 1,096 883
- ----------------------------------------------------------------------------------------------------------
Cash Flows from Investing Activities
Investment in Plant (2,041) (752) (491)
Unicom Merger Consideration -- (507) --
Proceeds from Direct Financing Leases -- 1,228 --
Investment in Sithe Energies, Inc. -- (704) --
InfraSource Acquisitions (30) (245) (222)
Investments in and Advances to Joint Ventures -- -- (118)
Proceeds from Nuclear Decommissioning Trust Funds 1,624 265 69
Investment in Nuclear Decommissioning Trust Funds (1,863) (380) (95)
Other Investing Activities (82) (108) (29)
- ----------------------------------------------------------------------------------------------------------
Net Cash Flows used in Investing Activities (2,392) (1,203) (886)
- ----------------------------------------------------------------------------------------------------------
Cash Flows from Financing Activities
Issuance of Long-Term Debt, net of issuance costs 2,270 1,021 4,170
Common Stock Repurchases -- (501) (1,693)
Retirement of Long-Term Debt (1,860) (665) (1,343)
Change in Short-Term Debt (1,013) 10 (388)
Redemption of Preferred Securities of Subsidiaries (17) (19) (258)
Dividends on Common Stock (583) (157) (196)
Change in Restricted Cash (58) (140) (174)
Proceeds from Employee Stock Plans 39 67 19
Capital Lease Payments -- -- (139)
Other Financing Activities (42) (11) 11
- ----------------------------------------------------------------------------------------------------------
Net Cash Flows provided by (used in) Financing Activities (1,264) (395) 9
- ----------------------------------------------------------------------------------------------------------
Increase (Decrease) in Cash and Cash Equivalents (41) (502) 6
Cash and Cash Equivalents at beginning of period 526 54 48
Cash Acquired in Unicom Merger -- 974 --
- ----------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at end of period $ 485 $ 526 $ 54
==========================================================================================================
See Notes to Consolidated Financial Statements
3
Consolidated Balance Sheets
Exelon Corporation and Subsidiary Companies
at December 31,
----------------------------
in millions 2001 2000
- ----------------------------------------------------------------------------------------------------------
Assets
Current Assets
Cash and Cash Equivalents $ 485 $ 526
Restricted Cash 372 314
Accounts Receivable, net
Customer 1,687 2,137
Other 472 371
Inventories, at average cost
Fossil Fuel 222 157
Materials and Supplies 249 297
Deferred Income Taxes 23 62
Other 272 287
- ----------------------------------------------------------------------------------------------------------
Total Current Assets 3,782 4,151
- ----------------------------------------------------------------------------------------------------------
Property, Plant and Equipment, net 13,742 12,936
Deferred Debits and Other Assets
Regulatory Assets 6,423 7,135
Nuclear Decommissioning Trust Funds 3,165 3,109
Investments 1,666 1,546
Goodwill, net 5,335 5,186
Other 708 723
- ----------------------------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 17,297 17,699
- ----------------------------------------------------------------------------------------------------------
Total Assets $ 34,821 $ 34,786
==========================================================================================================
Liabilities and Shareholders' Equity
Current Liabilities
Notes Payable $ 360 $ 1,373
Long-Term Debt Due Within One Year 1,406 908
Accounts Payable 964 1,193
Accrued Expenses 1,182 989
Other 505 530
- ----------------------------------------------------------------------------------------------------------
Total Current Liabilities 4,417 4,993
- ----------------------------------------------------------------------------------------------------------
Long-Term Debt 12,876 12,958
Deferred Credits and Other Liabilities
Deferred Income Taxes 4,303 4,409
Unamortized Investment Tax Credits 316 330
Nuclear Decommissioning Liability for Retired Plants 1,314 1,301
Pension Obligations 334 416
Non-Pension Postretirement Benefits Obligation 847 817
Spent Nuclear Fuel Obligation 843 810
Other 728 907
- ----------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 8,685 8,990
- ----------------------------------------------------------------------------------------------------------
Preferred Securities of Subsidiaries 613 630
Commitments and Contingencies
Shareholders' Equity
Common Stock 6,930 6,890
Deferred Compensation (2) (7)
Retained Earnings 1,200 332
Accumulated Other Comprehensive Income 102 --
- ----------------------------------------------------------------------------------------------------------
Total Shareholders' Equity 8,230 7,215
- ----------------------------------------------------------------------------------------------------------
Total Liabilities and Shareholders' Equity $ 34,821 $ 34,786
==========================================================================================================
See Notes to Consolidated Financial Statements
4
Consolidated Statements of Changes in Shareholders' Equity
Exelon Corporation and Subsidiary Companies
Accumulated
Other Total
Common Deferred Retained Treasury Comprehensive Shareholders'
Dollars in millions, shares in thousands Shares Stock Compensation Earnings Shares Income Equity
- ------------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 1998 224,684 $ 3,558 $ -- $ (501) $ -- $ -- $ 3,057
Net Income -- -- 570 -- -- 570
Long-Term Incentive Plan Issuances 670 19 (5) 15 -- -- 29
Amortization of Deferred Compensation -- 2 -- -- -- 2
Common Stock Dividends -- -- (196) -- -- (196)
Common Stock Repurchases -- -- 12 (1,705) -- (1,693)
Other Comprehensive Income,
net of income taxes of $3 -- -- -- -- 4 4
- ------------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 1999 225,354 $ 3,577 $ (3) $ (100) $ (1,705) $ 4 $ 1,773
Net Income -- -- 586 -- -- 586
Long-Term Incentive Plan Issuances 563 67 (9) 8 7 -- 73
Shares Issued to Acquire Unicom 147,963 5,310 -- -- -- -- 5,310
Merger Consideration-Stock Options 111 -- -- -- -- 111
Amortization of Deferred Compensation -- 5 -- -- -- 5
Common Stock Dividends -- -- (157) -- -- (157)
Common Stock Repurchases -- -- (5) (496) -- (501)
Stock Option Exercises -- -- -- 19 -- 19
Cancellation of Treasury Shares (54,875) (2,175) -- -- 2,175 -- --
Other Comprehensive Income,
net of income taxes of $(3) -- -- -- -- (4) (4)
- ------------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2000 319,005 $ 6,890 $ (7) $ 332 $ -- $ -- $ 7,215
Net Income -- -- 1,428 -- -- 1,428
Long-Term Incentive Plan Issuances 1,864 32 -- 23 -- -- 55
Employee Stock Purchase Plan Issuances 138 6 -- -- -- -- 6
Merger Consideration-Stock Options 2 -- -- -- -- 2
Amortization of Deferred Compensation -- 5 -- -- -- 5
Common Stock Dividends -- -- (583) -- -- (583)
Reclassified Net Unrealized Losses on
Marketable Securities, net of income
taxes of $22 -- -- -- -- (23) (23)
Other Comprehensive Income, net of income
tax benefit of $197 -- -- -- -- 125 125
- ------------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2001 321,007 $ 6,930 $ (2) $ 1,200 $ -- $ 102 $ 8,230
====================================================================================================================================
Consolidated Statements of Comprehensive Income
Exelon Corporation and Subsidiary Companies
For the Years Ended December 31,
----------------------------------
in millions 2001 2000 1999
- -----------------------------------------------------------------------------------------------------------------
Net Income $ 1,428 $ 586 $ 570
Other Comprehensive Income
SFAS 133 Transition Adjustment, net
of income taxes of $18 $ 44 $ -- $ --
Cash Flow Hedge Fair Value Adjustment, net of income taxes of $20 22 -- --
Foreign Currency Translation Adjustment,
net of income taxes of $0 (1) -- --
Unrealized Gain (Loss) on Marketable
Securities, net of income taxes of $145, $1 and $(1), respectively 60 (4) 4
- -----------------------------------------------------------------------------------------------------------------
Total Other Comprehensive Income 125 (4) 4
- -----------------------------------------------------------------------------------------------------------------
Total Comprehensive Income $ 1,553 $ 582 $ 574
=================================================================================================================
See Notes to Consolidated Financial Statements
5
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Exelon Corporation and Subsidiary Companies
(Dollars in millions, except per share data unless otherwise noted)
1. Significant Accounting Policies
Description of Business
Exelon Corporation (Exelon) is a utility services holding company formed as a
result of the merger of Unicom Corporation (Unicom) and PECO Energy Company
(PECO) (Merger). See Note 2 - Merger. Exelon is engaged, through subsidiaries,
in the energy delivery, wholesale generation and the energy-related enterprises
businesses. See Note 21 - Segment Information. The energy delivery business
consists of the retail electricity distribution and transmission businesses of
Commonwealth Edison Company (ComEd) in northern Illinois and PECO in
southeastern Pennsylvania and the natural gas distribution business of PECO
located in the Pennsylvania counties surrounding the City of Philadelphia. The
wholesale generation business consists of the electric generating facilities and
energy marketing operations of Exelon Generation LLC (Generation) and
Generation's interests in Sithe Energies, Inc. (Sithe) and AmerGen Energy
Company LLC (AmerGen). Exelon Enterprises Company, LLC (Enterprises) includes
energy and infrastructure services, competitive retail energy sales,
communications joint ventures and other investments weighted towards the
communications, energy services and retail services industries.
Basis of Presentation
The consolidated financial statements of Exelon include the accounts of its
majority-owned subsidiaries after the elimination of intercompany transactions.
Exelon generally accounts for its 20% to 50% owned investments and joint
ventures, in which it exerts significant influence, under the equity method of
accounting. Exelon consolidates its proportionate interest in its jointly owned
electric utility plants. Exelon accounts for its less than 20% owned investments
under the cost method of accounting. Accounting policies for regulated
operations are in accordance with those prescribed by the regulatory authorities
having jurisdiction, principally the Illinois Commerce Commission (ICC), the
Pennsylvania Public Utility Commission (PUC), the Federal Energy Regulatory
Commission (FERC) and the Securities and Exchange Commission (SEC) under the
Public Utility Holding Company Act of 1935 (PUHCA).
On October 20, 2000, Exelon became the parent of PECO through a share
exchange and Unicom, the parent of ComEd, was merged into Exelon. As a result of
these transactions, Unicom ceased to exist and Exelon became the parent of ComEd
and PECO. See Note 2 - Merger. In addition, for accounting purposes, PECO was
deemed the acquiror in the Merger. Accordingly, the financial statements of
Exelon for the periods presented prior to October 20, 2000 represent the
historical financial statements of PECO and for the periods from October 20,
2000 include the operations acquired from Unicom.
Accounting for the Effects of Regulation
Exelon accounts for all of its regulated electric and gas operations in
accordance with the Financial Accounting Standards Board (FASB) Statement of
Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of
Certain Types of Regulation," (SFAS No. 71) requiring Exelon to record in its
financial statements the effects of the rate regulation. Use of SFAS No. 71 is
applicable to the utility operations of Exelon that meet the following criteria:
(1) third-party regulation of rates; (2) cost-based rates; and (3) a reasonable
assumption that all costs will be recoverable from customers through rates.
Exelon believes that it is probable that currently recorded regulatory assets
will be recovered. If a separable portion of Exelon's business no longer meets
the provisions of SFAS No. 71, Exelon is required to eliminate the financial
statement effects of regulation for that portion.
Use of Estimates
The preparation of financial statements in conformity with generally accepted
accounting principles (GAAP) requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates. Significant
estimates have been made in the accounting for derivatives, nuclear
decommissioning liabilities, environmental costs and pension costs.
6
Revenues
Operating revenues are generally recorded as service is rendered or energy is
delivered to customers. At the end of each month, Exelon accrues an estimate for
the unbilled amount of energy delivered or services provided to its electric and
gas customers. Exelon recognizes contract revenues and profits on certain
long-term fixed-price contracts from its services businesses under the
percentage-of-completion method of accounting based on costs incurred as a
percentage of estimated total costs of individual contracts.
Purchased Gas Adjustment Clause
PECO's natural gas rates are subject to a fuel adjustment clause designed to
recover or refund the difference between the actual cost of purchased gas and
the amount included in base rates. Differences between the amounts billed to
customers and the actual costs recoverable are deferred and recovered or
refunded in future periods by means of prospective quarterly adjustments to
rates.
Nuclear Fuel
The cost of nuclear fuel is capitalized and charged to fuel expense using the
unit of production method. Estimated costs of nuclear fuel storage and disposal
at operating plants are charged to fuel expense as the related fuel is consumed.
Depreciation, Amortization and Decommissioning
Depreciation is provided over the estimated service lives of property, plant and
equipment on a straight line basis. Annual depreciation provisions for financial
reporting purposes, expressed as a percentage of average service life for each
asset category are presented in the table below. See Note 23 for information on
service life extensions for certain nuclear generating stations.
Asset Category 2001 2000 1999
- ---------------------------------------------------------------------------------------------------------
Electric-Transmission and Distribution 3.97% 4.16% 1.83%
Electric-Generation 3.11% 5.02% 5.12%
Gas 2.34% 2.39% 2.36%
Common - Gas and Electric 6.26% 5.09% 4.45%
Other Property and Equipment 9.53% 8.11% 8.61%
=========================================================================================================
Amortization of regulatory assets is provided over the recovery period as
specified in the related regulatory agreement. Goodwill associated with the
Merger was amortized on a straight line basis over 40 years in 2000 and 2001.
Goodwill associated with other acquisitions was amortized over periods from 10
to 20 years in 2000 and 2001. Accumulated amortization of goodwill was $185
million, $35 million and $1 million at December 31, 2001, 2000 and 1999,
respectively. Effective January 1, 2002 under SFAS No. 142 "Goodwill and Other
Intangible Assets" (SFAS No. 142), goodwill recorded by Exelon will no longer be
subject to amortization.
Exelon currently recovers costs for decommissioning its nuclear generating
stations through regulated rates. The amounts recovered from customers are
deposited in trust accounts and invested for funding of future costs for
operating and retired plants. Exelon accounts for the current period's cost of
decommissioning related to generating plants previously owned by PECO following
common regulatory accounting practices by recording a charge to depreciation
expense and a corresponding liability in accumulated depreciation concurrently
with decommissioning collections. Regulatory accounting practices for the
generating stations previously owned by ComEd were discontinued as a result of
an ICC order capping ComEd's ultimate recovery of decommissioning costs. See
Note 4 - Corporate Restructuring and Note 12 - Nuclear Decommissioning and Spent
Fuel Storage, regarding regulatory accounting practices for nuclear generating
stations transferred by ComEd to Generation. The difference between the current
cost decommissioning estimate and the decommissioning liability recorded in
accumulated depreciation for the former ComEd operating stations is amortized to
depreciation expense on a straight-line basis over the remaining lives. The
current cost decommissioning estimate (adjusted annually to reflect inflation)
for the former ComEd retired units recorded in deferred credits and other
liabilities is accreted to depreciation expense. Exelon believes that the
amounts being recovered from customers through electric rates along with the
earnings on the trust funds will be sufficient to fully fund its decommissioning
obligations.
7
Capitalized Interest
Exelon uses SFAS No. 34, "Capitalizing Interest Costs," to calculate the costs
during construction of debt funds used to finance its non-regulated construction
projects. Exelon recorded capitalized interest of $17 million, $2 million and $6
million in 2001, 2000 and 1999, respectively.
Allowance for Funds Used During Construction (AFUDC) is the cost, during
the period of construction, of debt and equity funds used to finance
construction projects for regulated operations. AFUDC is recorded as a charge to
Construction Work in Progress and as a non-cash credit to AFUDC which is
included in Other Income and Deductions. The rates used for capitalizing AFUDC
are computed under a method prescribed by regulatory authorities.
Income Taxes
Deferred Federal and state income taxes are provided on all significant
temporary differences between book bases and tax bases of assets and
liabilities. Investment tax credits previously utilized for income tax purposes
have been deferred on the Consolidated Balance Sheets and are recognized in book
income over the life of the related property. Exelon and its subsidiaries file a
consolidated Federal income tax return. Income taxes are allocated to each of
Exelon's subsidiaries within the consolidated group based on the separate return
method.
Gains and Losses on Reacquired Debt
Recoverable gains and losses on reacquired debt related to regulated operations
are deferred and amortized to interest expense over the period consistent with
rate recovery for ratemaking purposes. Gains and losses on other debt are
recognized in Exelon's Consolidated Statements of Income as incurred.
Comprehensive Income
Comprehensive income includes all changes in equity during a period except those
resulting from investments by and distributions to shareholders. Comprehensive
income is reflected in the Consolidated Statements of Changes in Shareholders'
Equity and the Consolidated Statements of Comprehensive Income.
Cash and Cash Equivalents
Exelon considers all temporary cash investments purchased with an original
maturity of three months or less to be cash equivalents.
Restricted Cash
Restricted cash reflects unused cash proceeds from the issuance of the
transition bonds and transitional trust notes, and escrowed cash to be applied
to the principal and interest payment on the transition bonds and transitional
trust notes.
Marketable Securities
Marketable securities are classified as available-for-sale securities and are
reported at fair value, with the unrealized gains and losses, net of tax,
reported in other comprehensive income. Under regulatory accounting practices,
unrealized gains and losses on marketable securities held in the nuclear
decommissioning trust funds are reported in accumulated depreciation for
operating units and as a reduction of regulatory assets for retired units. When
regulatory accounting practices are discontinued, unrealized gains and losses on
marketable securities held in the nuclear decommissioning trust funds are
reported in accumulated other comprehensive income. At December 31, 2001 and
2000, Exelon had no held-to-maturity or trading securities.
8
Property, Plant and Equipment
Property, plant and equipment is recorded at cost. Exelon evaluates the carrying
value of property, plant and equipment and other long-term assets based upon
current and anticipated undiscounted cash flows, and recognizes an impairment
when it is probable that such estimated cash flows will be less than the
carrying value of the asset. Measurement of the amount of impairment, if any, is
based upon the difference between carrying value and fair value. The cost of
maintenance, repairs and minor replacements of property are charged to
maintenance expense as incurred.
Upon retirement, the cost of regulated property plus removal costs less
salvage value, are charged to accumulated depreciation by the regulated
subsidiaries in accordance with regulatory practices. For unregulated property,
the cost and accumulated depreciation of property, plant and equipment retired
or otherwise disposed of are removed from the related accounts and included in
the determination of the gain or loss on disposition.
Capitalized Software Costs
Costs incurred during the application development stage of software projects for
software which is developed or obtained for internal use are capitalized. At
December 31, 2001 and 2000, capitalized software costs totaled $240 million and
$285 million, respectively, net of $85 million and $53 million accumulated
amortization, respectively. Such capitalized amounts are amortized ratably over
the expected lives of the projects when they become operational, not to exceed
ten years. Certain capitalized software is being amortized over fifteen years
pursuant to regulatory approval.
Derivative Financial Instruments
Exelon accounts for derivative financial instruments under SFAS No. 133
"Accounting for Derivatives and Hedging Activities" (SFAS No. 133). Under the
provisions of SFAS No. 133, all derivatives are recognized on the balance sheet
at their fair value unless they qualify for a normal purchases and normal sales
exception. Changes in the fair value of the derivative financial instruments are
recognized in earnings unless specific hedge accounting criteria are met. A
derivative financial instrument can be designated as a hedge of the fair value
of a recognized asset or liability or of an unrecognized firm commitment (fair
value hedge), or a hedge of a forecasted transaction or the variability of cash
flows to be received or paid related to a recognized asset or liability (cash
flow hedge). Changes in the fair value of a derivative that is highly effective
as, and is designated and qualifies as, a fair value hedge, along with the gain
or loss on the hedged asset or liability that is attributable to the hedged
risk, are recorded in earnings. Changes in the fair value of a derivative that
is highly effective as, and is designated as and qualifies as a cash flow hedge
are recorded in other comprehensive income, until earnings are affected by the
variability of cash flows being hedged.
In connection with Exelon's Risk Management Policy (RMP), Exelon enters
into derivatives to manage its exposure to fluctuation in interest rates related
to its variable rate debt instruments, changes in interest rates related to
planned future debt issuances prior to their actual issuance and changes in the
fair value of outstanding debt which is planned for early retirement. As it
relates to energy transactions, Exelon utilizes derivatives to manage the
utilization of its available generating capability and provisions of wholesale
energy to its affiliates. Exelon also utilizes energy option contracts and
energy financial swap arrangements to limit the market price risk associated
with forward energy commodity contracts. Additionally, Exelon enters into
certain energy related derivatives for trading or speculative purposes.
As part of Exelon's energy marketing business, Exelon enters into contracts
to buy and sell energy to meet the requirements of its customers. These
contracts include short-term and long-term commitments to purchase and sell
energy and energy related products in the retail and wholesale markets with the
intent and ability to deliver or take delivery. While these contracts are
considered derivative financial instruments under SFAS No. 133, the majority of
these transactions have been designated as "normal purchases" and "normal sales"
and are not subject to the provisions of SFAS No. 133. Normal purchases and
normal sales are contracts where physical delivery is probable, quantities are
expected to be used or sold in the normal course of business over a reasonable
period of time, and price is not tied to an unrelated underlying derivative.
Under these contracts Exelon recognizes gains or losses when the underlying
physical transaction affects earnings. Revenues and expenses associated with
market price risk management contracts are amortized over the terms of such
contracts. Commitments under these contracts are discussed in Note 20 -
Commitments and Contingencies. The remainder
9
of these contracts are generally considered cash flow hedges under SFAS No. 133.
To the extent that the hedges are effective, changes in the fair value of these
contracts are recorded in other comprehensive income, until earnings are
affected by the variability of cash flows being hedged.
Additionally, during 2001, as part of the creation of Exelon's energy
trading operation, Exelon began to enter into contracts to buy and sell energy
for trading purposes subject to limits. These contracts are recognized on the
balance sheet at fair value and changes in the fair value of these derivative
financial instruments are recognized in earnings.
Prior to the adoption of SFAS No. 133, Exelon applied hedge accounting only
if the derivative reduced the risk of the underlying hedged item and was
designated at the inception of the hedge, with respect to the hedged item.
Exelon recognized any gains or losses on these derivatives when the underlying
physical transaction affected earnings.
Contracts entered into by Exelon to limit market risk associated with
forward energy commodity contracts are reflected in the financial statements at
the lower or cost or market using the accrual method of accounting. Under these
contracts Exelon recognizes any gains or losses when the underlying physical
transaction affects earnings. Revenues and expenses associated with market price
risk management contracts were amortized over the terms of such contracts.
New Accounting Pronouncements
In 2001, the FASB issued SFAS No. 141, "Business Combinations" (SFAS No. 141),
SFAS No. 142, No. 143, "Asset Retirement Obligations" (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 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 SFAS No. 143 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.
10
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 net 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.
Reclassifications
Certain prior year amounts have been reclassified for comparative purposes. The
reclassifications did not affect net income.
2. Merger
On October 20, 2000, Exelon became the parent corporation of PECO and ComEd as a
result of the completion of the transactions contemplated by an Agreement and
Plan of Exchange and Merger, as amended (Merger Agreement), among PECO, Unicom
Corporation (Unicom) and Exelon. Pursuant to the Merger Agreement, Unicom merged
with and into Exelon (Merger). In the Merger, each share of the outstanding
common stock of Unicom was converted into 0.875 shares of common stock of Exelon
plus $3.00 in cash. As a result of the Share Exchange, Exelon became the owner
of all of the common stock of PECO. As a result of the Merger, Unicom ceased to
exist and its subsidiaries, including ComEd, became subsidiaries of Exelon.
The Merger was accounted for using the purchase method of accounting. The
total purchase price was $5,975 million. In connection with the Merger, Exelon
issued 148 million shares of common stock in the amount of $5,310 million and
paid $507 million in cash to Unicom shareholders pursuant to the terms of the
Merger Agreement. The source of the cash consideration was borrowings under an
Exelon term loan. In addition, the Merger consideration included $113 million of
fair value of stock options and awards for certain Unicom employees and $45
million of direct acquisition costs. The cost in excess of net assets acquired
was $5,136 million as adjusted to reflect final purchase price allocations.
Exelon's results of operations include Unicom's results of operations since
October 20, 2000. The fair value of the assets acquired, including the cost in
excess of net assets acquired, and liabilities assumed in the Merger are as
follows:
- -----------------------------------------------------------------------------------------------------------
Current Assets (including cash of $974) $ 2,744
Property, Plant and Equipment 7,641
Deferred Debits and Other Assets 5,535
Cost in excess of net assets acquired 5,136
Current Liabilities (2,413)
Long-Term Debt (7,419)
Deferred Credits and Other Liabilities (4,921)
Preferred Securities of Subsidiaries (328)
- -----------------------------------------------------------------------------------------------------------
Total Purchase Price $ 5,975
===========================================================================================================
11
Goodwill associated with the merger increased by $262 million in 2001 as a
result of the finalization of the purchase price allocation. The adjustment
resulted primarily from the after-tax effects of the reduction of the regulatory
asset for decommissioning retired nuclear plants, as discussed in Note 12 -
Nuclear Decommissioning and Spent Fuel Storage, additional employee separation
costs and the finalization of other purchase price allocations.
Selected unaudited pro forma combined results of operations for the years
ended December 31, 2000 and 1999, assuming the Merger Transaction occurred on
January 1, 2000 and 1999, respectively, are presented as follows:
(unaudited) 2000 1999
- -----------------------------------------------------------------------------------------------------------
Total revenues $ 13,531 $ 12,225
Pro forma net income $ 1,007 $ 1,184
Merger-related costs (net of income taxes of $147 million) 220 --
Extraordinary items (net of income taxes of $2 million and
$25 million for 2000 and 1999, respectively) (4) (37)
Cumulative effect of a change in accounting principle (net of
income taxes of $16 million) 24 --
- -----------------------------------------------------------------------------------------------------------
Pro forma net income before Merger-related costs, extraordinary
items and cumulative effect of a change in accounting principle $ 1,247 $ 1,147
===========================================================================================================
Proforma net income before Merger-related costs, extraordinary
items and cumulative effect of a change in accounting principle
per common share (diluted) $ 3.86 $ 3.55
===========================================================================================================
Pro forma information assumes the effects of Unicom's 1999 fossil plant sale and
the issuance of transition bonds and notes occurred at the beginning of 1999.
The pro forma financial information is not necessarily indicative of the
operating results that would have occurred had the Merger been consummated as of
the dates indicated, nor are they necessarily indicative of future operating
results.
Merger-Related Costs
In association with the Merger, Exelon recorded certain reserves for
restructuring costs. The reserves associated with PECO were charged to expense,
while the reserves associated with Unicom were recorded as part of the
application of purchase accounting and did not affect results of operations.
Merger-related costs charged to expense in 2000 were $276 million,
consisting of $124 million for PECO employee costs and $152 million of direct
incremental costs. Direct incremental costs represent expenses directly
associated with completing the Merger, including professional fees, regulatory
approval and settlement costs, and settlement of compensation arrangements.
Employee costs represent estimated severance costs and pension and
postretirement benefits provided under Exelon's merger separation plans for
eligible employees who are expected to be involuntarily terminated before
December 2002 due to integration activities of the merged companies.
The purchase price allocation as of December 31, 2000 included a liability
of $307 million for Unicom employee costs and liabilities of approximately $39
million for estimated costs of exiting various business activities of former
Unicom activities that were not compatible with the strategic business direction
of Exelon.
12
During 2001, Exelon finalized its plans for consolidation of functions,
including negotiation of an agreement with the union regarding severance
benefits to union employees and recorded adjustments to the purchase price
allocation as follows:
Original 2001 Adjusted
Estimate Adjustments Liabilities
- ------------------------------------------------------------------------------------------------------------
Employee severance payments $ 128 $ 33 $ 161 (a)
Actuarially determined pension and postretirement costs 158 (11) 147 (b)
Relocation and other severance 21 9 30 (a)
- ------------------------------------------------------------------------------------------------------------
Total Unicom - Employee Cost $ 307 $ 31 $ 338
============================================================================================================
(a) The increase is a result of the identification in 2001 of additional positions to be eliminated.
(b) The reduction results from lower estimated pension and post retirement welfare benefits reflecting revised
actuarial estimates.
Additional employee severance costs of $48 million primarily related to PECO
employees were charged to expense in 2001. Exelon anticipates that a total of
$289 million of employee costs will be funded from pension and postretirement
benefit plans and $191 million of Unicom employee severance costs will be funded
from general corporate funds.
The following table provides a reconciliation of the reserve for employee
severance and relocation costs associated with the merger:
- -----------------------------------------------------------------------------------------------------------
Employee severance and relocation reserve as of October 20, 2000 $ 149
Additional reserve 42
- -----------------------------------------------------------------------------------------------------------
Adjusted employee severance and relocation reserve 191
Payments to employees (October 2000-December 2001) (77)
- -----------------------------------------------------------------------------------------------------------
Employee severance and relocation reserve as of December 31, 2001 $ 114
============================================================================================================
Approximately 3,400 Unicom and PECO positions have been identified to be
eliminated as a result of the merger. Exelon has terminated 1,461 employees as
of December 31, 2001. The remaining positions are expected to be eliminated by
the end of 2002.
3. Acquisitions
Sithe Energies, Inc. Acquisition 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 any 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.
13
Sithe, headquartered in New York, is a leading independent power producer,
with ownership interests in 27 facilities in North America. Sithe has net
generation capacity of 3,371 MW, primarily in New York and Massachusetts, 2,651
MW under construction and 2,400 MW in advanced development.
InfraSource, Inc. Acquisitions
In 2001 InfraSource, Inc. (InfraSource), formerly Exelon Infrastructure
Services, Inc., acquired the assets of a utility service contracting company for
an aggregate purchase price of approximately $30 million. In 2000, InfraSource
acquired the stock or assets of seven utility services contracting companies for
an aggregate purchase price of approximately $245 million. The acquisitions were
accounted for using the purchase method of accounting. The initial estimates of
the excess of purchase price over the fair value of net assets acquired in the
2001 acquisition and in the 2000 acquisitions were approximately $19 million and
$216 million, respectively. The allocation of purchase price to the fair value
of assets acquired and liabilities assumed in these acquisitions is as follows:
2001 2000
- -----------------------------------------------------------------------------------------------------------
Current Assets (net of cash acquired) $ 10 $ 63
Property, Plant and Equipment 11 17
Cost in excess of net assets acquired 19 216
Current Liabilities (10) (51)
- -----------------------------------------------------------------------------------------------------------
Total $ 30 $ 245
===========================================================================================================
At December 31, 2001 and 2000, Current Assets includes $77 million and $70
million, respectively, of Costs and Earnings in Excess of Billings on
uncompleted contracts and Current Liabilities includes $56 million and $23
million, respectively, of Billings and Earnings in Excess of Costs on
uncompleted contracts.
AmerGen Energy Company, LLC
In August 2000, AmerGen Energy Company, LLC (AmerGen), a joint venture with
British Energy, Inc., a wholly owned subsidiary of British Energy plc, (British
Energy), completed the purchase of Oyster Creek Nuclear Generating Facility
(Oyster Creek) from GPU, Inc. (GPU) for $10 million. Under the terms of the
purchase agreement, GPU agreed to fund outage costs of $89 million, including
the cost of fuel, for a refueling outage that occurred in 2000. AmerGen is
repaying these costs to GPU in equal annual installments through 2009. In
addition, AmerGen assumed full responsibility for the ultimate decommissioning
of Oyster Creek. At the closing of the sale, GPU provided funding for the
decommissioning trust of $440 million. In conjunction with this acquisition,
AmerGen has received a fully funded decommissioning trust fund which has been
computed assuming the anticipated costs to appropriately decommission Oyster
Creek discounted to net present value using the NRC's mandated rate of 2%.
AmerGen believes that the amount of the trust fund and investment earnings
thereon will be sufficient to meet its decommissioning obligation. GPU is
purchasing the electricity generated by Oyster Creek pursuant to a three-year
power purchase agreement.
4. Corporate Restructuring
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 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 Enterprises, respectively.
Additionally, certain operations and assets and liabilities of ComEd and PECO
were transferred to Exelon Business Services Company (BSC).
14
5. Accounting Changes
On January 1, 2001, Exelon recognized a non-cash gain of $12 million, net of
income taxes, in earnings and deferred a non-cash gain of $44 million, net of
income taxes, in Accumulated Other Comprehensive Income, a component of
shareholders' equity, to reflect the adoption of SFAS No. 133, as amended.
During the fourth quarter of 2000, as a result of the synchronization of
accounting policies with Unicom in connection with the Merger, PECO changed its
method of accounting for nuclear outage costs to record such costs as incurred.
Previously, PECO accrued these costs over the operating unit cycle. As a result
of the change in accounting method for nuclear outage costs, PECO recorded
income of $24 million, net of income taxes of $16 million. The change is
reported as a cumulative effect of a change in accounting principle on the
Consolidated Statements of Income as of December 31, 2000, representing the
balance of the nuclear outage cost reserve at January 1, 2000.
6. Regulatory Issues
ComEd
In 2001, the phased process to implement competition in the electric industry
continued as mandated by the requirements of the Illinois restructuring
legislation.
Customer Choice As of December 31, 2000, all non-residential customers were
eligible to choose a new electric supplier or elect the power purchase option
which allows the purchase of electric energy from ComEd at market-based prices.
ComEd's residential customers become eligible to choose a new electric supplier
in May 2002. As of December 31, 2001, approximately 18,700 non-residential
customers, representing approximately 22% of ComEd's annual retail kilowatt-hour
sales, had elected to purchase their electric energy from an alternate electric
supplier or had chosen the power purchase option. Customers who receive energy
from an alternative supplier continue to pay a delivery charge. ComEd is unable
to predict the long term impact of customer choice on results of operations.
Rate Reductions and Return on Common Equity Threshold The Illinois restructuring
legislation provided a 15% residential base rate reduction effective August 1,
1998 with an additional 5% residential base rate reduction effective October 1,
2001. ComEd's operating revenues were reduced by approximately $24 million in
2001 due to the 5% residential rate reduction. Notwithstanding the rate
reductions and subject to certain earnings tests, a rate freeze is generally in
effect until at least January 1, 2005. A utility may request a rate increase
during the rate freeze period only when necessary to ensure the utility's
financial viability. Under the Illinois legislation, if the earned return on
common equity of a utility during this period exceeds an established threshold,
one-half of the excess earnings must be refunded to customers. The threshold
rate of return on common equity is based on the 30-Year Treasury Bond rate plus
8.5% in the years 2000 through 2004. Earnings for purposes of ComEd's threshold
include ComEd's net income calculated in accordance with GAAP and reflect the
amortization of regulatory assets and goodwill. As a result of the Illinois
legislation, at December 31, 2001, ComEd had a regulatory asset with an
unamortized balance of $277 million that it expects to fully recover and
amortize by the end of 2004. Consistent with the provisions of the Illinois
legislation, regulatory assets may be recovered at amounts that provide ComEd an
earned return on common equity within the Illinois legislation earnings
threshold. The earned return on common equity and the threshold return on common
equity for ComEd are each calculated on a two-year average basis. ComEd did not
trigger the earnings sharing provision in 2000 or 2001 and does not currently
expect to trigger the earnings sharing provisions in the years 2002 through
2004.
15
PECO
In 2001, the phased process to implement competition in the electric industry
continued as mandated by the requirements of the PUC's Final Restructuring
Order.
Customer Choice The PUC's Final Restructuring Order provided for the phase-in of
customer choice of electric generation supplier (EGS) for all customers and as
of January 1, 2000 all customers were eligible for customer choice. The Final
Restructuring Order also established market share thresholds to ensure that a
minimum number of residential and commercial customers choose an EGS or a PECO
affiliate. If less than 35% and 50% of residential and commercial customers have
chosen an EGS, including residential customers assigned to an EGS as a provider
of last resort default supplier, by January 1, 2001 and January 1, 2003,
respectively, the number of customers sufficient to meet the necessary threshold
levels shall be randomly selected and assigned to an EGS through a
PUC-determined process. On January 1, 2001, the 35% threshold was met for all
three customer classes as a result of agreements assigning customers to New
Power Company and Green Mountain as providers of last resort default service.
During 2001, PECO experienced an increase in the number of customers selecting
or returning to PECO as their EGS and at December 31, 2001, 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 from an
alternative generation supplier. Customers who purchase energy from an EGS
continue to pay a delivery charge.
Rate Reductions and Caps Under the Final Restructuring Order, retail electric
rates were capped at year-end 1996 levels (system-wide average of 9.96
cents/kilowatt hour (kWh)) through June 2005. The Final Restructuring Order
required PECO to reduce its retail electric rates by 8% from the 1996
system-wide average rate on January 1, 1999. This rate reduction decreased to 6%
on January 1, 2000 until January 1, 2001. The transmission and distribution rate
component was capped at a system-wide average rate of 2.98 cents/kWh through
June 30, 2005. Additionally, generation rate caps, defined as the sum of the
applicable transition charge and energy and capacity charge, will remain in
effect through 2010.
On March 16, 2000, the PUC issued an order authorizing PECO to securitize
up to an additional $1 billion of its authorized stranded costs recovery. In
accordance with the terms of that order, PECO provided its retail customers with
rate reductions of $60 million for calendar year 2001 only.
Under a comprehensive settlement agreement in connection with achieving
regulatory approval of the Merger, PECO agreed to $200 million in aggregate rate
reductions for all customers in Pennsylvania over the period January 1, 2002
through 2005 and extended the rate caps on PECO's retail electric distribution
charges through December 31, 2006.
7. Supplemental Financial Information
Supplemental Income Statement Information
For the Years Ended December 31,
-------------------------------------------
2001 2000 1999
- -----------------------------------------------------------------------------------------------------------
Taxes Other Than Income
Utility $ 342 $ 196 $ 155
Real estate 140 68 72
Payroll 81 41 28
Other 60 17 7
- -----------------------------------------------------------------------------------------------------------
Total $ 623 $ 322 $ 262
===========================================================================================================
Other, Net
Investment income $ 47 $ 64 $ 52
Gain (loss) on disposition of assets, net 4 (19) (1)
Settlement of power purchase agreement -- 6 --
AFUDC, equity and borrowed 18 3 4
Other 10 (1) 4
- -----------------------------------------------------------------------------------------------------------
Total $ 79 $ 53 $ 59
===========================================================================================================
16
Supplemental Cash Flow Information
For the Years Ended December 31,
-------------------------------------------
2001 2000 1999
- -----------------------------------------------------------------------------------------------------------
Cash paid during the year:
Interest (net of amount capitalized) $ 963 $ 519 $ 350
Income taxes (net of refunds) $ 749 $ 272 $ 304
Non-cash investing and financing:
Regulatory Asset Fair Value Adjustment $ 347 -- --
Purchase Accounting Estimate Adjustments $ (85) -- --
Issuance of Exelon Shares for Unicom -- $ 5,310 --
Issuance of InfraSource stock $ 35 $ 14 $ 11
Depreciation and amortization:
Property, plant and equipment $ 702 $ 325 $ 207
Nuclear fuel 393 149 104
Regulatory assets 445 53 --
Decommissioning 144 46 29
Goodwill 150 34 1
Leased property -- -- 17
- -----------------------------------------------------------------------------------------------------------
Total Depreciation and Amortization $ 1,834 $ 607 $ 358
===========================================================================================================
Supplemental Balance Sheet Information
Investments
December 31,
--------------------------
2001 2000
- -----------------------------------------------------------------------------------------------------------
Investment in Sithe $ 725 $ 704
Direct financing leases 427 409
Energy services and other ventures 161 170
Communication ventures 116 97
Investment in AmerGen 113 44
Affordable housing projects 98 88
Investment in subsidiaries and joint ventures 26 34
- -----------------------------------------------------------------------------------------------------------
Total $ 1,666 $ 1,546
===========================================================================================================
Prior to the Merger, Unicom entered into a like-kind exchange transaction
pursuant to which approximately $1.6 billion was invested in passive generating
station leases with two separate entities unrelated to Exelon. The generating
stations were leased back to such entities as part of the transaction. For
financial accounting purposes, the investments are accounted for as direct
financing lease investments. Under the terms of the lease agreements, Exelon
received a prepayment of $1.2 billion in the fourth quarter of 2000, which
reduced the investment in the lease. The remaining payments are payable at the
end of the thirty year lease and there are no minimum scheduled lease payments
to be received over the next five years. The components of the net investment in
the direct financing leases are as follows:
December 31,
---------------------------
2001 2000
- -----------------------------------------------------------------------------------------------------------
Total minimum lease payments $ 1,492 $ 1,492
Less: Unearned income 1,065 1,083
- -----------------------------------------------------------------------------------------------------------
Net investment in direct financing leases $ 427 $ 409
===========================================================================================================
17
Regulatory Assets
December 31,
---------------------------
2001 2000
- -----------------------------------------------------------------------------------------------------------
Competitive transition charge $ 4,947 $ 5,218
Recoverable deferred income taxes (see Note 15) 701 632
Nuclear decommissioning costs for retired plants 310 719
Recoverable transition costs 277 385
Loss on reacquired debt 112 99
Compensated absences 5 4
Non-pension postretirement benefits 71 78
- -----------------------------------------------------------------------------------------------------------
Long-Term Regulatory Assets 6,423 7,135
Deferred energy costs (current asset) 56 86
- -----------------------------------------------------------------------------------------------------------
Total $ 6,479 $ 7,221
===========================================================================================================
At December 31, 2001 and 2000, the Competitive Transition Charge (CTC) includes
the unamortized balance of $4.5 billion and $4.8 billion, respectively, of
Intangible Transition Property (ITP) sold to PECO Energy Transition Trust
(PETT), a wholly owned subsidiary of PECO, in connection with the securitization
of PECO's stranded cost recovery. PETT financed its purchase of the ITP through
the issuance of transition bonds. See Note 14 - Long-Term Debt. ITP represents
the irrevocable right of PECO or its assignee to collect non-bypassable charges
from customers to recover stranded costs. The CTC represents PECO's stranded
costs that are recoverable through regulated rates. The CTC is recoverable over
a twelve year period ending December 31, 2010 with a return on the unamortized
balance of 10.75%.
8. Earnings Per Share
Diluted earnings per share are calculated by dividing net income by the weighted
average shares of common stock outstanding including shares issuable upon
exercise of stock options outstanding under Exelon's stock option plans
considered to be common stock equivalents. The following table shows the effect
of these stock options on the weighted average number of shares outstanding used
in calculating diluted earnings per share (in millions):
2001 2000 1999
- -----------------------------------------------------------------------------------------------------------
Average Common Shares Outstanding 320 202 196
Assumed Exercise of Stock Options 2 2 1
- -----------------------------------------------------------------------------------------------------------
Average Dilutive Common Shares Outstanding 322 204 197
===========================================================================================================
9. Accounts Receivable
Accounts receivable -- Customer at December 31, 2001 and 2000 included unbilled
operating revenues of $438 million and $498 million, respectively. The allowance
for uncollectible accounts at December 31, 2001 and 2000 was $213 million and
$200 million, respectively.
Accounts receivable -- Other at December 31, 2001 and 2000 included demand
notes receivable from a communications joint venture in the amount of $153
million. The receivable has been adjusted for Exelon's share of this joint
venture's operating losses incurred in excess of its investment. The notes bear
interest at the Applicable Federal Rate, compounded semi-annually. The average
interest rate on the notes receivable was 4.18% and 6.22% at December 31, 2001
and 2000, respectively. Interest income related to the notes receivable was $6
million and $10 million in 2001 and 2000, respectively.
PECO is party to an agreement with a financial institution under which it
can sell or finance with limited recourse an undivided interest, adjusted daily,
in up to $225 million of designated accounts receivable until November 2005. At
December 31, 2001, PECO had sold a $225 million interest in accounts receivable,
consisting of a $170 million interest in accounts receivable
18
which PECO accounted for as a sale under SFAS No. 140, "Accounting for Transfers
and Servicing of Financial Assets and Extinguishment of Liabilities - a
Replacement of FASB Statement No. 125," and a $55 million interest in
special-agreement accounts receivable which was accounted for as a long-term
note payable. See Note 14 - Long-Term Debt. PECO retains the servicing
responsibility for these receivables. The agreement requires PECO to maintain
the $225 million interest, which, if not met, requires PECO to deposit cash in
order to satisfy such requirements. At December 31, 2001 and 2000, PECO met this
requirement and was not required to make any cash deposits.
10. Property, Plant and Equipment
A summary of property, plant and equipment by classification as of December 31,
2001 and 2000 is as follows:
Asset Category 2001 2000
- -----------------------------------------------------------------------------------------------------------
Electric-Transmission and Distribution $ 10,156 $ 9,447
Electric-Generation 4,344 4,044
Gas 1,281 1,181
Common 399 408
Nuclear Fuel 2,681 2,341
Construction Work in Progress 1,294 1,189
Leased Property - 2
Other Property, Plant and Equipment 1,371 1,274
- -----------------------------------------------------------------------------------------------------------
Total Property, Plant and Equipment 21,526 19,886
Less Accumulated Depreciation (including accumulated
amortization of nuclear fuel of $1,838 and $1,445 in 2001
and 2000, respectively) 7,784 6,950
- -----------------------------------------------------------------------------------------------------------
Property, Plant and Equipment, net $13,742 $12,936
===========================================================================================================
11. Jointly Owned Electric Utility Plant
Exelon's undivided ownership interests in jointly owned electric plant at
December 31, 2001, were as follows:
Production Plant
----------------------------------------------------------------- Transmission
Peach Bottom Salem Keystone Conemaugh Quad Cities and Other Plant
PSE&G
Operator Generation Nuclear Reliant Reliant Generation Various Co.
- --------------------------------------------------------------------------------------------------------------
Participating Interest 50% 42.59% 20.99% 20.72% 75% 21 to 44%
Exelon's Share:
Plant $ 387 $ 12 $ 121 $ 193 $ 96 $ 66
Accumulated Depreciation $ 220 $ 4 $ 98 $ 124 $ 10 $ 25
Construction Work
in Progress $ 13 $ 53 $ 13 $ 12 $ 52 $ 1
- -------------------------------------------------------------------------------------------------------------
Exelon's undivided ownership interests are financed with Exelon funds and, when
placed in service, all operations are accounted for as if such participating
interests were wholly owned facilities.
19
12. Nuclear Decommissioning and Spent Fuel Storage
Exelon has an obligation to decommission its nuclear power plants. Exelon's
current estimate of its nuclear facilities' decommissioning cost for its owned
nuclear power plants is $7.2 billion in current year (2002) dollars. These
expenditures are expected to occur after the plants retirement, estimated to
begin in 2045. Decommissioning costs are currently recoverable through regulated
rates. Under rates in effect through December 31, 2001, Exelon collected
approximately $102 million in 2001 from customers. At December 31, 2001 the
decommissioning liability, recorded in Accumulated Depreciation and Deferred
Credits and Other Liabilities on Exelon's Consolidated Balance Sheets, was $2.7
billion and $1.3 billion, respectively. At December 31, 2000 the decommissioning
liability, recorded in Accumulated Depreciation and Deferred Credits and Other
Liabilities on Exelon's Consolidated Balance Sheets, was $2.6 billion and $1.3
billion, respectively. In order to fund future decommissioning costs, at
December 31, 2001 and 2000, Exelon held $3.2 billion and $3.1 billion,
respectively, in trust accounts which are included as Investments in Exelon's
Consolidated Balance Sheets at their fair market value. Exelon believes that the
amounts being recovered from customers through regulated rates and earnings on
nuclear decommissioning trust funds will be sufficient to fully fund its
decommissioning obligations.
In connection with the transfer of ComEd's nuclear generating stations to
Generation, ComEd asked the ICC to approve the continued recovery of
decommissioning costs after the transfer. On December 20, 2000, the ICC issued
an order finding that the ICC has the legal authority to permit ComEd to
continue to recover decommissioning costs from customers for the six-year term
of the power purchase agreements between ComEd and Generation. Under the ICC
order, ComEd is permitted to recover $73 million per year from customers for
decommissioning for the years 2001 through 2004. In 2005 and 2006, ComEd can
recover up to $73 million annually, depending upon the portion of the output of
the former ComEd nuclear stations that ComEd purchases from Generation. Under
the ICC order, subsequent to 2006, there will be no further recoveries of
decommissioning costs from customers. The ICC order also provides that any
surplus funds after the nuclear stations are decommissioned must be refunded to
customers. The amount of recovery in the ICC order is less than the $84 million
annual amount ComEd recovered in 2000. The ICC order is currently pending on
appeal in the Illinois Appellate Court.
To account for the effects of the ICC order, in the first quarter of 2001
ComEd reduced its nuclear decommissioning regulatory asset to $372 million,
reflecting the reduction in expected probable future recoveries from customers
through 2006. The reduction in the regulatory asset in the amount of $347
million was recorded as an adjustment to the initial purchase price allocation
relating to the asset and resulted in a corresponding increase in goodwill.
Also, ComEd recorded an obligation to Generation of approximately $440 million
representing ComEd's legal requirement to remit funds to Generation for the
remaining regulatory asset amount of $372 million upon collection from
customers, and for collections from customers prior to the establishment of
external decommissioning trust funds in 1989 to be remitted to Generation for
deposit into the decommissioning trusts through 2006. Unrealized gains and
losses on decommissioning trust funds (based on the market value of the assets
on the Merger date, in accordance with purchase accounting) had previously been
recorded in accumulated depreciation or regulatory assets. As a result of the
transfer of the ComEd nuclear plants to Generation and the ICC order limiting
the regulated recoveries of decommissioning costs, net unrealized losses of $23
million (net of income taxes) at that date were reclassified to accumulated
other comprehensive income. All subsequent realized gains and losses on these
decommissioning trust funds' assets are based on the cost basis of the trust
fund assets established on the Merger date and are reflected in Other Income and
Deductions in Exelon's Consolidated Statements of Income.
Under the Nuclear Waste Policy Act of 1982 (NWPA), the U.S. Department of
Energy (DOE) is responsible for the selection and development of repositories
for, and the disposal of, spent nuclear fuel (SNF) and high-level radioactive
waste. ComEd and PECO, as required by the NWPA, each signed a contract with the
DOE (Standard Contract) to provide for disposal of SNF from their respective
nuclear generating stations. In accordance with the NWPA and the Standard
Contract, ComEd and PECO pay the DOE one mill ($.001) per kilowatt-hour of net
nuclear generation for the cost of nuclear fuel long-term storage and disposal.
This fee may be adjusted prospectively in order to ensure full cost recovery.
The NWPA and the Standard Contract required the DOE to begin taking possession
of SNF generated by nuclear generating units by no later than January 1998. The
DOE, however, failed to meet that deadline and its performance is expected to be
delayed significantly. The DOE's current estimate for opening a SNF facility is
2010. This extended delay in SNF acceptance by the DOE has led to Exelon's
adoption of dry storage at its Dresden and Peach Bottom Units and its
consideration of dry storage at other units.
20
In July 1998, ComEd filed a complaint against the United States Government
(Government) in the United States Court of Federal Claims (Court) seeking to
recover damages caused by the DOE's failure to honor its contractual obligation
to begin disposing of SNF in January 1998. In August 2001, the Court granted
ComEd's motion for partial summary judgment for liability on ComEd's breach of
contract claim. In November 2001 the Government filed two partial summary
judgment motions relating to certain damage issues in the case as well as two
motions to dismiss claims other than ComEd's breach of contract claim. The Court
has deferred briefing on those motions pending completion of discovery on
certain damage issues.
In July 2000, PECO entered into an agreement with the DOE relating to
PECO's Peach Bottom nuclear generating unit to address the DOE's failure to
begin removal of SNF in January 1998 as required by the Standard Contract. Under
that agreement, the DOE agrees to provide PECO with credits against PECO's
future contributions to the Nuclear Waste Fund over the next ten years to
compensate PECO for SNF storage costs incurred as a result of the DOE's breach
of the contract. The agreement also provides that, upon PECO's request, the DOE
will take title to the SNF and the interim storage facility at Peach Bottom
provided certain conditions are met. In November 2000, eight utilities with
nuclear power plants filed a Joint Petition for Review against the DOE with the
United States Court of Appeals for the Eleventh Circuit seeking to invalidate
that portion of the agreement providing for credits to PECO against nuclear
waste fund payments on the ground that such provision is a violation of the
NWPA. PECO intervened as a defendant in that case, which is ongoing. In April
2001, an individual filed suit against the DOE with the United States District
Court for the Middle District of Pennsylvania seeking to invalidate the
agreement on the grounds that the DOE has violated the National Environmental
Policy Act and the Administrative Procedure Act. PECO intervened as a defendant
and moved to dismiss the complaint. The Court has not yet ruled on the motion to
dismiss.
The Standard Contract with the DOE also requires that PECO and ComEd pay
the DOE a one-time fee applicable to nuclear generation through April 6, 1983.
PECO's fee has been paid. Pursuant to the Standard Contract, ComEd elected to
pay the one-time fee of $277 million, with interest to the date of payment, just
prior to the first delivery of SNF to the DOE. As of December 31, 2001, the
liability for the one-time fee with interest was $843 million. The liabilities
for spent nuclear fuel disposal costs, including the one-time fee, were
transferred to Generation as part of the corporate restructuring.
13. Notes Payable
2001 2000 1999
- ------------------------------------------------------------------------------------------------------------
Average borrowings $193 $186 $242
Average interest rates, computed on daily basis 4.01% 6.62% 5.62%
Maximum borrowings outstanding $599 $500 $728
Average interest rates, at December 31 2.63% 7.18% 6.80%
============================================================================================================
Exelon, ComEd, PECO and Generation entered into a $1.5 billion 364 day unsecured
revolving credit facility on December 12, 2001 with a group of banks. This
credit facility is used principally to support the commercial paper programs of
Exelon, ComEd and PECO. At December 31, 2001 and 2000, the amount of commercial
paper outstanding was $360 million and $161 million, respectively. Interest
rates on the advances from the credit facility are based on the London Interbank
Offering Rate (LIBOR) as of the date of the advance.
In October 2000, Exelon obtained a $1.25 billion term loan due June 30,
2001 to finance the cash consideration paid to former holders of Unicom common
stock in connection with the Merger and to finance the purchase of its 49.9%
interest in Sithe in December 2000. On December 31, 2000, Exelon had $1,210
million outstanding on the term loan which is also reflected in Notes Payable on
the Consolidated Balance Sheets. This term loan was refinanced with long-term
debt in the second quarter of 2001. The average interest rate on this term loan
for the period it was outstanding in 2001 and 2000 was 6.4% and 7.6%,
respectively.
21
14. Long-Term Debt
at December 31,
--------------------------------------------------
Maturity
Rates Date 2001 2000
- -----------------------------------------------------------------------------------------------------------
ComEd Transitional Trust Notes
Series 1998-A: 5.00%-6.00% 2002-2008 $ 2,380 $ 2,720
PETT Bonds Series 1999-A:
Fixed rates 5.63%-6.13% 2003-2008 (a) 2,561 2,706
Floating rates 5.081%-6.52% 2004-2007 (a) 327 1,132
PETT Bonds Series 2000-A: 7.3%-7.65% 2002-2009 (a) 890 1,000
PETT Bonds Series 2001: 6.52% 2010 (a) 805 --
First and Refunding Mortgage Bonds (b) (c):
Fixed rates 4.00%-10.00% 2002-2023 3,942 4,260
Floating rates 1.46%-1.62% 2012 154 154
Notes payable 6.75%-9.20% 2002-2020 2,647 1,459
Pollution control notes:
Fixed rates 5.875% 2007 44 46
Floating rates 1.59%-2.45% 2009-2034 583 461
Notes payable - accounts receivable agreement 5.625%-10.25% 2005 55 40
Sinking fund debentures 3.125%-4.75% 2004-2011 23 27
- -----------------------------------------------------------------------------------------------------------
Total Long-Term debt (d) 14,411 14,005
Unamortized debt discount and premium, net (129) (139)
Due within one year (1,406) (908)
- -----------------------------------------------------------------------------------------------------------
Long-Term debt $12,876 $ 12,958
===========================================================================================================
(a) The maturity date represents the expected final payment date which is the date when all principal and
interest of the related class of transition bonds is expected to be paid in full in accordance with
the expected amortization schedule for the applicable class. The date when all principal and interest
must be paid in full for the PETT Bonds Series 1999-A, 2000-A and 2001-A are 2003 through 2009, 2003
through 2010 and 2010, respectively. The current portion of transition bonds is based upon the
expected maturity date.
(b) Utility plant of ComEd and PECO is subject to the liens of their respective mortgage indentures.
(c) Includes first mortgage bonds issued under the ComEd and PECO mortgage indentures securing pollution
control notes.
(d) Long-term debt maturities in the period 2002 through 2006 and thereafter are as follows:
2002 $ 1,406
2003 1,391
2004 896
2005 1,308
2006 1,268
Thereafter 8,142
----------------------
Total $14,411
======================
In 2001, ComEd entered into forward starting interest rate swaps with an
aggregate notional amount of $250 million to manage interest rate exposure
associated with the anticipated $400 million refinancing of ComEd First Mortgage
Bonds. ComEd also entered into an interest rate swap agreement with a notional
amount of $235 million to effectively convert fixed rate debt to floating rate
debt.
In 1999, PECO entered into treasury forwards associated with the
anticipated issuance of the Series 2000-A Transition Bonds. On May 2, 2000,
these instruments were settled with net proceeds to the counterparties of $13
million which has been deferred and is being amortized over the life of the
Series 2000-A Transition Bonds as an increase to interest expense.
22
In 1998, PECO entered into treasury forwards and forward starting interest
rate swaps to manage interest rate exposure associated with the anticipated
issuance of the Series 1999-A Transition Bonds. On March 18, 1999, these
instruments were settled with net proceeds of $80 million to PECO which were
deferred and are being amortized over the life of the Series 1999-A Transition
Bonds as a reduction of interest expense.
In connection with the refinancing of a portion of the two floating rate
series of transition bonds in the first quarter of 2001, PECO settled $318
million of a forward starting interest rate swap resulting in a $6 million gain
which is reflected in other income and deductions due to the transaction no
longer being probable. Also, in connection with the refinancing, PECO settled a
portion of the interest rate swaps and the remaining portion of the forward
starting interest rate swaps resulting in gains of $25 million, which were
deferred and are being amortized over the expected remaining lives of the
related debt.
At December 31, 2001 and 2000, the aggregate unamortized net gain on the
settlement of PECO transactions was $55 million and $51 million, respectively.
Prepayment premiums of $39 million, offset by unamortized issuance premiums
of $17 million, associated with the early retirement of debt in 2001 have been
deferred in regulatory assets and will be amortized to interest expense over the
life of the related new debt issuance consistent with regulatory recovery. In
2000 and 1999, Exelon incurred extraordinary charges aggregating $6 million ($4
million, net of tax) and $62 million ($37 million, net of tax), respectively for
prepayment premiums and the write-offs of unamortized deferred financing costs
associated with the early retirement of debt.
15. Income Taxes
Income tax expense (benefit) is comprised of the following components:
For the Years Ended December 31,
------------------------------------------
2001 2000 1999
- -----------------------------------------------------------------------------------------------------------
Included in operations:
Federal
Current $ 880 $ 163 $ 293
Deferred (61) 163 6
Investment tax credit, net (14) (15) (14)
State
Current 119 -- 72
Deferred 7 30 1
- -----------------------------------------------------------------------------------------------------------
$ 931 $ 341 $ 358
===========================================================================================================
Included in extraordinary item:
Federal
Current $ -- $ (2) $ (19)
State
Current -- -- (6)
- -----------------------------------------------------------------------------------------------------------
$ -- $ (2) $ (25)
===========================================================================================================
Included in cumulative effects of changes
in accounting principles:
Federal
Deferred $ 6 $ 13 $ --
State
Deferred 2 3 --
- -----------------------------------------------------------------------------------------------------------
$ 8 $ 16 $ --
===========================================================================================================
23
The effective income tax rate varies from the U.S. Federal statutory rate for
the years ended December 31 principally due to the following:
For the Years Ended December 31,
------------------------------------------
2001 2000 1999
- -----------------------------------------------------------------------------------------------------------
U.S. Federal statutory rate 35.0% 35.0% 35.0%
Increase (decrease) due to:
Property basis differences (0.2) 0.1 (0.8)
State income taxes, net of Federal income tax benefit 3.4 2.1 4.8
Amortization of investment tax credit (0.5) (1.6) (1.5)
Amortization of goodwill 1.9 0.9 --
Prior period income taxes (0.3) 0.4 (0.7)
Dividends on PECO Preferred Stock 0.2 0.4 0.4
Other, net 0.2 0.3 (0.1)
- -----------------------------------------------------------------------------------------------------------
Effective income tax rate 39.7% 37.6% 37.1%
===========================================================================================================
The tax effects of temporary differences giving rise to significant portions of
Exelon's deferred tax assets and liabilities as of December 31, 2001 and 2000
are presented below:
2001 2000
- -----------------------------------------------------------------------------------------------------------
Deferred tax liabilities:
Plant basis difference $ 5,116 $ 4,535
Deferred gain on like-kind exchange 453 466
Deferred investment tax credit 222 330
Deferred debt refinancing costs 44 48
Other, net 63 5
- -----------------------------------------------------------------------------------------------------------
Total deferred tax liabilities 5,898 5,384
- -----------------------------------------------------------------------------------------------------------
Deferred tax assets:
Decommissioning and decontamination obligations (898) --
Deferred pension and postretirement obligations (382) (437)
Other, net (22) (270)
- -----------------------------------------------------------------------------------------------------------
Total deferred tax assets (1,302) (707)
- -----------------------------------------------------------------------------------------------------------
Deferred income taxes (net) on the balance sheet $ 4,596 $ 4,677
===========================================================================================================
Prior to 2001, the offsetting deferred tax assets and liabilities resulting from
decommissioning and decontamination assets and obligations, accounted for as
regulatory assets and liabilities, were recorded within the plant basis
difference caption above. As a result of the corporate restructuring, on January
1, 2001, the decommissioning and decontamination obligations were transferred to
Generation, an unregulated subsidiary; however the regulatory asset related to
decommissioning and decontamination remained with ComEd as a receivable from its
regulated customers. The deferred tax liability relating to the regulatory asset
is reflected in the plant basis difference caption, however, the deferred tax
asset related to the decommissioning and decontamination obligation is no longer
recorded in the plant basis difference caption with the regulatory assets and
liabilities.
In accordance with regulatory treatment of certain temporary differences,
Exelon has recorded a regulatory asset for recoverable deferred income taxes of
$701 million and $632 million at December 31, 2001 and 2000, respectively. These
recoverable deferred income taxes include the deferred tax effects associated
principally with liberalized depreciation accounted for in accordance with the
ratemaking policies of the ICC and PUC, as well as the revenue impacts thereon,
and assume continued recovery of these costs in future rates.
24
The Internal Revenue Service and certain state tax authorities are
currently auditing certain tax returns of Exelon's predecessor entities, Unicom
and PECO. The current audits are not expected to have an adverse impact on
financial condition or results of operations of Exelon.
16. Retirement Benefits
Exelon sponsors defined benefit pension plans and postretirement welfare benefit
plans applicable to essentially all ComEd, PECO, Generation and BSC employees
and certain employees of Enterprises. In 2001, Exelon consolidated the former
Unicom and PECO plans into Exelon plans. Essentially all management employees,
and electing union employees, hired on or after January 1, 2001 participate in
newly established cash balance pension plans. 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. Benefits under Exelon's pension plans generally reflect each
employee's compensation, years of service and age at retirement. Funding is
based upon actuarially determined contributions that take into account the
amount deductible for income tax purposes and the minimum contribution required
under the Employee Retirement Income Security Act of 1974, as amended. The
following tables provide a reconciliation of benefit obligations, plan assets
and funded status of the plans.
Pension Benefits Other Postretirement Benefits
--------------------------------------------------------
2001 2000 2001 2000
- -----------------------------------------------------------------------------------------------------------
Change in Benefit Obligation:
Net benefit obligation at beginning of year $ 6,695 $ 2,054 $ 2,275 $ 798
Service cost 94 39 42 24
Interest cost 498 219 161 83
Plan participants' contributions -- -- 4 1
Plan amendments 44 -- (191) --
Actuarial (gain)loss 254 228 173 144
Acquisitions -- 4,231 -- 1,228
Curtailments/Settlements (38) (74) -- 4
Special accounting costs 48 217 3 48
Gross benefits paid (494) (219) (136) (55)
- -----------------------------------------------------------------------------------------------------------
Net benefit obligation at end of year $ 7,101 $ 6,695 $ 2,331 $ 2,275
===========================================================================================================
Change in Plan Assets:
Fair value of plan assets at beginning of year $ 7,000 $ 2,982 $ 1,188 $ 244
Actual return on plan assets (265) 173 (14) (7)
Employer contributions 38 2 90 84
Plan participants' contributions -- -- 4 1
Acquisitions -- 4,062 -- 921
Gross benefits paid (494) (219) (136) (55)
- -----------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of year $ 6,279 $ 7,000 $ 1,132 $ 1,188
===========================================================================================================
Funded status at end of year $ (822) $ 305 $ (1,199) $ (1,087)
Miscellaneous adjustment -- -- -- 5
Unrecognized net actuarial (gain)loss 397 (777) 440 143
Unrecognized prior service cost 108 77 (191) --
Unrecognized net transition obligation (asset) (17) (21) 103 122
- -----------------------------------------------------------------------------------------------------------
Net amount recognized at end of year $ (334) $ (416) $ (847) $ (817)
===========================================================================================================
25
Pension Benefits Other Postretirement Benefits
-------------------------------------------------------------------------------------
2001 2000 1999 2001 2000 1999
- --------------------------------------------------------------------------------------------------------------------------
Weighted-average assumptions
as of December 31,
Discount rate 7.35% 7.60% 8.00% 7.35% 7.60% 8.00%
Expected return on plan assets 9.50% 9.50% 9.50% 9.50% 8.00% 8.00%
Rate of compensation increase 4.00% 4.30% 5.00% 4.00% 4.30% 5.00%
Health care cost trend on
covered charges N/A N/A N/A 10.00% 7.00% 8.00%
decreasing decreasing decreasing
to ultimate to ultimate to ultimate
trend of 4.5% trend of 5.0% trend of 5.0%
in 2008 in 2005 in 2006
Pension Benefits Other Postretirement Benefits
-------------------------------------------------------------------------------------
2001 2000 1999 2001 2000 1999
- --------------------------------------------------------------------------------------------------------------------------
Components of net periodic
benefit cost (benefit):
Service cost $ 94 $ 39 $ 29 $ 42 $ 24 $ 19
Interest cost 498 219 154 161 83 57
Expected return on assets (625) (316) (222) (99) (34) (16)
Amortization of:
Transition obligation (asset) (4) (4) (4) 10 12 12
Prior service cost 9 7 5 (9) -- --
Actuarial (gain) loss (25) (26) (8) 1 -- --
Curtailment charge (credit) (12) (12) -- 9 24 --
Settlement charge (credit) (9) (16) -- -- -- --
- --------------------------------------------------------------------------------------------------------------------------
Net periodic benefit cost (benefit) $ (74) $ (109) $ (46) $ 115 $ 109 $ 72
==========================================================================================================================
Special accounting costs $ 48 $ 217 $ -- $ 3 $ 48 $ --
==========================================================================================================================
Sensitivity of retiree welfare results
- -----------------------------------------------------------------------------------------------------------
Effect of a one percentage point increase in assumed health care cost trend
on total service and interest cost components $ 33
on postretirement benefit obligation $ 276
Effect of a one percentage point decrease in assumed health care cost trend
on total service and interest cost components $ (28)
on postretirement benefit obligation $ (239)
- -----------------------------------------------------------------------------------------------------------
Prior service cost is amortized on a straight-line basis over the average
remaining service period of employees expected to receive benefits under the
plans.
Special accounting costs of $48 million in 2001 represent accelerated
separation and enhancement benefits provided to PECO employees expected to be
terminated as a result of the Merger. Special accounting costs in 2000 of $217
million represented PECO's accelerated separation and enhancement benefits of
$96 million and ComEd's accelerated liability increase of $121 million inclusive
of $96 million for separation benefits and $25 million for plan enhancements.
26
Exelon provides certain health care and life insurance benefits for retired
employees. In 2001, Exelon adopted an amendment to the former Unicom
postretirement medical benefit plan that changed the eligibility requirement of
the plan to cover only employees who retire with 10 years of service after age
45 rather than with 10 years of service and having attained the age of 55.
Welfare benefits for active employees are provided by several insurance policies
or self-funded plans whose premiums or contributions are based upon the benefits
paid during the year.
Additionally, Exelon sponsors nonqualified supplemental retirement plans
which cover any excess pension benefits that would be payable to management
employees under the qualified plan but which are limited by the Internal Revenue
Code. The fair value of plan assets excludes $58 million held in trust as of
December 31, 2001 for the payment of benefits under the supplemental plan and $8
million held in trust as of December 31, 2001 for the payment of postretirement
medical benefits.
Exelon sponsors savings plans for the majority of its employees. The plans
allow employees to contribute a portion of their pretax income in accordance
with specified guidelines. Exelon matches a percentage of the employee
contribution up to certain limits. The cost of Exelon's matching contribution to
the savings plans totaled $57 million, $17 million and $7 million in 2001, 2000
and 1999, respectively.
17. Preferred Securities of Subsidiaries
Preferred and Preference Stock
At December 31, 2001 and 2000, Series Preference Stock of PECO, no par value,
consisted of 100,000,000 shares authorized, of which no shares were outstanding.
At December 31, 2001 and 2000, cumulative Preferred Stock of PECO, no par value,
consisted of 15,000,000 shares authorized and the amounts set forth below:
at December 31,
---------------------------------------------------------------
Current 2001 2000 2001 2000
Redemption ---------------------------------------------------------------
Price(a) Shares Outstanding Dollar Amount
- -----------------------------------------------------------------------------------------------------------
Series (without mandatory
redemption)
$4.68 $ 104.00 150,000 150,000 $ 15 $ 15
$4.40 112.50 274,720 274,720 27 27
$4.30 102.00 150,000 150,000 15 15
$3.80 106.00 300,000 300,000 30 30
$7.48 (b) 500,000 500,000 50 50
- -----------------------------------------------------------------------------------------------------------
1,374,720 1,374,720 137 137
Series (with mandatory
redemption)
$6.12 (c) 185,400 370,800 19 37
- -----------------------------------------------------------------------------------------------------------
Total preferred stock 1,560,120 1,745,520 $ 156 $ 174
===========================================================================================================
(a) Redeemable, at the option of PECO, at the indicated dollar amounts per share, plus accrued dividends.
(b) None of the shares of this series is subject to redemption prior to April 1, 2003.
(c) PECO made the annual sinking fund payments of $18.5 million on August 1, 2001 and August 2, 2000. The
future sinking fund requirement in 2002 is $18.5 million.
At December 31, 2001, ComEd Prior Preferred Stock and ComEd Preference Stock
consisted of 850,000 and 6,810,451 shares authorized, respectively, none of
which were outstanding.
27
Company Obligated Mandatorily Redeemable Preferred Securities At December 31,
2001 and 2000, subsidiary trusts of PECO and ComEd had outstanding the following
preferred securities:
at December 31,
-----------------------------------------------
Mandatory Distri- Liqui- 2001 2000 2001 2000
Redemption bution dation -----------------------------------------------
Date Rate Value Trust Securities Outstanding Dollar Amount
- -----------------------------------------------------------------------------------------------------------
PECO Energy
Capital Trust II 2037 8.00% $ 25 2,000,000 2,000,000 $ 50 $ 50
PECO Energy
Capital Trust III 2028 7.38% 1,000 78,105 78,105 78 78
- -----------------------------------------------------------------------------------------------------------
Total 2,078,105 2,078,105 $ 128 $ 128
===========================================================================================================
ComEd Financing I 2035 8.48% $ 25 8,000,000 8,000,000 $ 200 200
ComEd Financing II 2027 8.50% 1,000 150,000 150,000 150 150
Unamortized Discount (21) (22)
- -----------------------------------------------------------------------------------------------------------
Total 8,150,000 8,150,000 $ 329 $ 328
===========================================================================================================
The securities issued by the PECO trusts represent Company Obligated Mandatorily
Redeemable Preferred Securities of a Partnership (COMRPS) having a distribution
rate and liquidation value equivalent to the trust securities. The COMRPS are
the sole assets of these trusts and represent limited partnership interests of
PECO Energy Capital, L.P. (Partnership), a Delaware limited partnership. Each
holder of a trust's securities is entitled to withdraw the corresponding number
of COMRPS from the trust in exchange for the trust securities so held. Each
series of COMRPS is supported by PECO's deferrable interest subordinated
debentures, held by the Partnership, which bear interest at rates equal to the
distribution rates on the related series of COMRPS.
ComEd Financing I and ComEd Financing II are wholly owned subsidiary trusts
of ComEd. Each ComEd trust's sole assets are subordinated deferrable interest
securities issued by ComEd bearing interest rates equivalent to the distribution
rate of the related trust security.
The interest expense on the debentures and deferrable interest securities
is included in Distributions on Preferred Securities of Subsidiaries in the
Consolidated Statements of Income and is deductible for income tax purposes.
18. Common Stock
At December 31, 2001 and 2000, common stock without par value consisted of
600,000,000 and 600,000,000 shares authorized and 321,006,904 and 319,005,112
shares outstanding, respectively.
Stock Repurchase
In January 2000, in connection with the Merger Agreement, PECO entered into a
forward purchase agreement to purchase $500 million of its common stock from
time to time. Settlement of this forward purchase agreement was, at PECO's
election, on a physical, net share or net cash basis. In May 2000, PECO utilized
a portion of the proceeds from the securitization of its stranded cost recovery
to physically settle this agreement, resulting in the repurchase of 12 million
shares of common stock for $496 million. In connection with the settlement of
this agreement, PECO received $1 million in accumulated dividends on the
repurchased shares and paid $6 million of interest.
During 1997, PECO's Board of Directors authorized the repurchase of up to
25 million shares of its common stock from time to time through open-market,
privately negotiated and/or other types of transactions in conformity with the
rules of the SEC. Pursuant to these authorizations, PECO entered into forward
purchase agreements to be settled from time to time, at PECO's election, on a
physical, net share or net cash basis. PECO utilized the proceeds from the
securitization of a portion of its stranded cost recovery in the first quarter
of 1999, to physically settle these agreements, resulting in the purchase of 21
million shares of common stock for $696 million. In connection with the
settlement of these agreements, PECO received $18 million in accumulated
dividends on the repurchased shares and paid $6 million of interest.
28
Stock-Based Compensation Plans
Exelon maintains a Long-Term Incentive Plan (LTIP) for certain full-time
salaried employees and previously maintained a broad-based incentive program for
certain other employees. The types of long-term incentive awards that have been
granted under the LTIP are non-qualified options to purchase shares of Exelon's
common stock and common stock awards. At December 31, 2001, there were 9,000,000
options authorized for issuance under the LTIP and 2,000,000 options authorized
under the broad-based incentive program. Exelon uses the disclosure-only
provisions of SFAS No. 123, "Accounting for Stock-Based Compensation" (SFAS No.
123). If Exelon elected to account for its stock-based compensation plans based
on SFAS No. 123, it would have recognized compensation expense of $7 million,
$60 million and $10 million, for 2001, 2000 and 1999, respectively. In addition,
net income would have been $1,421 million, $526 million and $560 million for
2001, 2000 and 1999, respectively, and earnings per share would have been $4.41,
$2.58 and $2.84 for 2001, 2000 and 1999, respectively.
The exercise price of the stock options is equal to the fair market value
of the underlying stock on the date of option grant. Options granted under the
LTIP and the broad-based incentive program become exercisable upon attainment of
a target share value and/or time. All options expire 10 years from the date of
grant. Information with respect to the LTIP and the broad-based incentive
program at December 31, 2001 and changes for the three years then ended, is as
follows:
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Price Price Price
Shares (per share) Shares (per share) Shares (per share)
2001 2001 2000 2000 1999 1999
- -----------------------------------------------------------------------------------------------------------
Balance at January 1 15,287,859 42.13 6,065,897 $ 31.91 4,663,008 $ 27.71
Options granted/assumed 629,200 66.42 11,089,051 (a) 46.09 2,049,789 39.32
Options exercised (1,695,474) 34.84 (1,725,058) 31.79 (568,000) 25.17
Options canceled (181,589) 52.64 (142,031) 39.95 (78,900) 38.14
- -----------------------------------------------------------------------------------------------------------
Balance at December 31 14,039,996 43.96 15,287,859 42.13 6,065,897 31.91
===========================================================================================================
Exercisable at
December 31 8,006,193 38.75 4,953,942 30.04 3,331,903 25.60
===========================================================================================================
Weighted average fair value
of options granted
during year $ 19.59 $ 16.62 $ 8.24
===========================================================================================================
(a) Includes 5.3 million options converted in the Merger.
The fair value of each option is estimated on the date of grant using the
Black-Scholes option-pricing model with the following weighted average
assumptions used for grants in 2001, 2000 and 1999, respectively:
2001 2000 1999
- -----------------------------------------------------------------------------------------------------------
Dividend yield 3.2% 3.6% 5.7%
Expected volatility 36.8% 36.8% 30.5%
Risk-free interest rate 4.9% 5.9% 5.9%
Expected life (years) 5.0 5.0 9.5
- -----------------------------------------------------------------------------------------------------------
29
At December 31, 2001, the options outstanding, based on ranges of exercise
prices, were as follows:
Options Outstanding Options Exercisable
----------------------------------------------------------------------------------
Weighted
Average
Remaining Weighted Weighted
Contractual Average Average
Range of Number Life Exercise Number Exercise
Exercise Prices Outstanding (years) Price Exercisable Price
- ------------------------------------------------------------------------------------------------------------
$10.01-$20.00 597,400 6.14 $19.68 597,400 $19.68
$20.01-$30.00 1,639,611 4.40 25.03 1,639,611 25.03
$30.01-$40.00 5,395,604 7.54 37.85 3,069,046 37.63
$40.01-$50.00 1,438,206 7.43 41.56 1,023,557 41.21
$50.01-$60.00 4,332,775 8.82 59.46 1,669,077 59.49
$60.01-$70.00 636,400 9.04 67.30 7,502 64.97
- ------------------------------------------------------------------------------------------------------------
Total 14,039,996 8,006,193
============================================================================================================
Under Exelon's LTIP 195,725 shares and 120,300 shares of common stock awards
were issued during 2000 and 1999, respectively. Vesting for the common stock
awards is over a period not to exceed 10 years from the grant date. Compensation
cost of $14 million associated with these awards is amortized to expense over
the vesting period. The related accumulated amortization was approximately $12
million, $7 million and $2 million at December 31, 2001, 2000 and 1999,
respectively.
Additionally under Exelon's LTIP, 426,794 and 159,129 Exelon common share
awards were granted during 2001 and 2000, respectively. Compensation cost of $30
million is to be accrued to expense over the vesting period of up to 5 years
from the date of the grant. The related accumulated amortization was
approximately $17 million and $6 million at December 31, 2001 and 2000,
respectively.
In June 2001, the Board of Directors of Exelon approved the Employee Stock
Purchase Plan (ESPP). The purpose of the ESPP is to provide employees of Exelon,
and its subsidiary companies the right to purchase shares of Exelon's common
stock at below-market prices. A total of 5,000,000 shares of Exelon's common
stock have been reserved for issuance under the ESPP. Employees' purchases are
limited to no more than 125 shares per quarter and no more than $25,000 in fair
market value in any plan year. During 2001, employees purchased 137,648 shares
of Exelon common stock under the ESPP.
30
19. Fair Value of Financial Assets and Liabilities
The carrying amounts and fair values of Exelon's financial assets and
liabilities as of December 31, 2001 and 2000 were as follows:
2001 2000
-------------------------------------------------------------------
Carrying Carrying
Amount Fair Value Amount Fair Value
- -----------------------------------------------------------------------------------------------------------
Non-derivatives:
Liabilities
Long-term debt (including
amounts due within one year) $ 14,282 $ 14,912 $ 13,866 $ 14,336
Preferred Securities of Subsidiaries 613 572 630 601
Derivatives:
Interest rate swaps (20) (20) -- (19)
Forward interest rate swaps (1) (1) -- 40
Energy derivatives 92 92 (34) (34)
- -----------------------------------------------------------------------------------------------------------
Cash and cash equivalents, customer accounts receivable and trust accounts for
decommisioning nuclear plants are recorded at their fair value.
As of December 31, 2001 and 2000, Exelon's carrying amounts of cash and
cash equivalents and accounts receivable are representative of fair value
because of the short-term nature of these instruments. Fair values of the trust
accounts for decommissioning nuclear plants, long-term debt and preferred
securities of subsidiaries are estimated based on quoted market prices for the
same or similar issues. The fair value of Exelon's interest rate swaps and power
purchase and sale contracts is determined using quoted exchange prices, external
dealer prices, or internal valuation models which utilize assumptions of future
energy prices and available market pricing curves.
Financial instruments that potentially subject Exelon to concentrations of
credit risk consist principally of cash equivalents and customer accounts
receivable. Exelon places its cash equivalents with high-credit quality
financial institutions. Generally, such investments are in excess of the Federal
Deposit Insurance Corporation limits. Concentrations of credit risk with respect
to customer accounts receivable are limited due to Exelon's large number of
customers and their dispersion across many industries.
Exelon has entered into interest rate swaps and forward-starting interest
rate swaps to manage interest rate exposure in the aggregate notional amount of
$576 million. These swaps have been designated as cash-flow hedges under SFAS
No. 133, and as such, as long as the hedge remains effective and the underlying
transaction remains probable, changes in the fair value of these swaps will be
recorded in accumulated other comprehensive income (loss) until earnings are
affected by the variability of the cash flows being hedged.
Exelon has also entered into an interest rate swap to lock in the value of
a $235 million fixed-rate obligation of ComEd. This swap has been designated as
a fair-value hedge, as defined in SFAS No. 133 and as such, changes in the fair
value of the swap will be recorded in earnings. However, as long as the hedge
remains effective and the underlying transaction remains probable, changes in
the fair value of the swap will be offset by changes in the fair value of the
hedged liabilities. Any change in the fair value of the hedge as a result of
ineffectiveness would be recorded immediately in earnings.
The notional amount of derivatives do not represent amounts that are
exchanged by the parties and, thus, are not a measure of Exelon's exposure. The
amounts exchanged are calculated on the basis of the notional or contract
amounts, as well as on the other terms of the derivatives, which relate to
interest rates and the volatility of these rates.
Exelon utilizes derivatives to manage the utilization of its available
generating capacity and provision of wholesale energy to its affiliates. Exelon
also utilizes energy option contracts and energy financial swap arrangements to
limit the market price risk associated with forward energy commodity contracts.
Additionally, Exelon enters into certain energy-related derivatives for trading
or speculative purposes.
Exelon would be exposed to credit-related losses in the event of
non-performance by the counterparties that issued the derivative instruments.
The credit exposure of derivatives contracts is represented by the fair value of
contracts at the
31
reporting date. Exelon's interest rate swaps are documented under master
agreements. Among other things, these agreements provide for a maximum credit
exposure for both parties. Payments are required by the appropriate party when
the maximum limit is reached. The majority of power purchase and sale contracts
are documented under master netting agreements.
On January 1, 2001, Exelon recognized a non-cash gain of $12 million, net
of income taxes, in earnings and deferred a non-cash gain of $44 million, net of
income taxes, in accumulated other comprehensive income, a component of
shareholders' equity, to reflect the initial adoption of SFAS No. 133, as
amended. SFAS No. 133 must be applied to all derivative instruments and requires
that such instruments be recorded in the balance sheet either as an asset or a
liability measured at their fair value through earnings, with special accounting
permitted for certain qualifying hedges.
During 2001, Exelon recognized net gains of $16 million ($10 million, net
of income taxes) relating to mark-to-market (MTM) adjustments of certain
non-trading power purchase and sale contracts pursuant to SFAS No. 133. MTM
adjustments on power purchase contracts are reported in fuel and purchased power
and MTM adjustments on power sale contracts are reported as Operating Revenues
in the Consolidated Statements of Income. During 2001, Exelon recognized net
gains aggregating $14 million ($10 million, net of income taxes) on derivative
instruments entered into for trading purposes. Exelon commenced financial
trading in the second quarter of 2001. Gains and losses associated with
financial trading are reported as Other Income and Deductions in the
Consolidated Statements of Income. During 2001, no amounts were reclassified
from accumulated other comprehensive income into earnings as a result of
forecasted energy commodity transactions no longer being probable. For 2001, a
$6 million gain ($4 million, net of income taxes) was reclassified from
accumulated other comprehensive income into earnings as a result of forecasted
financing transactions no longer being probable.
As of December 31, 2001, $65 million of deferred net gains on derivative
instruments accumulated in other comprehensive income are expected to be
reclassified to earnings during the next twelve months. Amounts in accumulated
other comprehensive income related to interest rate cash flows are reclassified
into earnings when the forecasted interest payment occurs. Amounts in
accumulated other comprehensive income related to energy commodity cash flows
are reclassified into earnings when the forecasted purchase or sale of the
energy commodity occurs. The majority of Exelon's cash flow hedges are expected
to settle within the next 3 years.
Exelon classifies investments in the trust accounts for decommissioning
nuclear plants as available-for-sale. The following tables show the fair values,
gross unrealized gains and losses and amortized costs bases for the securities
held in these trust accounts.
December 31,2001
--------------------------------------------------------------
Gross Gross
Amortized Unrealized Unrealized Estimated
Cost Gains Losses Fair Value
- -----------------------------------------------------------------------------------------------------------
Equity securities $ 1,666 $ 130 $ (236) $ 1,560
Debt securities
Government obligations 882 28 (3) 907
Other debt securities 701 16 (19) 698
- -----------------------------------------------------------------------------------------------------------
Total debt securities 1,583 44 (22) 1,605
- -----------------------------------------------------------------------------------------------------------
Total available-for-sale securities $ 3,249 $ 174 $ (258) $ 3,165
===========================================================================================================
December 31,2000
--------------------------------------------------------------
Gross Gross
Amortized Unrealized Unrealized Estimated
Cost Gains Losses Fair Value
- -----------------------------------------------------------------------------------------------------------
Equity securities $ 1,702 $ 144 $ (180) $ 1,666
Debt securities
Government obligations 932 40 -- 972
Other debt securities 470 8 (7) 471
- -----------------------------------------------------------------------------------------------------------
Total debt securities 1,402 48 (7) 1,443
- -----------------------------------------------------------------------------------------------------------
Total available-for-sale securities $ 3,104 $ 192 $ (187) $ 3,109
===========================================================================================================
32
Net unrealized losses of $84 million and gains of $5 million were recognized in
Accumulated Depreciation, Regulatory Assets and Accumulated Other Comprehensive
Income in Exelon's Consolidated Balance Sheets at December 31, 2001 and 2000,
respectively.
For the Years December 31
---------------------------
2001 2000
- -----------------------------------------------------------------------------------------------------------
Proceeds from sales $ 1,624 $ 265
Gross realized gains 76 9
Gross realized losses (189) (46)
- -----------------------------------------------------------------------------------------------------------
Net realized gains of $14 million and net realized losses of $37 million were
recognized in Accumulated Depreciation and Regulatory Assets in Exelon's
Consolidated Balance Sheets at December 31, 2001 and 2000, respectively and $127
million of net realized losses was recognized in Other Income and Deductions in
Exelon's Consolidated Income Statements for 2001.
The available-for-sale securities held at December 31, 2001 have an average
maturity of eight to ten years. The cost of these securities was determined on
the basis of specific identification. See Note 12 - Nuclear Decommissioning and
Spent Fuel Storage for further information regarding the nuclear decommissioning
trusts.
20. Commitments and Contingencies
Capital Commitments
In December 2001, Generation agreed to purchase two generation plants located in
the Dallas-Fort Worth metropolitan area from TXU Corp. (TXU) to expand its
presence in the Texas region. The $443 million purchase of the two natural-gas
and oil-fired plants, to be funded through available cash and commercial paper
proceeds, will add approximately 2,300 megawatts (MW) capacity. The transaction
includes a power purchase agreement for TXU to purchase power during the months
of May through September from 2002 through 2006. During the periods covered by
the power purchase agreement, TXU will make fixed capacity payments and will
provide fuel to Exelon in return for exclusive rights to the energy and capacity
of the generation plants. The closing of the acquisition is contingent upon
receipt of the necessary regulatory approvals and is anticipated to occur in the
first quarter of 2002. Also, Exelon has committed to provide AmerGen with
capital contributions equivalent to 50% of the purchase price of any
acquisitions AmerGen makes in 2002 and Exelon and British Energy have each
agreed to provide up to $100 million to AmerGen at any time for operating
expenses.
Nuclear Insurance
The Price-Anderson Act limits the liability of nuclear reactor owners for claims
that could arise from a single incident. The current limit is $9.5 billion and
is subject to change to account for the effects of inflation and changes in the
number of licensed reactors. Through its subsidiaries, Exelon carries the
maximum available commercial insurance of $200 million and the remaining $9.3
billion is provided through mandatory participation in a financial protection
pool. Under the Price-Anderson Act, all nuclear reactor licensees can be
assessed up to $89 million per reactor per incident, payable at no more than $10
million per reactor per incident per year. This assessment is subject to
inflation and state premium taxes. In addition, the U.S. Congress could impose
revenue-raising measures on the nuclear industry to pay claims. The
Price-Anderson Act is scheduled to expire in August 2002. Although replacement
legislation has been proposed from time to time, Exelon is unable to predict
whether replacement legislation will be enacted.
Exelon carries property damage, decontamination and premature
decommissioning insurance for each station loss resulting from damage to its
nuclear plants. In the event of an accident, insurance proceeds must first be
used for reactor stabilization and site decontamination. If the decision is made
to decommission the facility, a portion of the insurance proceeds will be
allocated to a fund, which Exelon is required by the Nuclear Regulatory
Commission (NRC) to maintain, to provide for decommissioning the facility.
Exelon is unable to predict the timing of the availability of insurance proceeds
to Exelon and the amount of such proceeds which would be available. Under the
terms of the various insurance agreements, Exelon could be
33
assessed up to $121 million for losses incurred at any plant insured by the
insurance companies. In the event that one or more acts of terrorism cause
accidental property damage within a twelve month period from the first
accidental property damage under one or more policies for all insureds, the
maximum recovery for all losses by all insureds will be an aggregate of $3.2
billion plus such additional amounts as the insurer may recover for all such
losses from reinsurance, indemnity, and any other source, applicable to such
losses.
Additionally, through its subsidiaries, Exelon is a member of an industry
mutual insurance company that provides replacement power cost insurance in the
event of a major accidental outage at a nuclear station. The premium for this
coverage is subject to assessment for adverse loss experience. Exelon's maximum
share of any assessment is $46 million per year. Recovery under this insurance
for terrorist acts is subject to the $3.2 billion aggregate limit and secondary
to the property insurance described above.
In addition, Exelon participates in the American Nuclear Insurers Master
Worker Program, which provides coverage for worker tort claims filed for bodily
injury caused by a nuclear energy accident. This program was modified, effective
January 1, 1998, to provide coverage to all workers whose "nuclear-related
employment" began on or after the commencement date of reactor operations.
Exelon will not be liable for a retrospective assessment under this new policy.
However, in the event losses incurred under the small number of policies in the
old program exceed accumulated reserves, a maximum retroactive assessment of up
to $50 million could apply.
Exelon is self-insured to the extent that any losses may exceed the amount
of insurance maintained. Such losses could have a material adverse effect on
Exelon's financial condition and results of operations.
Energy Commitments
Exelon's wholesale operations include the physical delivery and marketing of
power obtained through its generation capacity, and long, intermediate and
short-term contracts. Exelon maintains a net positive supply of energy and
capacity, through ownership of generation assets and power purchase and lease
agreements, to protect it from the potential operational failure of one of its
owned or contracted power generating units. Exelon has also contracted for
access to additional generation through bilateral long-term power purchase
agreements. These agreements are firm commitments related to power generation of
specific generation plants and/or are dispatchable in nature - similar to asset
ownership. Exelon enters into power purchase agreements with the objective of
obtaining low-cost energy supply sources to meet its physical delivery
obligations to its customers. Exelon has also purchased firm transmission rights
to ensure that it has reliable transmission capacity to physically move its
power supplies to meet customer delivery needs. The primary intent and business
objective for the use of its capital assets and contracts is to provide Exelon
with physical power supply to enable it to deliver energy to meet customer
needs. Exelon primarily uses financial contracts in its wholesale marketing
activities for hedging purposes. Exelon also uses financial contracts to manage
the risk surrounding trading for profit activities.
Exelon has entered into bilateral long-term contractual obligations for
sales of energy to load-serving entities, including electric utilities,
municipalities, electric cooperatives, and retail load aggregators. Exelon also
enters into contractual obligations to deliver energy to wholesale market
participants who primarily focus on the resale of energy products for delivery.
Exelon provides delivery of its energy to these customers through access to its
transmission assets or rights for firm transmission.
Generation has power purchase arrangements (PPAs) with Midwest Generation,
LLC (Midwest Generation) for the purchase of capacity from its coal fired
stations, in declining amounts through 2004. Contracted capacity and capacity
available through the exercise of an annual option are as follows (in
megawatts):
Contracted Available Option
Capacity Capacity
- ------------------------------------------------------------------------------------------------------------
2002 4,013 1,632
2003 1,696 3,949
2004 1,696 3,949
- ------------------------------------------------------------------------------------------------------------
34
The agreements also provide for the option to purchase 2,698 megawatts of oil
and gas-fired capacity, and 944 megawatts of peaking capacity, subject to
reduction.
Generation has entered into PPAs with AmerGen, under which it will purchase
all the energy from Unit No. 1 at Three Mile Island Nuclear Station (TMI) after
December 31, 2001 through December 31, 2014. Under a 1999 PPA, Generation will
purchase from AmerGen all of the residual energy from the Clinton Nuclear Power
Station (Clinton), through December 31, 2002. Currently, the residual output
approximates 25% of the total output of the Clinton.
At December 31, 2001, Exelon had long-term commitments, relating to the
purchase and sale of energy, capacity and transmission rights from unaffiliated
utilities and others, including the Midwest Generation and AmerGen contracts, as
expressed in the following tables:
Transmission
Capacity Rights Power Only Power Only
Purchases Purchases Purchases Sales
- -------------------------------------------------------------------------------------------------------------
2002 $ 1,005 $ 139 $ 551 $ 1,803
2003 1,214 31 345 666
2004 1,222 15 346 219
2005 406 15 264 139
2006 406 5 250 58
Thereafter 3,657 -- 2,321 22
- -------------------------------------------------------------------------------------------------------------
Total $ 7,910 $ 205 $ 4,077 $ 2,907
=============================================================================================================
Environmental Issues
Exelon's operations have in the past and may in the future require substantial
capital expenditures in order to comply with environmental laws. Additionally,
under Federal and state environmental laws, Exelon, through its subsidiaries, is
generally liable for the costs of remediating environmental contamination of
property now or formerly owned by Exelon and of property contaminated by
hazardous substances generated by Exelon. Exelon owns or leases a number of real
estate parcels, including parcels on which its operations or the operations of
others may have resulted in contamination by substances which 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. Included in the
environmental investigation and remediation cost obligation as of December 31,
2001 and 2000 is $100 million and $110 million, respectively, that has been
recorded on a discount basis, (reflecting discount rates of 5.5%). Such
estimates, reflecting the effects of a 3% inflation rate before the effects of
discounting were $154 million and $170 million at December 31, 2001 and 2000,
respectively. Exelon anticipates that payments related to the discounted
environmental investigation and remediation costs, recorded on an undiscounted
basis, of $68 million will be incurred for the five-year period through 2006.
Exelon cannot reasonably estimate whether it will incur other significant
liabilities for additional investigation and remediation costs at these or
additional sites identified by Exelon, environmental agencies or others, or
whether such costs will be recoverable from third parties.
35
Leases
Minimum future operating lease payments, including lease payments for real
estate, computers, rail cars and office equipment, as of December 31, 2001 were:
- -----------------------------------------------------------------------------------------------------------
2002 $ 82
2003 84
2004 68
2005 67
2006 61
Remaining years 628
- -----------------------------------------------------------------------------------------------------------
Total minimum future lease payments $ 990
===========================================================================================================
Rental expense under operating leases totaled $75 million, $41 million, and $54
million in 2001, 2000 and 1999, respectively.
Litigation
Chicago Franchise. In March 1999, ComEd reached a settlement agreement with the
City of Chicago (Chicago)to end the arbitration proceeding between ComEd and
Chicago regarding the January 1, 1992 franchise agreement. As part of the
settlement agreement, ComEd and Chicago agreed to a revised combination of
ongoing work under the franchise agreement and new initiatives that will result
in defined transmission and distribution expenditures by ComEd to improve
electric services in Chicago. The settlement agreement provides that ComEd would
be subject to liquidated damages if the projects are not completed by various
dates, unless it was prevented from doing so by events beyond its reasonable
control. In addition, ComEd and Chicago established an Energy Reliability and
Capacity Account, into which ComEd deposited $25 million during each of the
years 1999 through 2001 and has conditionally agreed to deposit $25 million at
the end of 2002, to help ensure an adequate and reliable electric supply for
Chicago.
Cotter Corporation Litigation. During 1989 and 1991, actions were brought in
Federal and state courts in Colorado against ComEd and its subsidiary, Cotter
Corporation (Cotter), seeking unspecified damages and injunctive relief based on
allegations that Cotter permitted radioactive and other hazardous material to be
released from its mill into areas owned or occupied by the plaintiffs, resulting
in property damage and potential adverse health effects. In 1994, a Federal jury
returned nominal dollar verdicts against Cotter on eight plaintiffs' claims in
the 1989 cases, which verdicts were upheld on appeal. The remaining claims in
the 1989 actions were settled or dismissed. In 1998, a jury verdict was rendered
against Cotter in favor of 14 of the plaintiffs in the 1991 cases, totaling
approximately $6 million in compensatory and punitive damages, interest and
medical monitoring. On appeal, the Tenth Circuit Court of Appeals reversed the
jury verdict, and remanded the case for new trial. These plaintiffs' cases were
consolidated with the remaining 26 plaintiffs' cases, which had not been tried.
The consolidated trial was completed on June 28, 2001. The jury returned a
verdict against Cotter and awarded $16.3 million in various damages. On November
20, 2001, the District Court entered an amended final judgment which included an
award of both pre-judgment and post-judgment interests, costs, and medical
monitoring expenses which total $43.3 million. This matter is being appealed by
Cotter in the Tenth Circuit Court of Appeals. Cotter will vigorously contest the
award.
In November 2000, another trial involving a separate sub-group of 13
plaintiffs, seeking $19 million in damages plus interest was completed in
federal district court in Denver. The jury awarded nominal damages of $42,500 to
11 of 13 plaintiffs, but awarded no damages for any personal injury or health
claims, other than requiring Cotter to perform periodic medical monitoring at
minimal cost. The plaintiffs appealed the verdict to the Tenth Circuit Court of
Appeals.
36
On February 18, 2000, ComEd sold Cotter to an unaffiliated third party. As
part of the sale, ComEd agreed to indemnify Cotter for any liability incurred by
Cotter as a result of these actions, as well as any liability arising in
connection with the West Lake Landfill discussed in the next paragraph. In
connection with the corporate restructuring, the responsibility to indemnify
Cotter for any liability related to these matters was transferred to Generation.
Exelon's management believes adequate reserves have been established in
connection with these proceedings.
The United States Environmental Protection Agency (EPA) has advised Cotter
that it is potentially liable in connection with radiological contamination at a
site known as the West Lake Landfill in Missouri. Cotter is alleged to have
disposed of approximately 39,000 tons of soils mixed with 8,700 tons of leached
barium sulfate at the site. Cotter, along with three other companies identified
by the EPA as potentially responsible parties (PRPs), is reviewing a draft
feasibility study that recommends capping the site. The PRPs are also engaged in
discussions with the State of Missouri and the EPA. The estimated costs of
remediation for the site are $10 to $15 million. Once a final feasibility study
is complete and a remedy selected, it is expected that the PRPs will agree on an
allocation of responsibility for the costs. Until an agreement is reached,
Exelon cannot predict its share of the costs.
FERC Municipal Request for Refund. Three of ComEd's wholesale municipal
customers filed a complaint and request for refund with the FERC alleging that
ComEd failed to properly adjust its rates, as provided for under the terms of
the electric service contracts with the municipal customers and to track certain
refunds made to ComEd's retail customers in the years 1992 through 1994. In the
third quarter of 1998, FERC granted the complaint and directed that refunds be
made, with interest. ComEd filed a request for rehearing. On April 30, 2001,
FERC issued an order granting rehearing in which it determined that its 1998
order had been erroneous and that no refunds were due from ComEd to the
municipal customers. On June 29, 2001, FERC denied the customers' requests for
rehearing of the order granting rehearing. In August 2001, each of the three
wholesale municipal customers appealed the April 30, 2001 FERC order to the
Federal circuit court, which consolidated the appeals for the purposes of
briefing and decision. In November 2001, the court suspended briefing pending
court-initiated settlement discussions.
Godley Park District Litigation. On April 18, 2001, the Godley Park District
filed suit in Will County Circuit Court against ComEd and Exelon alleging that
oil spills at Braidwood Station have contaminated the Park District's water
supply. The complaint sought actual damages, punitive damages of $100 million
and statutory penalties. The court dismissed all counts seeking punitive damages
and statutory penalties, and the plaintiff has filed an amended complaint before
the court. Exelon is contesting the liability and damages sought by the
plaintiff.
Pennsylvania Real Estate Tax Appeals. Exelon is involved in tax appeals
regarding two of its nuclear facilities, Limerick Generating Station (Montgomery
County) and Peach Bottom Atomic Power Station (York County), and one of its
fossil facilities, Eddystone (Delaware County). Exelon is also involved in the
tax appeal for TMI (Dauphin County) through AmerGen. Exelon does not believe the
outcome of these matters will have a material adverse effect on Exelon's results
of operations or financial condition.
Retail Rate Law. In 1996, several developers of non-utility generating
facilities filed litigation against various Illinois officials claiming that the
enforcement against those facilities of an amendment to Illinois law removing
the entitlement of those facilities to state-subsidized payments for electricity
sold to ComEd after March 15, 1996 violated their rights under the Federal and
state constitutions. The developers also filed suit against ComEd for a
declaratory judgement that their rights under their contracts with ComEd were
not affected by the amendment. On August 4, 1999, the Illinois Appellate Court
held that the developers' claims against the state were premature, and the
Illinois Supreme Court denied leave to appeal that ruling. Developers of both
facilities have since filed amended complaints repeating their allegations that
ComEd breached the contracts in question and requesting damages for such breach,
in the amount of the difference between the state-subsidized rate and the amount
ComEd was willing to pay for the electricity. ComEd is contesting this matter.
37
Service Interruptions. In August 1999, three class action lawsuits were filed
against ComEd, and subsequently consolidated, in the Circuit Court of Cook
County, Illinois seeking damages for personal injuries, property damage and
economic losses related to a series of service interruptions that occurred in
the summer of 1999. The combined effect of these interruptions resulted in over
168,000 customers losing service for more than four hours. Conditional class
certification was approved by the court for the sole purpose of exploring
settlement talks. ComEd filed a motion to dismiss the complaints. On April 24,
2001, the court dismissed four of the five counts of the consolidated complaint
without prejudice and the sole remaining count was dismissed in part. On June 1,
2001, the plaintiffs filed a second amended consolidated complaint and ComEd has
filed an answer. A portion of any settlement or verdict may be covered by
insurance; discussions with the carrier are ongoing. Exelon's management
believes adequate reserves have been established in connection with these cases.
Enron. Exelon is an unsecured creditor in Enron Corp.'s (Enron) bankruptcy
proceeding. Exelon's claim for power and other products sold to Enron in
November and early December 2001 is $8.5 million. Enron may assert that Exelon
should not have closed out and terminated all of its forward contracts with
Enron. If Enron is successful in this argument, Exelon's exposure could be
greater than $8.5 million. Exelon may also be subject to exposure due to the
credit policies of ISO-operated spot markets that allocate defaults of market
participants to non-defaulting participants. Exelon has established reserves for
these matters.
As a result of Enron's bankruptcy, ComEd has potential monetary exposure
for customers served by Enron Energy Services (EES), either as a billing agent
or a third party supplier. EES is the billing agent for 366 of ComEd's customer
accounts. On January 7, 2002, EES was authorized by the bankruptcy court to
reject its contracts for 129 of these accounts. EES advised Exelon on January
10, 2002, that it will move to reject its contracts with the remaining 237
accounts during the week of January 14, 2002. Exelon is working to ensure that
customers know what amounts are owed to ComEd, and is obtaining updated billing
addresses for these accounts. As of January 8, 2002, approximately $3.5 million
in payments to Exelon were overdue and an additional $1.8 million in charges is
currently payable but not overdue. Therefore, Exelon's total amount outstanding
with respect to the EES accounts is approximately $5.3 million. Because that
amount is owed to Exelon by individual customers, it is not part of the bankrupt
Enron's estate.
General. Exelon is involved in various other litigation matters. The ultimate
outcome of such matters, as well as the matters discussed above, while
uncertain, are not expected to have a material adverse effect on its respective
financial condition or results of operations.
38
21. Segment Information
Exelon evaluates the performance of its business segments based on Earnings
Before Interest Expense and Income Taxes (EBIT).
Energy Delivery consists of the retail electricity distribution and
transmission businesses of ComEd in northern Illinois and PECO in southeastern
Pennsylvania and the natural gas distribution business of PECO located in the
Pennsylvania counties surrounding the City of Philadelphia. Generation consists
of electric generating facilities, energy marketing operations and Exelon's
interests in Sithe and AmerGen. Enterprises consists of competitive retail
energy sales, energy and infrastructure services, communications and other
investments weighted towards the communications, energy services and retail
services industries. An analysis and reconciliation of Exelon's business segment
information to the respective information in the consolidated financial
statements are as follows:
Energy Intersegment
Delivery Generation Enterprises Corporate Eliminations Consolidated
- ---------------------------------------------------------------------------------------------------------------------
Total Revenues:
2001 $ 10,171 $ 7,048 $ 2,292 $ 341 $ (4,712) $ 15,140
2000 4,511 3,316 1,395 -- (1,723) 7,499
1999 3,265 2,411 644 -- (842) 5,478
Intersegment Revenues:
2001 $ 94 $ 4,102 $ 179 $ 337 $ (4,712) $ --
2000 24 1,227 472 -- (1,723) --
1999 -- 842 -- -- (842) --
EBIT (a):
2001 $ 2,623 $ 962 $ (107) $ (22) $ -- $ 3,456
2000 (b) 1,503 440 (140) (328) -- 1,475
1999 1,372 379 (212) (194) -- 1,345
Depreciation and
Amortization:
2001 $ 1,081 $ 282 $ 69 $ 17 $ -- $ 1,449
2000 297 126 35 -- -- 458
1999 108 125 4 -- -- 237
Capital Expenditures:
2001 $ 1,133 $ 803 $ 70 $ 35 $ -- $ 2,041
2000 367 288 70 27 -- 752
1999 205 245 1 40 -- 491
Total Assets:
2001 $ 26,448 $ 7,588 $ 1,699 $ (914) $ -- $ 34,821
2000 27,613 5,734 2,277 (838) -- 34,786
1999 10,306 1,734 640 407 -- 13,087
- ---------------------------------------------------------------------------------------------------------------------
(a) EBIT consists of operating income, equity in earnings (losses) of unconsolidated affiliates, and other income and
expenses recorded in other, net with the exception of investment income. Investment income for 2001, 2000 and
1999 was $47 million, $64 million and $52 million, respectively.
(b) Includes non-recurring items of $276 million for Merger-related expenses in 2000.
Equity in losses of communications joint ventures and other investments of $19
million, $45 million and $38 million for 2001, 2000 and 1999, respectively, are
included in the Enterprises business unit's EBIT and equity losses of affordable
housing investments of $9 million for 2001 are included in Corporate's EBIT.
Equity in earnings of AmerGen and Sithe of $90 million and $4 million for 2001
and 2000, respectively, are included in the Generation business unit's EBIT.
39
22. Related Party Transactions
In August 2001, Exelon loaned Sithe, an equity method investment of Generation,
$150 million. The note, which bore interest at the eurodollar rate, plus 2.25%,
was repaid in December 2001 with the proceeds of bank borrowings. In connection
with the bank 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. Exelon recorded $2 million of interest income on the note in
2001.
Generation has entered into 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 TMI 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. For the years
ended December 31, 2001, 2000 and 1999 the amount of purchased power recorded in
Fuel and Purchased Power in the Consolidated Statements of Income is $57
million, $52 million and $0 million respectively. As of December 31, 2001 and
2000 Generation had a payable of $3 million resulting from this PPA .
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 Exelon's fully allocated costs for performing the
services or the market price. For the years ended December 31, 2001, 2000 and
1999 the amount charged to AmerGen for these services was $80 million, $32
million and $1 million respectively. As of December 31, 2001 and 2000,
Generation had a receivable of $47 million and $20 million respectively,
resulting from these services.
23. Change in Accounting Estimate
Effective April 1, 2001, Exelon changed its accounting estimates related to the
depreciation and decommissioning of certain generating stations. The estimated
service lives were extended by 20 years for three nuclear stations, by periods
of up to 20 years for certain fossil stations and by 50 years for a pumped
storage station. Effective July 1, 2001, the estimated service lives were
extended by 20 years for the remainder of Exelon's operating nuclear stations.
These changes were based on engineering and economic feasibility studies
performed by Exelon considering, among other things, future capital and
maintenance expenditures at these plants. As a result of the change, net income
for 2001 increased $90 million ($54 million, net of income taxes). At the end of
the year, annualized savings resulting from the change would be $132 million
($79 million, net of income taxes).
40
24. Quarterly Data (Unaudited)
The data shown below include all adjustments which Exelon considers necessary
for a fair presentation of such amounts:
Income (Loss) Before
Extraordinary Items
and Cumulative
Effect of a Change in
Operating Revenues Operating Income Accounting Principle Net Income (Loss)
--------------------------------------------------------------------------------------
2001 2000 2001 2000 (a) 2001 2000 2001 2000
- --------------------------------------------------------------------------------------------------------------
Quarter ended:
March 31 $3,823 $1,353 $889 $352 $387 $167 $399 $191
June 30 3,651 1,385 792 309 315 119 315 116
September 30
As initially reported 4,285 1,629 912 446 403 233 403 232
As amended (b) 4,285 1,629 912 446 376 233 376 232
December 31(c) 3,381 3,132 769 420 338 47 338 47
Earnings per Share Before
Extraordinary Items
Average Shares and Cumulative Effect
Outstanding of a Change in Earnings per Share
(in millions) Accounting Principle Net Income
------------------------------------------------------------------------------------
2001 2000 2001 2000 2001 2000
- ------------------------------------------------------------------------------------------------------------
Quarter ended:
March 31 320 181 $1.21 $0.92 $1.25 $1.05
June 30 321 174 0.98 0.69 0.98 0.67
September 30
As initially reported 321 170 1.26 1.37 1.26 1.37
As amended (b) 321 170 1.17 1.37 1.17 1.37
December 31 (c) 320 283 1.06 0.17 1.06 0.17
(a) Reflects a $276 million charge ($177 million, net of income taxes) for merger-related costs consisting
of $152 million of direct incremental costs and $124 million for employee costs. Incremental merger
expenses of $11 million, $9 million, $13 million and $13 million for each of the four quarters in 2000,
respectively, were reflected in Operating and Maintenance Expense.
(b) Reflects the effects of the quarter ended September 30, 2001 restatement. In January 2002, Exelon
discovered that its September 30, 2001 financial statements required a restatement for additional net
realized and unrealized losses on investments of Generation's nuclear decommissioning trust funds that
were incurred prior to September 30, 2001 but not recorded.
(c) Reflects the effects of the Unicom merger (October 20, 2000).
41
25. Subsequent Events
On February 1, 2002, ComEd called $200 million of its First Mortgage Bonds at
the redemption price of 103.84% of the principal amount, plus accrued interest
to the March 21, 2002 redemption date. The bonds, which carried an interest rate
of 8.625% and had a maturity date of February 1, 2022, are expected to be
refinanced with long-term debt.
On March 1, 2002, Enterprises announced an agreement to sell its 49%
interest in AT&T Wireless PCS of Philadelphia, LLC for $285 million in cash. The
transaction is expected to close in the first half of 2002. Enterprises expects
to record a pre-tax gain of approximately $200 million on the sale ($120 million
after income taxes) resulting in an increase in diluted earnings per share in
2002 of $0.37. Proceeds from the transaction will be used for Exelon's general
corporate purposes.
42