Exhibit 99-4
Exelon Corporation and Subsidiary Companies Financial Statements and
Supplementary Data
Report of Independent Accountants
To the Shareholders and
Board of Directors of
Exelon Corporation:
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of income, cash flows and changes in shareholders'
equity and comprehensive income present fairly, in all material respects, the
financial position of Exelon Corporation and Subsidiary Companies (Exelon) at
December 31, 2002 and December 31, 2001, and the results of their operations and
their cash flows for each of the three years in the period ended December 31,
2002 in conformity with accounting principles generally accepted in the United
States of America. These financial statements are the responsibility of Exelon's
management; our responsibility is to express an opinion on these financial
statements based on our audits. We conducted our audits of these statements in
accordance with auditing standards generally accepted in the United States of
America, which require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
As discussed in Note 2 to the consolidated financial statements, Exelon acquired
Unicom Corporation on October 20, 2000 in a business combination accounted for
under the purchase method of accounting. The results of Unicom Corporation are
included in the consolidated financial statements since the acquisition date.
As discussed in Note 4 to the consolidated financial statements, Exelon changed
its method of accounting for nuclear outage costs in 2000.
As discussed in Note 1 to the consolidated financial statements, Exelon changed
its method of accounting for derivative instruments and hedging activities
effective January 1, 2001.
As discussed in Note 4 to the consolidated financial statements, Exelon changed
its method of accounting for goodwill effective January 1, 2002.
Chicago, Illinois
January 29, 2003, except for Note 23 for which the date is February 20, 2003.
74
Exelon Corporation and Subsidiary Companies
Consolidated Statements of Income
For the Years Ended December 31,
------------------------------------------------
in millions, except per share data 2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
Operating Revenues $ 14,955 $ 14,918 $ 7,499
Operating Expenses
Purchased Power 3,262 3,156 1,620
Purchased Power from Unconsolidated Affiliate 273 57 52
Fuel 1,727 1,877 934
Operating and Maintenance 4,345 4,394 2,310
Merger-Related Costs -- -- 276
Depreciation and Amortization 1,340 1,449 458
Taxes Other Than Income 709 623 322
- -------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 11,656 11,556 5,972
- -------------------------------------------------------------------------------------------------------------------
Operating Income 3,299 3,362 1,527
- -------------------------------------------------------------------------------------------------------------------
Other Income and Deductions
Interest Expense, net of amounts capitalized (966) (1,107) (614)
Distributions on Preferred Securities of Subsidiaries (45) (49) (24)
Equity in Earnings (Losses) of Unconsolidated Affiliates, net 80 62 (41)
Other, Net 300 79 53
- -------------------------------------------------------------------------------------------------------------------
Total Other Income and Deductions (631) (1,015) (626)
- -------------------------------------------------------------------------------------------------------------------
Income Before Income Taxes and the
Cumulative Effect of Changes in Accounting Principles 2,668 2,347 901
Income Taxes 998 931 339
- -------------------------------------------------------------------------------------------------------------------
Income Before Cumulative Effect
of Changes in Accounting Principles 1,670 1,416 562
Cumulative Effect of Changes in Accounting Principles (net of income taxes of
$(90), $8 and $16 in 2002, 2001 and 2000,
respectively) (230) 12 24
- -------------------------------------------------------------------------------------------------------------------
Net Income $ 1,440 $ 1,428 $ 586
- -------------------------------------------------------------------------------------------------------------------
Average Shares of Common Stock Outstanding
Basic 322 320 202
Diluted 325 322 204
- -------------------------------------------------------------------------------------------------------------------
Earnings Per Common Share - Basic:
Income Before Cumulative
Effect of Changes in Accounting Principles $ 5.18 $ 4.42 $ 2.79
Cumulative Effect of Changes in Accounting Principles (0.71) 0.04 0.12
- -------------------------------------------------------------------------------------------------------------------
Net Income $ 4.47 $ 4.46 $ 2.91
- -------------------------------------------------------------------------------------------------------------------
Earnings Per Common Share - Diluted:
Income Before Cumulative
Effect of Changes in Accounting Principles $ 5.15 $ 4.39 $ 2.75
Cumulative Effect of Changes in Accounting Principles (0.71) 0.04 0.12
- -------------------------------------------------------------------------------------------------------------------
Net Income $ 4.44 $ 4.43 $ 2.87
- -------------------------------------------------------------------------------------------------------------------
Dividends Per Common Share $ 1.76 $ 1.82 $ 0.91
- -------------------------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements
75
Exelon Corporation and Subsidiary Companies
Consolidated Statements of Cash Flows For the Years Ended December 31,
-------------------------------------------
in millions 2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
Cash Flows from Operating Activities
Net Income $ 1,440 $ 1,428 $ 586
Adjustments to reconcile Net Income to Net
Cash Flows provided by Operating Activities:
Depreciation and Amortization, including nuclear fuel 1,701 1,834 607
Cumulative Effects of Changes in Accounting
Principles (net of income taxes) 230 (12) (24)
Provision for Uncollectible Accounts 129 145 89
Net Gain on Sale of Investments (199) -- --
Deferred Income Taxes 278 (68) 193
Merger-Related Costs -- -- 276
Employee Severance Costs -- 46 --
Deferred Energy Costs 25 29 (79)
Equity in (Earnings) Losses of Unconsolidated Affiliates, net (80) (62) 41
Write-down of Investments 41 36 --
Net Realized Losses on Nuclear
Decommissioning Trust Funds 32 127 --
Other Operating Activities 12 (16) (165)
Changes in Working Capital:
Accounts Receivable (448) 318 (445)
Repurchase of Accounts Receivable -- -- (50)
Inventories (37) (33) 49
Accounts Payable, Accrued Expenses & Other Current Liabilities 470 (190) (2)
Other Current Assets 20 33 20
- -------------------------------------------------------------------------------------------------------------------
Net Cash Flows provided by Operating Activities 3,614 3,615 1,096
- -------------------------------------------------------------------------------------------------------------------
Cash Flows from Investing Activities
Capital Expenditures (2,150) (2,088) (752)
Acquisitions of Generating Plants (445) -- --
Unicom Merger Consideration -- -- (507)
Proceeds from Direct Financing Leases -- -- 1,228
Investment in Sithe Energies, Inc. -- -- (704)
Enterprises Acquisitions, net of cash acquired -- (30) (245)
Proceeds from the Sale of Investments 287 -- --
Proceeds from Nuclear Decommissioning Trust Funds 1,612 1,624 265
Investment in Nuclear Decommissioning Trust Funds (1,824) (1,863) (380)
Note Receivable from Unconsolidated Affiliate (35) -- --
Other Investing Activities 17 (35) (108)
- -------------------------------------------------------------------------------------------------------------------
Net Cash Flows used in Investing Activities (2,538) (2,392) (1,203)
- -------------------------------------------------------------------------------------------------------------------
Cash Flows from Financing Activities
Issuance of Long-Term Debt 1,223 2,270 1,021
Common Stock Repurchases -- -- (501)
Retirement of Long-Term Debt (2,134) (1,860) (665)
Change in Short-Term Debt 321 (1,013) 10
Redemption of Preferred Securities of Subsidiaries (18) (17) (19)
Dividends Paid on Common Stock (563) (583) (157)
Change in Restricted Cash (24) (58) (140)
Proceeds from Employee Stock Plans 78 39 67
Contribution from Minority Interest of Consolidated Subsidiary 43 -- --
Other Financing Activities (18) (42) (11)
- -------------------------------------------------------------------------------------------------------------------
Net Cash Flows used in Financing Activities (1,092) (1,264) (395)
- -------------------------------------------------------------------------------------------------------------------
Decrease in Cash and Cash Equivalents (16) (41) (502)
Cash and Cash Equivalents at beginning of period 485 526 54
Cash Acquired in Unicom Merger -- -- 974
- -------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at end of period $ 469 $ 485 $ 526
- -------------------------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements
76
Exelon Corporation and Subsidiary Companies
Consolidated Balance Sheets
December 31,
-------------------------------------
in millions 2002 2001
- -------------------------------------------------------------------------------------------------------------------
Assets
Current Assets
Cash and Cash Equivalents $ 469 $ 485
Restricted Cash 396 372
Accounts Receivable, net
Customer 2,095 1,687
Other 265 381
Receivable from Unconsolidated Affiliate 32 44
Inventories, at average cost
Fossil Fuel 218 222
Materials and Supplies 306 249
Deferred Income Taxes 6 23
Other 331 272
- -------------------------------------------------------------------------------------------------------------------
Total Current Assets 4,118 3,735
- -------------------------------------------------------------------------------------------------------------------
Property, Plant and Equipment, net 17,134 13,791
Deferred Debits and Other Assets
Regulatory Assets 5,938 6,423
Nuclear Decommissioning Trust Funds 3,053 3,165
Investments 1,393 1,623
Goodwill, net 4,992 5,335
Other 850 672
- -------------------------------------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 16,226 17,218
- -------------------------------------------------------------------------------------------------------------------
Total Assets $ 37,478 $ 34,744
- -------------------------------------------------------------------------------------------------------------------
Liabilities and Shareholders' Equity
Current Liabilities
Notes Payable $ 681 $ 360
Note Payable to Unconsolidated Affiliate 534 --
Long-Term Debt Due Within One Year 1,402 1,406
Accounts Payable 1,563 964
Accrued Expenses 1,311 1,135
Other 483 505
- -------------------------------------------------------------------------------------------------------------------
Total Current Liabilities 5,974 4,370
- -------------------------------------------------------------------------------------------------------------------
Long-Term Debt 13,127 12,879
Deferred Credits and Other Liabilities
Deferred Income Taxes 3,702 4,362
Unamortized Investment Tax Credits 301 316
Nuclear Decommissioning Liability for Retired Plants 1,395 1,353
Pension Obligation 1,959 334
Non-Pension Postretirement Benefits Obligation 877 847
Spent Nuclear Fuel Obligation 858 843
Other 871 694
- -------------------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 9,963 8,749
- -------------------------------------------------------------------------------------------------------------------
Commitments and Contingencies
Minority Interest of Consolidated Subsidiaries 77 31
Preferred Securities of Subsidiaries 595 613
Shareholders' Equity
Common Stock 7,059 6,961
Deferred Compensation (1) (2)
Retained Earnings 2,042 1,169
Accumulated Other Comprehensive Income (Loss) (1,358) (26)
- -------------------------------------------------------------------------------------------------------------------
Total Shareholders' Equity 7,742 8,102
- -------------------------------------------------------------------------------------------------------------------
Total Liabilities and Shareholders' Equity $ 37,478 $ 34,744
- -------------------------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements
77
Exelon Corporation and Subsidiary Companies
Consolidated Statements of Changes in Shareholders' Equity
Accumulated
Other Total
Dollars in millions, Common Deferred Retained Treasury Comprehensive Shareholders'
shares in thousands Shares Stock Compensation Earnings Shares Income (Loss) Equity
- --------------------------------------------------------------------------------------------------------------------
Balance, December 31, 1999 225,354 $ 3,577 $ (3) $ (100) $ (1,705) $ 4 $ 1,773
Net Income -- -- 586 -- -- 586
Long-Term Incentive Plan Activity 563 75 (9) -- 7 -- 73
Shares Issued to Acquire Unicom 147,963 5,310 -- -- -- -- 5,310
Merger Consideration-Stock Options 111 -- -- -- -- 111
Amortization of Deferred Compensation -- 5 -- -- -- 5
Common Stock Dividends Declared -- -- (157) -- -- (157)
Common Stock Repurchases -- -- (5) (496) -- (501)
Stock Option Exercises -- -- -- 19 -- 19
Cancellation of Treasury Shares (54,875) (2,175) -- -- 2,175 -- --
Other Comprehensive Income (Loss),
net of income taxes of $(1) -- -- -- -- (4) (4)
- --------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2000 319,005 $ 6,898 $ (7) $ 324 $ -- $ -- $ 7,215
Net Income -- -- 1,428 -- -- 1,428
Long-Term Incentive Plan Activity 1,864 55 -- -- -- -- 55
Employee Stock Purchase Plan Issuances 138 6 -- -- -- -- 6
Merger Consideration-Stock Options 2 -- -- -- -- 2
Amortization of Deferred Compensation -- 5 -- -- -- 5
Common Stock Dividends Declared -- -- (583) -- -- (583)
Reclassified Net Unrealized Losses on
Marketable Securities, net of income
taxes of $(22) -- -- -- -- (23) (23)
Other Comprehensive Income (Loss),
net of income taxes of $(7) -- -- -- -- (3) (3)
- --------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2001 321,007 $ 6,961 $ (2) $ 1,169 $ -- $ (26) $ 8,102
Net Income -- -- 1,440 -- -- 1,440
Long-Term Incentive Plan Activity 2,049 87 -- -- -- -- 87
Employee Stock Purchase Plan Issuances 257 11 -- -- -- -- 11
Amortization of Deferred Compensation -- 1 -- -- -- 1
Common Stock Dividends Declared -- -- (567) -- -- (567)
Other Comprehensive Income (Loss),
net of income taxes of $(850) -- -- -- -- (1,332) (1,332)
- --------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2002 323,313 $ 7,059 $ (1) $ 2,042 $ -- $ (1,358) $ 7,742
- --------------------------------------------------------------------------------------------------------------------
Exelon Corporation and Subsidiary Companies
Consolidated Statements of Comprehensive Income
For the Years Ended December 31,
--------------------------------------
in millions 2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
Net Income $ 1,440 $ 1,428 $ 586
Other Comprehensive Income (Loss)
Minimum Pension Liability, net of income taxes of $(597) (1,007) -- --
SFAS No. 133 Transition Adjustment, net
of income taxes of $32 -- 44 --
Cash Flow Hedge Fair Value Adjustment, net of income taxes of $(132)
and $17, respectively (199) 22 --
Foreign Currency Translation Adjustment,
net of income taxes of $0 -- (1) --
Unrealized Gain (Loss) on Marketable
Securities, net of income taxes of $(116), $(40) and $(1), respectively (119) (41) (4)
Interest in Other Comprehensive Income (Loss) of Unconsolidated Affiliates,
net of income taxes of $(5) and $(16), respectively (7) (27) --
- -------------------------------------------------------------------------------------------------------------------
Total Other Comprehensive Income (Loss) (1,332) (3) (4)
- -------------------------------------------------------------------------------------------------------------------
Total Comprehensive Income $ 108 $ 1,425 $ 582
- -------------------------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements
78
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Exelon Corporation and Subsidiary Companies
(Dollars in millions, except per share data unless otherwise noted)
1. Significant Accounting Policies
Description of Business
Exelon Corporation (Exelon) is a utility services holding company formed as
a result of the merger of Unicom Corporation (Unicom), the former parent company
of Commonwealth Edison Company (ComEd), and PECO Energy Company (PECO) (Merger)
(see Note 2 - Merger). Exelon is engaged, through its subsidiaries, in the
energy delivery, wholesale generation and the enterprises businesses discussed
below (see Note 20 - Segment Information). The Energy Delivery segment's
businesses include the sale of electricity and distribution and transmission
services by ComEd in northern Illinois and PECO in southeastern Pennsylvania and
the sale of natural gas and distribution services by PECO in the Pennsylvania
counties surrounding the City of Philadelphia. The wholesale generation business
consists of the electric generating facilities and energy marketing operations
of Exelon Generation Company, LLC (Generation) and Generation's interests in
Sithe Energies, Inc. (Sithe) and AmerGen Energy Company, LLC (AmerGen). Exelon
Enterprises Company, LLC (Enterprises) includes energy and infrastructure
services, competitive retail energy sales, communications joint ventures and
other investments weighted towards the communications, energy services and
retail services industries.
Basis of Presentation
The consolidated financial statements of Exelon include the accounts of its
majority-owned subsidiaries after the elimination of intercompany transactions.
Investments and joint ventures in which a 20% to 50% interest is owned and a
significant influence is exerted are accounted for under the equity method of
accounting. The proportionate interests in jointly owned electric utility plants
are consolidated. Investments in which less than a 20% interest is owned are
primarily accounted for under the cost method of accounting. Exelon owns 100% of
all significant consolidated subsidiaries, either directly or indirectly, except
for ComEd of which Exelon owns more than 99%, InfraSource Inc. (InfraSource) of
which Exelon owns 95% and Southeast Chicago Energy Project, LLC of which Exelon
owns 70% through Generation. Exelon has reflected the third-party interests in
the above majority owned investments as minority interests in its Consolidated
Statements of Cash Flows, Consolidated Balance Sheets and in Other, Net on the
Consolidated Statements of Income. Accounting policies for regulated operations
are in accordance with those prescribed by the regulatory authorities having
jurisdiction, principally the Illinois Commerce Commission (ICC), the
Pennsylvania Public Utility Commission (PUC), the Federal Energy Regulatory
Commission (FERC) and the Securities and Exchange Commission (SEC) under the
Public Utility Holding Company Act of 1935 (PUHCA). On October 20, 2000, Exelon
became the parent of PECO through a share exchange and Unicom was merged into
Exelon. As a result of these transactions, Unicom ceased to exist and Exelon
became the parent of ComEd and PECO (see Note 2 - Merger). For accounting
purposes, PECO was deemed the acquiror in the Merger. Accordingly, the financial
statements of Exelon for the periods presented prior to October 20, 2000
represent the historical financial statements of PECO and for the periods from
October 20, 2000 include the operations acquired from Unicom.
Accounting for the Effects of Regulation
Exelon accounts for all of its regulated electric and gas operations in
accordance with the Financial Accounting Standards Board (FASB) Statement of
Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of
Certain Types of Regulation," (SFAS No. 71) requiring Exelon to record in its
financial statements the effects of rate regulation. Use of SFAS No. 71 is
applicable to the utility operations of Exelon that meet the following criteria:
(1) third-party regulation of rates; (2) cost-based rates; and (3) a reasonable
assumption that all costs will be recoverable from customers through
79
rates. Exelon believes that it is probable that currently recorded regulatory
assets will be recovered. If a separable portion of Exelon's business no longer
meets the provisions of SFAS No. 71, Exelon is required to eliminate the
financial statement effects of regulation for that portion.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles (GAAP) requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates. Areas in
which significant estimates have been made include, but are not limited to, the
accounting for derivatives, nuclear decommissioning liabilities, asset
impairment analyses, environmental costs and pension costs.
Revenues
Operating revenues are generally recorded as service is rendered or energy
is delivered to customers. At the end of each month, Exelon accrues an estimate
for the unbilled amount of energy delivered or services provided to its electric
and gas customers (see Note 8 - Accounts Receivable). Exelon recognizes contract
revenues and profits on certain long-term fixed-price contracts from its
services businesses under the percentage-of-completion method of accounting
based on costs incurred as a percentage of estimated total costs of individual
contracts. Premiums received and paid on option contracts and swap arrangements
are amortized to revenue and expense over the life of the contracts. Certain of
these contracts are considered derivative instruments and are recorded at fair
value with subsequent changes in fair value recognized as revenues and expenses
unless hedge accounting is applied. Commodity derivatives used for trading
purposes are accounted for using the mark-to-market method. Under this
methodology, these derivatives are adjusted to fair value, and the unrealized
gains and losses are recognized in current period income.
Long-Term Contract Accounting
Enterprises recognizes contract revenue and profits on certain long-term
fixed-price contracts by the percentage-of-completion method of accounting. In
determining the amount of revenue to recognize, Exelon is required to estimate
the total costs and profits expected to be recorded under the contract over its
contract term, and the recoverability of costs related to change orders. Changes
in these estimates could result in the recognition of differences in earnings.
At December 31, 2002 and 2001, Current Assets includes $70 million and $77
million, respectively, of Costs and Earnings in Excess of Billings on
uncompleted contracts and Current Liabilities includes $44 million and $56
million, respectively, of Billings and Earnings in Excess of Costs on
uncompleted contracts.
At December 31, 2002 and 2001, Accounts Receivable includes $49 million and
$46 million, respectively, of contract retention. This amount represents revenue
recognized on costs incurred that is not yet billable until final completion of
the project and acceptance by the customer. In applying the
percentage-of-completion accounting method, the collection of these estimated
revenues is deemed probable.
Purchased Gas Adjustment Clause
PECO's natural gas rates are subject to a fuel adjustment clause designed
to recover or refund the difference between the actual cost of purchased gas and
the amount included in base rates. Differences between the amounts billed to
customers and the actual costs recoverable are deferred and recovered or
refunded in future periods by means of prospective quarterly adjustments to
rates.
Nuclear Fuel
80
The cost of nuclear fuel is capitalized and charged to fuel expense using the
unit of production method. Estimated costs of nuclear fuel storage and disposal
at operating plants are charged to fuel expense as the related fuel is consumed.
Stock-Based Compensation
Exelon uses the disclosure-only provisions of SFAS No. 123, "Accounting for
Stock-Based Compensation" (SFAS No. 123). See Note 17 - Common Stock for further
discussion of these plans. The table below shows the effect on net income and
earnings per share had Exelon elected to account for its stock-based
compensation plans using the fair value method under SFAS No. 123 for the years
ended December 31, 2002, 2001 and 2000:
2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
Net income - as reported $ 1,440 $ 1,428 $ 586
Deduct: Total stock-based compensation expense
determined under fair value based method for all
awards, net of income taxes 33 26 25
- -------------------------------------------------------------------------------------------------------------------
Pro forma net income $ 1,407 $ 1,402 $ 561
- -------------------------------------------------------------------------------------------------------------------
Earnings per share:
Basic - as reported $ 4.47 $ 4.46 $ 2.91
Basic - pro forma $ 4.36 $ 4.38 $ 2.77
Diluted - as reported $ 4.44 $ 4.43 $ 2.87
Diluted - pro forma $ 4.33 $ 4.35 $ 2.75
- -------------------------------------------------------------------------------------------------------------------
Income Taxes
Deferred Federal and state income taxes are provided on all significant
temporary differences between book basis and tax basis of assets and
liabilities. Investment tax credits previously utilized for income tax purposes
have been deferred on the Consolidated Balance Sheets and are recognized in book
income over the life of the related property. Exelon and its subsidiaries file a
consolidated Federal income tax return. Income taxes are allocated to each of
Exelon's subsidiaries within the consolidated group based on the separate return
method. Exelon estimates its income tax valuation allowance by assessing which
deferred tax assets are more likely than not to be recovered in the future (see
Note 14 - Income Taxes).
Gains and Losses on Reacquired Debt
Recoverable gains and losses on reacquired debt related to regulated
operations are deferred and amortized to interest expense over the period
consistent with rate recovery for ratemaking purposes. Gains and losses on other
debt are recognized in Exelon's Consolidated Statements of Income as incurred
(see Note 6 - Supplemental Financial Information).
Comprehensive Income
Comprehensive income includes all changes in equity during a period except
those resulting from investments by and distributions to shareholders.
Comprehensive income is reflected in the Consolidated Statements of Changes in
Shareholders' Equity and the Consolidated Statements of Comprehensive Income.
Cash and Cash Equivalents
Exelon considers all temporary cash investments purchased with an original
maturity of three months or less to be cash equivalents.
81
Restricted Cash
Restricted cash reflects escrowed cash to be applied to the principal and
interest payment on the transition bonds and transitional trust notes.
Marketable Securities
Marketable securities are classified as available-for-sale securities and
are reported at fair value, with the unrealized gains and losses, net of tax,
reported in other comprehensive income. Under regulatory accounting practices,
unrealized gains and losses on marketable securities held in the nuclear
decommissioning trust funds are reported in accumulated depreciation for
operating units and as a reduction of regulatory assets for retired units. If
regulatory accounting practices are not applicable, unrealized gains and losses
on marketable securities held in the nuclear decommissioning trust funds are
reported in accumulated other comprehensive income. At December 31, 2002 and
2001, Exelon had no held-to-maturity or trading securities.
Property, Plant and Equipment
Property, plant and equipment is recorded at cost. Exelon evaluates the
carrying value of property, plant and equipment and other long-term assets based
upon current and anticipated undiscounted cash flows, and recognizes an
impairment when it is probable that such estimated cash flows will be less than
the carrying value of the asset. Measurement of the amount of impairment, if
any, is based upon the difference between the carrying value and fair value. The
cost of maintenance, repairs and minor replacements of property is charged to
maintenance expense as incurred.
Upon retirement, the cost of regulated property plus removal costs less
salvage value is charged to accumulated depreciation by the regulated
subsidiaries in accordance with regulatory practices. For unregulated property,
the cost and accumulated depreciation of property, plant and equipment retired
or otherwise disposed of are removed from the related accounts and included in
the determination of the gain or loss on disposition.
Depreciation, Amortization and Decommissioning
Depreciation is provided over the estimated service lives of property,
plant and equipment on a straight-line basis. Annual depreciation provisions for
financial reporting purposes, expressed as a percentage of average service life
for each asset category, are presented in the table below. See Note 4 - Adoption
of New Accounting Pronouncements and Accounting Changes for information on
service life extensions for certain nuclear generating stations and Energy
Delivery's change in depreciation rates.
Asset Category 2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
Electric-Transmission and Distribution 3.11% 3.97% 4.16%
Electric-Generation 3.65% 3.11% 5.02%
Gas 2.13% 2.34% 2.39%
Common - Gas and Electric 6.40% 6.26% 5.09%
Other Property and Equipment 7.88% 9.53% 8.11%
- -------------------------------------------------------------------------------------------------------------------
Amortization of regulatory assets is provided over the recovery period
specified in the related regulatory agreement. Goodwill associated with the
Merger was amortized on a straight-line basis over 40 years in 2001 and 2000.
Goodwill associated with other acquisitions was amortized over periods from 10
to 20 years in 2001 and 2000. Accumulated amortization of goodwill was $185
million and $35 million at December 31, 2001 and 2000, respectively. Effective
January 1, 2002, under SFAS No. 142 "Goodwill and Other Intangible Assets" (SFAS
No. 142), goodwill recorded by Exelon is no longer subject to amortization but
is subject to an annual impairment test (see Note 4 - Adoption of New Accounting
Pronouncements and Accounting Changes).
Exelon currently recovers costs for decommissioning its nuclear generating
stations, excluding AmerGen, through regulated rates. The amounts recovered from
customers are deposited in trust
82
accounts and invested for funding of future costs for operating and retired
nuclear generating stations. The majority of the eventual work to decommission
Exelon's nuclear generating stations will occur after 2029.
Exelon accounts for the current period's cost of decommissioning related to
generating plants previously owned by PECO following common regulatory
accounting practices by recording a charge to depreciation expense and a
corresponding liability in accumulated depreciation concurrently with
decommissioning collections. Financial activity of the decommissioning trust
(e.g., investment income and realized and unrealized gains and losses on trust
investments) is reflected in Nuclear Decommissioning Trust Funds in Exelon's
Consolidated Balance Sheets with a corresponding offset recorded to the
liability in accumulated depreciation. Under common regulatory practices, the
deposit of funds into the decommissioning trust accounts plus the financial
activity reflected in Nuclear Decommissioning Trust Funds in Exelon's
Consolidated Balance Sheets will, over time, establish a corresponding liability
in accumulated depreciation reflecting the cost to decommission the nuclear
generating stations previously owned by PECO. Exelon will adopt SFAS No. 143,
"Asset Retirement Obligations" (SFAS No. 143) as of January 1, 2003. See "New
Accounting Pronouncements" within this note for a discussion as to how this
standard will change the accounting for nuclear decommissioning costs.
Regulatory accounting practices for the nuclear generating stations
previously owned by ComEd were discontinued as a result of an ICC order capping
ComEd's ultimate recovery of decommissioning costs. See Note 11 - Nuclear
Decommissioning and Spent Fuel Storage regarding regulatory accounting practices
for nuclear generating stations transferred by ComEd to Generation. The
difference between the current decommissioning cost estimate and the
decommissioning liability recorded in accumulated depreciation for the former
ComEd operating stations is being amortized to depreciation expense on a
straight-line basis over the remaining lives of the stations. The current
decommissioning cost estimate (adjusted annually to reflect inflation) for the
former ComEd retired units recorded in deferred credits and other liabilities is
accreted to depreciation expense. Financial activity of the decommissioning
trust related to Exelon's nuclear generating stations no longer accounted for
under common regulatory practices (e.g., investment income and realized and
unrealized gains and losses on trust investments) is reflected in Nuclear
Decommissioning Trust Funds in Exelon's Consolidated Balance Sheets with a
corresponding gain or expense recorded in Exelon's Consolidated Income Statement
or in other comprehensive income. The offset to the financial activity in the
decommissioning trust funds is summarized as follows:
o Interest income is recorded in other income and deductions,
o Realized gains and losses are recorded in other income and deductions,
o Unrealized gains and losses are recorded in other comprehensive
income, and
o Trust fund operating expenses are recorded in operation and
maintenance expense
Exelon believes that the amounts being recovered from customers through
electric rates along with the earnings on the trust funds will be sufficient to
fully fund its decommissioning obligations.
Capitalized Interest
Exelon uses SFAS No. 34, "Capitalizing Interest Costs," to calculate the
costs during construction of debt funds used to finance its non-regulated
construction projects. Exelon recorded capitalized interest of $20 million, $17
million and $2 million in 2002, 2001 and 2000, respectively.
Allowance for Funds Used During Construction (AFUDC) is the cost, during
the period of construction, of debt and equity funds used to finance
construction projects for regulated operations. AFUDC is recorded as a charge to
Construction Work in Progress and as a non-cash credit to AFUDC that is included
in Other Income and Deductions. The rates used for capitalizing AFUDC are
computed under a method prescribed by regulatory authorities (see Note 6 -
Supplemental Financial Information).
83
Capitalized Software Costs
Costs incurred during the application development stage of software
projects for software that is developed or obtained for internal use are
capitalized. At December 31, 2002, 2001 and 2000, capitalized software costs
totaled $335 million, $240 million and $285 million, respectively, net of $156
million, $85 million and $53 million of accumulated amortization, respectively.
Such capitalized amounts are amortized ratably over the expected lives of the
projects when they become operational, not to exceed ten years. Certain
capitalized software is being amortized over fifteen years pursuant to
regulatory approval.
Derivative Financial Instruments
Exelon accounts for derivative financial instruments under SFAS No. 133,
"Accounting for Derivatives and Hedging Activities" (SFAS No. 133). Under the
provisions of SFAS No. 133, all derivatives are recognized on the balance sheet
at their fair value unless they qualify for a normal purchases and normal sales
exception. Normal purchases and normal sales are contracts where physical
delivery is probable, quantities are expected to be used or sold in the normal
course of business over a reasonable period of time, and price is not tied to an
unrelated underlying derivative. Changes in the fair value of the derivative
financial instruments that do not qualify for a normal purchase and normal sales
exception are recognized in earnings unless specific hedge accounting criteria
are met. A derivative financial instrument can be designated as a hedge of the
fair value of a recognized asset or liability or of an unrecognized firm
commitment (fair value hedge), or a hedge of a forecasted transaction or the
variability of cash flows to be received or paid related to a recognized asset
or liability (cash flow hedge). Changes in the fair value of a derivative that
is highly effective as, and is designated and qualifies as, a fair value hedge,
along with the gain or loss on the hedged asset or liability that is
attributable to the hedged risk, are recorded in earnings. Changes in the fair
value of a derivative that is highly effective as, and is designated as and
qualifies as a cash flow hedge are recorded in other comprehensive income, until
earnings are affected by the variability of cash flows being hedged.
In connection with Exelon's Risk Management Policy (RMP), Exelon enters
into derivatives to manage its exposure to fluctuations in interest rates
related to its variable rate debt instruments, changes in interest rates related
to planned future debt issuances prior to their actual issuance and changes in
the fair value of outstanding debt which is planned for early retirement. As it
relates to energy transactions, Exelon utilizes derivatives to manage the
utilization of its available generating capability and provisions of wholesale
energy to its affiliates. Exelon also utilizes energy option contracts and
energy financial swap arrangements to limit the market price risk associated
with forward energy commodity contracts. Additionally, Exelon enters into
certain energy related derivatives for trading or speculative purposes.
As part of Exelon's energy marketing business, Exelon enters into contracts
to buy and sell energy to meet the requirements of its customers. These
contracts include short-term and long-term commitments to purchase and sell
energy and energy related products in the retail and wholesale markets with the
intent and ability to deliver or take delivery. While these contracts are
considered derivative financial instruments under SFAS No. 133, the majority of
these transactions have been designated as "normal purchases" or "normal sales"
and are not subject to the provisions of SFAS No. 133. Under these contracts,
Exelon recognizes gains or losses when the underlying physical transaction
affects earnings. Revenues and expenses associated with market price risk
management contracts are amortized over the terms of such contracts. Commitments
under these contracts are discussed in Note 19 - Commitments and Contingencies.
The remainder of these contracts are generally considered cash flow hedges under
SFAS No. 133. To the extent that the hedges are effective, changes in the fair
value of these contracts are recorded in other comprehensive income, until
earnings are affected by the variability of cash flows being hedged.
Additionally, during 2001, as part of the creation of Exelon's energy
trading operation, Exelon began to enter into contracts to buy and sell energy
for trading purposes subject to limits. These contracts are recognized on the
balance sheet at fair value and changes in the fair value of these derivative
financial instruments are recognized in earnings.
84
Prior to the adoption of SFAS No. 133, Exelon applied hedge accounting only
if the derivative reduced the risk of the underlying hedged item and was
designated at the inception of the hedge, with respect to the hedged item.
Exelon recognized any gains or losses on these derivatives when the underlying
physical transaction affected earnings.
Contracts entered into by Exelon to limit market risk associated with
forward energy commodity contracts are reflected in the financial statements at
the lower of cost or market using the accrual method of accounting. Under these
contracts, Exelon recognizes any gains or losses when the underlying physical
transaction affects earnings. Revenues and expenses associated with market price
risk management contracts are amortized over the terms of such contracts.
New Accounting Pronouncements
In 2001, the FASB issued SFAS No. 143, "Asset Retirement Obligations" (SFAS
No. 143). SFAS No. 143 provides accounting requirements for retirement
obligations associated with tangible long-lived assets. Exelon will adopt SFAS
No. 143 as of January 1, 2003. Retirement obligations associated with long-lived
assets included within the scope of SFAS No. 143 are those for which there is a
legal obligation to settle under existing or enacted law, statute, written or
oral contract or by legal construction under the doctrine of promissory
estoppel. Adoption of SFAS No. 143 will change the accounting for the
decommissioning of Generation's nuclear generating plants as well as certain
other long-lived assets.
As it relates to nuclear decommissioning, the effect of this cumulative
adjustment will be to decrease the decommissioning liability to reflect the fair
value of the decommissioning obligation at the balance sheet date. Additionally,
SFAS No. 143 will require the recognition of an asset related to the
decommissioning obligation, which will be amortized over the remaining lives of
the plants. The net difference, between the asset recognized and the change in
the liability to reflect fair value recorded upon adoption of SFAS No. 143, will
be recorded in earnings and recognized as a cumulative effect of a change in
accounting principle, net of expected regulatory recovery and income taxes. The
decommissioning liability will then represent an obligation for the future
decommissioning of the plants and, as a result, accretion expense will be
accrued on this liability until such time as the obligation is satisfied.
Currently, Generation records the obligation for decommissioning ratably
over the lives of the plants. Based on the current information and the
credit-adjusted risk-free rate, we estimate the increase in 2003 non-cash
expense to impact earnings before the cumulative effect of a change in
accounting principle for the adoption of SFAS No. 143 by approximately $24
million, after income taxes. Additionally, the adoption of SFAS No. 143 is
expected to result in a large, non-cash, one-time cumulative effect of a change
in accounting principle gain of at least $1.5 billion, after income taxes. The
$1.5 billion gain and the $24 million charge includes our share of the impact of
the SFAS No. 143 adoption related to AmerGen's nuclear plants. These impacts are
based on our current interpretation of SFAS No. 143 and are subject to continued
refinement based on the finalization of assumptions and interpretation at the
time of adopting the standard, including the determination of the
credit-adjusted risk-free rate. Under SFAS No. 143, the fair value of the
nuclear decommissioning obligation will continue to be adjusted on an ongoing
basis as these model input factors change.
The final determination of the 2003 earnings impact and the cumulative
effect of adopting SFAS No. 143, is in part a function of the credit adjusted
risk-free rate at the time of the adoption of SFAS No. 143. Additionally,
although over the life of the plant the charges to earnings for the depreciation
of the asset and the interest on the liability will be equal to the amounts that
would have been recognized as decommissioning expense under the current
accounting, the timing of those charges will change and in the near-term period
subsequent to adoption, the depreciation of the asset and the interest on the
liability is expected to result in an increase in expense.
85
In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities" (SFAS No. 146). SFAS No. 146
requires that the liability for costs associated with exit or disposal
activities be recognized when incurred, rather than at the date of a commitment
to an exit or disposal plan. SFAS No. 146 is to be applied prospectively to exit
or disposal activities initiated after December 31, 2002.
In November 2002, the FASB released FASB Interpretation No. (FIN) 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others" (FIN No. 45), providing for
expanded disclosures and recognition of a liability for the fair value of the
obligation undertaken by the guarantor. Under FIN No. 45, guarantors are
required to disclose the nature of the guarantee, the maximum amount of
potential future payments, the carrying amount of the liability and the nature
and amount of recourse provisions or available collateral that would be
recoverable by the guarantor. Exelon has adopted the disclosure requirements
under FIN No. 45, (see Note 19 - Commitments and Contingencies) which were
effective for financial statements for periods ended after December 15, 2002.
The recognition and measurement provisions of FIN No. 45 are effective, on a
prospective basis, for guarantees issued or modified after December 31, 2002.
In January 2003, the FASB issued FIN No. 46, "Consolidation of Variable
Interest Entities" (FIN No. 46). FIN No. 46 addresses consolidating certain
variable interest entities and applies immediately to variable interest entities
created after January 31, 2003. The impact, if any, of adopting FIN 46 on our
consolidated financial position, results of operations and cash flows, has not
been fully determined.
See Note 4 - Adoption of New Accounting Pronouncements and Accounting
Changes for discussion of the impact of new accounting pronouncements adopted by
Exelon.
Reclassifications
Certain prior year amounts have been reclassified for comparative purposes.
The reclassifications did not affect net income or shareholders' equity.
2. Merger
On October 20, 2000, Exelon became the parent corporation of PECO and ComEd
as a result of the completion of the transactions contemplated by an Agreement
and Plan of Exchange and Merger, as amended (Merger Agreement), among PECO,
Unicom and Exelon. Pursuant to the Merger Agreement, Unicom merged with and into
Exelon. In the Merger, each share of the outstanding common stock of Unicom was
converted into 0.875 shares of common stock of Exelon plus $3.00 in cash. As a
result of the Share Exchange, Exelon became the owner of all of the common stock
of PECO. As a result of the Merger, Unicom ceased to exist and its subsidiaries,
including ComEd, became subsidiaries of Exelon.
86
The Merger was accounted for using the purchase method of accounting. The
total purchase price was $6,014 million. In connection with the Merger, Exelon
issued 148 million shares of common stock in the amount of $5,310 million and
paid $507 million in cash to Unicom shareholders pursuant to the terms of the
Merger Agreement. The source of the cash consideration was borrowings under an
Exelon term loan. In addition, the Merger consideration included $113 million of
fair value of stock options and awards for certain Unicom employees and $84
million of direct acquisition costs. The cost in excess of net assets acquired
was $5,150 million as adjusted to reflect final purchase price allocations.
Exelon's results of operations include Unicom's results of operations since
October 20, 2000. The fair value of the assets acquired, including the cost in
excess of net assets acquired, and liabilities assumed in the Merger are as
follows:
- -------------------------------------------------------------------------------
Current Assets (including cash of $974) $ 2,744
Property, Plant and Equipment 7,641
Deferred Debits and Other Assets 5,535
Cost in excess of net assets acquired 5,150
Current Liabilities (2,390)
Long-Term Debt (7,419)
Deferred Credits and Other Liabilities (4,919)
Preferred Securities of Subsidiaries (328)
- -------------------------------------------------------------------------------
Total Purchase Price $ 6,014
- -------------------------------------------------------------------------------
Goodwill associated with the Merger increased by $14 million and $262
million in 2002 and 2001, respectively, as a result of the finalization of the
purchase price allocation. The adjustment resulted primarily from the after-tax
effects of the reduction of the regulatory asset for decommissioning retired
nuclear plants, as discussed in Note 11 - Nuclear Decommissioning and Spent Fuel
Storage, additional employee separation costs, the resolution of certain tax
matters and the finalization of other purchase price allocations.
Selected unaudited pro forma combined results of operations for the year
ended December 31, 2000, assuming the Merger Transaction occurred on January 1,
2000 are presented as follows:
(unaudited) 2000
- -------------------------------------------------------------------------------------------------------------------
Total revenues $ 13,531
Pro forma net income $ 1,003
Merger-related costs (net of income taxes of $147) 220
Cumulative effect of a change in accounting principle (net of income taxes of $16) 24
- -------------------------------------------------------------------------------------------------------------------
Pro forma net income before Merger-related costs
and the cumulative effect of a change in accounting principle $ 1,247
- -------------------------------------------------------------------------------------------------------------------
Pro forma net income before Merger-related costs
and the cumulative effect of a change in accounting principle
per common share (diluted) $ 3.86
- -------------------------------------------------------------------------------------------------------------------
Pro forma information assumes the issuance of transition bonds in 2000 had
occurred at the beginning of 2000. The pro forma financial information is not
necessarily indicative of the operating results that would have occurred had the
Merger been consummated as of the dates indicated, nor are they necessarily
indicative of future operating results.
87
Merger-Related Costs
In association with the Merger, Exelon recorded certain reserves for
restructuring costs. The reserves associated with PECO were charged to expense
pursuant to FASB Emerging Issues Task Force (EITF) Issue 94-3, "Liability
Recognition for Certain Employee Termination Benefits and Other Costs to Exit an
Activity (including Certain Costs Incurred in a Restructuring)"; while the
reserves associated with Unicom were recorded as part of the application of
purchase accounting and did not affect results of operations, consistent with
EITF Issue 95-3, "Recognition of Liabilities in Connection with a Purchase
Business Combination."
Merger costs charged to expense. PECO's merger-related costs charged to expense
in 2000 were $248 million, consisting of $116 million for PECO employee costs
and $132 million of direct incremental costs incurred by PECO in conjunction
with the merger transaction. Direct incremental costs represent expenses
directly associated with completing the Merger, including professional fees,
regulatory approval and settlement costs, and settlement of compensation
arrangements. Employee costs represent estimated severance costs and pension and
postretirement benefits provided under Exelon's merger separation plans for
eligible employees who were expected to be involuntarily terminated before
December 2002 due to integration activities of the merged companies. Additional
employee severance costs of $48 million, primarily related to PECO employees,
were charged to operating and maintenance expense in 2001, and a $10 million
reduction in the estimated liability related to Generation employees was
recorded in operating and maintenance expense in the first quarter of 2002.
Employee costs are being paid from Exelon's pension and postretirement benefit
plans, except for certain benefits such as outplacement services, continuation
of health care coverage and educational benefits. As of December 31, 2002, a
liability of $4 million is reflected on Exelon's consolidated balance sheet for
payment of these benefits, of which $1 million is reflected on PECO's balance
sheet and $1 million is reflected on Generation's balance sheet.
A total of 960 PECO positions were expected to be eliminated as a result of
the Merger, 274 of which related to generation, 230 of which related to PECO
energy delivery and 456 of which related to enterprises and corporate support
areas. As of December 31, 2002, 858 of the positions had been eliminated, of
which 224 related to generation, 195 related to PECO energy delivery, and 439 to
enterprises and corporate support. Of the remaining 102 positions, 58 were
eliminated as a result of normal attrition and 44 positions will not be
eliminated due to changes in certain business plans.
Additionally, in the third quarter of 2000, approximately $20 million of
closing costs and $8 million of stock compensation costs associated with Unicom
were charged to expense.
Merger costs included in purchase price allocation. The purchase price
allocation as of December 31, 2000 included a liability of $307 million for
Unicom employee costs and liabilities of approximately $39 million for estimated
costs of exiting various business activities of former Unicom activities that
were not compatible with the strategic business direction of Exelon.
88
During 2001, Exelon finalized plans for consolidation of functions,
including negotiation of an agreement with the International Brotherhood of
Electrical Workers Local 15 regarding severance benefits to union employees. In
the third quarter of 2002, Exelon reduced its reserve by $12 million due to the
elimination of identified positions through normal attrition, which did not
require payments under Exelon's merger separation plans, and a determination
that certain positions would not be eliminated by the end of 2002, as originally
planned, due to a change in certain business plans. The reduction in the reserve
was recorded as a purchase price adjustment to goodwill. In 2001 and 2002,
Exelon recorded adjustments to the purchase price allocation as follows:
Adjustments
Original ------------------ Adjusted
Estimate 2001 2002 Liabilities
- -------------------------------------------------------------------------------------------------------------------
Employee severance payments $ 128 $ 33 $ (10) $ 151 (a)
Other benefits 21 9 (2) 28 (a)
- -------------------------------------------------------------------------------------------------------------------
Employee severance payments and other benefits 149 42 (12) 179
Actuarially determined pension and postretirement costs 158 (11) -- 147 (b)
- -------------------------------------------------------------------------------------------------------------------
Total Unicom employee cost $ 307 $ 31 $ (12) $ 326
- -------------------------------------------------------------------------------------------------------------------
(a) The increase is a result of the identification in 2001 of additional
positions to be eliminated, partially offset by the 2002 elimination of
identified positions through normal attrition and changes in certain
business plans.
(b) The reduction results from lower estimated pension and postretirement
welfare benefits reflecting revised actuarial estimates.
The following table provides a reconciliation of the reserve for
employee severance and other benefits associated with the Merger:
- -------------------------------------------------------------------------------------------------------------------
Adjusted employee severance and other benefits reserve $ 179
Payments to employees in 2000 (5)
Payments to employees in 2001 (72)
Payments to employees in 2002 (74)
- -------------------------------------------------------------------------------------------------------------------
Employee severance and other benefits reserve as of December 31, 2002 (1) $ 28
- -------------------------------------------------------------------------------------------------------------------
(1) Relates to certain benefits that are being paid after 2002.
The following table provides a reconciliation of the former Unicom
positions that were expected to be eliminated as a result of the Merger:
Total
- -------------------------------------------------------------------------------------------------------------------
Estimate at October 20, 2000 2,275
2001 adjustments (a) 118
- -------------------------------------------------------------------------------------------------------------------
Total positions 2,393
- -------------------------------------------------------------------------------------------------------------------
Employees terminated in 2000 279
Employees terminated in 2001 607
Employees terminated in 2002 1,053
Normal attrition 298
Business plan changes (b) 156
- -------------------------------------------------------------------------------------------------------------------
Total positions 2,393
- -------------------------------------------------------------------------------------------------------------------
(a) The increase is a result of the identification of additional positions to
be eliminated in 2001.
(b) The reduction is due to a determination in the third quarter of 2002, that
certain positions would not be eliminated by the end of 2002 as originally
planned due to a change in certain business plans.
89
3. Acquisitions and Dispositions
Sithe New England Holdings Asset Acquisition
On November 1, 2002, Generation purchased the assets of Sithe New England
Holdings, LLC (Sithe New England), a subsidiary of Sithe, and related power
marketing operations. Sithe New England's primary assets are gas-fired
facilities currently under development. The purchase price for the Sithe New
England assets consisted of a $534 million note to Sithe, $14 million of direct
acquisition costs and an adjustment to Generation's investment in Sithe to
reflect Sithe's sale of Sithe New England to Generation. Additionally,
Generation will assume various Sithe guarantees related to an equity
contribution agreement between Sithe New England and Sithe Boston Generation,
LLC (SBG), a project subsidiary of Sithe New England. The equity contribution
agreement requires, among other things, that Sithe New England, upon the
occurrence of certain events, contribute up to $38 million of equity for the
purpose of completing the construction of two generating facilities. SBG has a
$1.25 billion credit facility (the SBG Facility) to finance the construction of
these two generating facilities. The $1.0 billion outstanding under the facility
at December 31, 2002 is reflected on Exelon's Consolidated Balance Sheet. Sithe
New England owns 4,066 megawatts (MWs) of generation capacity, consisting of
1,645 MWs in operation and 2,421 MWs under construction. Sithe New England's
generation facilities are located primarily in Massachusetts.
The allocation of purchase price to the fair value of assets acquired and
liabilities assumed in the acquisition is as follows:
- -----------------------------------------------------------------------------
Current Assets (including $12 of cash acquired) $ 82
Property, Plant and Equipment 1,889
Deferred Debits and Other Assets 62
Current Liabilities (159)
Deferred Credits and Other Liabilities (124)
Long-Term Debt (1,036)
- -----------------------------------------------------------------------------
Total Purchase Price $ 714
- -----------------------------------------------------------------------------
The SBG Facility provides that if these construction projects are not
completed by June 12, 2003, the SBG Facility lenders will have the right, but
will not be required, to, among other things, declare all amounts then
outstanding under the SBG Facility and the interest rate swap agreements to be
due. Generation believes that the construction projects will be substantially
complete by May 31, 2003, but that all of the approvals required under the SBG
Facility may not be issued by that date. Generation is currently evaluating
whether the requirements of the SBG Facility relating to the construction
projects can be satisfied by June 12, 2003. In the event that the requirements
are not expected to be satisfied by June 12, 2003, Generation will contact the
SBG Facility lenders concerning an amendment or waiver of these provisions of
the SBG Facility. Generation currently expects that arrangements for such an
amendment or waiver, if necessary, can be successfully negotiated with the SBG
Facility lenders.
See Note 19 - Commitments and Contingencies for further discussion of
Sithe.
90
Acquisition of Generating Plants from TXU
On April 25, 2002, Generation acquired two natural-gas and oil-fired plants
from TXU Corp. (TXU) for an aggregate purchase price of $443 million. The
purchase included the 893-megawatt Mountain Creek Steam Electric Station in
Dallas and the 1,441-megawatt Handley Steam Electric Station in Fort Worth. The
transaction included a purchased power agreement for TXU to purchase power
during the months of May through September from 2002 through 2006. During the
periods covered by the purchased power agreement, TXU will make fixed capacity
payments, variable expense payments, and will provide fuel to Exelon in return
for exclusive rights to the energy and capacity of the generation plants.
Substantially all of the purchase price has been allocated to property, plant
and equipment.
Sale of AT&T Wireless
On April 1, 2002, Enterprises sold its 49% interest in AT&T Wireless PCS of
Philadelphia, LLC to a subsidiary of AT&T Wireless Services for $285 million in
cash. Enterprises recorded an after-tax gain of $116 million in Other Income and
Deductions on Exelon's Consolidated Statements of Income on its $84 million
investment, which had been reflected in Deferred Debits and Other Assets on
Exelon's Consolidated Balance Sheets.
InfraSource Acquisitions
In 2001, Exelon's infrastructure services business (InfraSource), acquired
the assets of a utility service contracting company for an aggregate purchase
price of approximately $31 million. The acquisition was accounted for using the
purchase method of accounting. The excess of purchase price over the fair value
of net assets acquired was $19 million. The allocation of purchase price to the
fair value of assets acquired and liabilities assumed in the acquisition is as
follows:
- ------------------------------------------------------------------------------
Current Assets (including cash acquired of $1) $ 11
Property, Plant and Equipment 11
Cost in excess of net assets acquired 19
Current Liabilities (10)
- ------------------------------------------------------------------------------
Total $ 31
- ------------------------------------------------------------------------------
AmerGen Energy Company, LLC
In August 2000, AmerGen, a joint venture with British Energy, Inc., a
wholly owned subsidiary of British Energy plc, (British Energy), completed the
purchase of Oyster Creek Nuclear Generating Facility (Oyster Creek) from GPU,
Inc. (GPU) for $10 million. Under the terms of the purchase agreement, GPU
agreed to fund outage costs of $89 million, including the cost of fuel, for a
refueling outage that occurred in 2000. AmerGen is repaying these costs to GPU
in equal annual installments through 2009. In addition, AmerGen assumed full
responsibility for the ultimate decommissioning of Oyster Creek. At the closing
of the sale, GPU provided funding for the decommissioning trust of $440 million.
In conjunction with this acquisition, AmerGen has received a fully funded
decommissioning trust fund which has been computed assuming the anticipated
costs to appropriately decommission Oyster Creek discounted to net present value
using the NRC's mandated rate of 2%. AmerGen believes that the amount of the
trust fund and investment earnings thereon will be sufficient to meet its
decommissioning obligation. GPU is purchasing the electricity generated by
Oyster Creek pursuant to a three-year power purchase agreement.
4. Adoption of New Accounting Pronouncements and Accounting Changes
SFAS No. 141 and SFAS No. 142
91
In 2001, FASB issued SFAS No. 141, "Business Combinations" (SFAS No. 141),
which requires that all business combinations be accounted for under the
purchase method of accounting and establishes criteria for the separate
recognition of intangible assets acquired in business combinations. SFAS No. 141
became effective for business combinations initiated after June 30, 2001. In
addition, SFAS No. 141 required that unamortized negative goodwill related to
pre-July 1, 2001 purchases be recognized as a change in accounting principle
concurrent with the adoption of SFAS No. 142, "Goodwill and Other Intangible
Assets" (SFAS No. 142). At December 31, 2001, AmerGen, an equity-method investee
of Generation, had $43 million of negative goodwill, net of accumulated
amortization, recorded on its balance sheet. Upon AmerGen's adoption of SFAS No.
141 in January 2002, Generation recognized its proportionate share of income of
$22 million ($13 million, net of income taxes) as a cumulative effect of a
change in accounting principle.
Exelon adopted SFAS No. 142 as of January 1, 2002. SFAS No. 142 establishes
new accounting and reporting standards for goodwill and intangible assets. Other
than goodwill, Exelon does not have significant other intangible assets recorded
on its consolidated balance sheets. Under SFAS No. 142, goodwill is no longer
subject to amortization; however, goodwill is subject to an assessment for
impairment using a two-step fair value based test. The first step must be
performed at least annually, or more frequently if events or circumstances
indicate that goodwill might be impaired and compares the fair value of a
reporting unit to its carrying amount, including goodwill. If the carrying
amount of the reporting unit exceeds its fair value, the second step is
performed. The second step compares the carrying amount of the goodwill to the
fair value of the goodwill. If the fair value of goodwill is less than the
carrying amount, an impairment loss is reported as a reduction to goodwill and a
charge to operating expense, except at the transition date, when the loss is
reflected as a cumulative effect of a change in accounting principle.
As of December 31, 2001, Exelon's Consolidated Balance Sheets reflected
approximately $5.3 billion in goodwill net of accumulated amortization,
including $4.9 billion of net goodwill related to the Merger recorded on ComEd's
Consolidated Balance Sheets, with the remainder related to Enterprises. The
first step of the transitional impairment analysis indicated that ComEd's
goodwill was not impaired but that an impairment did exist with respect to
goodwill recorded in Enterprises' reporting units. InfraSource, the energy
services business (Exelon Services) and the competitive retail energy sales
business (Exelon Energy) were determined to be those reporting units of
Enterprises that had goodwill allocated to them. The second step of the
analysis, which compared the fair value of each of Enterprises' reporting units'
goodwill to the carrying value at December 31, 2001, indicated a total goodwill
impairment of $357 million ($243 million, net of income taxes and minority
interest). The fair value of the Enterprises' reporting units was determined
using discounted cash flow models reflecting the expected range of future cash
flow outcomes related to each of the Enterprises reporting units over the life
of the investment. These cash flows were discounted to 2002 using a
risk-adjusted discount rate. The impairment was recorded as a cumulative effect
of a change in accounting principle in the first quarter of 2002.
The changes in the carrying amount of goodwill by reportable segment (see
Note 20 - Segment Information) for the year ended December 31, 2002 are as
follows:
Energy
Delivery Enterprises Total
- -------------------------------------------------------------------------------------------------------------------
Balance as of January 1, 2002 $ 4,902 $ 433 $ 5,335
Impairment losses -- (357) (357)
Resolution of certain tax matters 21 -- 21
Merger severance adjustment (7) -- (7)
- -------------------------------------------------------------------------------------------------------------------
Balance as of December 31, 2002 $ 4,916 $ 76 $ 4,992
- -------------------------------------------------------------------------------------------------------------------
The December 31, 2002, Energy Delivery goodwill relates to ComEd and the
remaining Enterprises goodwill relates to the InfraSource and Exelon Services
reporting units. Consistent with
92
SFAS No. 142, the remaining goodwill will be reviewed for impairment on an
annual basis, or more frequently if significant events occur that could indicate
an impairment exists. ComEd and Enterprises performed an impairment review in
the fourth quarter of 2002. Such review was consistent with the review conducted
related to the implementation of SFAS No. 142, which required estimates of
numerous items with varying degrees of uncertainty, such as discount rates,
terminal value earnings multiples, future revenue levels and estimated future
expenditure levels for ComEd and Enterprises; load growth and the resolution of
future rate proceedings for ComEd; and customer base and construction back logs
for Enterprises. These valuations determined the Step I calculated fair value of
both ComEd and the Enterprises' units to be in excess of their respective book
values at November 1, 2002. Significant changes from the assumptions used in the
impairment review could possibly result in a future impairment loss. Illinois
legislation provides that reductions to ComEd's common equity resulting from
goodwill impairments will not impact ComEd's earnings through 2006 under the
earnings provisions of the legislation. See Note 5 - Regulatory Issues for
further discussion of ComEd's earnings provisions.
The components of the net transitional impairment loss recognized in the
first quarter of 2002 as a cumulative effect of a change in accounting principle
are as follows:
- -------------------------------------------------------------------------------------------------------------------
Enterprises goodwill impairment (net of income taxes of $103) $ (254)
Minority interest (net of income taxes of $4) 11
Elimination of AmerGen negative goodwill (net of income taxes of $9) 13
- -------------------------------------------------------------------------------------------------------------------
Total cumulative effect of a change in accounting principle $ (230)
- -------------------------------------------------------------------------------------------------------------------
The following tables set forth Exelon's net income and earnings per common
share for 2002, 2001, and 2000 adjusted to exclude 2001 and 2000 amortization
expense related to goodwill that is no longer being amortized.
2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
Reported income before cumulative effect
of changes in accounting principles $ 1,670 $ 1,416 $ 562
Cumulative effect of changes in accounting principles (230) 12 24
- -------------------------------------------------------------------------------------------------------------------
Reported net income 1,440 1,428 586
Goodwill amortization -- 155 34
- -------------------------------------------------------------------------------------------------------------------
Adjusted net income $ 1,440 $ 1,583 $ 620
- -------------------------------------------------------------------------------------------------------------------
Basic earnings per common share:
Reported income before cumulative effect
of changes in accounting principles $ 5.18 $ 4.42 $ 2.79
Cumulative effect of changes in accounting principles (0.71) 0.04 0.12
- -------------------------------------------------------------------------------------------------------------------
Reported net income 4.47 4.46 2.91
Goodwill amortization -- 0.48 0.17
- -------------------------------------------------------------------------------------------------------------------
Adjusted net income $ 4.47 $ 4.94 $ 3.08
- -------------------------------------------------------------------------------------------------------------------
Diluted earnings per common share:
Reported income before cumulative effect
of changes in accounting principles $ 5.15 $ 4.39 $ 2.75
Cumulative effect of changes in accounting principles (0.71) 0.04 0.12
- -------------------------------------------------------------------------------------------------------------------
Reported net income 4.44 4.43 2.87
Goodwill amortization -- 0.48 0.17
- -------------------------------------------------------------------------------------------------------------------
Adjusted net income $ 4.44 $ 4.91 $ 3.04
- -------------------------------------------------------------------------------------------------------------------
93
The cessation of the amortization of negative goodwill of AmerGen on
January 1, 2002 did not have a material impact on Exelon's reported net income
for 2002.
EITF Issue 02-3
In the third quarter of 2002, Exelon and Generation adopted the provision
of EITF Issue 02-3, "Accounting for Contracts Involved in Energy Trading and
Risk Management Activities" (EITF 02-3) issued by the FASB EITF in June 2002
that requires revenues and energy costs related to energy trading contracts to
be presented on a net basis in the income statement. Prior to the adoption,
revenues from trading activity were presented in Revenue and the energy costs
related to energy trading were presented as either Purchased Power or Fuel
expense on Exelon and Generation's Consolidated Statements of Income. For
comparative purposes, energy costs related to energy trading have been
reclassified in prior periods to revenue to conform to the net basis of
presentation required by EITF 02-3. Exelon commenced trading activities in April
2001, as such $207 million of purchased power expense and $15 million of fuel
expense, respectively, was reclassified and reflected as a reduction to revenue
for the year ended December 31, 2001.
SFAS No. 144
In September 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets" (SFAS No. 144). Exelon adopted SFAS
No. 144 on January 1, 2002. SFAS No. 144 establishes accounting and reporting
standards for both the impairment and disposal of long-lived assets. SFAS No.
144 is effective for fiscal years beginning after December 15, 2001 and its
provisions are generally applied prospectively. The adoption of SFAS No. 144 had
no effect on Exelon's reported financial position, results of operations or cash
flows.
SFAS No. 145
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements
No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections"
(SFAS No. 145). SFAS No. 145 eliminates SFAS No. 4 "Reporting Gains and Losses
from Extinguishment of Debt" and thus allows for only those gains or losses on
the extinguishment of debt that meet the criteria of extraordinary items to be
treated as such in the financial statements. SFAS No. 145 also amends Statement
of Financial Accounting Standards No. 13, "Accounting for Leases" to require
sale-leaseback accounting for certain lease modifications that have economic
effects that are similar to sale-leaseback transactions. The adoption of SFAS
No. 145 required a reclassification of the 2000 extraordinary item of $4
million, net of income taxes, to interest expense; otherwise, it had no effect
on Exelon's reported financial position or cash flows.
SFAS No. 133
SFAS No. 133 applies to all derivative instruments and requires that such
instruments be recorded on the balance sheet either as an asset or a liability
measured at their fair value through earnings, with special accounting permitted
for certain qualifying hedges. On January 1, 2001, Exelon adopted SFAS No. 133.
Generation recognized a non-cash gain of $12 million, net of income taxes, in
earnings and deferred a non-cash gain of $4 million, net of income taxes, in
accumulated other comprehensive income and PECO deferred a non-cash gain of $40
million, net of income taxes, in accumulated other comprehensive income.
Nuclear Outage Costs
During the fourth quarter of 2000, as a result of the synchronization of
accounting policies with Unicom in connection with the Merger, PECO changed its
method of accounting for nuclear outage costs to record such costs as incurred.
Previously, PECO accrued these costs over the operating unit cycle. As a result
of the change in accounting method for nuclear outage costs, PECO recorded
income of $24
94
million, net of income taxes of $16 million. The change is reported as a
cumulative effect of a change in accounting principle on the Consolidated
Statements of Income as of December 31, 2000, representing the balance of the
nuclear outage cost reserve at January 1, 2000.
SFAS No. 148
In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure - an amendment of FASB Statement No.
123" (SFAS No. 148). SFAS No. 148 provides alternative methods of transition for
a voluntary change to the fair value based method of accounting for stock-based
employee compensation and requires disclosures in both annual and interim
financial statements regarding the method of accounting for stock-based
compensation and the effect of the method on financial results. SFAS No. 148 is
effective for financial statements for fiscal years ending after December 15,
2002. As of December 31, 2002, Exelon has adopted the additional disclosure
requirements of SFAS No. 148 and continues to account for its stock-compensation
plans under the disclosure only provision of SFAS No. 123.
Changes in Accounting Estimates
Effective July 1, 2002, ComEd decreased its depreciation rates based on a
new depreciation study reflecting its significant construction program in recent
years, changes in and development of new technologies, and changes in estimated
plant service lives since the last depreciation study. The annualized reduction
in depreciation expense, based on December 31, 2001 plant balances, is estimated
to be approximately $100 million ($60 million, net of income taxes). As a result
of the change, net income for 2002 increased approximately $48 million ($29
million, net of income taxes).
Effective April 1, 2001, Generation changed its accounting estimates
related to the depreciation and decommissioning of certain generating stations.
The estimated service lives were extended by 20 years for three nuclear
stations, by periods of up to 20 years for certain fossil stations and by 50
years for a pumped storage station. Effective July 1, 2001, the estimated
service lives were extended by 20 years for the remainder of Exelon's operating
nuclear stations. These changes were based on engineering and economic
feasibility studies performed by Generation considering, among other things,
future capital and maintenance expenditures at these plants. The service life
extension is subject to Nuclear Regulatory Commission (NRC) approval of an
extension of existing NRC operating licenses, which are generally 40 years. The
estimated annualized reduction in expense from the change is $132 million ($79
million, net of income taxes).
In April 2002, ComEd changed its accounting estimate related to the
allowance for uncollectible accounts based on an independently prepared
evaluation of the risk profile of ComEd's customer accounts receivable. As a
result of the new evaluation, the allowance for uncollectible accounts reserve
was reduced by $11 million in the second quarter of 2002.
In December 2002, PECO changed its accounting estimate related to the
allowance for uncollectible accounts based on an independently prepared
evaluation of the risk profile of PECO's customer accounts receivable. As a
result of the new evaluation, the allowance for uncollectible accounts reserve
was reduced by $17 million in the fourth quarter of 2002.
In 2002, Generation increased its allowance for uncollectible accounts by
$6 million based on an independently prepared evaluation of the risk profile of
Power Team's counterparties. Power Team is the unit within Generation that
manages the output of Generation's assets and energy sales to reduce the
volatility of Generation's earnings and cash flows.
5. Regulatory Issues
ComEd
95
Delivery Service Rates. On June 1, 2001, ComEd filed with the ICC to
establish delivery service charges for residential customers in preparation for
residential customer choice, which began in May 2002. ComEd is authorized to
charge customers who purchase electricity from an alternative supplier for the
use of its distribution system to deliver that electricity. These delivery
service rates are set through proceedings before the ICC based upon, among other
things, the operating costs associated with ComEd's distribution system and the
capital investment that ComEd has made in its distribution system.
On April 1, 2002, the ICC issued an interim order in ComEd's Delivery
Services Rate Case. The interim order is subject to an audit of test year (2000)
expenditures, including capital plant expenditures, with a final order to be
issued in 2003. The order sets delivery rates for residential customers choosing
a new retail electric supplier. The new rates became effective May 1, 2002 when
residential customers became eligible to choose their supplier of electricity.
Traditional bundled rates paid by customers that retain ComEd as their
electricity supplier are not affected by this order. Bundled rates will remain
frozen through 2006, as a result of the June 6, 2002 amendments to the Illinois
Restructuring Act that extended the freeze on bundled rates for an additional
two years. Delivery service rates for non-residential customers are not affected
by the order.
In October 2002, the ICC received the report on the audit of the test year
expenditures by a consulting firm engaged by the ICC to perform the audit. The
consulting firm recommended certain additional disallowances to test year
expenditures and rate base levels. ComEd does not expect this matter to have a
significant impact on results of operations in 2003, however, the estimated
potential investment write-off, before income taxes, could be up to
approximately $100 million, if the ICC ultimately determines that all or some
portion of ComEd's distribution plant is not recoverable through rates. In 2002,
ComEd recorded a charge to earnings, before income taxes, of $12 million
representing the estimated minimum probable exposure pursuant to SFAS No. 90,
"Regulated Enterprises - Accounting for Abandonments and Disallowances of Plant
Costs an Amendment of FASB Statement No. 71." ComEd is in negotiations with
several parties to resolve the delivery service case.
Customer Choice. As of December 31, 2002, all ComEd's customers were
eligible to choose an alternative electric supplier and non-residential
customers can also elect the power purchase option (PPO) that allows the
purchase of electric energy from ComEd at market-based prices. ComEd's
residential customers became eligible to choose a new electric supplier in May
2002. However, as of December 31, 2002, no alternative supplier had sought
approval from the ICC and no electric utilities have chosen to enter the ComEd
residential market for the supply of electricity. As of December 31, 2002,
approximately 22,700 non-residential customers, representing approximately 26%
of ComEd's annual retail kilowatt-hour sales, had elected to purchase their
electric energy from an alternate electric supplier or had chosen the power
purchase option. Customers who receive energy from an alternative supplier
continue to pay a delivery charge. ComEd is unable to predict the long-term
impact of customer choice on results of operations.
Rate Reductions and Return on Common Equity Threshold. The Illinois
restructuring legislation provided a 15% residential base rate reduction
effective August 1, 1998 with an additional 5% residential base rate reduction
effective October 1, 2001. ComEd's operating revenues were reduced by
approximately $99 million and $24 million in 2002 and 2001, respectively due to
the 5% residential rate reduction. Notwithstanding the rate reductions and
subject to certain earnings tests, a rate freeze is generally in effect until at
least January 1, 2007. A utility may request a rate increase during the rate
freeze period only when necessary to ensure the utility's financial viability.
Under the Illinois legislation, if the earned return on common equity of a
utility during this period exceeds an established threshold, one-half of the
excess earnings must be refunded to customers. The threshold rate of return on
common equity is based on the Monthly Treasury Bond Long-Term Average (25 years
and above). Earnings for purposes of ComEd's threshold include ComEd's net
income calculated in accordance with GAAP and
96
reflect the amortization of regulatory assets and goodwill. As a result of the
Illinois legislation, at December 31, 2002, ComEd had a regulatory asset with an
unamortized balance of $175 million that it expects to fully recover and
amortize by the end of 2006. Consistent with the provisions of the Illinois
legislation, regulatory assets may be recovered at amounts that provide ComEd an
earned return on common equity within the Illinois legislation earnings
threshold. The earned return on common equity and the threshold return on common
equity for ComEd are each calculated on a two-year average basis. ComEd did not
trigger the earnings sharing provision in 2002, 2001 or 2000 and does not
currently expect to trigger the earnings sharing provisions in the years 2003
through 2006.
PECO
Revenue Neutral Reconciliation Adjustment. As permitted by the Pennsylvania
Electric Competition Act, the Pennsylvania Department of Revenue calculated a
2002 Revenue Neutral Reconciliation (RNR) adjustment to the gross receipts tax
rate in order to neutralize the impact of electric restructuring on its tax
revenues. In January 2002, the PUC approved the RNR adjustment to the gross
receipts tax rate collected from customers. Effective January 1, 2002, PECO
implemented the change in the gross receipts tax rate. The RNR adjustment
increases the gross receipts tax rate, which increased PECO's annual revenues
and tax obligations by approximately $50 million in 2002. The RNR adjustment was
appealed. The case was remanded to the PUC and in August 2002, the PUC ruled
that PECO is properly authorized to recover these costs. In December 2002, the
PUC approved the inclusion of the RNR factor in PECO's base rates eliminating
the need for an annual filing to obtain approval for recovery.
Customer Choice. The PUC's Final Electric Restructuring Order provided for
the phase-in of customer choice of electric generation suppliers (EGS) and as of
January 1, 2000, all customers were eligible for customer choice. The Final
Restructuring Order also established market share thresholds (MST) to promote
competition. The MST requirements provided that, if as of January 1, 2001 and
January 1, 2003, respectively, less than 35% and 50% of residential and
commercial customers were shopping, the number of customers sufficient to meet
the MST shall be randomly selected and assigned to an EGS through a
PUC-determined process. For residential and small commercial customers, the
threshold measurement is by number of customers. For large commercial customers
the measurement is by load. On January 1, 2001, the 35% MST threshold was met
for all customer classes as a result of agreements assigning customers to New
Power Company (New Power) and Green Mountain as providers of last resort default
service. During 2002, PECO experienced an increase in the number of customers
selecting or returning to PECO as their EGS and at December 31, 2002,
approximately 21% of PECO's residential load, 10% of its small commercial and
industrial load and 7% of its large commercial and industrial load were
purchasing generation from an alternative generation supplier. Customers who
purchase energy from an EGS continue to pay a delivery charge. In January 2003,
PECO submitted to the PUC an MST plan to meet the 50% threshold requirement for
its small and large commercial customer classes, which was approved on February
6, 2003. According to the approved plan, randomly assigned customers who
participated will be switched to winning MST bidders as of their respective
meter read dates. Also in February 2003, PECO filed an MST plan for the
residential customer classes which is pending PUC approval.
In February 2002, New Power notified PECO of its intent to withdraw from
providing Competitive Default Service (CDS) to approximately 180,000 residential
customers. As a result of that withdrawal, those CDS customers were returned to
PECO in the second quarter of 2002. Pursuant to a tariff filing approved by the
PUC, PECO is serving those returned customers at the discount energy rates on
generation provided for under the original New Power CDS Agreement for the
remaining term of that contract. Subsequently, in the second quarter of 2002,
New Power also advised PECO it planned to
97
withdraw from serving all of its customers in Pennsylvania, including
approximately 15,000 non-CDS PECO customers. These customers were returned to
PECO during the third quarter of 2002.
Rate Reductions and Caps. Under the Final Restructuring Order, retail
electric rates were capped at year-end 1996 levels (system-wide average of 9.96
cents/kilowatt hour (kWh)) through June 2005. The Final Restructuring Order
required PECO to reduce its retail electric rates by 8% from the 1996
system-wide average rate on January 1, 1999. This rate reduction decreased to 6%
on January 1, 2000 until January 1, 2001. The transmission and distribution rate
component was capped at a system-wide average rate of 2.98 cents/kWh through
June 30, 2005. Additionally, generation rate caps, defined as the sum of the
applicable transition charge and energy and capacity charge, will remain in
effect through 2010.
On March 16, 2000, the PUC issued an order authorizing PECO to securitize
up to an additional $1 billion of its authorized stranded costs recovery. In
accordance with the terms of that order, PECO provided its retail customers with
rate reductions of $60 million for calendar year 2001 only.
Under a comprehensive settlement agreement in connection with achieving
regulatory approval of the Merger, PECO agreed to $200 million in aggregate rate
reductions for all customers in Pennsylvania over the period January 1, 2002
through 2005 and extended the rate caps on PECO's retail electric distribution
charges through December 31, 2006.
6. Supplemental Financial Information
Supplemental Income Statement Information
For the Years Ended December 31,
------------------------------------------------
2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
Taxes Other Than Income
Utility (a) $ 412 $ 342 $ 196
Real estate 149 140 68
Payroll 98 88 41
Other 50 53 17
- -------------------------------------------------------------------------------------------------------------------
Total $ 709 $ 623 $ 322
- -------------------------------------------------------------------------------------------------------------------
Other, Net
Investment income $ 130 $ 47 $ 64
Gain (loss) on disposition of assets, net 199 4 (19)
Write-down of impaired investments (41) (36) --
AFUDC, equity and borrowed 19 18 3
Reserve for potential plant disallowance (12) -- --
Settlement of power purchase agreement -- -- 6
Other 5 46 (1)
- -------------------------------------------------------------------------------------------------------------------
Total $ 300 $ 79 $ 53
- -------------------------------------------------------------------------------------------------------------------
(a) Municipal and state utility taxes are also recorded in Revenues on Exelon's
Consolidated Statements of Income.
98
Supplemental Cash Flow Information
For the Years Ended December 31,
------------------------------------------------
2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
Cash paid during the year:
Interest (net of amount capitalized) $ 905 $ 963 $ 519
Income taxes (net of refunds) $ 614 $ 749 $ 272
Non-cash investing and financing activities:
Regulatory Asset Fair Value Adjustment $ -- $ 347 $ --
Resolution of Certain Tax Matters and Merger
Severance Adjustment 14 -- --
Purchase Accounting Estimate Adjustments -- (85) --
Issuance of Exelon Shares for Unicom -- -- 5,310
Capital Lease Obligations 52 -- --
Issuance of InfraSource Stock -- 35 14
Contribution of Land from Minority Interest of
Consolidated Subsidiary 12 -- --
Note Issued to Sithe in the
Sithe New England Acquisition 534 -- --
Depreciation and amortization:
Property, plant and equipment $ 729 $ 697 $ 325
Regulatory assets 472 445 53
Nuclear fuel 374 393 149
Decommissioning 126 144 46
Goodwill -- 155 34
- -------------------------------------------------------------------------------------------------------------------
Total Depreciation and Amortization $ 1,701 $ 1,834 $ 607
- -------------------------------------------------------------------------------------------------------------------
Supplemental Balance Sheet Information
December 31,
-----------------------------------
2002 2001
- -------------------------------------------------------------------------------------------------------------------
Investments
Investment in Sithe $ 478 $ 700
Direct financing leases 445 427
Energy services and other ventures 167 161
Investment in AmerGen 160 95
Affordable housing projects 88 98
Communication ventures 39 116
Investment in subsidiaries and joint ventures 16 26
- -------------------------------------------------------------------------------------------------------------------
Total $ 1,393 $ 1,623
- -------------------------------------------------------------------------------------------------------------------
99
Prior to the Merger, Unicom entered into a like-kind exchange transaction
pursuant to which approximately $1.6 billion was invested in passive generating
station leases with two separate entities unrelated to Exelon. The generating
stations were leased back to such entities as part of the transaction. For
financial accounting purposes, the investments are accounted for as direct
financing lease investments. Unicom Investments, Inc. holds the leasehold
interests in the generating stations in several separate bankruptcy remote,
special purpose companies it directly or indirectly wholly owns. Under the terms
of the lease agreements, Exelon received a prepayment of $1.2 billion in the
fourth quarter of 2000, which reduced the investment in the lease. The remaining
payments are payable at the end of the thirty year lease and there are no
minimum scheduled lease payments to be received over the next five years. The
components of the net investment in the direct financing leases are as follows:
December 31,
-----------------------------------
2002 2001
- -------------------------------------------------------------------------------------------------------------------
Total minimum lease payments $ 1,492 $ 1,492
Less: Unearned income 1,047 1,065
- -------------------------------------------------------------------------------------------------------------------
Net investment in direct financing leases $ 445 $ 427
- -------------------------------------------------------------------------------------------------------------------
December 31,
-----------------------------------
2002 2001
- -------------------------------------------------------------------------------------------------------------------
Regulatory Assets
Competitive transition charge $ 4,639 $ 4,947
Recoverable deferred income taxes (see Note 14) 661 701
Nuclear decommissioning costs for retired plants 248 310
Recoverable transition costs 175 277
Reacquired debt costs and interest rate swap settlements 137 112
Non-pension postretirement benefits 65 71
Compensated absences 6 5
Other 7 --
- -------------------------------------------------------------------------------------------------------------------
Long-Term Regulatory Assets 5,938 6,423
Deferred energy costs (current asset) 31 56
- -------------------------------------------------------------------------------------------------------------------
Total $ 5,969 $ 6,479
- -------------------------------------------------------------------------------------------------------------------
o Competitive Transition Charges (CTC) represent PECO's stranded costs that
the PUC determined would be allowed to be recoverable through regulated
rates. These costs are related to the deregulation of the generation
portion of the electric utility business in Pennsylvania. The unamortized
balance of the CTC of $4.6 billion and $4.9 billion as of December 31, 2002
and 2001, respectively, was recorded on our Consolidated Balance Sheets.
The CTC includes Intangible Transition Property sold to PECO Energy
Transition Trust, a wholly owned subsidiary of PECO, in connection with the
securitization of PECO's stranded cost recovery. These charges are being
amortized through December 31, 2010 with a return on the unamortized
balance of 10.75%.
o Nuclear decommissioning costs for retired plants - recovery is provided
through ComEd's current regulated rates and is expected to be fully
recovered by the end of 2006.
o Recoverable transition costs - recovery is provided for in regulated rates
pursuant to the Illinois Restructuring Act and is expected to be recovered
by the end of 2006.
o Reacquired debt costs and interest rate swap settlements - recoverable
gains and losses on reacquired debt are deferred and amortized over the
rate-regulatory period, which is over the life of the new debt issued to
finance the debt redemption. Interest rate swap settlements are deferred
and amortized over the period that the related debt is outstanding.
100
The regulatory assets related to the nuclear decommissioning costs and
deferred income taxes did not require a cash outlay of investor supplied funds;
consequently, these costs are not earning a rate of return. Recovery of the
regulatory assets for loss on reacquired debt and recoverable transition costs
is provided for through regulated revenue sources that are based on the pre-open
access cost of service. Therefore, they are earning a rate of return.
December 31,
-----------------------------------
2002 2001
- -------------------------------------------------------------------------------------------------------------------
Accrued Expenses
Taxes Accrued $ 420 $ 91
Interest Accrued 307 299
Other Accrued Expenses 584 745
- -------------------------------------------------------------------------------------------------------------------
Total $ 1,311 $ 1,135
- -------------------------------------------------------------------------------------------------------------------
7. Earnings Per Share
Diluted earnings per share are calculated by dividing net income by the
weighted average shares of common stock outstanding including shares issuable
upon exercise of stock options outstanding under Exelon's stock option plans
considered to be common stock equivalents. The following table shows the effect
of these stock options on the weighted average number of shares outstanding used
in calculating diluted earnings per share (in millions):
2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
Average Common Shares Outstanding 322 320 202
Assumed Exercise of Stock Options 3 2 2
- -------------------------------------------------------------------------------------------------------------------
Average Dilutive Common Shares Outstanding 325 322 204
- -------------------------------------------------------------------------------------------------------------------
Stock options not included in average common shares used in calculating
diluted earnings per share due to their antidilutive effect were approximately
five million, five million and 30,000 for 2002, 2001 and 2000, respectively.
8. Accounts Receivable
Accounts Receivable -- Customer at December 31, 2002 and 2001 included
unbilled operating revenues of $442 million and $438 million, respectively. The
allowance for uncollectible accounts at December 31, 2002 and 2001 was $132
million and $213 million, respectively.
PECO is party to an agreement with a financial institution under which it
can sell or finance with limited recourse an undivided interest, adjusted daily,
in up to $225 million of designated accounts receivable until November 2005. At
December 31, 2002, PECO had sold a $225 million interest in accounts receivable,
consisting of a $164 million interest in accounts receivable which PECO
accounted for as a sale under SFAS No. 140, "Accounting for Transfers and
Servicing of Financial Assets and Extinguishment of Liabilities - a Replacement
of FASB Statement No. 125," and a $61 million interest in special-agreement
accounts receivable which was accounted for as a long-term note payable (see
Note 13 - Long-Term Debt). PECO retains the servicing responsibility for these
receivables. The agreement requires PECO to maintain the $225 million interest,
which, if not met, requires cash, which would otherwise be received by PECO
under this program, to be held in escrow until the requirement is met. At
December 31, 2002 and 2001, PECO met this requirement and was not required to
make any cash deposits.
101
9. Property, Plant, and Equipment
A summary of property, plant and equipment by classification as of December
31, 2002 and 2001 is as follows:
Asset Category 2002 2001
- -------------------------------------------------------------------------------------------------------------------
Electric-Transmission and Distribution $ 10,980 $ 10,156
Electric-Generation 5,678 4,344
Gas 1,319 1,281
Common 404 399
Nuclear Fuel 3,112 2,681
Construction Work in Progress 2,783 1,294
Other Property, Plant and Equipment 1,628 1,371
- -------------------------------------------------------------------------------------------------------------------
Total Property, Plant and Equipment 25,904 21,526
Less Accumulated Depreciation (including accumulated
amortization of nuclear fuel of $2,212 and $1,838 as of
December 31, 2002 and 2001, respectively) 8,770 7,735
- -------------------------------------------------------------------------------------------------------------------
Property, Plant and Equipment, net $ 17,134 $13,791
- -------------------------------------------------------------------------------------------------------------------
10. Jointly Owned Electric Utility Plant
Exelon's undivided ownership interests in jointly owned electric plant at
December 31, 2002 and 2001 were as follows:
Production Plant
------------------------------------------------------------------------- Transmission
December 31, 2002 Peach Bottom Salem Keystone Conemaugh Quad Cities and Other Plant
- ---------------------------------------------------------------------------------------------------------------------
Operator Generation PSE&G Reliant Reliant Generation Various Co.
Participating Interest 50% 42.59% 20.99% 20.72% 75% 21 to 44%
Exelon's Share:
Plant $ 417 $ 44 $ 131 $ 214 $ 171 $ 58
Accumulated Depreciation 243 12 117 145 4 22
Construction Work
in Progress 52 36 28 1 35 --
- ---------------------------------------------------------------------------------------------------------------------
102
Production Plant
------------------------------------------------------------------------- Transmission
December 31, 2001 Peach Bottom Salem Keystone Conemaugh Quad Cities and Other Plant
- ----------------------------------------------------------------------------------------------------------------------
Operator Generation PSE&G Reliant Reliant Generation Various Co.
Participating Interest 50% 42.59% 20.99% 20.72% 75% 21 to 44%
Exelon's Share:
Plant $ 387 $ 12 $ 121 $ 193 $ 96 $ 66
Accumulated Depreciation 220 4 98 124 10 25
Construction Work
in Progress 13 53 13 12 52 1
- ---------------------------------------------------------------------------------------------------------------------
Exelon's undivided ownership interests are financed with Exelon funds and,
when placed in service, all operations are accounted for as if such
participating interests were wholly owned facilities. Direct expenses of the
jointly owned plants are included in the corresponding operating expenses on the
Consolidated Income Statements.
11. Nuclear Decommissioning and Spent Fuel Storage
Exelon has an obligation to decommission its nuclear power plants. Exelon's
current estimate of its nuclear facilities' decommissioning cost for its owned
nuclear power plants is $7.4 billion in current year (2003) dollars. Based on
the extended license lives of the nuclear plants, expenditures are expected to
occur primarily when the operating plants are decommissioned, during the period
2029 through 2056. Decommissioning costs are currently recoverable through
regulated rates. Under rates in effect through December 31, 2002, Exelon
collected approximately $102 million in 2002 from customers. At December 31,
2002, the decommissioning liability, recorded in Accumulated Depreciation and
Deferred Credits and Other Liabilities on Exelon's Consolidated Balance Sheets,
was $2.8 billion and $1.4 billion, respectively. At December 31, 2001, the
decommissioning liability, recorded in Accumulated Depreciation and Deferred
Credits and Other Liabilities on Exelon's Consolidated Balance Sheets, was $2.7
billion and $1.4 billion, respectively. In order to fund future decommissioning
costs, at December 31, 2002 and 2001, Exelon held $3.1 billion and $3.2 billion,
respectively, in trust accounts that are included as Investments in Exelon's
Consolidated Balance Sheets at their fair market value. Exelon believes that the
amounts being recovered from customers through regulated rates and earnings on
nuclear decommissioning trust funds will be sufficient to fully fund its
decommissioning obligations.
In connection with the transfer of ComEd's nuclear generating stations to
Generation, ComEd asked the ICC to approve the continued recovery of
decommissioning costs after the transfer. On December 20, 2000, the ICC issued
an order finding that the ICC has the legal authority to permit ComEd to
continue to recover decommissioning costs from customers for the six-year term
of the power purchase agreements between ComEd and Generation. Under the ICC
order, ComEd is permitted to recover $73 million per year from customers for
decommissioning for the years 2001 through 2004. In 2005 and 2006, ComEd can
recover up to $73 million annually, depending upon the portion of the output of
the former ComEd nuclear stations that ComEd purchases from Generation. Under
the ICC order, subsequent to 2006, there will be no further recoveries of
decommissioning costs from customers. The ICC order also provides that any
surplus funds after the nuclear stations are decommissioned must be refunded to
customers. The amount of recovery in the ICC order is less than the $84 million
annual amount ComEd recovered in 2000. The ICC order has been upheld on appeal
in the Illinois Appellate Court and the Illinois Supreme Court has declined to
review the Appellate Court's decision.
To account for the effects of the ICC order, in the first quarter of 2001
ComEd reduced its nuclear decommissioning regulatory asset to $372 million,
reflecting the reduction in expected probable future recoveries from customers
through 2006. The reduction in the regulatory asset in the amount of $347
million was recorded as an adjustment to the initial Merger purchase price
allocation and resulted in a corresponding increase in goodwill. Also, ComEd
recorded an obligation to Generation of approximately
103
$440 million representing ComEd's legal requirement to remit funds to Generation
for the remaining regulatory asset amount of $372 million upon collection from
customers, and for collections from customers prior to the establishment of
external decommissioning trust funds in 1989 to be remitted to Generation for
deposit into the decommissioning trusts through 2006. Unrealized gains and
losses on decommissioning trust funds (based on the market value of the assets
on the Merger date, in accordance with purchase accounting) had previously been
recorded in accumulated depreciation or regulatory assets. As a result of the
transfer of the ComEd nuclear plants to Generation and the ICC order limiting
the regulated recoveries of decommissioning costs, net unrealized losses of $23
million (net of income taxes) at that date were reclassified to accumulated
other comprehensive income. All subsequent realized gains and losses on these
decommissioning trust funds' assets are based on the cost basis of the trust
fund assets established on the Merger date and are reflected in Other Income and
Deductions in Exelon's Consolidated Statements of Income.
Nuclear decommissioning costs associated with the nuclear generating
stations formerly owned by PECO continue to be recovered currently through rates
charged by PECO to regulated customers. These amounts are remitted to Generation
as allowed by the PUC. Under an agreement effective September 2001, PECO remits
$29 million per year to Generation related to nuclear decommissioning cost
recovery.
On December 31, 2002, PECO filed with the PUC for an annual increase in its
decommissioning cost recovery of $20 million effective June 1, 2004. The filing
is consistent with provisions in the Restructuring Settlement and the Merger
Settlement which require PECO to update the cost of decommissioning every five
years. The additional amount requested is expected to be reduced as it does not
reflect pending life extensions at Peach Bottom. The approval of the life
extensions is expected by mid-2003.
Under the Nuclear Waste Policy Act of 1982 (NWPA), the U.S. Department of
Energy (DOE) is responsible for the selection and development of repositories
for, and the disposal of, spent nuclear fuel (SNF) and high-level radioactive
waste. ComEd and PECO, as required by the NWPA, each signed contracts with the
DOE (Standard Contract) to provide for disposal of SNF from their respective
nuclear generating stations. In accordance with the NWPA and the Standard
Contract, ComEd and PECO pay the DOE one mill ($.001) per kilowatt-hour of net
nuclear generation for the cost of nuclear fuel long-term storage and disposal.
This fee may be adjusted prospectively in order to ensure full cost recovery.
The NWPA and the Standard Contract required the DOE to begin taking possession
of SNF generated by nuclear generating units by no later than January 31, 1998.
The DOE, however, failed to meet that deadline and its performance will be
delayed significantly. The DOE's current estimate for opening a SNF facility is
2010. This extended delay in SNF acceptance by the DOE has led to Exelon's
adoption of dry storage at its Dresden, Quad Cities and Peach Bottom Units and
its consideration of dry storage at other units.
In July 1998, ComEd filed a complaint against the United States Government
(Government) in the United States Court of Federal Claims (Court) seeking to
recover damages caused by the DOE's failure to honor its contractual obligation
to begin disposing of SNF in January 1998. In August 2001, the Court granted
ComEd's motion for partial summary judgment for liability on ComEd's breach of
contract claim. In November 2001, the Government filed two partial summary
judgment motions relating to certain damage issues in the case as well as two
motions to dismiss claims other than ComEd's breach of contract claim. On August
30, 2002, after taking certain damages related to discovery, ComEd filed briefs
in response to the DOE's motions. The Court has postponed the time for the DOE
to file reply briefs while it entertains additional DOE discovery motions. This
litigation was assumed by Generation in the corporate restructuring.
In July 2000, PECO entered into an agreement with the DOE relating to
PECO's Peach Bottom nuclear generating unit to address the DOE's failure to
begin removal of SNF in January 1998 as required by the Standard Contract. Under
that agreement, the DOE agreed to provide PECO with credits against PECO's
future contributions to the Nuclear Waste Fund over the next ten years to
compensate PECO for SNF storage costs incurred as a result of the DOE's breach
of the contract. The agreement also provides
104
that, upon PECO's request, the DOE will take title to the SNF and the interim
storage facility at Peach Bottom provided certain conditions are met. Generation
assumed this contract in restructuring.
In November 2000, eight utilities with nuclear power plants filed a Joint
Petition for Review against the DOE with the United States Court of Appeals for
the Eleventh Circuit seeking to invalidate that portion of the agreement
providing for credits to PECO against nuclear waste fund payments on the ground
that such provision is a violation of the NWPA. PECO intervened as a defendant
in that case, and Generation assumed the claim in the 2001 corporate
restructuring. On September 24, 2002, the United States Court of Appeals for the
Eleventh Circuit ruled that the fee adjustment provision of the agreement
violates the NWPA and therefore is null and void. The Court did not hold that
the agreement as a whole is invalid. Article XVI(I) of the Amendment provides
that if any portion of the Amendment is found to be void, the DOE and Generation
agree to negotiate in good faith and attempt to reach an enforceable agreement
consistent with the spirit and purpose of this Amendment. That provision further
provides that should a major term be declared void, and the DOE and Generation
cannot reach a subsequent agreement, the entire Amendment would be rendered null
and void, the original Peach Bottom Standard Contract would remain in effect and
the parties would return to pre-Amendment status. Pursuant to Article XIV(I),
Generation has begun negotiations with the DOE and those negotiations are
ongoing. Under the agreement, Generation has received approximately $40 million
in credits against contributions to the nuclear waste fund.
In April 2001, an individual filed suit against the DOE with the United
States District Court for the Middle District of Pennsylvania seeking to
invalidate the agreement on the grounds that the DOE has violated the National
Environmental Policy Act and the Administrative Procedure Act. PECO intervened
as a defendant and moved to dismiss the complaint. Generation assumed the
defense in restructuring. On September 30, 2002, the Court granted Generation's
motion and dismissed the lawsuit on the ground that the Court did not have
jurisdiction over the matter.
The Standard Contract with the DOE also requires that PECO and ComEd pay
the DOE a one-time fee applicable to nuclear generation through April 6, 1983.
PECO's fee has been paid. Pursuant to the Standard Contract, ComEd elected to
pay the one-time fee of $277 million, with interest to the date of payment, just
prior to the first delivery of SNF to the DOE. As of December 31, 2002, the
unfunded liability for the one-time fee with interest was $858 million. The
liabilities for spent nuclear fuel disposal costs, including the one-time fee,
were transferred to Generation as part of the corporate restructuring.
12. Notes Payable
2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
Average borrowings $ 337 $ 193 $ 186
Average interest rates, computed on daily basis 1.94% 4.01% 6.62%
Maximum borrowings outstanding $ 783 $ 599 $ 500
Average interest rates, at December 31 1.88% 2.63% 7.18%
- -------------------------------------------------------------------------------------------------------------------
Exelon, ComEd, PECO and Generation entered into a $1.5 billion unsecured
revolving credit facility on November 22, 2002 with a group of banks. Under the
credit facility, each borrower may borrow up to a designated sublimit amount on
a revolving credit basis through November 20, 2003. This credit facility
includes a term-out option that allows any outstanding borrowings at the end of
the revolving credit period to be repaid on November 21, 2004. This credit
facility is used principally to support the commercial paper programs of Exelon,
ComEd, PECO and Generation. At December 31, 2002, the amount of commercial paper
outstanding was $681 million which does not include $267 million that has been
classified as long-term debt. At December 31, 2001, the amount of commercial
paper outstanding was $360 million. Interest rates on the advances under the
credit facility are based on the London Interbank Offering Rate (LIBOR) as of
the date of the advance.
105
13. Long-Term Debt
December 31,
------------------------------------------------------------
Maturity
Rates Date 2002 2001
- -------------------------------------------------------------------------------------------------------------------
Securitized Long-Term Debt
ComEd Transitional Trust Notes
Series 1998-A: 5.39%-5.74% 2003-2008 $ 2,040 $ 2,380
PETT Bonds Series 1999-A:
Fixed rates 5.63%-6.13% 2003-2008 (a) 2,426 2,577
Floating rates 1.48%-1.55% 2004-2007 (a) 274 310
PETT Bonds Series 2000-A: 7.63%-7.65% 2009 (a) 750 890
PETT Bonds Series 2001: 6.52% 2010 (a) 805 805
Other Long-Term Debt
First and Refunding Mortgage Bonds (b) (c):
Fixed rates 4.4%-9.875% 2003-2023 3,614 3,942
Floating rates 1.08%-1.41% 2012-2013 254 154
Notes payable and other 6.40%-9.20% 2003-2020 2,393 2,651
SBG Facility 6.37%(d) 2007 1,036 --
Pollution control notes:
Fixed rates 5.2%-6.95% 2007-2034 199 44
Floating rates 1.05%-1.50% 2009-2034 456 583
Notes payable - accounts receivable agreement 1.42% 2005 61 55
Sinking fund debentures 3.125%-4.75% 2004-2011 20 23
Commercial Paper (e) 1.88% (f) 2003 267 --
- -------------------------------------------------------------------------------------------------------------------
Total Long-Term Debt (g) 14,595 14,414
Unamortized debt discount and premium, net (107) (129)
Fair value hedge carrying value adjustment 41 --
Due within one year (1,402) (1,406)
- -------------------------------------------------------------------------------------------------------------------
Long-Term Debt $ 13,127 $ 12,879
- -------------------------------------------------------------------------------------------------------------------
(a) The maturity date represents the expected final payment date which is the
date when all principal and interest of the related class of transition
bonds is expected to be paid in full in accordance with the expected
amortization schedule for the applicable class. The date when all principal
and interest must be paid in full for the PETT Bonds Series 1999-A, 2000-A
and 2001-A are 2003 through 2009, 2010 and 2010, respectively. The current
portion of transition bonds is based upon the expected maturity date.
(b) Utility plant of ComEd and PECO is subject to the liens of their respective
mortgage indentures. (c) Includes first mortgage bonds issued under the
ComEd and PECO mortgage indentures securing pollution
control notes.
(d) The rate for the SBG Facility is stated as an average rate. Under the terms
of the SBG Facility, SBG is required to effectively fix the interest rate
on 50% of the borrowings under the facility through its maturity in 2007.
The SBG Facility is subject to a variable rate based on the LIBOR rate plus
a margin of 1.375%, however, through the required interest rate swaps, SBG
has effectively fixed the LIBOR component of the interest rate at 5.73% on
83% of the debt balance as of December 31, 2002.
(e) Classified as long-term at December 31, 2002 since it was refinanced with
long-term debt in January 2003.
(f) Average interest rate of commercial paper outstanding at December 31, 2002.
(g) Long-term debt maturities in the period 2003 through 2007 and thereafter
are as follows:
2003 $ 1,669
2004 962
2005 1,313
2006 1,273
2007 1,172
Thereafter 8,206
-----------------
Total $14,595
-----------------
2003 maturities include $267 million of commercial paper classified as
long-term debt (see Note 23 - Subsequent Events).
106
In 2002, ComEd issued $700 million of long-term debt primarily consisting
of the issuance of $600 million of 6.15% First Mortgage Bonds, Series 98, due
March 15, 2012 and the issuance of $100 million of Illinois Development Finance
Authority floating-rate Pollution Control Revenue Refunding Bonds, Series 2002
due April 15, 2013. In 2002, ComEd redeemed or paid at maturity $1,540 million
of long-term debt primarily consisting of the redemption of $100 million of
7.25% Illinois Development Finance Authority Pollution Control Revenue Refunding
Bonds, Series 1991 due June 1, 2011, the redemption of $200 million of 8.625%
First Mortgage Bonds, Series 81, due February 1, 2022, the redemption of $200
million of 8.5% First Mortgage Bonds, Series 84 due July 15, 2022, the payment
at maturity of $200 million of 7.375% First Mortgage Bonds, Series 85, due
September 15, 2002, the redemption of $200 million of 8.375% First Mortgage
Bonds, Series 86, due September 15, 2022, the payment at maturity of $200
million of variable rate senior notes due September 30, 2002, the payment at
maturity of $100 million of 9.17% medium-term notes due October 15, 2002, and
the retirement of $340 million in transitional trust notes.
In 2002, Generation exchanged $700 million of 6.95% Senior Notes issued in
2001 for notes which are registered under the Securities Act. ComEd exchanged
$600 million of 6.15% First Mortgage Bonds, Series 98, due March 15, 2012, for
bonds which are registered under the Securities Act. PECO exchanged $250 million
of 5.95% private placement First and Refunding Mortgage Bonds, due November 1,
2011, for bonds which are registered under the Securities Act. The exchange
bonds are identical to the outstanding bonds except for the elimination of
certain transfer restrictions and registration rights pertaining to the
outstanding bonds. ComEd, PECO and Generation did not receive any cash proceeds
from issuance of the exchange bonds.
In 2002 and 2001, ComEd entered into forward starting interest rate swaps
with an aggregate notional amount of $830 million and $250 million,
respectively, to manage interest rate exposure associated with anticipated debt
issuance. In 2002, forward starting interest rate swaps with an aggregate
notional amount of $450 million were settled with net proceeds to counterparties
of $10 million that has been deferred in regulatory assets and is being
amortized over the life of the First Mortgage Bonds as an increase to interest
expense.
In 2002 and 2001, ComEd entered into interest rate swap agreements with a
notional amount of $250 million and $235 million, respectively, to effectively
convert fixed rate debt to floating rate debt.
In 2002, PECO issued $225 million of 4.75% First and Refunding Mortgage
Bonds, due October 1, 2012. This bond issuance repaid commercial paper that was
used to pay $222 million of First and Refunding Mortgage Bonds at maturity with
a weighted average interest rate of 7.30%. In connection with the issuance of
the First and Refunding Mortgage Bonds, PECO settled forward starting interest
rate swaps in the aggregate notional amount of $200 million resulting in a $5
million pre-tax loss recorded in other comprehensive income, which is being
amortized over the expected remaining life of the related debt.
In 2001, ComEd redeemed $196 million of 9.875% First Mortgage Bonds, Series
75, due June 15, 2020 and retired $340 million in transitional trust notes.
In 2001, PECO Energy Transition Trust (PETT), a Delaware business trust and
a wholly owned subsidiary of PECO, refinanced $805 million of floating rate
Series 1999-A Transition Bonds through the issuance by PETT of fixed-rate
transition bonds (Series 2001-A Transition Bonds). The 2001-A Transition Bonds
are non-callable, fixed rate securities with an interest rate of 6.52%. The
Series 2001-A Transition Bonds have an expected final payment date of September
1, 2010 and a termination date of December 31, 2010. In connection with this
refinancing, PECO settled $318 million of forward starting interest rate swaps
resulting in a $6 million gain which is reflected in other income and deductions
due to the transaction no longer being probable. Also, in connection with this
refinancing, PECO settled a portion of the interest rate swaps and the remaining
portion of the forward starting interest rate swaps resulting in gains of $25
million, which were deferred and are being amortized over the expected remaining
lives of the related debt.
In 1999, PECO entered into treasury forwards associated with the
anticipated issuance of the Series 2000-A Transition Bonds. On May 2, 2000,
these instruments were settled with net proceeds to
107
the counterparties of $13 million that has been deferred and is being amortized
over the life of the Series 2000-A Transition Bonds as an increase to interest
expense.
In 1998, PECO entered into treasury forwards and forward starting interest
rate swaps to manage interest rate exposure associated with the anticipated
issuance of the Series 1999-A Transition Bonds. On March 18, 1999, these
instruments were settled with net proceeds of $80 million to PECO that were
deferred and are being amortized over the life of the Series 1999-A Transition
Bonds as a reduction of interest expense.
At December 31, 2002 and 2001, the aggregate unamortized net gain on the
settlement of the PECO swap transactions was $36 million and $55 million,
respectively, recorded in Other Comprehensive Income.
ComEd prepayment premiums of $24 million, and net unamortized premiums,
discounts and debt issuance expenses of $3 million, and prepayment premiums of
$39 million, offset by unamortized issuance premiums of $17 million associated
with the early retirement of debt in 2002 and 2001, respectively, have been
deferred in regulatory assets and will be amortized to interest expense over the
life of the related new debt issuance consistent with regulatory recovery. In
2000, PECO incurred charges aggregating $6 million ($4 million, net of tax) for
prepayment premiums and the write-offs of unamortized deferred financing costs
associated with the early retirement of debt that have been recorded in interest
expense.
14. Income Taxes
Income tax expense (benefit) is comprised of the following components:
For the Years Ended December 31,
-----------------------------------------------
2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
Included in operations:
Federal
Current $ 624 $ 880 $ 161
Deferred 250 (61) 163
Investment tax credit amortization (15) (14) (15)
State
Current 96 119 --
Deferred 43 7 30
- -------------------------------------------------------------------------------------------------------------------
$ 998 $ 931 $ 339
- -------------------------------------------------------------------------------------------------------------------
Included in cumulative effect of changes in accounting principles:
Federal
Deferred $ (87) $ 6 $ 13
State
Deferred (3) 2 3
- -------------------------------------------------------------------------------------------------------------------
$ (90) $ 8 $ 16
- -------------------------------------------------------------------------------------------------------------------
The effective income tax rate varies from the U.S. Federal statutory rate
principally due to the following:
108
For the Years Ended December 31,
------------------------------------------------
2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
U.S. Federal statutory rate 35.0% 35.0% 35.0%
Increase (decrease) due to:
Property basis differences (0.4) (0.2) 0.1
State income taxes, net of Federal income tax benefit 3.2 3.4 2.1
Amortization of investment tax credit (0.4) (0.5) (1.6)
Amortization of goodwill -- 1.9 0.9
Dividends on PECO Preferred Stock 0.1 0.2 0.4
Other, net (0.1) (0.1) 0.7
- -------------------------------------------------------------------------------------------------------------------
Effective income tax rate 37.4% 39.7% 37.6%
- -------------------------------------------------------------------------------------------------------------------
The tax effects of temporary differences giving rise to significant
portions of Exelon's deferred tax assets and liabilities as of December 31, 2002
and 2001 are presented below:
2002 2001
- -------------------------------------------------------------------------------------------------------------------
Deferred tax liabilities:
Plant basis difference $ 4,710 $ 4,630
Deferred gain on sale of plants 860 872
Deferred investment tax credit 212 222
Deferred debt refinancing costs 96 44
Tax deductible goodwill -- 2
Unrealized gain on derivative financial instruments -- 34
- -------------------------------------------------------------------------------------------------------------------
Total deferred tax liabilities 5,878 5,804
- -------------------------------------------------------------------------------------------------------------------
Deferred tax assets:
Decommissioning and decontamination obligations (607) (573)
Deferred pension and postretirement obligations (911) (382)
Tax deductible goodwill (95) --
Unrealized loss on derivative financial instruments (60) --
Other, net (208) (194)
- -------------------------------------------------------------------------------------------------------------------
Total deferred tax assets (1,881) (1,149)
- -------------------------------------------------------------------------------------------------------------------
Deferred income taxes (net) on the balance sheet $ 3,997 $ 4,655
- -------------------------------------------------------------------------------------------------------------------
In accordance with regulatory treatment of certain temporary differences,
Exelon has recorded a regulatory asset for recoverable deferred income taxes,
pursuant to SFAS No. 109, "Accounting for Income Taxes," of $661 million and
$701 million at December 31, 2002 and 2001, respectively. These recoverable
deferred income taxes include the deferred tax effects associated principally
with liberalized depreciation accounted for in accordance with the ratemaking
policies of the ICC and PUC, as well as the revenue impacts thereon, and assume
continued recovery of these costs in future rates.
Exelon's predecessor entities, Unicom and PECO, have years that are under
review at the audit or appeals level of the Internal Revenue Service (IRS) and
certain state authorities. These reviews by the governmental taxing authorities
are not expected to have an adverse impact on the financial condition or result
of operations at Exelon.
ComEd has taken certain tax positions, which have been disclosed to the
IRS, to defer the tax gain on the 1999 sale of its fossil generating assets. As
of December 31, 2002, a deferred tax liability of approximately $860 million
related to the fossil plant sale is reflected in Deferred Income Taxes on
Exelon's Consolidated Balance Sheets. ComEd's management believes an adequate
reserve for interest has been established in the event that such positions are
not sustained. Changes in IRS interpretations of existing tax authority or
challenges to ComEd's positions could have the impact of accelerating future
income tax payments and increasing interest expense above amounts reserved
related to the deferred tax
109
gain that becomes current. The Federal tax returns covering the period of the
1999 fossil plant sale are anticipated to be under IRS audit beginning in 2003.
Final resolution of this matter is not anticipated for several years.
As of December 31, 2002 and 2001, Exelon had recorded valuation allowances
of $13 million and $2 million, respectively.
15. Retirement Benefits
Exelon sponsors defined benefit pension plans and postretirement welfare
benefit plans applicable to essentially all ComEd, PECO, Generation and Business
Services Company (BSC) employees and certain employees of Enterprises. In 2001,
Exelon consolidated the former Unicom and PECO plans into Exelon plans.
Essentially all management employees, and electing union employees, hired on or
after January 1, 2001 participate in newly established cash balance pension
plans. Approximately 4,700 management employees who were active participants in
the former Unicom and PECO pension plans on December 31, 2000, and remained
employed by Exelon on January 1, 2002 elected to transfer to the cash balance
plan. Benefits under Exelon's pension plans generally reflect each employee's
compensation, years of service and age at retirement. Funding is based upon
actuarially determined contributions that take into account the amount
deductible for income tax purposes and the minimum contribution required under
the Employee Retirement Income Security Act of 1974, as amended. The following
tables provide a reconciliation of benefit obligations, plan assets and funded
status of the plans.
110
Pension Benefits Other Postretirement Benefits
------------------------------------------------------------
2002 2001 2002 2001
- -------------------------------------------------------------------------------------------------------------------
Change in benefit obligation:
Net benefit obligation at beginning of year $ 7,101 $ 6,695 $ 2,331 $ 2,275
Service cost 95 94 57 42
Interest cost 525 498 160 161
Plan participants' contributions -- -- 8 4
Plan amendments 120 44 -- (191)
Actuarial (gain)/loss 514 254 155 173
Curtailments/Settlements -- (38) -- --
Special accounting costs 4 48 -- 3
Gross benefits paid (505) (494) (156) (136)
- -------------------------------------------------------------------------------------------------------------------
Net benefit obligation at end of year $ 7,854 $ 7,101 $ 2,555 $ 2,331
- -------------------------------------------------------------------------------------------------------------------
Change in plan assets:
Fair value of plan assets at beginning of year $ 6,279 $ 7,000 $ 1,132 $ 1,188
Actual return on plan assets (581) (265) (125) (14)
Employer contributions 202 38 73 90
Plan participants' contributions -- -- 8 4
Gross benefits paid (505) (494) (156) (136)
- -------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of year $ 5,395 $ 6,279 $ 932 $ 1,132
- -------------------------------------------------------------------------------------------------------------------
Funded status at end of year: $ (2,459) $ (822) $ (1,623) $ (1,199)
Miscellaneous adjustment (3) -- -- --
Unrecognized net actuarial (gain)/loss 2,118 397 793 440
Unrecognized prior service cost 211 108 (149) (191)
Unrecognized net transition obligation (asset) (11) (17) 102 103
- -------------------------------------------------------------------------------------------------------------------
Net amount recognized at end of year $ (144) $ (334) $ (877) $ (847)
- -------------------------------------------------------------------------------------------------------------------
Amounts recognized in statements of financial position:
Prepaid benefit cost $ 145 $ -- $ -- $ --
Accrued benefit cost (289) (334) (877) (847)
Additional minimum liability (1,815) -- -- --
Intangible asset 211 -- -- --
Accumulated other comprehensive income 1,604 -- -- --
- -------------------------------------------------------------------------------------------------------------------
Net amount recognized at end of year $ (144) $ (334) $ (877) $ (847)
- -------------------------------------------------------------------------------------------------------------------
111
Pension Benefits Other Postretirement Benefits
-----------------------------------------------------------------------------
2002 2001 2000 2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
Weighted-average assumptions
as of December 31,
Discount rate 6.75% 7.35% 7.60% 6.75% 7.35% 7.60%
Expected return on plan assets 9.50% 9.50% 9.50% 8.80% 8.80% 8.80%
Rate of compensation increase 4.00% 4.00% 4.30% 4.00% 4.00% 4.30%
Health care cost trend on
covered charges N/A N/A N/A 8.5% 10.00% 7.00%
decreasing decreasing decreasing
to ultimate to ultimate to ultimate
trend of 4.5% trend of 4.5% trend of 5.0%
in 2008 in 2008 in 2005
- -------------------------------------------------------------------------------------------------------------------
Pension Benefits Other Postretirement Benefits
-----------------------------------------------------------------------------
2002 2001 2000 2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
Components of net periodic
benefit cost (benefit):
Service cost $ 95 $ 94 $ 39 $ 57 $ 42 $ 24
Interest cost 525 498 219 160 161 83
Expected return on assets (628) (625) (316) (93) (99) (34)
Amortization of:
Transition obligation (asset) (4) (4) (4) 10 10 12
Prior service cost 16 9 7 (37) (9) --
Actuarial (gain) loss -- (25) (26) 6 1 --
Curtailment charge (credit) -- (12) (12) -- 9 24
Settlement charge (credit) -- (9) (16) -- -- --
- -------------------------------------------------------------------------------------------------------------------
Net periodic benefit cost (benefit) $ 4 $ (74) $ (109) $ 103 $ 115 $ 109
- -------------------------------------------------------------------------------------------------------------------
Special accounting costs $ 4 $ 48 $ 217 $ -- $ 3 $ 48
- -------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------
Sensitivity of retiree welfare results
Effect of a one percentage point increase in assumed health care cost trend
on total service and interest cost components $ 33
on postretirement benefit obligation $ 302
Effect of a one percentage point decrease in assumed health care cost trend
on total service and interest cost components $ (27)
on postretirement benefit obligation $ (252)
- -------------------------------------------------------------------------------------------------------------------
Prior service cost is amortized on a straight-line basis over the average
remaining service period of employees expected to receive benefits under the
plans.
Exelon's costs of providing pension and postretirement benefit plans are
dependent upon a number of factors, such as the rates of return on pension plan
assets, discount rate, and the rate of increase in health care costs. The market
value of plan assets has been affected by sharp declines in the equity market
since the third quarter of 2000. As a result, at December 31, 2002, Exelon was
required to recognize an additional minimum liability and an intangible asset as
prescribed by SFAS No. 87 "Employers' Accounting for Pensions." The liability
was recorded as a reduction to shareholders' equity, and the equity will be
restored to the balance sheet in future periods when the fair value of plan
assets exceeds the accumulated benefit obligations. The amount of the reduction
to shareholders' equity (net of income taxes) in 2002 was $1.0 billion. The
recording of this reduction did not affect net income or cash flow in 2002 or
compliance with debt covenants.
112
Special accounting costs of $4 million in 2002 and $48 million in 2001
represent accelerated separation and enhancement benefits provided to PECO
employees expected to be terminated as a result of the Merger. Special
accounting costs in 2000 of $217 million represented PECO's accelerated
separation and enhancement benefits of $96 million and ComEd's accelerated
liability increase of $121 million inclusive of $96 million for separation
benefits and $25 million for plan enhancements.
Exelon provides certain health care and life insurance benefits for retired
employees. In 2001, Exelon adopted an amendment to the former Unicom
postretirement medical benefit plan that changed the eligibility requirement of
the plan to cover only employees who retire with 10 years of service after age
45 rather than with 10 years of service and having attained the age of 55.
Welfare benefits for active employees are provided by several insurance policies
or self-funded plans whose premiums or contributions are based upon the benefits
paid during the year.
Exelon sponsors savings plans for the majority of its employees. The plans
allow employees to contribute a portion of their pretax income in accordance
with specified guidelines. Exelon matches a percentage of the employee
contribution up to certain limits. The cost of Exelon's matching contribution to
the savings plans totaled $63 million, $57 million and $17 million in 2002, 2001
and 2000, respectively.
16. Preferred Securities of Subsidiaries
Preferred and Preference Stock
At December 31, 2002 and 2001, cumulative Preferred Stock of PECO, no par
value, consisted of 15,000,000 shares authorized and the amounts set forth
below:
December 31,
--------------------------------------------------------------------------
Current 2002 2001 2002 2001
Redemption --------------------------------------------------------------------------
Price(a) Shares Outstanding Dollar Amount
- -------------------------------------------------------------------------------------------------------------------
Series (without mandatory
redemption)
$4.68 $ 104.00 150,000 150,000 $ 15 $ 15
$4.40 112.50 274,720 274,720 27 27
$4.30 102.00 150,000 150,000 15 15
$3.80 106.00 300,000 300,000 30 30
$7.48 (b) 500,000 500,000 50 50
- -------------------------------------------------------------------------------------------------------------------
1,374,720 1,374,720 137 137
Series (with mandatory
redemption)
$6.12 (c) -- 185,400 -- 19
- -------------------------------------------------------------------------------------------------------------------
Total preferred stock 1,374,720 1,560,120 $ 137 $ 156
- -------------------------------------------------------------------------------------------------------------------
(a) Redeemable, at the option of PECO, at the indicated dollar amounts per
share, plus accrued dividends.
(b) None of the shares of this series is subject to redemption prior to April
1, 2003.
(c) PECO made the annual sinking fund payments of $18.5 million on August 1,
2002 and August 1, 2001. At December 31, 2000, shares and principal
outstanding were 370,800 and $37 million, respectively.
113
At December 31, 2002 and 2001, ComEd Preferred Stock and ComEd Preference
Stock consisted of 850,000 and 6,810,451 shares authorized, respectively, none
of which were outstanding.
Company Obligated Mandatorily Redeemable Preferred Securities
At December 31, 2002 and 2001, subsidiary trusts of PECO and ComEd had
outstanding the following preferred securities:
December 31,
----------------------------------------------------
Mandatory Distri- Liqui- 2002 2001 2002 2001
Redemption bution dation -------------------------- -------------------------
Date Rate Value Trust Securities Outstanding Dollar Amount
- -------------------------------------------------------------------------------------------------------------------
PECO Energy
Capital Trust II 2037 8.00% $ 25 2,000,000 2,000,000 $ 50 $ 50
PECO Energy
Capital Trust III 2028 7.38% 1,000 78,105 78,105 78 78
- -------------------------------------------------------------------------------------------------------------------
Total 2,078,105 2,078,105 $ 128 $ 128
- -------------------------------------------------------------------------------------------------------------------
ComEd Financing I 2035 8.48% $ 25 8,000,000 8,000,000 $ 200 $ 200
ComEd Financing II 2027 8.50% 1,000 150,000 150,000 150 150
Unamortized Discount (20) (21)
- -------------------------------------------------------------------------------------------------------------------
Total 8,150,000 8,150,000 $ 330 $ 329
- -------------------------------------------------------------------------------------------------------------------
The securities issued by the PECO trusts represent Company Obligated
Mandatorily Redeemable Preferred Securities of a Partnership (COMRPS) having a
distribution rate and liquidation value equivalent to the trust securities. The
COMRPS are the sole assets of these trusts and represent limited partnership
interests of PECO Energy Capital, L.P. (Partnership), a Delaware limited
partnership. Each holder of a trust's securities is entitled to withdraw the
corresponding number of COMRPS from the trust in exchange for the trust
securities so held. Each series of COMRPS is supported by PECO's deferrable
interest subordinated debentures, held by the Partnership, which bear interest
at rates equal to the distribution rates on the related series of COMRPS.
ComEd Financing I and ComEd Financing II are wholly owned subsidiary trusts
of ComEd. Each of ComEd trust's sole assets are subordinated deferrable interest
securities issued by ComEd bearing interest rates equivalent to the distribution
rate of the related trust security.
The preferred securities issued by each of ComEd Financing I and ComEd
Financing II have no voting privileges, except (i) for the right to approve a
merger, consolidation or other transaction involving the applicable trust that
would result in certain United States Federal income tax consequences to that
trust, (ii) with respect to certain amendments to the applicable trust
agreement, (iii) for certain voting privileges that arise upon an event of
default under the applicable trust agreement or (iv) with respect to certain
amendments to the related ComEd guarantee agreement.
The interest expense on the debentures and deferrable interest securities
is included in Distributions on Preferred Securities of Subsidiaries in the
Consolidated Statements of Income and is deductible for income tax purposes.
17. Common Stock
At December 31, 2002 and 2001, common stock without par value consisted of
600,000,000 and 600,000,000 shares authorized and 323,312,586 and 321,006,904
shares outstanding, respectively.
Stock Repurchase
In January 2000, in connection with the Merger Agreement, PECO entered into
a forward purchase agreement to purchase $500 million of its common stock from
time to time. Settlement of this forward purchase agreement was, at PECO's
election, on a physical, net share or net cash basis. In May 2000, PECO utilized
a portion of the proceeds from the securitization of its stranded cost recovery
to
114
physically settle this agreement, resulting in the repurchase of 12 million
shares of common stock for $496 million. In connection with the settlement of
this agreement, PECO received $1 million in accumulated dividends on the
repurchased shares and paid $6 million of interest.
Stock-Based Compensation Plans
Exelon maintains a Long-Term Incentive Plan (LTIP) for certain full-time
salaried employees and previously maintained a broad-based incentive program for
certain other employees. The types of long-term incentive awards that have been
granted under the LTIP are non-qualified options to purchase shares of Exelon's
common stock and common stock awards. At December 31, 2002, there were
13,000,000 options authorized for issuance under the LTIP and 2,000,000 options
authorized under the broad-based incentive program.
The exercise price of the stock options is equal to the fair market value
of the underlying stock on the date of option grant. Options granted under the
LTIP and the broad-based incentive program become exercisable upon attainment of
a target share value and/or time. All options expire 10 years from the date of
grant. Information with respect to the LTIP and the broad-based incentive
program at December 31, 2002 and changes for the three years then ended, is as
follows:
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Price Price Price
Shares (per share) Shares (per share) Shares (per share)
2002 2002 2001 2001 2000 2000
- -------------------------------------------------------------------------------------------------------------------
Balance at January 1 14,039,996 $ 43.96 15,287,859 $ 42.13 6,065,897 $ 31.91
Options granted/assumed 3,938,632 47.12 629,200 66.42 11,089,051 (a) 46.09
Options exercised (1,821,339) 33.37 (1,695,474) 34.84 (1,725,058) 31.79
Options canceled (270,299) 53.62 (181,589) 52.64 (142,031) 39.95
- -------------------------------------------------------------------------------------------------------------------
Balance at December 31 15,886,990 45.80 14,039,996 43.96 15,287,859 42.13
- -------------------------------------------------------------------------------------------------------------------
Exercisable at
December 31 10,491,184 43.96 8,006,193 38.75 4,953,942 30.04
- -------------------------------------------------------------------------------------------------------------------
Weighted average fair value
of options granted during year $ 13.62 $ 19.59 $ 16.62
- -------------------------------------------------------------------------------------------------------------------
(a) Includes 5.3 million options converted in the Merger.
The fair value of each option is estimated on the date of grant using
the Black-Scholes option-pricing model with the following weighted average
assumptions used for grants in 2002, 2001 and 2000, respectively:
2002 2001 2000
- -------------------------------------------------------------------------------
Dividend yield 3.3% 3.2% 3.6%
Expected volatility 36.8% 36.8% 36.8%
Risk-free interest rate 4.6% 4.9% 5.9%
Expected life (years) 5.0 5.0 5.0
- -------------------------------------------------------------------------------
115
At December 31, 2002, the options outstanding, based on ranges of exercise
prices, were as follows:
Options Outstanding Options Exercisable
------------------- -------------------
Weighted
Average
Remaining Weighted Weighted
Contractual Average Average
Range of Number Life Exercise Number Exercise
Exercise Prices Outstanding (years) Price Exercisable Price
- -------------------------------------------------------------------------------------------------------------------
$10.01-$20.00 560,700 6.14 $ 19.68 560,700 $ 19.68
$20.01-$30.00 926,332 4.64 25.49 926,332 25.49
$30.01-$40.00 4,668,877 7.53 37.87 4,031,683 37.76
$40.01-$50.00 4,844,505 9.39 45.61 1,419,748 42.25
$50.01-$60.00 4,265,109 8.84 59.39 3,159,481 59.47
$60.01-$70.00 621,467 9.03 67.32 393,240 67.28
- -------------------------------------------------------------------------------------------------------------------
Total 15,886,990 10,491,184
- -------------------------------------------------------------------------------------------------------------------
Exelon common stock awards under Exelon's LTIP of 316,025 shares were
issued during 2000 and 1999. Vesting for the common stock awards is over a
period not to exceed 10 years from the grant date. Compensation cost of $14
million associated with these awards is amortized to expense over the vesting
period. The related accumulated amortization of $13 million includes
amortization expense of approximately $1 million, $5 million and $5 million
during 2002, 2001 and 2000, respectively.
Exelon common share awards of 590,074, 426,794 and 159,129 shares were
granted under Exelon's LTIP and board compensation plans during 2002, 2001 and
2000, respectively. Total accumulated compensation cost of $60 million is to be
accrued to expense over the vesting period of up to 5 years from the grant date.
The related accumulated amortization of $37 million includes amortization
expense of $20 million, $11 million and $6 million during 2002, 2001 and 2000,
respectively.
In June 2001, the Board of Directors of Exelon approved the Employee Stock
Purchase Plan (ESPP). The purpose of the ESPP is to provide employees of Exelon,
and its subsidiary companies the right to purchase shares of Exelon's common
stock at below-market prices. A total of 3,000,000 shares of Exelon's common
stock have been reserved for issuance under the ESPP. Employees' purchases are
limited to no more than 125 shares per quarter and no more than $25,000 in fair
market value in any plan year. Employees purchased 257,455 and 137,648 shares of
Exelon common stock under the ESPP in 2002 and 2001, respectively.
Fund Transfer Restrictions Under PUHCA
Under PUHCA, Exelon is precluded from borrowing or receiving any extension
of credit or indemnity from its subsidiaries and can lend, but not borrow, from
Exelon's intercompany money pool. Additionally, under PUHCA, Exelon, ComEd, PECO
and Generation can pay dividends only from retained, undistributed or current
earnings. However, the SEC order granted permission to ComEd, and to Exelon to
the extent we receive dividends from ComEd paid from ComEd additional
paid-in-capital, to pay up to $500 million in dividends out of additional
paid-in capital, although Exelon may not pay dividends out of paid-in capital
after December 31, 2002 if its ratio of common equity to total capitalization is
less than 30%. At December 31, 2002, Exelon had retained earnings of $2.0
billion, which includes ComEd retained earnings of $577 million, PECO retained
earnings of $401 million and Generation undistributed earnings of $924 million.
In 2002, Exelon recorded a reduction to shareholders' equity of $1.0 billion
related to the minimum pension liability. At December 31, 2002, Exelon's common
equity to total capitalization ratio was 32%.
116
Undistributed Earnings of Equity Method Investments
At December 31, 2002, Exelon had consolidated undistributed earnings of
equity method investments of $145 million.
18. Fair Value of Financial Assets and Liabilities
The carrying amounts and fair values of Exelon's financial assets and
liabilities as of December 31, 2002 and 2001 were as follows:
2002 2001
------------------------------ ------------------------------
Carrying Carrying
Amount Fair Value Amount Fair Value
- -------------------------------------------------------------------------------------------------------------------
Non-derivatives:
Liabilities
Long-term debt (including
amounts due within one year) $ 14,529 $ 15,950 $ 14,285 $ 14,912
Preferred Securities of Subsidiaries 595 739 613 572
Derivatives:
Fixed to floating interest rate swaps 41 41 (20) (20)
Floating to fixed interest rate swaps (114) (114) -- --
Forward starting interest rate swaps (52) (52) (1) (1)
Energy derivatives (143) (143) 78 78
- -------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents, customer accounts receivable and trust accounts
for decommissioning nuclear plants are recorded at their fair value.
As of December 31, 2002 and 2001, Exelon's carrying amounts of cash and
cash equivalents and accounts receivable are representative of fair value
because of the short-term nature of these instruments. Fair values of the trust
accounts for decommissioning nuclear plants, long-term debt and preferred
securities of subsidiaries are estimated based on quoted market prices for the
same or similar issues. The fair value of Exelon's interest rate swaps and power
purchase and sale contracts is determined using quoted exchange prices, external
dealer prices, or internal valuation models which utilize assumptions of future
energy prices and available market pricing curves.
Financial instruments that potentially subject Exelon to concentrations of
credit risk consist principally of cash equivalents and customer accounts
receivable. Exelon places its cash equivalents with high-credit quality
financial institutions. Generally, such investments are in excess of the Federal
Deposit Insurance Corporation limits. Concentrations of credit risk with respect
to customer accounts receivable are limited due to Exelon's large number of
customers and, in the case of the Energy Delivery business, their dispersion
across many industries.
Exelon has entered into fixed to floating interest rate swaps in the
aggregate amount of $485 million of fixed-rate obligations of ComEd. These swaps
have been designated as fair-value hedges, as defined in SFAS No. 133 and as
such, changes in the fair value of the swap will be recorded in earnings.
However, as long as the hedges remain effective and the underlying transaction
remains probable, changes in the fair value of the swaps will be offset by
changes in the fair value of the hedged liabilities. Any change in the fair
value of the hedges as a result of ineffectiveness would be recorded immediately
in earnings. The fair market value of these swaps was $41 million at December
31, 2002.
117
Under the terms of the SBG credit facility, SBG is required to effectively
fix the interest rate on 50% of the borrowings under the facility through its
maturity in 2007. As of December 31, 2002, Generation has entered into floating
to fixed interest rate swap agreements which have effectively fixed the interest
rate on $861 million of notional principal, or 83% of borrowings outstanding at
December 31, 2002. These swaps have been designated as cash flow hedges under
SFAS No. 133, and as such, as long as the hedge remains effective and the
underlying transaction remains probable, changes in the fair value of these
swaps will be recorded in accumulated other comprehensive income (loss) until
earnings are affected by the variability of the cash flows being hedged. The
fair market value exposure of these swaps was $92 million at December 31, 2002.
Exelon has also entered into floating to fixed interest rate swaps to
manage interest rate exposure associated with the floating rate series of
transition bonds issued to securitize PECO's stranded cost recovery. These
interest rate swaps were designated as cash flow hedges. These interest rate
swaps had an aggregate fair market value exposure of $22 million at December 31,
2002.
PECO also has interest rate swaps in place to satisfy counterparty credit
requirements in regards to the floating rate series of transition bonds which
are mirror swaps of each other. These swaps are not designated as cash flow
hedges, therefore, they are required to be marked-to-market if there is a
difference in their values. Since these swaps are offsetting each other, a
mark-to-market adjustment is not expected to occur.
During 2002, PECO entered into forward starting interest rate swaps, with
an aggregate notional amount of $200 million, in anticipation of the issuance of
debt at PECO. These interest rate swaps were designated as cash flow hedges. In
connection with bond issuances in 2002, PECO settled these forward starting
interest rate swaps resulting in a $5 million pretax loss recorded in other
comprehensive income, which is being amortized over the life of the related
debt.
During 2002 and 2001, ComEd entered into forward-starting interest rate
swaps, with an aggregate notional amount of $830 million and $250 million,
respectively, in anticipation of the issuance of debt. In connection with bond
issuances in 2002, ComEd settled forward starting interest rate swaps in the
aggregate notional amount of $450 million, resulting in a $10 million pre-tax
loss recorded as a regulatory asset, which is being amortized over the life of
the related debt in interest expense. At December 31, 2002, ComEd had $630
million of forward starting interest rate swaps outstanding. These interest rate
swaps, designated as cash flow hedges, had a fair market value exposure of $52
million at December 31, 2002. As it remained probable that the debt issuances,
the forecasted future transactions these swaps were hedging, would occur,
although the issuances had been delayed, we continued to account for these
interest rate swap transactions as hedges. In connection with ComEd's January
22, 2003 issuance of $700 million in First Mortgage Bonds, ComEd settled swaps,
in the aggregate notional amount of $550 million, for a payment of $43 million,
which will be recorded as a regulatory asset and amortized over the life of the
debt issuance.
The notional amount of derivatives does not represent amounts that are
exchanged by the parties and, thus, is not a measure of Exelon's exposure. The
amounts exchanged are calculated on the basis of the notional or contract
amounts, as well as on the other terms of the derivatives, which relate to
interest rates and the volatility of these rates.
Exelon utilizes derivatives to manage the utilization of its available
generating capacity and provision of wholesale energy to its affiliates. Exelon
also utilizes energy option contracts and energy financial swap arrangements to
limit the market price risk associated with forward energy commodity
118
contracts. Additionally, Exelon enters into certain energy-related derivatives
for trading or speculative purposes.
During 2002 and 2001, Generation recognized net losses of $6 million ($4
million, net of income taxes) and gains of $16 million ($10 million, net of
income taxes), respectively, relating to mark-to-market adjustments of certain
non-trading power purchase and sale contracts pursuant to SFAS No. 133.
Mark-to-market adjustments on non-trading power purchase and sale contracts are
reported in fuel and purchased power and mark-to-market adjustments on trading
activities are reported as Operating Revenues in the Consolidated Statements of
Income. During 2002 and 2001, Generation recognized net losses aggregating $9
million ($6 million, net of income taxes) and net gains aggregating $14 million
($10 million, net of income taxes), respectively, relating to mark-to-market
adjustments on derivative instruments entered into for trading purposes. Exelon
Generation commenced financial trading in the second quarter of 2001. Gains and
losses associated with financial trading are reported as Operating Revenue in
the Consolidated Statements of Income. During 2002 and 2001, no amounts were
reclassified from accumulated other comprehensive income into earnings as a
result of forecasted energy commodity transactions no longer being probable. For
2002, no amounts were reclassified from accumulated other comprehensive income
into earnings as a result of forecasted financing transactions no longer being
probable. For 2001, a $6 million gain ($4 million, net of income taxes) was
reclassified from accumulated other comprehensive income into earnings as a
result of forecasted financing transactions no longer being probable.
Enterprises has entered into a limited number of energy commodity
derivative contracts in connection with its service of gas customers. While the
majority of these contracts qualify as normal purchases and sales or as cash
flow hedges under SFAS No. 133, $16 million was recorded as a reduction to fuel
expense as a result of contracts being marked to market in 2002. Of this $16
million, $3 million was recorded upon contract settlement and $13 million was
recorded as a change in fair value prior to contract settlement. The offset to
this $13 million was recorded as an asset on the balance sheet and it is
expected that $11 million and $2 million will reverse as fuel expense in 2003
and 2004, respectively. At December 31, 2002, there was a net asset of $20
million on the balance sheet related to Enterprises' mark-to-market contracts.
The remaining $7 million of the offset to this asset was recorded in other
comprehensive income and is expected to be reclassified to earnings within the
next twelve months. Enterprises' counterparties in these contracts are all
investment grade, with the exception of Dynegy Inc. (Dynegy), to whom
Enterprises has $2 million of exposure.
On January 1, 2001, Exelon recognized a non-cash gain of $12 million, net
of income taxes, in earnings and deferred a non-cash gain of $44 million, net of
income taxes, in accumulated other comprehensive income, a component of
shareholders' equity, to reflect the initial adoption of SFAS No. 133, as
amended. SFAS No. 133 must be applied to all derivative instruments and requires
that such instruments be recorded in the balance sheet either as an asset or a
liability measured at their fair value through earnings, with special accounting
permitted for certain qualifying hedges.
As of December 31, 2002, $102 million of deferred net losses on derivative
instruments in accumulated other comprehensive income are expected to be
reclassified to earnings during the next twelve months. Amounts in accumulated
other comprehensive income related to interest rate cash flows are reclassified
into earnings when the forecasted interest payment occurs. Amounts in
accumulated other comprehensive income related to energy commodity cash flows
are reclassified into earnings when the forecasted purchase or sale of the
energy commodity occurs. The majority of Exelon's cash flow hedges are expected
to settle within the next 4 years.
Exelon would be exposed to credit-related losses in the event of
non-performance by the counterparties that issued the derivative instruments.
The credit exposure of derivatives contracts is
119
represented by the fair value of contracts at the reporting date. Exelon's
interest rate swaps are documented under master agreements. Among other things,
these agreements provide for a maximum credit exposure for both parties.
Payments are required by the appropriate party when the maximum limit is
reached. Generation has entered into payment netting agreements or enabling
agreements that allow for payment netting with the majority of its large
counterparties, which reduce Generation's exposure to counterparty risk by
providing for the offset of amounts payable to the counterparty against amounts
receivable from the counterparty.
Exelon classifies investments in the trust accounts for decommissioning
nuclear plants as available-for-sale. The following tables show the fair values,
gross unrealized gains and losses and amortized costs bases for the securities
held in these trust accounts.
December 31, 2002
-------------------------------------------------------------------
Gross Gross
Amortized Unrealized Unrealized Estimated
Cost Gains Losses Fair Value
- -------------------------------------------------------------------------------------------------------------------
Equity securities $ 1,763 $ 72 $ (482) $ 1,353
Debt securities
Government obligations 938 62 -- 1,000
Other debt securities 698 32 (30) 700
- -------------------------------------------------------------------------------------------------------------------
Total debt securities 1,636 94 (30) 1,700
- -------------------------------------------------------------------------------------------------------------------
Total available-for-sale securities $ 3,399 $ 166 $ (512) $ 3,053
- -------------------------------------------------------------------------------------------------------------------
December 31, 2001
-------------------------------------------------------------------
Gross Gross
Amortized Unrealized Unrealized Estimated
Cost Gains Losses Fair Value
- -------------------------------------------------------------------------------------------------------------------
Equity securities $ 1,666 $ 130 $ (236) $ 1,560
Debt securities
Government obligations 882 28 (3) 907
Other debt securities 701 16 (19) 698
- -------------------------------------------------------------------------------------------------------------------
Total debt securities 1,583 44 (22) 1,605
- -------------------------------------------------------------------------------------------------------------------
Total available-for-sale securities $ 3,249 $ 174 $ (258) $ 3,165
- -------------------------------------------------------------------------------------------------------------------
Net unrealized losses of $346 million and $84 million were recognized in
Accumulated Depreciation, Regulatory Assets and Accumulated Other Comprehensive
Income in Exelon's Consolidated Balance Sheets at December 31, 2002 and 2001,
respectively.
For the Years Ended December 31
-------------------------------
2002 2001
- --------------------------------------------------------------------------------
Proceeds from sales $ 1,612 $ 1,624
Gross realized gains 56 76
Gross realized losses (86) (189)
- --------------------------------------------------------------------------------
Net realized gains of $2 million and $14 million were recognized in
Accumulated Depreciation and Regulatory Assets in Exelon's Consolidated Balance
Sheets at December 31, 2002 and 2001, respectively, and $32 million and $127
million of net realized losses were recognized in Other Income and Deductions in
Exelon's Consolidated Income Statements for 2002 and 2001, respectively. The
available-for-sale securities held at December 31, 2002 have an average maturity
of six to seven years. The cost of these securities was determined on the basis
of specific identification. See Note 11 - Nuclear
120
Decommissioning and Spent Fuel Storage for further information regarding the
nuclear decommissioning trusts.
19. Commitments and Contingencies
Capital Commitments
Exelon and British Energy, Generation's joint venture partner in AmerGen,
have each agreed to provide up to $100 million to AmerGen at any time that the
Management Committee of AmerGen determines, that in order to protect the public
health and safety and/or to comply with NRC requirements, such funds are
necessary to meet ongoing operating expenses or to safely maintain any AmerGen
plant. Although Exelon does not anticipate that AmerGen will make any
acquisitions in 2003, Exelon has committed to provide AmerGen with capital
contributions equivalent to 50% of the purchase price of any acquisitions
AmerGen makes in 2003.
Generation has a 70% interest in the Southeast Chicago Energy Project, LLC
(Southeast Chicago), which owns a peaking facility in Chicago. Southeast Chicago
is obligated to make equity distributions of $54 million over the next 20 years
to the party, which is not affiliated with Generation, that owns the remaining
30% interest. This amount reflects a return of that party's investment in
Southeast Chicago. Generation has the right to purchase, generally at a premium,
and the other party has the right to require Generation to purchase, generally
at a discount, the 30% interest in Southeast Chicago. Additionally, Generation
may be required to purchase the 30% interest upon the occurrence of certain
events, including Generation's failure to maintain an investment grade rating.
Nuclear Insurance
The Price-Anderson Act limits the liability of nuclear reactor owners for
claims that could arise from a single incident. As of January 1, 2003, the
current limit is $9.5 billion and is subject to change to account for the
effects of inflation and changes in the number of licensed reactors. Through its
subsidiaries, Exelon carries the maximum available commercial insurance of $300
million and the remaining $9.2 billion is provided through mandatory
participation in a financial protection pool. Under the Price-Anderson Act, all
nuclear reactor licensees can be assessed up to $89 million per reactor per
incident, payable at no more than $10 million per reactor per incident per year.
This assessment is subject to inflation and state premium taxes. In addition,
the U.S. Congress could impose revenue-raising measures on the nuclear industry
to pay claims. The Price-Anderson Act expired on August 1, 2002 but existing
facilities, including those owned and operated by Generation, remain covered.
The U.S. Congress has extended the provisions of the Price-Anderson Act related
to commercial facilities through 2003. The extension was passed as part of the
Consolidated Appropriations Resolution, 2003, which will be presented to the
President of the United States for his signature. The extension would affect
facilities obtaining NRC operating licenses in 2003. Existing facilities are
unaffected by the extension.
Exelon carries property damage, decontamination and premature
decommissioning insurance for each station loss resulting from damage to its
nuclear plants. In the event of an accident, insurance proceeds must first be
used for reactor stabilization and site decontamination. If the decision is made
to decommission the facility, a portion of the insurance proceeds will be
allocated to a fund, which Exelon is required by the NRC to maintain, to provide
for decommissioning the facility. Exelon is unable to predict the timing of the
availability of insurance proceeds to Exelon and the amount of such proceeds
that would be available. Under the terms of the various insurance agreements,
Exelon could be assessed up to $124 million for losses incurred at any plant
insured by the insurance companies. In the event that one or more acts of
terrorism cause accidental property damage within a twelve month period from the
first accidental property damage under one or more policies for all insureds,
the maximum recovery for all losses by all insureds will be an aggregate of $3.2
billion plus such additional amounts as the insurer may recover for all such
losses from reinsurance, indemnity, and any other source, applicable to such
losses. The $3.2 billion maximum recovery limit is not applicable, however, in
the event of a "certified act of terrorism" as defined in the Terrorism Risk
Insurance Act of 2002, as a result of government indemnity. Generally, a
"certified act of terrorism" is defined in the Terrorism Risk Insurance Act to
be any act, certified by the U.S. government, to be an act of terrorism
committed on behalf of a foreign person or interest.
Additionally, through its subsidiaries, Exelon is a member of an industry
mutual insurance company that provides replacement power cost insurance in the
event of a major accidental outage at a nuclear station. The premium for this
coverage is subject to assessment for adverse loss experience.
121
Exelon's maximum share of any assessment is $46 million per year. Recovery under
this insurance for terrorist acts is subject to the $3.2 billion aggregate limit
and secondary to the property insurance described above. This limit would also
not apply in cases of certified acts of terrorism under the Terrorism Risk
Insurance Act as described above.
In addition, Exelon participates in the American Nuclear Insurers Master
Worker Program, which provides coverage for worker tort claims filed for bodily
injury caused by a nuclear energy accident. This program was modified, effective
January 1, 1998, to provide coverage to all workers whose "nuclear-related
employment" began on or after the commencement date of reactor operations.
Exelon will not be liable for a retrospective assessment under this new policy.
However, in the event losses incurred under the small number of policies in the
old program exceed accumulated reserves, a maximum retroactive assessment of up
to $50 million could apply.
Exelon is self-insured to the extent that any losses may exceed the amount
of insurance maintained. Such losses could have a material adverse effect on
Exelon's financial condition and results of operations.
Energy Commitments
Exelon's wholesale operations include the physical delivery and marketing
of power obtained through its generation capacity, and long, intermediate and
short-term contracts. Exelon maintains a net positive supply of energy and
capacity, through ownership of generation assets and power purchase and lease
agreements, to protect it from the potential operational failure of one of its
owned or contracted power generating units. Exelon has also contracted for
access to additional generation through bilateral long-term power purchase
agreements. These agreements are firm commitments related to power generation of
specific generation plants and/or are dispatchable in nature. Exelon enters into
power purchase agreements with the objective of obtaining low-cost energy supply
sources to meet its physical delivery obligations to its customers. Exelon has
also purchased firm transmission rights to ensure that it has reliable
transmission capacity to physically move its power supplies to meet customer
delivery needs. The primary intent and business objective for the use of its
capital assets and contracts is to provide Exelon with physical power supply to
enable it to deliver energy to meet customer needs. Exelon primarily uses
financial contracts in its wholesale marketing activities for hedging purposes.
Exelon also uses financial contracts to manage the risk surrounding trading for
profit activities.
Exelon has entered into bilateral long-term contractual obligations for
sales of energy to load-serving entities, including electric utilities,
municipalities, electric cooperatives, and retail load aggregators. Exelon also
enters into contractual obligations to deliver energy to wholesale market
participants who primarily focus on the resale of energy products for delivery.
Exelon provides delivery of its energy to these customers through access to its
transmission assets or rights for firm transmission.
Generation has power purchase agreements (PPAs) with Midwest Generation,
LLC (Midwest Generation) for the purchase of capacity from its coal-fired
stations through 2004. Contracted capacity and capacity available through the
exercise of an annual option are 1,696 MWs and 3,949 MWs in 2003 and 2004,
respectively.
The agreements also provide for the option to purchase 1,084 MWs of oil and
gas-fired capacity, and 857 MWs of peaking capacity, subject to reduction.
Generation has entered into PPAs with AmerGen, under which it will purchase
all the energy from Unit No. 1 at Three Mile Island Nuclear Station after
December 31, 2001 through December 31, 2014. Under a January 1, 2003 PPA,
Generation will purchase from AmerGen all of the residual energy from the
Clinton Nuclear Power Station (Clinton), through December 31, 2003. Currently,
the residual output is approximately 31% of the total output of Clinton. In
accordance with the terms of the AmerGen partnership agreement, the 2003 PPA
will be extended through the end of the AmerGen partnership agreement in 2006.
122
Exelon has a long-term supply agreement through December 2022 with
Distrigas of Massachusetts, LLC to guarantee physical gas supply to its New
England generating units. Under the agreement, prices are indexed to New England
gas markets. At December 31, 2002, Exelon had long-term commitments, relating to
the purchase and sale of energy, capacity and transmission rights from
unaffiliated utilities and others, including the Midwest Generation and AmerGen
contracts, as expressed in the following tables:
Net Capacity Power Only Power Only Purchases from Transmission Rights
Purchases (1) Sales AmerGen Non-Affiliates Purchases (2)
- -------------------------------------------------------------------------------------------------------------------
2003 $ 589 $ 2,606 $ 280 $ 1,722 $ 86
2004 639 1,181 292 768 93
2005 356 355 472 283 84
2006 328 92 472 239 3
2007 408 22 179 227 --
Thereafter 3,742 1 2,638 829 --
- -------------------------------------------------------------------------------------------------------------------
Total $ 6,062 $ 4,257 $ 4,333 $ 4,068 $ 266
- -------------------------------------------------------------------------------------------------------------------
(1) On October 2, 2002, Generation notified Midwest Generation of its exercise
of termination options under the existing Collins Generating Station
(Collins) and Peaking Unit (Peaking) Purchase Power Agreements. Generation
exercised its termination options on 1,727 MWs in 2003 and 2004. In 2003,
Generation will take 1,778 MWs of option capacity under the Collins and
Peaking Unit Agreements as well as 1,265 MWs of option capacity under the
Coal Generation Purchase Power Agreement. Net capacity purchases in 2004
include 3,474 MWs of optional capacity from Midwest Generation. Net
Capacity Purchases also include capacity sales to TXU under the purchase
power agreement entered into in connection with the purchase of two
generating plants in April 2002, which states that TXU will purchase the
plant output from May through September from 2002 through 2006. During the
periods covered by the power purchase agreement, TXU will make fixed
capacity payments and will provide fuel to Exelon in return for exclusive
rights to the energy and capacity of the generation plants. The combined
capacity of the two plants is 2,334 MWs.
(2) Transmission Rights Purchases include estimated commitments in 2004 and
2005 for additional transmission rights that will be required to fulfill
firm sales contracts.
123
Commercial Commitments
Exelon's commercial commitments as of December 31, 2002, representing
commitments not recorded on the balance sheet but potentially triggered by
future events, including obligations to make payment on behalf of other parties
and financing arrangements to secure our obligations, are as follows:
Expiration within
------------------------------------------------------------
2008
Total 2003 2004-2005 2006-2007 and beyond
- -------------------------------------------------------------------------------------------------------------------
Credit Facility (a) $ 1,500 $ 1,500 $ -- $ -- $ -
Letters of Credit (non-debt) (b) 111 106 5 -- --
Letters of Credit (Long-Term Debt) (c) 456 305 151 -- --
Insured Long-Term Debt (d) 254 -- -- -- 254
Guarantees of Letters of Credit(e) 226 226 -- -- --
Performance Guarantees (f) 101 -- -- -- 101
Surety Bonds (g) 521 329 57 4 131
Energy Marketing Contract
Guarantees (h) 124 114 10 -- --
Nuclear Insurance Guarantees (i) 1,380 -- -- -- 1,380
Lease Guarantees (j) 13 -- -- 2 11
Preferred Securities (k) 128 -- -- -- 128
Sithe New England Equity Guarantee (l) 38 38 -- -- --
Guarantees of Long-Term Debt (m) 41 2 -- -- 39
- -------------------------------------------------------------------------------------------------------------------
Total $ 4,893 $ 2,620 $ 223 $ 6 $ 2,044
- -------------------------------------------------------------------------------------------------------------------
(a) Credit Facility - Exelon, along with ComEd, PECO and Generation, maintain a
$1.5 billion 364-day credit facility to support commercial paper issuances.
At December 31, 2002, there were no borrowings against the credit facility.
Additionally, at December 31, 2002, there was $948 million of commercial
paper outstanding.
(b) Letters of Credit (non-debt) - Exelon and certain of its subsidiaries
maintain non-debt letters of credit to provide credit support for certain
transactions as requested by third parties.
(c) Letters of Credit (Long-Term Debt) - Direct-pay letters of credit issued in
connection with variable-rate debt in order to provide liquidity in the
event that it is not possible to remarket all of the debt as required
following specific events, including changes in the basis of determining
the interest rate on the debt.
(d) Insured Long-Term Debt - Borrowings that have been credit-enhanced through
the purchase of insurance coverage equal to the amount of principal
outstanding plus interest.
(e) Guarantees of letters of credit - Guarantees issued to provide support for
letters of credit as required by third parties. These guarantees could be
called upon only in the event of non-payment by a subsidiary.
(f) Performance Guarantees - Guarantees issued to ensure execution under
specific contracts.
(g) Surety Bonds - Guarantees issued related to contract and commercial surety
bonds, excluding bid bonds.
(h) Energy Marketing Contract Guarantees - Guarantees issued to ensure
performance under energy commodity contracts.
(i) Nuclear Insurance Guarantees - Guarantees of nuclear insurance required
under the Price-Anderson Act. $1.1 billion of this total exposure is exempt
from the $4.5 billion PUHCA guarantee limit by SEC rule.
(j) Lease Guarantees - Guarantees issued to ensure payments on building leases.
(k) Preferred Securities - Guarantees issued to guarantee the preferred
securities of the subsidiary trusts of PECO. See Note 16 - Preferred
Securities of Subsidiaries for further information.
(l) Sithe New England Equity Guarantee- See Note 3 - Acquisitions and
Dispositions for further information on the $38 million guarantee. After
construction of the SBG facilities is complete, Exelon could be required to
guarantee up to an additional $42 million in order to ensure that the SBG
facilities have adequate funds available for potential outage and other
operating costs and requirements.
(m) Guarantees of Long-Term Debt - Issued to guarantee payment of subsidiary
debt.
Unconsolidated Equity Investments. Generation is a 49.9% owner of Sithe and
accounts for the investment as an unconsolidated equity investment. The Sithe
New England purchase did not affect the accounting for Sithe as an equity
investment. Separate from the Sithe New England transaction, Generation is
subject to a Put and Call Agreement (PCA) that gives Generation the right to
purchase (Call) the remaining 50.1% of Sithe, and gives the other Sithe
shareholders the right to sell (Put) their interest to Generation. If the Put
option is exercised, Generation has the obligation to complete the purchase.
124
The PCA originally provided that the Put and Call options became
exercisable as of December 18, 2002 and expired in December 2005. However, upon
Apollo Energy, LLC's (Apollo) purchase of Vivendi's 34.2% ownership and Sithe
management's 1% share, Apollo agreed to delay the effective date of its Put
right until June 1, 2003 and, if certain conditions are met, until September 1,
2003. There are also certain events that could trigger Apollo's Put right
becoming effective prior to June 1, 2003 including Exelon being downgraded below
investment grade by Standard and Poor's Rating Group or Moody's Investors
Service, Inc., a stock purchase agreement between Exelon and Apollo being
executed and subsequently terminated, or the occurence of any event of default,
other than a change of control, under certain Exelon or Apollo credit
agreements. Depending on the triggering event, Apollo's put price of
approximately $460 million, growing at a market rate of interest, needs to be
funded within 18 or 30 days of the Put being exercised. There have been no
changes to the Put and Call terms with respect to Marubeni's remaining 14.9%
interest.
The delay in the effective date of Apollo's Put right allows Exelon to
explore a further restructuring of our investment in Sithe. Exelon is continuing
discussions with Apollo and Marubeni regarding restructuring alternatives that
are designed in part to resolve Exelon's ownership limitations of Sithe's
qualifying facilities. Exelon would hope to implement any additional
restructuring of its Sithe investment in 2003. If Exelon is unsuccessful in
restructuring the Sithe transaction, Exelon will proceed to implement measures
to address the ownership of the qualified facilities as well as divest
non-strategic assets, for which the financial outcome is uncertain.
If Generation exercises its option to acquire the remaining outstanding
common stock in Sithe, or if all the other stockholders exercise their Put
Rights, the purchase price for Apollo's 35.2% interest will be approximately
$460 million, growing at a market rate of interest. The additional 14.9%
interest will be valued at fair market value subject to a floor of $141 million
and a ceiling of $290 million.
If Generation increases its ownership in Sithe to 50.1% or more, Sithe may
become a consolidated subsidiary and our financial results may include Sithe's
financial results from the date of purchase. At December 31, 2002, Sithe had
total assets of $2.6 billion and total debt of $1.3 billion. This $1.3 billion
includes $624 million of subsidiary debt incurred primarily to finance the
construction of six new generating facilities, $461 million of subordinated
debt, $103 million of line of credit borrowings, $43 million of the current
portion of long-term debt and capital leases, $30 million of capital leases, and
excludes $453 million of non-recourse project debt associated with Sithe's
equity investments. For the year ended December 31, 2002, Sithe had revenues of
$1.0 billion. As of December 31, 2002, Generation had a $449 million equity
investment in Sithe.
Environmental Issues
Exelon's operations have in the past and may in the future require
substantial capital expenditures in order to comply with environmental laws.
Additionally, under Federal and state environmental laws, Exelon, through its
subsidiaries, is generally liable for the costs of remediating environmental
contamination of property now or formerly owned by Exelon and of property
contaminated by hazardous substances generated by Exelon. Exelon owns or leases
a number of real estate parcels, including parcels on which its operations or
the operations of others may have resulted in contamination by substances that
are considered hazardous under environmental laws. Exelon has identified 71
sites where former manufactured gas plant (MGP) activities have or may have
resulted in actual site contamination. Exelon is currently involved in a number
of proceedings relating to sites where hazardous substances have been deposited
and may be subject to additional proceedings in the future.
As of December 31, 2002 and 2001, Exelon had accrued $156 million for
environmental investigation and remediation costs, including $125 million and
$127 million, respectively, for MGP investigation and remediation that currently
can be reasonably estimated. Included in the environmental investigation and
remediation cost obligation as of December 31, 2002 and 2001 is $97 million and
$100 million, respectively, that has been recorded on a discount basis
(reflecting discount rates of 5.0% and 5.5%, respectively). Such estimates,
reflecting the effects of a 2.5% and 3.0% inflation rate before the effects of
discounting were $138 million and $154 million at December 31, 2002 and 2001,
respectively.
125
Exelon anticipates that payments related to the discounted environmental
investigation and remediation costs, recorded on an undiscounted basis, of $76
million will be incurred for the five-year period through 2007. Exelon cannot
reasonably estimate whether it will incur other significant liabilities for
additional investigation and remediation costs at these or additional sites
identified by Exelon, environmental agencies or others, or whether such costs
will be recoverable from third parties.
Leases
Minimum future operating lease payments, including lease payments for
vehicles, real estate, computers, rail cars and office equipment, as of December
31, 2002 were:
- ---------------------------------------------------------------------------
2003 $ 77
2004 59
2005 58
2006 54
2007 49
Remaining years 598
- ---------------------------------------------------------------------------
Total minimum future lease payments $ 895
- ---------------------------------------------------------------------------
Rental expense under operating leases totaled $85 million, $75 million and
$41 million in 2002, 2001 and 2000, respectively.
Litigation
Securities Litigation. Between May 8 and June 14, 2002, several class
action lawsuits were filed in the Federal District Court in Chicago asserting
nearly identical securities law claims on behalf of purchasers of Exelon
securities between April 24, 2001 and September 27, 2001 (Class Period). The
complaints allege that Exelon violated Federal securities laws by issuing a
series of materially false and misleading statements relating to its 2001
earnings expectations during the Class Period. The court consolidated the
pending cases into one lawsuit and has appointed two lead plaintiffs as well as
lead counsel.
On October 1, 2002, the plaintiffs filed a consolidated amended complaint.
In addition to the original claims, this complaint contains allegations of new
facts and contains several new theories of liability. Exelon believes the
lawsuit is without merit and is vigorously contesting this matter.
FERC Municipal Request for Refund. Three of ComEd's wholesale municipal
customers filed a complaint and request for refund with FERC, alleging that
ComEd failed to properly adjust its rates, as provided for under the terms of
the electric service contracts with the municipal customers and to track certain
refunds made to ComEd's retail customers in the years 1992 through 1994. In the
third quarter of 1998, FERC granted the complaint and directed that refunds be
made, with interest. On April 30, 2001, FERC issued an order granting rehearing
in which it determined that its 1998 order had been erroneous and that no
refunds were due from ComEd to the municipal customers. In August 2001, each of
the three wholesale municipal customers appealed the April 30, 2001 FERC order
to the Federal circuit court, which consolidated the appeals for the purposes of
briefing and decision. The Federal circuit court has stayed the proceedings
pending settlement negotiations among the parties.
Retail Rate Law. In 1996, several developers of non-utility generating
facilities filed litigation against various Illinois officials claiming that the
enforcement against those facilities of an amendment to Illinois law removing
the entitlement of those facilities to state-subsidized payments for electricity
sold to ComEd after March 15, 1996 violated their rights under the Federal and
state constitutions. The developers also filed suit against ComEd for a
declaratory judgment that their rights under their contracts with ComEd were not
affected by the amendment. On November 25, 2002, the court granted developers'
126
motions for summary judgment. The judge also entered a permanent injunction
enjoining ComEd from refusing to pay the retail rate on the grounds of the
amendment, and Illinois from denying ComEd a tax credit on account of such
purchases. ComEd and Illinois have each appealed the ruling. ComEd believes that
it did not breach the contracts in question and that the damages claimed far
exceed any loss that any project incurred by reason of its ineligibility for the
subsidized rate. ComEd intends to prosecute its appeal and defend each case
vigorously.
Cotter Corporation Litigation. During 1989 and 1991, actions were brought
in Federal and state courts in Colorado against ComEd and its subsidiary, Cotter
Corporation (Cotter), seeking unspecified damages and injunctive relief based on
allegations that Cotter permitted radioactive and other hazardous material to be
released from its mill into areas owned or occupied by the plaintiffs, resulting
in property damage and potential adverse health effects. In 1994, a Federal jury
returned nominal dollar verdicts against Cotter on eight plaintiffs' claims in
the 1989 cases, which verdicts were upheld on appeal. The remaining claims in
the 1989 actions were settled or dismissed. In 1998, a jury verdict was rendered
against Cotter in favor of 14 of the plaintiffs in the 1991 cases, totaling
approximately $6 million in compensatory and punitive damages, interest and
medical monitoring. On appeal, the Tenth Circuit Court of Appeals reversed the
jury verdict, and remanded the case for new trial. These plaintiffs' cases were
consolidated with the remaining 26 plaintiffs' cases, which had not been tried.
The consolidated trial was completed on June 28, 2001. The jury returned a
verdict against Cotter and awarded $16 million in various damages. On November
20, 2001, the District Court entered an amended final judgment that included an
award of both pre-judgment and post-judgment interests, costs, and medical
monitoring expenses that total $43 million. In November 2000, another trial
involving a separate sub-group of 13 plaintiffs, seeking $19 million in damages
plus interest was completed in Federal District Court in Denver. The jury
awarded nominal damages of $42,500 to 11 of 13 plaintiffs, but awarded no
damages for any personal injury or health claims, other than requiring Cotter to
perform periodic medical monitoring at minimal cost. Cotter appealed these
judgments to the Tenth Circuit Court of Appeals. Cotter is vigorously contesting
the award.
On February 18, 2000, ComEd sold Cotter to an unaffiliated third party. As
part of the sale, ComEd agreed to indemnify Cotter for any liability incurred by
Cotter as a result of these actions, as well as any liability arising in
connection with the West Lake Landfill discussed in the next paragraph. In
connection with Exelon's 2001 corporate restructuring, the responsibility to
indemnify Cotter for any liability related to these matters was transferred by
ComEd to Generation.
The United States Environmental Protection Agency (EPA) has advised Cotter
that it is potentially liable in connection with radiological contamination at a
site known as the West Lake Landfill in Missouri. Cotter is alleged to have
disposed of approximately 39,000 tons of soils mixed with 8,700 tons of leached
barium sulfate at the site. Cotter, along with three other companies identified
by the EPA as potentially responsible parties (PRPs), has submitted a draft
feasibility study addressing options for remediation of the site. The PRPs are
also engaged in discussions with the State of Missouri and the EPA. The
estimated costs of remediation for the site range from $0 million to $87
million. Once a remedy is selected, it is expected that the PRPs will agree on
an allocation of responsibility for the costs. Until an agreement is reached,
Generation cannot predict its share of the costs.
Raytheon Arbitration. In March 2001, two subsidiaries of Sithe New England
Holdings (now Exelon New England Holdings) brought an action in the New York
Supreme Court against Raytheon Corporation (Raytheon) relating to its failure to
honor its guaranty with respect to the performance of the Mystic and Fore River
projects, as a result of the abandonment of the projects by the turnkey
contractor. In a related proceeding, in May 2002, Raytheon submitted claims to
the International Chamber of Commerce Court of Arbitration seeking equitable
relief and damages for alleged owner caused performance delays in connection
with the Fore River Power Plant Engineering, Procurement & Construction
Agreement (EPC Agreement). The EPC Agreement, executed by a Raytheon subsidiary
and guaranteed by Raytheon, governs the design, engineering, construction,
start-up, testing and delivery of
127
an 800-MW combined-cycle power plant in Weymouth, Massachusetts. Raytheon
recently amended its claim and now seeks 141 days of schedule relief (which
would reduce Raytheon's liquidated damage payment for late delivery by
approximately $25.4 million) and additional damages of $15.6 million. Raytheon
also has asserted a claim for loss of efficiency and productivity as a result of
an alleged constructive acceleration, for which a claim has not yet been
quantified. Generation believes the Raytheon assertions are without merit and is
vigorously contesting these claims. Hearings by the International Chamber of
Commerce Court of Arbitration with respect to liability were held in January and
February 2003. A decision on liability is expected to be issued in May 2003 and,
if necessary, additional hearings will be held on damages in May and June of
2003.
Real Estate Tax Appeals. Generation is involved in tax appeals regarding a
number of its nuclear facilities, Limerick Generating Station (Montgomery
County, PA), Peach Bottom Atomic Power Station (York County, PA), and Quad
Cities Station (Rock Island County, IL). Generation is also involved in the tax
appeal for Three Mile Island (Dauphin County, PA) through AmerGen. Generation
does not believe the outcome of these matters will have a material adverse
effect on Generation's results of operations or financial condition.
General. Exelon is involved in various other litigation matters. The
ultimate outcome of such matters, as well as the matters discussed above, while
uncertain, are not expected to have a material adverse effect on its respective
financial condition or results of operations.
Credit Contingencies
Generation is a counterparty to Dynegy in various energy transactions. In
early July 2002, the credit ratings of Dynegy were downgraded by two credit
rating agencies to below investment grade. As of December 31, 2002, Generation
had a net receivable from Dynegy of approximately $3 million, and consistent
with the terms of the existing credit arrangement, has received collateral in
support of this receivable. Generation also has credit risk associated with
Dynegy through Generation's equity investment in Sithe. Sithe is a 60% owner of
the Independence generating station, a 1,040-MW gas-fired qualified facility
that has an energy-only long-term tolling agreement with Dynegy, with a related
financial swap arrangement. As of December 31, 2002, Sithe had recognized an
asset on its balance sheet related to the fair market value of the financial
swap agreement with Dynegy that is marked-to-market under the terms of SFAS No.
133. If Dynegy is unable to fulfill the terms of this agreement, Sithe would be
required to impair this financial swap asset. We estimate, as a 49.9% owner of
Sithe, that the impairment would result in an after-tax reduction of our equity
earnings of approximately $10 million.
In addition to the impairment of the financial swap asset, if Dynegy was
unable to fulfill its obligations under the financial swap agreement and the
tolling agreement, we would likely incur a further impairment associated with
the Independence plant. Depending upon the timing of Dynegy's failure to fulfill
its obligations and the outcome of any restructuring initiatives, Exelon could
realize an after-tax charge of between $0 and $130 million. In the event of a
sale of our investment in Sithe to a third party, proceeds from the sale could
be negatively impacted by approximately $120 million, which would represent an
after-tax loss of approximately $65 million.
Additionally, the future economic value of AmerGen's purchased power
arrangement with Illinois Power, a subsidiary of Dynegy, could be impacted by
events related to Dynegy's financial condition.
128
20. Segment Information
Exelon evaluates the performance of its business segments based on Net
Income.
Energy Delivery consists of the retail electricity distribution and
transmission businesses of ComEd in northern Illinois and PECO in southeastern
Pennsylvania and the natural gas distribution business of PECO located in the
Pennsylvania counties surrounding the City of Philadelphia. Generation consists
of electric generating facilities, energy marketing operations and Exelon's
interests in Sithe and AmerGen. Enterprises consists of competitive retail
energy sales, energy and infrastructure services, communications and other
investments weighted towards the communications, energy services and retail
services industries. An analysis and reconciliation of Exelon's business segment
information to the respective information in the consolidated financial
statements are as follows:
Energy Intersegment
Delivery Generation Enterprises Corporate Eliminations Consolidated
- -------------------------------------------------------------------------------------------------------------------
Total Revenues:
2002 $ 10,457 $ 6,858 $ 2,033 $ 346 $ (4,739) $ 14,955
2001 10,171 6,826 2,292 341 (4,712) 14,918
2000 4,511 3,274 1,395 -- (1,681) 7,499
Intersegment Revenues:
2002 $ 76 $ 4,226 $ 97 $ 341 $ (4,740) $ --
2001 94 4,102 179 337 (4,712) --
2000 24 1,185 472 -- (1,681) --
Depreciation and Amortization:
2002 $ 978 $ 276 $ 55 $ 31 $ -- $ 1,340
2001 1,081 282 69 17 -- 1,449
2000 297 123 35 3 -- 458
Operating Expenses:
2002 $ 7,597 $ 6,349 $ 2,047 $ 402 $ (4,739) $ 11,656
2001 7,578 5,954 2,369 371 (4,716) 11,556
2000 (a) 3,009 2,833 1,473 324 (1,667) 5,972
Interest Expense:
2002 $ 854 $ 75 $ 14 $ 74 $ (51) $ 966
2001 973 115 37 133 (151) 1,107
2000 522 41 17 63 (29) 614
Income Taxes:
2002 $ 765 $ 217 $ 69 $ (53) $ -- $ 998
2001 703 327 (43) (56) -- 931
2000 421 160 (52) (190) -- 339
Net Income/(Loss):
2002 $ 1,268 $ 400 $ (178) $ (50) $ -- $ 1,440
2001 1,022 524 (85) (33) -- 1,428
2000 (a) 587 260 (94) (167) -- 586
Capital Expenditures:
2002 $ 1,041 $ 990 $ 44 $ 75 $ -- $ 2,150
2001 1,105 858 61 64 -- 2,088
2000 367 288 70 27 -- 752
Total Assets:
2002 $ 26,550 $ 11,007 $ 1,297 $ (1,376) $ -- $ 37,478
2001 26,365 8,145 1,743 (1,509) -- 34,744
- -------------------------------------------------------------------------------------------------------------------
(a) Includes non-recurring items of $276 million ($177 million after income
taxes) for Merger-related expenses in 2000.
129
Equity in earnings of AmerGen and Sithe of $88 million, $90 million and $4
million for 2002, 2001 and 2000, respectively, are included in Generation's Net
Income. Equity in earnings (losses) of communications joint ventures and other
investments of $3 million, $(19) million and $(45) million for 2002, 2001 and
2000, respectively, are included in Enterprises' Net Income. Equity in earnings
(losses) of affordable housing investments of $(11) million and $(9) million for
2002 and 2001, respectively, are included in Corporate's Net Income.
21. Related Party Transactions
Exelon's financial statements reflect related-party transactions with
unconsolidated affiliates as reflected in the tables below.
For the Years Ended December 31,
-----------------------------------------
2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
Purchased Power from AmerGen (1) $ 273 $ 57 $ 52
Interest Income from AmerGen (2) 2 -- --
Interest Income from Sithe (3) -- 2 --
Interest Expense to Sithe (4) 2 -- --
Services Provided to AmerGen (5) 70 80 32
Services Provided to Sithe (6) 1 -- --
Services Provided by Sithe (7) 13 -- --
- ------------------------------------------------------------------------------------------------------------------
130
December 31,
-----------------------------------
2002 2001
- --------------------------------------------------------------------------------
Net Receivable from AmerGen (1,2,3) $ 39 $ 44
Net Payable to Sithe (4,5) 7 --
Note Payable to Sithe (7) 534 --
- --------------------------------------------------------------------------------
(1) Generation has entered into PPAs dated December 18, 2001 and November 22,
1999 with AmerGen. Under the 2001 PPA, Generation has agreed to purchase
from AmerGen all the energy from Unit No. 1 at Three Mile Island Nuclear
Station from January 1, 2002 through December 31, 2014. Under the 1999 PPA,
Generation agreed to purchase from AmerGen all of the residual energy from
Clinton Nuclear Power Station (Clinton) through December 31, 2002.
Currently, the residual output is approximately 31% of the total output of
Clinton. In accordance with the terms of the AmerGen partnership agreement,
the 1999 PPA will be extended through the end of the AmerGen partnership
agreement in 2006.
(2) In February 2002, Generation entered into an agreement to loan AmerGen up
to $75 million at an interest rate equal to the 1-month London Interbank
Offering Rate plus 2.25%. In July 2002, the limit of the loan agreement was
increased to $100 million and the maturity date was extended to July 1,
2003. As of December 31 2002, the outstanding principal balance of the loan
was $35 million.
(3) In August 2001, Exelon loaned Sithe, an equity method investee of
Generation, $150 million. The note, which bore interest at the eurodollar
rate, plus 2.25%, was repaid in December 2001 with the proceeds of bank
borrowings. In connection with the bank borrowings, Exelon provided the
lenders with a support letter confirming its investment in Sithe and
Exelon's agreement to maintain a positive net worth of Sithe.
(4) Under the terms of the agreement to acquire Sithe New England dated
November 1, 2002, Generation issued a $534 million note to be paid in full
on June 18, 2003 to Sithe. The note bears interest at the rate equal to
LIBOR plus 0.875%. Interest accrued on the note as of December 31, 2002 was
$2 million.
(5) Under a service agreement dated March 1, 1999, Generation provides AmerGen
with certain operation and support services to the nuclear facilities owned
by AmerGen. This service agreement has an indefinite term and may be
terminated by Generation or AmerGen with 90 days notice. Generation is
compensated for these services in an amount agreed to in the work order,
which is not less than the higher of its fully allocated cost for
performing each service or the market price for such service.
(6) Under a service agreement dated December 18, 2000, Generation provides
certain engineering and environmental services for fossil facilities owned
by Sithe and for certain developmental projects. Generation is compensated
for these services in an amount agreed to in the work order, but not less
than the higher of fully allocated costs for performing such services or
the market price.
(7) Under a service agreement dated December 18, 2000, Sithe provides
Generation certain fuel and project development services. Sithe is
compensated for these services in the amount agreed to in the work order,
but not less than the higher of fully allocated costs for performing such
services or the market price.
22. Quarterly Data (Unaudited)
The data shown below include all reclassifications, including those
required upon the adoption of EITF 02-3, which Exelon considers necessary for a
fair presentation of such amounts:
Income Before the
Cumulative Effect of Changes
Operating Revenues Operating Income in Accounting Principles Net Income
------------------ ---------------- ------------------------ --------------
2002 2001 2002 2001 2002 2001 2002 2001
- -------------------------------------------------------------------------------------------------------------------
Quarter ended:
March 31 $ 3,357 $ 3,823 $ 605 $ 889 $ 238 $ 387 $ 8 $ 399
June 30 3,519 3,616 813 792 485 315 485 315
September 30 4,370 4,185 1,000 912 551 376 551 376
December 31 3,709 3,293 882 769 397 338 397 338
- -------------------------------------------------------------------------------------------------------------------
131
Earnings per Basic Share
Average Shares Before the Cumulative Earnings per
Basic Outstanding Effect of Changes Basic Share
(in millions) in Accounting Principles Net Income
------------- ------------------------ --------------
2002 2001 2002 2001 2002 2001
- -------------------------------------------------------------------------------------------------------------------
Quarter ended:
March 31 321 320 $ 0.74 $ 1.21 $ 0.02 $ 1.25
June 30 322 321 1.50 0.98 1.50 0.98
September 30 323 321 1.71 1.17 1.71 1.17
December 31 323 321 1.23 1.05 1.23 1.05
- -------------------------------------------------------------------------------------------------------------------
Earnings per Diluted Share
Average Shares Before the Cumulative Earnings per
Diluted Outstanding Effect of Changes Diluted Share
(in millions) in Accounting Principles Net Income
------------- ------------------------ --------------
2002 2001 2002 2001 2002 2001
- -------------------------------------------------------------------------------------------------------------------
Quarter ended:
March 31 323 324 $ 0.73 $ 1.19 $ 0.02 $ 1.23
June 30 324 324 1.50 0.97 1.50 0.97
September 30 324 323 1.70 1.16 1.70 1.16
December 31 325 322 1.22 1.05 1.22 1.05
- -------------------------------------------------------------------------------------------------------------------
The following table presents the New York Stock Exchange - Composite Common
Stock Prices and dividends by quarter on a per share basis:
2002 2001
------------------------------------------ ------------------------------------------
Fourth Third Second First Fourth Third Second First
Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter
- -------------------------------------------------------------------------------------------------------------------
High Price $ 53.06 $ 52.83 $ 56.99 $ 53.88 $ 48.69 $ 67.65 $ 70.26 $ 69.75
Low Price 42.38 37.85 50.10 45.90 39.65 38.75 62.10 53.60
Close 52.77 47.50 52.30 52.97 47.88 44.60 64.12 65.60
Dividends 0.44 0.44 0.44 0.44 0.43 0.42 0.42 0.55 (a)
- -------------------------------------------------------------------------------------------------------------------
(a) The first quarter dividend in 2001 was a pro rata dividend. Unicom and PECO
each paid their shareholders pro rata, per diem dividends from their last
regular dividend dates through October 19, 2000. The first quarter covered
the 119-day period from the date of the Merger, through the February 15,
2001 record date.
23. Subsequent Events
On January 22, 2003, ComEd issued $350 million of 3.70% First Mortgage
Bonds, due on February 1, 2008 and $350 million of 5.875% First Mortgage Bonds,
due on February 1, 2033. These bond proceeds were used to refinance long-term
debt that had been retired during the third and fourth quarters of 2002. As part
of these bond issuances, ComEd settled various forward starting interest rate
swaps, for $43 million, which will be recorded as a regulatory asset and
amortized over the life of the debt issuance.
On January 31, 2003, ComEd called $236 million of its First Mortgage
Bonds at a redemption price of 103.86% of the principal amount, plus accrued
interest to the March 18, 2003 redemption date. The bonds, which carried an
interest rate of 8.375% and had a maturity date of February 15, 2023, are
expected to be refinanced with long-term debt.
On February 14, 2003, ComEd called $200 million of its Trust Preferred
securities at a redemption price of 100% of the principal amount, plus accrued
interest to the March 20, 2003 redemption date. The preferred securities, which
carried an interest rate of 8.48% and had a maturity date of September 30, 2035,
are expected to be refinanced with trust preferred securities.
132
On February 20, 2003, ComEd entered into separate agreements with the City
of Chicago (City) and with Midwest Generation (Midwest Agreement). Under the
terms of the agreement with the City, ComEd will pay the City $60 million over
ten years and be relieved of a requirement, originally transferred to Midwest
Generation upon the sale of ComEd's fossil stations in 1999, to build a 500-MW
generation facility. Under the terms of the Midwest Agreement, ComEd will
receive from Midwest Generation $36 million over ten years, $22 million of which
was received on February 20, 2003, to relieve Midwest Generation's obligation
under the fossil sale agreement. Midwest Generation will also assume from the
City a Capacity Reservation Agreement which the City had entered into with
Calumet Energy Team, LLC (CET), that is effective through June 2012. ComEd will
reimburse the City for any nonperformance by Midwest Generation under the
Capacity Reservation Agreement and will pay approximately $2 million for amounts
owed to CET by the City at the time the agreement is executed. The net effect of
the settlement to ComEd will be amortized over the remaining life of the
franchise agreement with the City.
133