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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended March 31, 2003
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission File Name of Registrant; State of Incorporation; Address of IRS Employer
Number Principal Executive Offices; and Telephone Number Identification Number
----------------- ---------------------------------------------------------- ------------------------
1-16169 EXELON CORPORATION 23-2990190
(a Pennsylvania corporation)
10 South Dearborn Street - 37th Floor
P.O. Box 805379
Chicago, Illinois 60680-5379
(312) 394-7398
1-1839 COMMONWEALTH EDISON COMPANY 36-0938600
(an Illinois corporation)
10 South Dearborn Street - 37th Floor
P.O. Box 805379
Chicago, Illinois 60680-5379
(312) 394-4321
1-1401 PECO ENERGY COMPANY 23-0970240
(a Pennsylvania corporation)
P.O. Box 8699 2301 Market Street
Philadelphia, Pennsylvania 19101-8699
(215) 841-4000
333-85496 EXELON GENERATION COMPANY, LLC 23-3064219
(a Pennsylvania limited liability company)
300 Exelon Way
Kennett Square, Pennsylvania 19348
(610) 765-6900
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [_].
The number of shares outstanding of each registrant's common stock as of
March 31, 2003 was:
Exelon Corporation Common Stock, without par value 324,234,521
Commonwealth Edison Company Common Stock, $12.50 par value 127,016,427
PECO Energy Company Common Stock, without par value 170,478,507
Exelon Generation Company, LLC not applicable
Indicate by check mark whether the registrant is an accelerated filer
(as defined in Rule 12b-2 of the Act). Exelon Corporation Yes [X] No [ ]
Commonwealth Edison Company, PECO Energy Company and Exelon Generation Company,
LLC Yes [ ] No [X].
TABLE OF CONTENTS
Page No.
--------
FILING FORMAT 3
FORWARD-LOOKING STATEMENTS 3
WHERE TO FIND MORE INFORMATION 3
PART I. FINANCIAL INFORMATION 4
ITEM 1. FINANCIAL STATEMENTS 4
Exelon Corporation
Consolidated Statements of Income and Comprehensive Income 5
Consolidated Statements of Cash Flows 6
Consolidated Balance Sheets 7
Commonwealth Edison Company
Consolidated Statements of Income and Comprehensive Income 9
Consolidated Statements of Cash Flows 10
Consolidated Balance Sheets 11
PECO Energy Company
Consolidated Statements of Income and Comprehensive Income 13
Consolidated Statements of Cash Flows 14
Consolidated Balance Sheets 15
Exelon Generation Company, LLC
Consolidated Statements of Income and Comprehensive Income 17
Consolidated Statements of Cash Flows 18
Consolidated Balance Sheets 19
Condensed Combined Notes to Consolidated Financial Statements 21
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS 55
Exelon Corporation 55
Commonwealth Edison Company 73
PECO Energy Company 83
Exelon Generation Company, LLC 93
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK 100
ITEM 4. CONTROLS AND PROCEDURES 110
PART II. OTHER INFORMATION 112
ITEM 1. LEGAL PROCEEDINGS 112
ITEM 5. OTHER INFORMATION 113
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K 114
SIGNATURES 116
CERTIFICATIONS 118
2
FILING FORMAT
This combined Form 10-Q is being filed separately by Exelon
Corporation, Commonwealth Edison Company, PECO Energy Company and Exelon
Generation Company, LLC (Registrants). Information contained herein relating to
any individual registrant has been filed by such registrant on its own behalf.
No registrant makes any representation as to information relating to any other
registrant.
FORWARD-LOOKING STATEMENTS
Except for the historical information contained herein, certain of the
matters discussed in this Report are forward-looking statements, within the
meaning of the Private Securities Litigation Reform Act of 1995, that are
subject to risks and uncertainties. The factors that could cause actual results
to differ materially from the forward-looking statements made by a registrant
include those discussed herein, as well as those discussed in (a) the
Registrants' 2002 Annual Report on Form 10-K - ITEM 7. Management's Discussion
and Analysis of Financial Condition and Results of Operations--Business Outlook
and the Challenges in Managing Our Business for Exelon, ComEd, PECO and
Generation, (b) the Registrants' 2002 Annual Report on Form 10-K - ITEM 8.
Financial Statements and Supplementary Data: Exelon - Note 19, ComEd - Note 16,
PECO - Note 18 and Generation - Note 13 and (c) other factors discussed in
filings with the United States Securities and Exchange Commission (SEC) by the
Registrants. Readers are cautioned not to place undue reliance on these
forward-looking statements, which apply only as of the date of this Report. None
of the Registrants undertakes any obligation to publicly release any revision to
its forward-looking statements to reflect events or circumstances after the date
of this Report.
WHERE TO FIND MORE INFORMATION
The public may read and copy any reports or other information that the
Registrants file with the SEC at the SEC's public reference room at 450 Fifth
Street, N.W., Washington, D.C. 20549. The public may obtain information on the
operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.
These documents are also available to the public from commercial document
retrieval services, the web site maintained by the SEC at http://www.sec.gov and
Exelon Corporation's website at www.exeloncorp.com.
3
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
4
EXELON CORPORATION
- ------------------
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended March 31,
----------------------------
(in millions, except per share data) 2003 2002
- ----------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 4,074 $ 3,357
OPERATING EXPENSES
Purchased Power 840 612
Purchased Power from Unconsolidated Affiliate 67 56
Fuel 830 496
Operating and Maintenance 1,109 1,067
Depreciation and Amortization 274 335
Taxes Other Than Income 197 186
- ----------------------------------------------------------------------------------------------------
Total Operating Expenses 3,317 2,752
- ----------------------------------------------------------------------------------------------------
OPERATING INCOME 757 605
- ----------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (225) (249)
Distributions on Preferred Securities of Subsidiaries (12) (11)
Equity in Earnings of Unconsolidated Affiliates, net 18 13
Other, Net (141) 28
- ----------------------------------------------------------------------------------------------------
Total Other Income and Deductions (360) (219)
- ----------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT
OF CHANGES IN ACCOUNTING PRINCIPLES 397 386
INCOME TAXES 148 148
- ----------------------------------------------------------------------------------------------------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN
ACCOUNTING PRINCIPLES 249 238
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING
PRINCIPLES (net of income taxes of $69 and $(90) for the three
months ended March 31, 2003 and 2002, respectively) 112 (230)
- ----------------------------------------------------------------------------------------------------
NET INCOME $ 361 $ 8
- ----------------------------------------------------------------------------------------------------
OTHER COMPREHENSIVE INCOME (LOSS) (net of income taxes)
Cash Flow Hedge Adjustment (146) (53)
Foreign Currency Translation Adjustment 1 --
Unrealized Gain (Loss) on Marketable Securities, net 163 (15)
Interest in Other Comprehensive Income (Loss) of Unconsolidated Affiliates (9) --
- ----------------------------------------------------------------------------------------------------
Total Other Comprehensive Income (Loss), net 9 (68)
- ----------------------------------------------------------------------------------------------------
TOTAL COMPREHENSIVE INCOME (LOSS) $ 370 $ (60)
=====================================================================================================
AVERAGE SHARES OF COMMON STOCK OUTSTANDING - Basic 324 321
=====================================================================================================
AVERAGE SHARES OF COMMON STOCK OUTSTANDING - Diluted 326 323
=====================================================================================================
EARNINGS PER AVERAGE COMMON SHARE:
BASIC:
Income Before Cumulative Effect of Changes in Accounting Principles $ 0.77 $ 0.74
Cumulative Effect of Changes in Accounting Principles 0.34 (0.72)
- ----------------------------------------------------------------------------------------------------
Net Income $ 1.11 $ 0.02
=====================================================================================================
DILUTED:
Income Before Cumulative Effect of Changes in Accounting Principles $ 0.77 $ 0.73
Cumulative Effect of Changes in Accounting Principles 0.34 (0.71)
- ----------------------------------------------------------------------------------------------------
Net Income $ 1.11 $ 0.02
=====================================================================================================
DIVIDENDS PER COMMON SHARE $ 0.46 $ 0.44
=====================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
5
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended March 31,
----------------------------
(in millions) 2003 2002
- ----------------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 361 $ 8
Adjustments to Reconcile Net Income to Net Cash Flows
Provided by Operating Activities:
Depreciation and Amortization, including nuclear fuel 423 427
Cumulative Effect of Changes in Accounting Principles (net of income taxes) (112) 230
Provision for Uncollectible Accounts 31 29
Deferred Income Taxes (64) 67
Equity in (Earnings) Losses of Unconsolidated Affiliates, net (18) (13)
Writedown of Investments 205 2
Net Realized (Gains) Losses on Nuclear Decommissioning Trust Funds (6) 10
Other Operating Activities (16) 8
Changes in Assets and Liabilities:
Accounts Receivable (57) 58
Inventories 43 13
Accounts Payable, Accrued Expenses and Other Current Liabilities (99) (7)
Other Current Assets (262) (134)
Deferred Energy Costs (28) 34
Pension and Non-Pension Postretirement Benefits Obligations (77) (3)
Other Noncurrent Assets and Liabilities 59 97
- ----------------------------------------------------------------------------------------------------
Net Cash Flows provided by Operating Activities 383 826
- ----------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures (427) (586)
Proceeds from Nuclear Decommissioning Trust Funds 572 580
Investment in Nuclear Decommissioning Trust Funds (622) (605)
Note Receivable from Unconsolidated Affiliate -- (46)
Other Investing Activities 20 27
- ----------------------------------------------------------------------------------------------------
Net Cash Flows used in Investing Activities (457) (630)
- ----------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Long-Term Debt 951 408
Retirement of Long-Term Debt (963) (471)
Issuance of Preferred Securities of Subsidiaries 200 --
Retirement of Preferred Securities of Subsidiaries (200) --
Change in Short-Term Debt 219 78
Dividends Paid on Common Stock (145) (141)
Change in Restricted Cash 74 135
Proceeds from Employee Stock Plans 31 18
Other Financing Activities (59) (12)
- ----------------------------------------------------------------------------------------------------
Net Cash Flows provided by Financing Activities 108 15
- ----------------------------------------------------------------------------------------------------
INCREASE IN CASH AND CASH EQUIVALENTS 34 211
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 469 485
- ----------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 503 $ 696
====================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
6
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
(in millions) 2003 2002
- --------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 503 $ 469
Restricted Cash 322 396
Accounts Receivable, net
Customer 2,121 2,095
Other 243 265
Receivable from Unconsolidated Affiliate 20 32
Inventories, at average cost
Fossil Fuel 163 218
Materials and Supplies 317 306
Deferred Income Taxes 10 6
Other 625 331
- --------------------------------------------------------------------------------
Total Current Assets 4,324 4,118
- --------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT, NET 20,237 17,134
DEFERRED DEBITS AND OTHER ASSETS
Regulatory Assets 5,459 5,938
Nuclear Decommissioning Trust Funds 3,032 3,053
Investments 1,171 1,393
Goodwill, net 4,788 4,992
Other 890 850
- --------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 15,340 16,226
- --------------------------------------------------------------------------------
TOTAL ASSETS $39,901 $37,478
================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
7
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
(in millions) 2003 2002
- -----------------------------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Notes Payable $ 900 $ 681
Note Payable to Unconsolidated Affiliate 534 534
Long-Term Debt Due Within One Year 1,147 1,402
Accounts Payable 1,815 1,563
Accrued Expenses 1,182 1,311
Other 481 483
- -----------------------------------------------------------------------------------------------
Total Current Liabilities 6,059 5,974
- -----------------------------------------------------------------------------------------------
LONG-TERM DEBT 13,368 13,127
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred Income Taxes 3,849 3,702
Unamortized Investment Tax Credits 298 301
Nuclear Decommissioning Liability for Retired Plants -- 1,395
Asset Retirement Obligation 2,406 --
Pension Obligation 1,848 1,959
Non-Pension Postretirement Benefits Obligation 911 877
Spent Nuclear Fuel Obligation 861 858
Regulatory Liabilities 633 --
Other 976 871
- -----------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 11,782 9,963
- -----------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES
MINORITY INTEREST OF CONSOLIDATED SUBSIDIARIES 78 77
PREFERRED SECURITIES OF SUBSIDIARIES 610 595
SHAREHOLDERS' EQUITY
Common Stock 7,099 7,059
Deferred Compensation -- (1)
Retained Earnings 2,254 2,042
Accumulated Other Comprehensive Income (Loss) (1,349) (1,358)
- -----------------------------------------------------------------------------------------------
Total Shareholders' Equity 8,004 7,742
- -----------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 39,901 $ 37,478
===============================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
8
COMMONWEALTH EDISON COMPANY
- ---------------------------
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended March 31,
----------------------------
(in millions) 2003 2002
- -------------------------------------------------------------------------------------
OPERATING REVENUES
Operating Revenues $ 1,411 $ 1,304
Operating Revenues from Affiliates 13 11
- -------------------------------------------------------------------------------------
Total Operating Revenues 1,424 1,315
- -------------------------------------------------------------------------------------
OPERATING EXPENSES
Purchased Power 6 6
Purchased Power from Affiliate 572 532
Operating and Maintenance 231 195
Operating and Maintenance from Affiliates 30 42
Depreciation and Amortization 94 135
Taxes Other Than Income 80 73
- -------------------------------------------------------------------------------------
Total Operating Expenses 1,013 983
- -------------------------------------------------------------------------------------
OPERATING INCOME 411 332
- -------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (110) (126)
Distributions on Company-Obligated
Mandatorily Redeemable Preferred Securities of
Subsidiary Trusts Holding Solely the Company's
Subordinated Debt Securities (7) (7)
Interest Income from Affiliates 7 8
Other, Net 15 6
- -------------------------------------------------------------------------------------
Total Other Income and Deductions (95) (119)
- -------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF
A CHANGE IN ACCOUNTING PRINCIPLE 316 213
INCOME TAXES 126 84
- -------------------------------------------------------------------------------------
NET INCOME BEFORE CUMULTIVE EFFECT OF A CHANGE IN
ACCOUNTING PRINCIPLE 190 129
CUMULTIVE EFFECT OF A CHANGE IN ACCOUNTING
PRINCIPLE (net of income taxes of $0) 5 --
- -------------------------------------------------------------------------------------
NET INCOME $ 195 $ 129
- -------------------------------------------------------------------------------------
OTHER COMPREHENSIVE INCOME (net of income taxes)
Cash Flow Hedge Adjustment 31 3
Foreign Currency Translation Adjustment 1 --
- -------------------------------------------------------------------------------------
Total Other Comprehensive Income 32 3
- -------------------------------------------------------------------------------------
TOTAL COMPREHENSIVE INCOME $ 227 $ 132
=====================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
9
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended March 31,
----------------------------
(in millions) 2003 2002
- -------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 195 $ 129
Adjustments to Reconcile Net Income to Net Cash Flows
Provided by Operating Activities:
Depreciation and Amortization 94 135
Cumulative Effect of a Change in Accounting Principle (net of income taxes) (5) --
Provision for Uncollectible Accounts 12 11
Deferred Income Taxes 63 53
Other Operating Activities (3) 13
Changes in Assets and Liabilities:
Accounts Receivable (5) --
Inventories (1) 10
Accounts Payable, Accrued Expenses and Other Current Liabilities (143) 1
Changes in Receivables and Payables to Affiliates, net (146) (90)
Pension and Non-Pension Postretirement Benefits Obligations (36) 7
Other Noncurrent Assets and Liabilities 42 9
- -------------------------------------------------------------------------------------------------------------------
Net Cash Flows provided by Operating Activities 67 278
- -------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures (174) (182)
Other Investing Activities 10 7
- -------------------------------------------------------------------------------------------------------------------
Net Cash Flows used in Investing Activities (164) (175)
- -------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Long-Term Debt 700 400
Retirement of Long-Term Debt (377) (297)
Issuance of Company Obligated Mandatorily Redeemable Preferred Securities 200 --
Retirement of Company Obligated Mandatorily Redeemable Preferred Securities (200) --
Change in Short-Term Debt (26) --
Dividends on Common Stock (120) (118)
Change in Restricted Cash (5) (20)
Other Financing Activities (59) (9)
- -------------------------------------------------------------------------------------------------------------------
Net Cash Flows provided by (used in) Financing Activities 113 (44)
- -------------------------------------------------------------------------------------------------------------------
INCREASE IN CASH AND CASH EQUIVALENTS 16 59
- -------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 16 23
- -------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 32 $ 82
===================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
10
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
(in millions) 2003 2002
- -------------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 32 $ 16
Restricted Cash 70 65
Accounts Receivable, net
Customer 759 782
Other 88 72
Inventories, at average cost 66 65
Deferred Income Taxes 20 20
Receivables from Affiliates 6 15
Other 14 14
- -------------------------------------------------------------------------------------------------------------------
Total Current Assets 1,055 1,049
- -------------------------------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT, NET 7,840 7,744
DEFERRED DEBITS AND OTHER ASSETS
Regulatory Assets -- 447
Investments 48 54
Goodwill, net 4,711 4,916
Receivables from Affiliates 2,221 1,300
Other 355 320
- -------------------------------------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 7,335 7,037
- -------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS $ 16,230 $ 15,830
===================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
11
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
(in millions) 2003 2002
- -------------------------------------------------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Notes Payable $ 45 $ 71
Long-Term Debt Due Within One Year 871 698
Accounts Payable 192 201
Accrued Expenses 352 477
Payables to Affiliates 200 416
Customer Deposits 82 81
Other 70 79
- -------------------------------------------------------------------------------------------------------------------
Total Current Liabilities 1,812 2,023
- -------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT 5,421 5,268
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred Income Taxes 1,739 1,650
Unamortized Investment Tax Credits 50 51
Pension Obligation 46 91
Non-Pension Postretirement Benefits Obligation 147 138
Payables to Affiliates 7 224
Regulatory Liabilities 633 --
Other 345 297
- -------------------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 2,967 2,451
- -------------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES
COMPANY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED
SECURITIES OF SUBSIDIARY TRUSTS HOLDING SOLELY THE COMPANY'S
SUBORDINATED DEBT SECURITIES 344 330
SHAREHOLDERS' EQUITY
Common Stock 1,588 1,588
Preference Stock 7 7
Other Paid in Capital 4,029 4,239
Receivable from Parent (584) (615)
Retained Earnings 652 577
Accumulated Other Comprehensive Income (Loss) (6) (38)
- -------------------------------------------------------------------------------------------------------------------
Total Shareholders' Equity 5,686 5,758
- -------------------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 16,230 $ 15,830
===================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
12
PECO ENERGY COMPANY
- -------------------
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended March 31,
--------------------------------
(in millions) 2003 2002
- ------------------------------------------------------------------------------------------
OPERATING REVENUES
Operating Revenues $ 1,214 $ 1,017
Operating Revenues from Affiliates 3 3
- ------------------------------------------------------------------------------------------
Total Operating Revenues 1,217 1,020
- ------------------------------------------------------------------------------------------
OPERATING EXPENSES
Purchased Power 65 48
Purchased Power from Affiliate 357 303
Fuel 191 135
Operating and Maintenance 127 111
Operating and Maintenance from Affiliates 12 25
Depreciation and Amortization 120 112
Taxes Other Than Income 63 59
- ------------------------------------------------------------------------------------------
Total Operating Expenses 935 793
- ------------------------------------------------------------------------------------------
OPERATING INCOME 282 227
- ------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (86) (95)
Company-Obligated Mandatorily Redeemable Preferred
Securities of a Partnership, which Holds Solely
Subordinated Debentures of the Company (2) (2)
Other, Net 9 1
- ------------------------------------------------------------------------------------------
Total Other Income and Deductions (79) (96)
- ------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 203 131
INCOME TAXES 66 42
- ------------------------------------------------------------------------------------------
NET INCOME 137 89
Preferred Stock Dividends (2) (2)
- ------------------------------------------------------------------------------------------
NET INCOME ON COMMON STOCK $ 135 $ 87
==========================================================================================
OTHER COMPREHENSIVE INCOME (net of income taxes)
Net Income $ 137 $ 89
Other Comprehensive Income (net of income taxes):
Cash Flow Hedge Adjustment -- 2
- ------------------------------------------------------------------------------------------
Total Other Comprehensive Income -- 2
- ------------------------------------------------------------------------------------------
TOTAL COMPREHENSIVE INCOME $ 137 $ 91
==========================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
13
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended March 31,
----------------------------
(in millions) 2003 2002
- -------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 137 $ 89
Adjustments to Reconcile Net Income to Net Cash Flows
Provided by Operating Activities:
Depreciation and Amortization 120 112
Provision for Uncollectible Accounts 17 19
Deferred Income Taxes (20) 46
Other Operating Activities 3 (2)
Changes in Assets and Liabilities:
Accounts Receivable (37) (3)
Changes in Receivables and Payables to Affiliates, net 6 (17)
Inventories 45 35
Accounts Payable, Accrued Expenses and Other Current Liabilities 14 (83)
Prepaid Taxes (131) (133)
Deferred Energy Costs (28) 34
Other Current Assets -- (1)
Pension and Non-Pension Postretirement Benefits Obligations 8 2
Other Noncurrent Assets and Liabilities (8) 2
- -------------------------------------------------------------------------------------------------------------------
Net Cash Flows provided by Operating Activities 126 100
- -------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures (65) (68)
Other Investing Activities 6 3
- -------------------------------------------------------------------------------------------------------------------
Net Cash Flows used in Investing Activities (59) (65)
- -------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Long-Term Debt 250 --
Retirement of Long-Term Debt (364) (160)
Change in Short-Term Debt 43 58
Dividends on Preferred and Common Stock (91) (87)
Change in Restricted Cash 136 153
- -------------------------------------------------------------------------------------------------------------------
Net Cash Flows used in Financing Activities (26) (36)
- -------------------------------------------------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 41 (1)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 63 32
- -------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 104 $ 31
===================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
14
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
(in millions) 2003 2002
- ---------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 104 $ 63
Restricted Cash 195 331
Accounts Receivable, net
Customer 389 379
Other 49 39
Inventories, at average cost
Fossil Fuel 21 67
Materials and Supplies 9 8
Deferred Energy Costs 59 31
Prepaid Taxes 132 1
Other 8 8
- ---------------------------------------------------------------------------------------------
Total Current Assets 966 927
- ---------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT, NET 4,199 4,179
DEFERRED DEBITS AND OTHER ASSETS
Regulatory Assets 5,459 5,491
Investments 19 19
Prepaid Pension Asset 50 41
Other 61 63
- ---------------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 5,589 5,614
- ---------------------------------------------------------------------------------------------
TOTAL ASSETS $ 10,754 $ 10,720
=============================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
15
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
(in millions) 2003 2002
- -------------------------------------------------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Notes Payable $ 243 $ 200
Payables to Affiliates 146 170
Long-Term Debt Due Within One Year 264 689
Accounts Payable 117 87
Accrued Expenses 354 370
Deferred Income Taxes 27 27
Other 35 33
- -------------------------------------------------------------------------------------------------------------------
Total Current Liabilities 1,186 1,576
- -------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT 5,262 4,951
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred Income Taxes 2,890 2,903
Unamortized Investment Tax Credits 24 24
Non-Pension Postretirement Benefits Obligation 268 251
Payable to Affiliate 39 --
Other 120 126
- -------------------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 3,341 3,304
- -------------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES
COMPANY-OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES OF A PARTNERSHIP,
WHICH HOLDS SOLELY SUBORDINATED
DEBENTURES OF THE COMPANY 128 128
SHAREHOLDERS' EQUITY
Common Stock 1,976 1,976
Receivable from Parent (1,728) (1,758)
Preferred Stock 137 137
Retained Earnings 447 401
Accumulated Other Comprehensive Income 5 5
- -------------------------------------------------------------------------------------------------------------------
Total Shareholders' Equity 837 761
- -------------------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 10,754 $ 10,720
===================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
16
EXELON GENERATION COMPANY, LLC
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended March 31,
----------------------------
(in millions) 2003 2002
- -------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES
Operating Revenues $ 886 $ 569
Operating Revenues from Affiliates 993 892
- -------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 1,879 1,461
- -------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Purchased Power 761 553
Purchased Power from Affiliates 80 66
Fuel 364 209
Operating and Maintenance 445 375
Operating and Maintenance from Affiliates 42 57
Depreciation and Amortization 45 63
Taxes Other Than Income 48 49
- -------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 1,785 1,372
- -------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 94 89
- -------------------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (15) (17)
Interest Expense - Affiliates (4) --
Equity in Earnings of Unconsolidated Affiliates 19 23
Other, Net (167) 16
- -------------------------------------------------------------------------------------------------------------------
Total Other Income and Deductions (167) 22
- -------------------------------------------------------------------------------------------------------------------
INCOME (LOSS) BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF
CHANGES IN ACCOUNTING PRINCIPLES (73) 111
INCOME TAXES (21) 45
- -------------------------------------------------------------------------------------------------------------------
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGES IN
ACCOUNTING PRINCIPLES (52) 66
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES (net of income taxes
of $70 and $9 for the three months ended March 31, 2003 and 2002, respectively) 108 13
- -------------------------------------------------------------------------------------------------------------------
NET INCOME $ 56 $ 79
- -------------------------------------------------------------------------------------------------------------------
OTHER COMPREHENSIVE INCOME (LOSS) (net of income taxes)
Unrealized Gain (Loss) on Marketable Securities 163 (9)
Cash Flow Hedge Adjustment (180) (74)
Interest in Other Comprehensive Income (Loss) of Unconsolidated Affiliates (9) 6
- -------------------------------------------------------------------------------------------------------------------
Total Other Comprehensive Income (Loss) (26) (77)
- -------------------------------------------------------------------------------------------------------------------
TOTAL COMPREHENSIVE INCOME $ 30 $ 2
===================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
17
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended March 31,
----------------------------
(in millions) 2003 2002
- -------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 56 $ 79
Adjustments to Reconcile Net Income (Loss) to Net Cash Flows
Provided by Operating Activities:
Depreciation and Amortization 195 155
Cumulative Effect of Changes in Accounting Principles (net of income taxes) (108) (13)
Provision for Uncollectible Accounts 1 2
Deferred Income Taxes (106) (2)
Equity in Earnings of Unconsolidated Affiliates (19) (23)
Writedown of Investment 200 --
Net Realized (Gains) Losses on Nuclear Decommissioning Trust Funds (6) 10
Other Operating Activities 4 9
Changes in Assets and Liabilities:
Accounts Receivable (57) 53
Changes in Receivables and Payables to Affiliates, net 244 144
Inventories (10) (37)
Accounts Payable, Accrued Expenses and Other Current Liabilities 19 127
Other Current Assets (119) (26)
Pension and Non-Pension Postretirement Benefits Obligations (32) (13)
Other Noncurrent Assets and Liabilities 16 44
- -------------------------------------------------------------------------------------------------------------------
Net Cash Flows provided by Operating Activities 278 509
- -------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures (175) (308)
Proceeds from Nuclear Decommissioning Trust Funds 572 580
Investment in Nuclear Decommissioning Trust Funds (622) (605)
Note Receivable from Affiliate -- (46)
Other Investing Activities 9 --
- -------------------------------------------------------------------------------------------------------------------
Net Cash Flows used in Investing Activities (216) (379)
- -------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Long-Term Debt 1 --
Retirement of Long-Term Debt (2) 1
Change in Intercompany Payable, Affiliate (6) --
Change in Restricted Cash (56) --
- -------------------------------------------------------------------------------------------------------------------
Net Cash Flows provided by (used in) Financing Activities (63) 1
- -------------------------------------------------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (1) 131
- -------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 58 224
- -------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 57 $ 355
===================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
18
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
(in millions) 2003 2002
- ----------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 57 $ 58
Restricted Cash 56 --
Accounts Receivable, net
Customer 588 587
Other 80 57
Receivables from Affiliates 343 594
Inventories, at average cost
Fossil Fuel 140 140
Materials and Supplies 226 217
Deferred Income Taxes 7 7
Other 263 145
- ----------------------------------------------------------------------------------------
Total Current Assets 1,760 1,805
- ----------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT, NET 7,788 4,800
DEFERRED DEBITS AND OTHER ASSETS
Nuclear Decommissioning Trust Funds 3,032 3,053
Investments 438 657
Receivable from Affiliate 41 220
Deferred Income Taxes 196 271
Prepaid Pension Asset 13 --
Other 210 201
- ----------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 3,930 4,402
- ----------------------------------------------------------------------------------------
TOTAL ASSETS $ 13,478 $ 11,007
========================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
19
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
(in millions) 2003 2002
- ----------------------------------------------------------------------------------------------
LIABILITIES AND MEMBER'S EQUITY
CURRENT LIABILITIES
Long-Term Debt Due within One Year $ 5 $ 5
Accounts Payable 1,304 1,089
Payables to Affiliates 33 10
Notes Payable to Affiliates 857 863
Accrued Expenses 516 480
Other 207 216
- ----------------------------------------------------------------------------------------------
Total Current Liabilities 2,922 2,663
- ----------------------------------------------------------------------------------------------
LONG-TERM DEBT 2,131 2,132
DEFERRED CREDITS AND OTHER LIABILITIES
Unamortized Investment Tax Credits 224 226
Nuclear Decommissioning Liability for Retired Plants -- 1,395
Asset Retirement Obligation 2,402 --
Pension Obligation -- 37
Non-Pension Postretirement Benefits Obligation 428 410
Spent Nuclear Fuel Obligation 861 858
Payables to Affiliate, net 920 --
Other 396 333
- ----------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 5,231 3,259
- ----------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES
MINORITY INTEREST OF CONSOLIDATED SUBSIDIARY 54 54
MEMBER'S EQUITY
Membership Interest 2,507 2,296
Undistributed Earnings 980 924
Accumulated Other Comprehensive Income (Loss) (347) (321)
- ----------------------------------------------------------------------------------------------
Total Member's Equity 3,140 2,899
- ----------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND MEMBER'S EQUITY $ 13,478 $ 11,007
==============================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
20
EXELON CORPORATION AND SUBSIDIARY COMPANIES
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONDENSED COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
1. BASIS OF PRESENTATION (Exelon, ComEd, PECO and Generation)
The accompanying consolidated financial statements as of March 31, 2003
and for the three months then ended are unaudited, but in the opinion of
management of Exelon Corporation (Exelon), Commonwealth Edison Company (ComEd),
PECO Energy Company (PECO) and Exelon Generation Company, LLC (Generation)
include all adjustments that are considered necessary for a fair presentation of
their respective financial statements. All adjustments are of a normal,
recurring nature, except as otherwise disclosed. The December 31, 2002
consolidated balance sheets were derived from audited financial statements but
do not include all disclosures required by accounting principles generally
accepted in the United States of America (GAAP). Certain prior-year amounts have
been reclassified for comparative purposes. These reclassifications had no
effect on net income or shareholders' or member's equity. These notes should be
read in conjunction with the Notes to Consolidated Financial Statements of
Exelon, ComEd, PECO and Generation included in or incorporated by reference in
ITEM 8 of their Annual Report on Form 10-K for the year ended December 31, 2002.
2. NEW ACCOUNTING PRINCIPLES AND ACCOUNTING CHANGES (Exelon, ComEd, PECO and
Generation)
Accounting Principles with a Cumulative Effect upon Adoption
SFAS No. 143
Statement of Financial Accounting Standards (SFAS) No. 143, "Accounting
for Asset Retirement Obligations" (SFAS No. 143) provides accounting
requirements for retirement obligations (whether statutory, contractual or as a
result of principles of promissory estoppel) associated with tangible long-lived
assets. Exelon, ComEd, PECO and Generation were required to adopt SFAS No. 143
as of January 1, 2003. In Exelon's case, a significant retirement obligation is
Generation's obligation to decommission its nuclear plants at the end of their
license lives projected to be from 2029 through 2056. These nuclear plants and
the related nuclear decommissioning trust fund investments were transferred to
Generation by ComEd and PECO in connection with the Exelon corporate
restructuring on January 1, 2001.
Generation had decommissioning assets of $3,053 million and $3,032
million as of December 31, 2002 and March 31, 2003, respectively, in trust
accounts. Exelon and Generation anticipate that all trust fund assets will
ultimately be used to decommission its nuclear plants.
After considering recent interpretation of the transitional guidance
included in SFAS No. 143, Exelon recorded income of $112 million (after income
taxes) as a cumulative effect of a change in accounting principle in connection
with its adoption of this standard. The components of the cumulative effect of a
change in accounting principle, after income taxes, recorded in the
21
first quarter of 2003 are as follows:
- ---------------------------------------------------------------------------------------------
Generation (net of income taxes of $52 million) $ 80
Generation's investments in AmerGen Energy Company, LLC and
Sithe Energies, Inc. (net of income taxes of $18 million) 28
ComEd (net of income taxes of $0) 5
Exelon Enterprises Company, LLC (net of income taxes of $(1) million) (1)
- ---------------------------------------------------------------------------------------------
Total $ 112
=============================================================================================
The cumulative effect of the change in accounting principle in adopting
SFAS No. 143 had no impact on PECO's income statement.
The asset retirement obligations (ARO) were determined under SFAS No.
143 to be $2,366 million and $2,363 million for Exelon and Generation,
respectively. As further explained below, the adoption also resulted in
recording regulatory assets and liabilities. The following table provides a
reconciliation of the AROs reflected on the balance sheet at December 31, 2002
and March 31, 2003:
Generation Exelon
- --------------------------------------------------------------------------------
Accumulated Depreciation $2,845 $2,845
Nuclear decommissioning liability for retired units 1,395 1,395
- --------------------------------------------------------------------------------
Decommissioning Obligation at December 31, 2002 4,240 4,240
Net reduction due to adoption of SFAS No. 143 1,877 1,874
- --------------------------------------------------------------------------------
Decommissioning Obligation at January 1, 2003 2,363 2,366
Accretion expense for first quarter 2003 39 40
- --------------------------------------------------------------------------------
Balance at March 31, 2003 $2,402 $2,406
================================================================================
Determination of Asset Retirement Obligation
In accordance with SFAS No. 143, a probability-weighted, discounted
cash flow model with multiple scenarios was used to determine the "fair value"
of the decommissioning obligation. SFAS No. 143 also stipulates that fair value
represent the amount a third party would receive for assuming all of an entity's
obligation.
The present value of future estimated cash flows was calculated using
credit-adjusted risk-free rates applicable to the various businesses in order to
determine the fair value of Exelon's decommissioning obligation at the time of
adoption of SFAS No. 143.
Significant changes in the assumptions underlying the items discussed
above could materially affect the balance sheet amounts and future costs related
to decommissioning recorded in the Consolidated Financial Statements.
Exelon
The following tables set forth Exelon's net income and earnings per
common share for the three months ended March 31, 2002 adjusted as if SFAS No.
143 had been applied effective January 1, 2002.
22
Three Months Ended
March 31, 2002
- ------------------------------------------------------------------------------------------------------------
Reported income before cumulative effect of changes in accounting principles $ 238
Adjustment as if SFAS No. 143 had been applied effective January 1, 2002 10
- ------------------------------------------------------------------------------------------------------------
Adjusted income before cumulative effect of changes in accounting principles $ 248
============================================================================================================
Three Months Ended
March 31, 2002
- ------------------------------------------------------------------------------------------------------------
Reported net income $ 8
Adjustment as if SFAS No. 143 had been applied effective January 1, 2002:
Adjustment to income before cumulative effect of changes in accounting principles 10
Cumulative effect of changes in accounting principles 132
- ------------------------------------------------------------------------------------------------------------
Adjusted net income $ 150
============================================================================================================
Three Months Ended March 31, 2002
---------------------------------
Basic earnings per common share: Reported Adjustment (1) Adjusted
- -------------------------------------------------------------------------------------------------------------------
Income before cumulative effect
of changes in accounting principles $ 0.74 $ 0.03 $ 0.77
Net Income $ 0.02 $ 0.44 $ 0.46
- -------------------------------------------------------------------------------------------------------------------
Three Months Ended March 31, 2002
---------------------------------
Diluted earnings per common share: Reported Adjustment (1) Adjusted
- -------------------------------------------------------------------------------------------------------------------
Income before cumulative effect
of changes in accounting principles $ 0.73 $ 0.03 $ 0.76
Net Income $ 0.02 $ 0.44 $ 0.46
- -------------------------------------------------------------------------------------------------------------------
(1) The adjustment represents the earnings impact as if SFAS No. 143 had been applied effective January 1, 2002.
Effect of adopting SFAS No. 143
Exelon was required to re-measure the decommissioning liabilities at
fair value using the methodology prescribed by SFAS No. 143. The transition
provisions of SFAS No. 143 required Exelon to apply this re-measurement back to
the historical periods in which asset retirement obligations were incurred,
resulting in a re-measurement of these obligations at the date the related
assets were acquired. Since the nuclear plants previously owned by ComEd were
acquired by Exelon on the October 20, 2000 Merger date, Exelon's historical
accounting for its ARO has been revised as if SFAS No. 143 had been in effect at
the Merger date.
In the case of the former ComEd plants, the calculation of the SFAS No.
143 ARO yielded decommissioning obligations lower than the value of the
corresponding trust assets. ComEd has previously collected amounts from
customers (which were subsequently transferred to Generation) in advance of
Generation's recognition of decommissioning expense, under SFAS No. 143. While
it is expected that the trust assets will ultimately be used entirely for the
decommissioning of the plants, the current measurement required by SFAS No. 143
shows an excess of assets over related ARO liabilities. As such, in accordance
with regulatory accounting practices and a December 2000 ICC Order, a regulatory
liability of $948 million and a corresponding receivable from Generation were
recorded at ComEd upon the adoption of SFAS No. 143. Exelon believes that all of
the decommissioning assets, including the $73 million of annual collections
through 2006, will be used to decommission the former ComEd plants.
23
Accordingly, Exelon expects the regulatory liability and corresponding
receivable from Generation will be reduced to zero at the conclusion of the
decommissioning of the former ComEd plants.
In the case of the former PECO plants, the SFAS No. 143 ARO calculation
yielded decommissioning obligations greater than the corresponding trust assets.
As such, a regulatory asset of $20 million and a corresponding payable to
Generation were recorded upon adoption at PECO. Exelon also expects the
regulatory asset and corresponding payable to Generation will be reduced to zero
at the conclusion of the decommissioning of the former PECO plants.
Prior to the adoption of SFAS No. 143, Generation's Accumulated
Depreciation included $2,845 million for decommissioning liabilities related to
the active plants. This amount was reclassified to an ARO upon the adoption of
SFAS No. 143. Additionally, Generation adjusted the total decommissioning
liability for the ComEd plants to $1,575 million and for the PECO plants to $787
million. As described above, Generation recorded a payable to ComEd of $948
million and a receivable from PECO of $20 million. Generation also recorded an
Asset Retirement Cost asset (ARC) of $172 million related to the establishment
of the PECO ARO in accordance with SFAS No. 143. The ARC will be amortized over
the remaining lives of the plants.
As discussed above, Exelon re-measured its 2001 decommissioning related
balances associated with the October 2000 Merger purchase price allocation at
ComEd and the January 2001 corporate restructuring as if SFAS No. 143 had been
in effect at the Merger date. Exelon and ComEd concluded that had SFAS No. 143
been in effect, ComEd would not have recorded an impairment on its regulatory
asset for decommissioning of its retired nuclear plants as a purchase price
allocation adjustment in 2001 as a result of the December 2000 ICC order.
Increased net assets would have been transferred to Generation by ComEd in the
corporate restructuring. Accordingly, Exelon recorded a reduction of goodwill of
approximately $210 million, with a corresponding reduction in its overall
decommissioning obligation in connection with the implementation of SFAS No. 143
on January 1, 2003. Similarly, ComEd recorded a reduction of $210 million of
goodwill and of shareholders' equity, and Generation recorded a $210 million
increase in member's equity and a corresponding reduction of its decommissioning
obligation. In addition, Exelon and ComEd recorded a cumulative effect of a
change in accounting principle of $5 million to reverse goodwill amortization
that had been recorded in 2001. Exelon and ComEd also reclassified a regulatory
asset related to nuclear decommissioning costs for retired units of $248 million
to regulatory liabilities.
The following tables set forth ComEd and Generation's net income and
Generation's income before cumulative effect of changes in accounting principles
for the three months ended March 31, 2002 adjusted as if SFAS No. 143 had been
applied effective January 1, 2002. ComEd's income before cumulative effect of a
change in accounting principle was not affected by the adoption of SFAS No. 143.
24
Three Months Ended
ComEd March 31, 2002
- ------------------------------------------------------------------------------------------------------------
Reported net income $ 129
Adjustment as if SFAS No. 143 had been applied effective January 1, 2002:
Cumulative effect of a change in accounting principle 5
- ------------------------------------------------------------------------------------------------------------
Adjusted net income $ 134
============================================================================================================
Three Months Ended
Generation March 31, 2002
- ------------------------------------------------------------------------------------------------------------
Reported income before cumulative effect of changes in accounting principles $ 66
Adjustment as if SFAS No. 143 had been applied effective January 1, 2002 10
- ------------------------------------------------------------------------------------------------------------
Adjusted income before cumulative effect of changes in accounting principles $ 76
============================================================================================================
Three Months Ended
Generation March 31, 2002
- ------------------------------------------------------------------------------------------------------------
Reported net income $ 79
Adjustment as if SFAS No. 143 had been applied effective January 1, 2002:
Adjustment to income before cumulative effect of a change in accounting principle 10
Cumulative effect of a change in accounting principle 128
- ------------------------------------------------------------------------------------------------------------
Adjusted net income $ 217
============================================================================================================
Accounting methodology under SFAS No. 143
For the former ComEd plants, realized gains and losses on
decommissioning trust funds are reflected in other income and deductions in
Generation's Consolidated Statements of Income, while the unrealized gains and
losses on marketable securities held in the trust funds adjust the payable
Generation currently has to ComEd. The increases in the ARO are recorded in
accretion expense, while the funds received from ComEd for decommissioning are
recorded in revenue. Generation's payable to ComEd will be adjusted to reflect
the difference between the decommissioning assets and the ARO levels. As such,
if the ARO increases at a rate faster than the increase in the trust fund
assets, ComEd's regulatory liability and receivable from Generation will
decrease. If and when the trust assets are exceeded by the decommissioning
liability, Generation is responsible for any shortfall in funding. The result of
the above accounting will be adjusted to reflect no earnings impact to
Generation for as long as the trust assets exceed the decommissioning
liabilities for the former ComEd plants.
The above accounting practices are also applicable for former PECO
plants owned by Generation, with the addition of the depreciation expense
Generation will recognize on the ARC established upon adoption of SFAS No. 143.
However, as PECO has the expectation of full recovery of decommissioning costs,
the result of the above accounting will be adjusted to reflect no earnings
impact to Generation. Therefore, to the extent that the net of decommissioning
revenues collected and realized investment income differ from the accretion
expense to the decommissioning liability and the related depreciation of the
ARC, an adjustment to net the amounts to zero would be recorded by Generation
for that period.
The ongoing effects to Generation for the accounting for the
decommissioning of the AmerGen Energy Company, LLC (AmerGen) plants are recorded
within Generation's equity in earnings of AmerGen.
25
SFAS No. 141 and SFAS No. 142
In 2001, the 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, ComEd, PECO and Generation 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.
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 October 20, 2000 merger of
Unicom Corporation (Unicom), the former parent company of ComEd, and PECO
(Merger) recorded on ComEd's Consolidated Balance Sheets, with the remainder
related to Exelon Enterprises Company, LLC (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 Inc. (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 impairment was recorded as a cumulative effect of a change in
accounting principle in the first quarter of 2002.
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)
=================================================================================================
At March 31, 2003, Exelon had goodwill of $4.8 billion of which $4.7
billion relates to ComEd and the remaining goodwill relates to Enterprises'
reporting units. Consistent with SFAS No. 142, the remaining goodwill is
reviewed for impairment on an annual basis, or more
26
frequently if significant events occur that could indicate an impairment exists.
ComEd and Enterprises perform their annual reviews in the fourth quarter of
their fiscal years. The annual update impairment review during the fourth
quarter of 2002 did not identify any goodwill impairment.
Other Accounting Principles and Accounting Changes
EITF Issue 02-3
In the third quarter of 2002, Exelon and Generation adopted the
provisions of FASB Emerging Issue Task Force (EITF) Issue No. 02-3, "Accounting
for Contracts Involved in Energy Trading and Risk Management Activities" (EITF
02-3) issued by the 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 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 to revenue in the results of operations for the
three months ended March 31, 2002 to conform to the net basis of presentation
required by EITF 02-3.
SFAS No. 146
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. Exelon, ComEd, PECO
and Generation's results of operations were unaffected by the adoption SFAS No.
146.
FIN No. 45
In November 2002, the FASB released FASB Interpretation (FIN) No. 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, ComEd, PECO and Generation adopted the
disclosure requirements under FIN No. 45, which were effective for financial
statements for periods ended after December 15, 2002. The recognition and
measurement provisions of FIN No. 45 were effective for guarantees issued or
modified after December 31, 2002. The adoption of FIN No. 45 had no material
effect on Exelon, ComEd, PECO or Generation's results of operations. Liabilities
associated with guarantees entered into during the first quarter of 2003 are
reflected in Note 8 - Commitments and Contingencies.
27
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 was effective for financial statements for fiscal years ended after
December 15, 2002. Exelon 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, "Accounting for Stock-Based
Compensation" (SFAS No. 123). The tables below show the effect on net income and
earnings per share for Exelon and the effect on net income for ComEd, PECO and
Generation had Exelon elected to account for stock-based compensation plans
using the fair value method under SFAS No. 123 for the three months ended March
31, 2003 and 2002:
Exelon
Three Months Ended March 31,
----------------------------
2003 2002
- ----------------------------------------------------------------------------------------
Net income - as reported $ 361 $ 8
Deduct: Total stock-based compensation expense
determined under fair value based method for all
awards, net of income taxes (5) (8)
- ----------------------------------------------------------------------------------------
Pro forma net income $ 356 $ --
========================================================================================
Earnings per share:
Basic - as reported $ 1.11 $ 0.02
Basic - pro forma $ 1.10 $ --
Diluted - as reported $ 1.11 $ 0.02
Diluted - pro forma $ 1.09 $ --
- ----------------------------------------------------------------------------------------
ComEd
Three Months Ended March 31,
----------------------------
2003 2002
- ----------------------------------------------------------------------------------------
Net income - as reported $ 195 $ 129
Deduct: Total stock-based compensation expense
determined under fair value based method for all
awards, net of income taxes (1) (3)
- ----------------------------------------------------------------------------------------
Pro forma net income $ 194 $ 126
========================================================================================
28
PECO
Three Months Ended March 31,
----------------------------
2003 2002
- -----------------------------------------------------------------------------------
Net income on common stock- as reported $ 135 $ 87
Deduct: Total stock-based compensation expense
determined under fair value based method for all
awards, net of income taxes (1) (3)
- -----------------------------------------------------------------------------------
Pro forma net income $ 134 $ 84
===================================================================================
Generation
Three Months Ended March 31,
---------------------------
2003 2002
- -----------------------------------------------------------------------------------
Net income - as reported $ 56 $ 79
Deduct: Total stock-based compensation expense
determined under fair value based method for all
awards, net of income taxes (1) (4)
- -----------------------------------------------------------------------------------
Pro forma net income $ 55 $ 75
===================================================================================
FIN No. 46
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 No. 46 on
Exelon, ComEd, PECO and Generation's consolidated financial position, results of
operations and cash flows has not been determined.
SFAS No. 149
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement
133 on Derivative Instruments and Hedging Activities" (SFAS No. 149). SFAS No.
149 amends and clarifies financial accounting and reporting for derivative
instruments, including certain derivative instruments embedded in other
contacts, and for hedging activities under SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities" (SFAS No. 133). SFAS No. 149 also
amends SFAS No. 133 for decisions made (1) as part of the Derivatives
Implementation Group process that effectively required amendments to SFAS No.
133, (2) in connection with other FASB projects dealing with financial
instruments, and (3) in connection with implementation issues raised in relation
to the application of the definition of a derivative.
SFAS No. 149 is effective for contracts entered into or modified after
June 30, 2003, except as stated below, and for hedging relationships designated
after June 30, 2003. In addition, except as stated below, all provisions of SFAS
No. 149 will be applied prospectively.
The provisions of SFAS No. 149 that relate to SFAS No. 133
implementation issues that have been effective for fiscal quarters that began
prior to June 15, 2003 should continue to be applied in accordance with their
respective effective dates. In addition, certain provisions relating to forward
purchases or sales of when-issued securities or other securities that do not yet
exist, should be applied to both existing contracts and new contracts entered
into after June 30,
29
2003. Exelon, ComEd, PECO and Generation are currently determining the impact of
the adoption of SFAS No. 149 on their financial position and results of
operations.
Change in Accounting Estimate
ComEd
Effective July 1, 2002, ComEd lowered its depreciation rates based on a
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, was
estimated to be approximately $100 million ($60 million, after income taxes). As
a result of the change, net income for the three months ended March 31, 2003
increased approximately $24 million ($14 million, after income taxes).
3. ACQUISITIONS AND DISPOSITIONS (Exelon and Generation)
Sithe New England Holdings Acquisition
On November 1, 2002, Generation purchased the assets of Sithe New
England Holdings, LLC (currently known as Exelon New England), a subsidiary of
Sithe Energies, Inc. (Sithe), and related power marketing operations. Exelon New
England's primary assets are gas-fired facilities currently under construction.
The purchase price for the Exelon New England assets consisted of a $534 million
note to Sithe, $14 million of direct acquisition costs and a $208 million
adjustment to Generation's investment in Sithe related to Exelon New England.
Additionally, Generation assumed various Sithe guarantees. Generation's assumed
guarantees are related to an equity contribution agreement between Exelon New
England and Sithe Boston Generating, LLC (currently known as Exelon Boston
Generating, LLC (EBG)), a project subsidiary of Exelon New England. The equity
contribution agreement requires, among other things, that Exelon 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. EBG
has a $1.25 billion credit facility (EBG Facility), which was entered into
primarily to finance the construction of these two generating facilities. The
$1.0 billion of debt outstanding under the credit facility at March 31, 2003 is
reflected on Exelon and Generation's Consolidated Balance Sheets. Exelon New
England owns 4,066 megawatts (MWs) of generation capacity, consisting of 1,645
MWs in operation and 2,421 MWs under construction. Exelon New England's
generation facilities are located primarily in Massachusetts.
30
The allocation of the preliminary purchase price to the fair value of
assets acquired and liabilities assumed in the acquisition is as follows:
- --------------------------------------------------------------------------------
Current Assets (including $12 million of cash acquired) $ 82
Property, Plant and Equipment 1,956
Deferred Debits and Other Assets 62
Current Liabilities (159)
Deferred Credits and Other Liabilities (149)
Long-Term Debt (1,036)
- --------------------------------------------------------------------------------
Total Purchase Price $ 756
================================================================================
The purchase price has been adjusted in the first quarter of 2003 for a
$64 million reclassification from Generation's investment in Sithe to property,
plant and equipment.
The EBG Facility provides that if these construction projects are not
completed by June 12, 2003, the EBG Facility lenders will have the right, but
will not be required to, among other things, declare all amounts then
outstanding under the EBG Facility to be due, to terminate the interest rate
swap agreements, foreclose on all the pledged assets or ownership of the project
subsidiaries, or require that all cash held by the project subsidiaries be used
to reduce the debt. An event of default under the EBG Facility does not
constitute an event of default under any other debt instruments of Exelon or its
subsidiaries. Generation believes that the construction projects will be
substantially complete by June 12, 2003, but that all of the requirements may
not be met by that date. However, Generation continues to monitor and evaluate
its construction progress as to whether the requirements of the EBG Facility
relating to the construction projects can be satisfied by June 12, 2003.
Generation currently expects that arrangements for amendments or waivers, if
necessary, can be negotiated with the EBG Facility lenders in the event that the
requirements are not satisfied by June 12, 2003.
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-MW Mountain Creek Steam Electric Station in Dallas and
the 1,441-MW 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 has agreed to fixed capacity and variable
expense payments, and to 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 a gain of $201 million ($116 million after
income taxes) in Other Income and Deductions on Exelon's Consolidated Statements
of Income.
31
4. REGULATORY ISSUES (Exelon and ComEd)
On March 3, 2003, ComEd entered into an agreement with various Illinois
electric retail market suppliers, key customer groups and governmental parties
regarding several matters affecting ComEd's rates for electric service
(Agreement). The Agreement addressed, among other things, issues related to
ComEd's residential delivery services rate proceeding, market value index
proceeding, the process for competitive service declarations for large-load
customers and an extension of the purchased power agreement (PPA) with
Generation. The parties to the Agreement agreed to make and support a series of
coordinated filings intended to lead to the issuance by the ICC of orders
consistent with the Agreement. Those orders, which were issued on March 28,
2003, are subject to rehearing. Rehearing requests have been filed with the ICC.
Rehearing requests may be considered through the middle of May 2003. The
Agreement will not become effective as long as any of the ICC orders are subject
to any pending rehearing request or if a stay is issued with respect to any of
those orders.
During the first quarter of 2003, ComEd recorded a charge to earnings,
associated with the funding of specified programs and initiatives associated
with the Agreement, of $51 million on a present value basis before income taxes.
This amount is partially offset by the reversal of a $12 million (before income
taxes) reserve established in the third quarter of 2002 for a potential capital
disallowance in ComEd's delivery services rate proceeding, and a credit of $10
million (before income taxes) related to the capitalization of employee
incentive payments provided for in the delivery services order. The net one-time
charge for these items was $29 million (before income taxes).
5. EARNINGS PER SHARE (Exelon)
Diluted earnings per share are calculated by dividing net income by the
weighted average number of 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):
Three Months Ended March 31,
----------------------------
2003 2002
- --------------------------------------------------------------------------------
Average Common Shares Outstanding 324 321
Assumed Exercise of Stock Options 2 2
- --------------------------------------------------------------------------------
Average Dilutive Common Shares Outstanding 326 323
================================================================================
There were five million stock options not included in average common
shares used in calculating diluted earnings per share due to their antidilutive
effect for the three months ended March 31, 2003 and 2002.
32
6. SEGMENT INFORMATION (Exelon, ComEd, PECO and Generation)
Exelon operates in three business segments: energy delivery (including
ComEd and PECO), generation (includes Generation) and enterprises. Exelon
evaluates the performance of its business segments on the basis of net income.
ComEd, PECO and Generation each operate in a single business segment. Exelon's
segment information for the three months ended March 31, 2003 and 2002 and at
March 31, 2003 and December 31, 2002 is as follows:
Corporate and
Energy Intersegment
Delivery Generation Enterprises Eliminations Consolidated
- --------------------------------------------------------------------------------------------------------------------
Total Revenues (1):
2003 $ 2,642 $ 1,879 $ 580 $ (1,027) $ 4,074
2002 2,335 1,461 490 (929) 3,357
Intersegment Revenues:
2003 $ 16 $ 993 $ 19 $ (1,028) $ --
2002 14 892 25 (931) --
Income (Loss) Before Income Taxes and the Cumulative Effect of Changes in Accounting Principles:
2003 $ 517 $ (73) $ (30) $ (17) $ 397
2002 341 111 (47) (19) 386
Income Taxes:
2003 $ 192 $ (21) $ (13) $ (10) $ 148
2002 126 45 (19) (4) 148
Cumulative Effect of Changes in Accounting Principles:
2003 $ 5 $ 108 $ (1) $ -- $ 112
2002 -- 13 (243) -- (230)
Net Income (Loss):
2003 $ 330 $ 56 $ (18) $ (7) $ 361
2002 215 79 (271) (15) 8
Total Assets:
March 31, 2003 $ 26,984 $ 13,478 $ 1,283 $ (1,844) $ 39,901
December 31, 2002 26,550 11,007 1,297 (1,376) 37,478
- --------------------------------------------------------------------------------------------------------------------
(1) $62 million and $57 million in utility taxes are included in the Revenues
and Expenses for the three months ended March 31, 2003 and 2002,
respectively, for ComEd. $51 million and $44 million in utility taxes are
included in the Revenues and Expenses for the three months ended March 31,
2003 and 2002, respectively, for PECO.
7. FAIR VALUE OF FINANCIAL ASSETS AND LIABILITIES (Exelon, ComEd, PECO and
Generation)
During the three months ended March 31, 2003 and 2002, Exelon recorded
pre-tax gains and (losses) in other comprehensive income relating to
mark-to-market (MTM) adjustments of contracts designated as cash flow hedges as
follows:
ComEd PECO Generation Enterprises Exelon
- ---------------------------------------------------------------------------------------------------------
Three months ended March 31, 2003 $ 1 $ 3 $ (294) $ 4 $ (286)
Three months ended March 31, 2002 $ (2) $ 6 $ (122) $ 17 $ (101)
- ---------------------------------------------------------------------------------------------------------
Generation recognized net MTM losses on non-trading energy derivative
contracts not designated as cash flow hedges, in Purchased Power on Generation's
Consolidated Statements of
33
Income of $31 million during the three months ended March 31, 2003 and gains of
$6 million during the three months ended March 31, 2002.
Generation recognized net MTM losses on proprietary trading contracts
in earnings of $2 million during the three months ended March 31, 2003 and net
MTM gains of $1 million during the three months ended March 31, 2002.
During the three months ended March 31, 2003 and 2002, no amounts were
reclassified to other income in the Consolidated Statements of Income and
Comprehensive Income as a result of the discontinuance of cash flow hedges
related to certain forecasted financing transactions that were no longer
probable of occurring.
During the three months ended March 31, 2003 and 2002, Generation did
not reclassify any amounts from accumulated other comprehensive income into
earnings as a result of forecasted energy commodity transactions no longer being
probable.
As of March 31, 2003, deferred net gains/(losses) on derivative
instruments accumulated in other comprehensive income that are expected to be
reclassified to earnings during the next twelve months are as follows:
ComEd PECO Generation Enterprises Exelon
- -----------------------------------------------------------------------------------------------------------------------
Net Gains (Losses) Expected to be Reclassified $ -- $ 14 $ (364) $ 5 $ (345)
- -----------------------------------------------------------------------------------------------------------------------
Amounts in accumulated other comprehensive income related to interest
rate cash flow hedges 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.
As of March 31, 2003, ComEd expects to amortize during the next
twelve months $7 million of regulatory assets for settled cash flow swaps.
During the first quarter 2003, ComEd reclassified $51 million ($30 million,
after income taxes) from other comprehensive income to regulatory assets for
cash flow swaps settled during the quarter.
ComEd has also entered into interest rate swaps to effectively convert
$485 million in fixed-rate debt to floating rate debt. 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 swaps will be recorded in earnings. However, as long as
the hedge remains effective, 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 hedge as a result of ineffectiveness would be recorded
immediately in earnings. As of March 31, 2003, these swaps had an aggregate fair
market value of $42 million which was classified as Other Deferred Debits and
Other Assets within the Consolidated Balance Sheets.
Generation 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 cost bases for
the securities held in these trust accounts.
34
March 31, 2003
----------------------------------------------------------
Gross Gross
Amortized Unrealized Unrealized Estimated
Cost Gains Losses Fair Value
- ------------------------------------------------------------------------------------------------
Equity securities $ 1,852 $ 53 $ (532) $ 1,373
Debt securities
Government obligations 916 55 (2) 969
Other debt securities 693 33 (36) 690
- ------------------------------------------------------------------------------------------------
Total debt securities 1,609 88 (38) 1,659
- ------------------------------------------------------------------------------------------------
Total available-for-sale securities $ 3,461 $ 141 $ (570) $ 3,032
================================================================================================
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
================================================================================================
Net unrealized losses of $429 million were recognized in Regulatory
Assets, Regulatory Liabilities and Accumulated Other Comprehensive Income in
Exelon's Consolidated Balance Sheet at March 31, 2003. Net unrealized losses of
$429 million were recognized in noncurrent affiliate payables and receivables
and Accumulated Other Comprehensive Income in Generation's Consolidated Balance
Sheet as of March 31, 2003. Net unrealized losses of $346 million were
recognized in Accumulated Depreciation and Accumulated Other Comprehensive
Income in the Consolidated Balance Sheets of Exelon and Generation at December
31, 2002.
Three months ended March 31,
-----------------------------
2003 2002
- ----------------------------------------------------------------------------
Proceeds from sales $ 572 $ 580
Gross realized gains 15 18
Gross realized losses (8) (32)
- ----------------------------------------------------------------------------
Net realized gains of $7 million and net realized losses of $10 million
for the three months ended March 31, 2003 and 2002 respectively, were recorded
in other income and deductions. Net realized losses of $4 million for the three
months ended March 31, 2002 were recognized in Accumulated Depreciation. The
available-for-sale securities held at March 31, 2003 have an average maturity of
eight to ten years. The cost of these securities was determined on the basis of
specific identification.
35
8. COMMITMENTS AND CONTINGENCIES (Exelon, ComEd, PECO and Generation)
For information regarding capital commitments, nuclear decommissioning
and spent fuel storage, see the Commitments and Contingencies and Nuclear
Decommissioning and Spent Fuel Storage Notes in the Notes to Consolidated
Financial Statements of Exelon, ComEd, PECO and Generation for the year ended
December 31, 2002. See Note 4 - New Accounting Principles and Accounting Changes
for further discussion of nuclear decommissioning commitments and contingencies.
Environmental Liabilities
As of March 31, 2003, Exelon had accrued $143 million for
environmental investigation and remediation costs that currently can be
reasonably estimated, including $114 million for manufactured gas plant (MGP)
investigation and remediation. Exelon has identified 71 sites where former MGP
activities have or may have resulted in actual site contamination.
As of March 31, 2003, ComEd had accrued $92 million for environmental
investigation and remediation costs that currently can be reasonably estimated.
This reserve included $87 million (discounted) for MGP investigation and
remediation.
As of March 31, 2003, PECO had accrued $37 million (undiscounted) for
environmental investigation and remediation costs that currently can be
reasonably estimated, including $27 million for MGP investigation and
remediation.
As of March 31, 2003, Generation had accrued $14 million (undiscounted)
for environmental investigation and remediation cost, none of which relates to
MGP investigation and remediation.
Exelon, ComEd, PECO and Generation cannot predict the extent to which
they will incur other significant liabilities for additional investigation and
remediation costs at these or additional sites identified by environmental
agencies or others, or whether such costs may be recoverable from third parties.
36
Energy Commitments
Exelon and Generation had long-term commitments relating to the net
purchase and sale of energy, capacity and transmission rights from unaffiliated
utilities, including Midwest Generation, LLC (Midwest Generation), and others,
including AmerGen, as expressed in the following table:
Net Capacity Power Only Power Only Purchases from Transmission Rights
-------------------------
Purchases (1) Sales AmerGen Non-Affiliates Purchases (2)
- ----------------------------------------------------------------------------------------------------
2003 $ 543 $2,367 $ 187 $1,625 $ 64
2004 765 1,356 315 1,036 93
2005 426 431 488 319 84
2006 397 124 493 243 3
2007 475 31 227 212 --
Thereafter 3,821 1 1,590 843 --
- ----------------------------------------------------------------------------------------------------
Total $6,427 $4,310 $3,300 $4,278 $ 244
====================================================================================================
(1) Net Capacity Purchases includes Midwest Generation commitments as of
March 31, 2003. On October 2, 2002, Generation notified Midwest Generation
of its exercise of termination options under the existing Collins
Generating Station (Collins) PPA and Peaking Unit (Peaking) PPA. 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 PPA. 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 PPA 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. 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.
Additionally, Generation has the following energy commitments:
In connection with the 2001 corporate restructuring, Generation entered
into a PPA with ComEd under which Generation has agreed to supply all of ComEd's
load requirements through 2004. Prices for this energy vary depending upon the
time of day and month of delivery. During 2005 and 2006, ComEd's PPA is a
partial requirements agreement under which ComEd will purchase all of its
required energy and capacity from Generation, up to the available capacity of
the nuclear generating plants formerly owned by ComEd and transferred to
Generation. Under the terms of the PPA, Generation is responsible for obtaining
any required transmission service, subject to ComEd's obligation to obtain
network service over the ComEd system. The PPA also specifies that prior to
2005, ComEd and Generation will jointly determine and agree on a market-based
price for energy delivered under the PPA for 2005 and 2006. In the event that
the parties cannot agree to market-based prices for 2005 and 2006 prior to July
1, 2004, ComEd has the option of terminating the PPA effective December 31,
2004. ComEd will obtain any additional supply required from market sources in
2005 and 2006, and subsequent to 2006, will obtain all of its supply from market
sources, which could include Generation. The PPA for 2005 and 2006 may be
extended to a full requirements contract as a result of the Agreement (See Note
4 - Regulatory Issues).
In connection with the 2001 corporate restructuring, Generation entered
into a PPA with PECO under which Generation has agreed to supply PECO with
substantially all of PECO's electric supply needs through 2010. Also, under the
restructuring, PECO assigned its rights and
37
obligations under various PPAs and fuel supply agreements to Generation.
Generation supplies power to PECO from the transferred generation assets,
assigned PPAs and other market sources.
Under terms of the 2001 corporate restructuring, ComEd remits to
Generation any amounts collected from customers for nuclear decommissioning.
Under an agreement effective September 2001, PECO remits to Generation any
amounts collected from customers for nuclear decommissioning.
Litigation
Exelon
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.
ComEd
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. ComEd filed a request for rehearing. On April 30, 2001,
FERC issued an order granting rehearing in which it determined that its 1998
order had been erroneous and that no refunds were due from ComEd to the
municipal customers. 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. ComEd currently believes that the outcome of this matter will
not have a material impact on its results of operations or financial condition.
Retail Rate Law. In 1996, several developers of non-utility generating
facilities filed litigation against various Illinois officials claiming that the
enforcement against those facilities of an amendment to Illinois law removing
the entitlement of those facilities to state-subsidized payments for electricity
sold to ComEd after March 15, 1996 violated their rights under the Federal and
state constitutions. The developers also filed suit against ComEd for a
declaratory judgment that their rights under their contracts with ComEd were not
affected by the amendment. On November 25, 2002, the court granted the
developers' motions for summary
38
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.
Service Interruptions. In August 1999, three class action lawsuits were
filed against ComEd, and subsequently consolidated, in the Circuit Court of Cook
County, Illinois seeking damages for personal injuries, property damage and
economic losses related to a series of service interruptions that occurred in
the summer of 1999. The combined effect of these interruptions resulted in over
168,000 customers losing service for more than four hours. Conditional class
certification was approved by the court for the sole purpose of exploring
settlement. ComEd filed a motion to dismiss the complaints. On April 24, 2001,
the court dismissed four of the five counts of the consolidated complaint
without prejudice and the sole remaining count was dismissed in part. On June 1,
2001, the plaintiffs filed a second amended consolidated complaint and ComEd has
filed an answer. On December 5, 2002, a settlement was reached, pending court
approval, whereby ComEd will pay up to $8 million, which includes $4 million
paid to date. The settlement, when approved, will release ComEd from all claims
arising from the 1999 power outages. A portion of any settlement or verdict may
be covered by insurance.
Generation
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. On April 22, 2003, the Tenth Circuit Court of Appeals reversed both
judgments and remanded the cases for retrial. Cotter intends to vigorously
defend each case.
39
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 U.S. 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 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 acquired in November 2002, 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 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 million) and additional damages of $16
million. Raytheon also has asserted a claim in the amount of approximately $12
million for loss of efficiency and productivity as a result of an alleged
constructive acceleration. 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.
Clean Air Act. On June 1, 2001, the EPA issued to EBG a Notice of
Violation (NOV) and Reporting Requirement pursuant to Sections 113 and 114 of
the Clean Air Act, alleging numerous exceedances of opacity limits and
violations of opacity-related monitoring, recording and reporting requirements
at Mystic Station in Everett, Massachusetts. On January 8, 2002, the EPA
indicated that it had decided to resolve the NOV through an administrative
compliance order and a judicial civil penalty action. In March 2002, the EPA
issued and Sithe Mystic LLC, a wholly owned subsidiary of EBG, voluntarily
entered a Compliance Order and Reporting Requirement (Compliance Order)
regarding Mystic Station, under which Mystic Station installed
40
new ignition equipment on three of the four units at the plant. Mystic Station
also undertook an extensive opacity monitoring and testing program for all four
units at the plant to help determine if additional compliance measures were
needed. Pursuant to the requirements of the Compliance Order, the EBG switched
three of the four units to a lower sulfur fuel oil by June 1, 2002. The
Compliance Order does not address civil penalties. By a letter dated April 21,
2003, the United States Department of Justice notified EBG that, at the request
of the EPA, it intended to bring a civil penalty action, but also offered to the
opportunity to resolve the matter through settlement discussions. EBG is
pursuing settlement discussions with the EPA and the Department of Justice.
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.
Exelon, ComEd, PECO and Generation
Exelon, ComEd, PECO and Generation are 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 their respective financial condition or results of operations.
41
Commercial Commitments
Exelon, ComEd, PECO and Generation's commercial commitments as of March
31, 2003, 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 their obligations,
are as follows:
Expiration within
----------------------------------------------------------------
2008
Exelon Total 2003 2004-2005 2006-2007 and beyond
- --------------------------------------------------------------------------------------------------------------------
Related to Obligations Recorded on the Balance Sheet
- ----------------------------------------------------
Credit Facility (a) $ 1,500 $ 1,500 $ -- $ -- $ --
Letters of Credit (non-debt) (b) 112 99 13 -- --
Letters of Credit (long-term debt) (c) 456 175 281 -- --
Insured Long-Term Debt (d) 254 -- -- -- 254
Preferred Securities Guarantee (e) 128 -- -- -- 128
Preferred Securities Guarantees (f) 350 -- -- -- 350
Guarantees of Long-Term Debt (g) 40 -- -- -- 40
Midwest Generation Capacity
Reservation Agreement Guarantee (h) 35 3 7 7 18
Other
- -----
Guarantees of Letters of Credit (i) 93 87 6 -- --
Performance Guarantees (j) 108 5 2 -- 101
Surety Bonds (k) 539 256 78 12 193
Energy Marketing Contract
Guarantees (l) 145 110 35 -- --
Nuclear Insurance Guarantees (m) 1,380 -- -- -- 1,380
Lease Guarantees (n) 13 -- -- 2 11
Exelon New England
Equity Guarantee (o) 38 38 -- -- --
- --------------------------------------------------------------------------------------------------------------------
Total $ 5,191 $ 2,273 $ 422 $ 21 $ 2,475
====================================================================================================================
Expiration within
----------------------------------------------------------------
2008
ComEd Total 2003 2004-2005 2006-2007 and beyond
- --------------------------------------------------------------------------------------------------------------------
Related to Obligations Recorded on the Balance Sheet
- ----------------------------------------------------
Credit Facility (a) $ 100 $ 100 $ -- $ -- $ --
Letters of Credit (non-debt) (b) 23 23 -- -- --
Letters of Credit (long-term debt) (c) 92 92 -- -- --
Insured Long-Term Debt (d) 100 -- -- -- 100
Preferred Securities Guarantees (f) 350 -- -- -- 350
Midwest Generation Capacity
Reservation Agreement Guarantee (h) 35 3 7 7 18
Other
- -----
Performance Guarantees (j) 7 5 2 -- --
Surety Bonds (k) 18 18 -- -- --
- --------------------------------------------------------------------------------------------------------------------
Total $ 725 $ 241 $ 9 $ 7 $ 468
====================================================================================================================
42
Expiration within
----------------------------------------------------------------
2008
PECO Total 2003 2004-2005 2006-2007 and beyond
- --------------------------------------------------------------------------------------------------------------------
Related to Obligations Recorded on the Balance Sheet
- ----------------------------------------------------
Credit Facility (a) $ 600 $ 600 $ -- $ -- $ --
Letters of Credit (non-debt) (b) 30 30 -- -- --
Letters of Credit (long-term debt) (c) 17 17 -- -- --
Insured Long-Term Debt (d) 154 -- -- -- 154
Preferred Securities Guarantee (e) 128 -- -- -- 128
Other
- -----
Surety Bonds (k) 46 46 -- -- --
- --------------------------------------------------------------------------------------------------------------------
Total $ 975 $ 693 $ -- $ -- $ 282
====================================================================================================================
Expiration within
----------------------------------------------------------------
2008
Generation Total 2003 2004-2005 2006-2007 and beyond
- --------------------------------------------------------------------------------------------------------------------
Related to Obligations Recorded on the Balance Sheet
- ----------------------------------------------------
Credit Facility (a) $ -- $ -- $ -- $ -- $ --
Letters of Credit (non-debt) (b) 14 9 5 -- --
Letters of Credit (long-term debt) (c) 347 66 281 -- --
Other
- -----
Guarantees of Letters of Credit (i) 66 66 -- -- --
Performance Guarantees (j) 101 -- -- -- 101
Surety Bonds (k) 43 -- -- -- 43
Energy Marketing Contract
Guarantees (l) 25 25 -- -- --
Nuclear Insurance Guarantees (p) 134 -- -- -- 134
Exelon New England
Equity Guarantee (o) 38 38 -- -- --
- --------------------------------------------------------------------------------------------------------------------
Total $ 768 $ 204 $ 286 $ -- $ 278
====================================================================================================================
(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 March 31, 2003, there were no borrowings against the
credit facility. Additionally, at March 31, 2003, commercial paper
outstanding was as follows:
Exelon Consolidated $ 1,150
ComEd 45
PECO 493
Generation --
At March 31, 2003, $250 million of Exelon and PECO's commercial paper
was classified as long-term debt.
(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) Preferred Securities Guarantees - Guarantees issued to guarantee the
preferred securities of the subsidiary trusts of PECO.
(f) Preferred Securities Guarantees - Guarantees issued to guarantee the
preferred securities of the subsidiary trusts of ComEd.
(g) Guarantees of Long-Term Debt - Issued to guarantee payment of
Enterprises' debt.
(h) Midwest Generation Capacity Reservation Agreement Guarantee - In
connection with ComEd's agreement with the City of Chicago (Chicago)
entered into on February 20, 2003, Midwest Generation assumed from
Chicago a Capacity Reservation Agreement which Chicago had entered into
with Calumet Energy Team, LLC. ComEd will reimburse Chicago for any
nonperformance by Midwest Generation under the Capacity Reservation
Agreement. The fair value of
43
this guarantee under FIN 45 of $4 million is included as a liability on
Exelon and ComEd's Consolidated Balance Sheets. Additional information
regarding this reserve is included within this section under the heading
"General" below.
(i) 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.
(j) Performance Guarantees - Guarantees issued to ensure performance under
specific contracts.
(k) Surety Bonds - Guarantees issued related to contract and commercial
surety bonds, excluding bid bonds.
(l) Energy Marketing Contract Guarantees - Guarantees issued to ensure
performance under energy commodity contracts.
(m) 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.
(n) Lease Guarantees - Guarantees issued to ensure payments on building
leases.
(o) Exelon New England Equity Guarantee- See Note 3 - Acquisitions and
Dispositions for further information on the $38 million guarantee. After
construction of the EBG facilities is complete, Exelon could be required
to guarantee up to an additional $42 million in order to ensure that the
EBG facilities have adequate funds available for potential outage and
other operating costs and requirements.
(p) Nuclear Insurance Guarantee - Guarantees of nuclear insurance required
under the Price-Anderson Act. This amount relates to Generation's
guarantee of AmerGen's plants. Exelon has a $1.2 billion guarantee
relating to Generation's directly owned plants that is not included in
this amount.
Unconsolidated Equity Investments
Generation is a 49.9% owner of Sithe and accounts for the investment as
an unconsolidated equity investment. In the first quarter of 2003, Exelon and
Generation recorded an impairment charge of $200 million before income taxes in
other income and deductions, associated with a decline in the Sithe investment
value, which is considered to be other than temporary. Exelon and Generation's
management considered various factors in the decision to record an impairment of
this investment, including management's recent experience of exploring the sale
of its interest in Sithe. The discussions surrounding the sale indicated that
the fair value of the Sithe investment is below its book value, and as such, an
impairment charge was required. This impairment reduced the book value of the
investment to $212 million at March 31, 2003.
Generation continues to be 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.
The PCA originally provided that the Put and Call options became
exercisable as of December 18, 2002 and expires in December 2005. However, upon
Apollo Energy, LLC's (Apollo) purchase of Vivendi's 34.2% ownership and Sithe
management's 1% share, Apollo agreed to delay the effective date of its Put
right until June 1, 2003 and, if certain conditions are met, until September 1,
2003. There are also certain events that could trigger Apollo's Put right
becoming effective prior to June 1, 2003, including Exelon being downgraded
below investment grade by Standard and Poor's Rating Group or Moody's Investors
Service, Inc., a stock purchase agreement between Exelon and Apollo being
executed and subsequently terminated, or the occurrence of any event of default,
other than a change of control, under certain Exelon or Apollo credit
agreements. Depending on the triggering event, Apollo's Put 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.
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
44
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 Exelon and Generation's financial
results may include Sithe's financial results from the date of purchase. At
March 31, 2003, Sithe had total assets of $2.5 billion (including the $534
million note from Generation) and total debt of $1.3 billion. The $1.3 billion
of debt includes $625 million of subsidiary debt incurred primarily to finance
the construction of six new generating facilities, $457 million of subordinated
debt, $119 million of line of credit borrowings, $41 million of the current
portion of long-term debt and capital leases, $30 million of capital leases, and
excludes $464 million of non-recourse project debt associated with Sithe's
equity investments. For the three months ended March 31, 2003, Sithe had
revenues of $199 million.
Credit Contingencies
Generation is a counterparty to Dynegy in various energy transactions.
In early July 2002, the credit ratings of Dynegy were downgraded to below
investment grade by two credit rating agencies. As of March 31, 2003, Generation
had a net receivable from Dynegy of approximately $4 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 (Independence), 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 March 31, 2003, 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.
Generation estimates, as a 49.9% owner of Sithe, that the impairment would
result in an after-tax reduction of its earnings of approximately $13 million.
In addition to the impairment of the financial swap asset, if Dynegy
were unable to fulfill its obligations under the financial swap agreement and
the tolling agreement, Generation may incur a further impairment associated with
Independence.
Additionally, the future economic value of AmerGen's PPA with Illinois
Power Company, a subsidiary of Dynegy, could be impacted by events related to
Dynegy's financial condition.
45
General
On February 20, 2003, ComEd entered into separate agreements with the
City of Chicago (Chicago) and with Midwest Generation (Midwest Agreement). Under
the terms of the agreement with Chicago, ComEd will pay Chicago $60 million over
ten years ($6 million was paid during the first quarter of 2003) 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
$32 million, $22 million of which was received during the first quarter 2003,
and the remainder was received during April 2003, to relieve Midwest
Generation's obligation under the fossil sale agreement. Midwest Generation will
also assume from Chicago a Capacity Reservation Agreement which Chicago had
entered into with Calumet Energy Team, LLC (CET), which is effective through
June 2012. ComEd will reimburse Chicago for any nonperformance by Midwest
Generation under the Capacity Reservation Agreement and paid approximately $2
million for amounts owed to CET by Chicago at the time the agreement was
executed. In the first quarter of 2003, ComEd recorded a guarantee liability of
$4 million under the provisions of FIN 45 related to ComEd's obligation to
reimburse Chicago for any nonperformance by Midwest Generation. The net effect
of the settlement and the FIN 45 liability to ComEd will be amortized over the
remaining life of the franchise agreement with Chicago.
ComEd and PECO have entered into several agreements with a tax
consultant related to the filing of refund claims with the Internal Revenue
Service (IRS). The fees for these agreements are contingent upon a successful
outcome and are based upon a percentage of the refunds recovered from the IRS,
if any. As such, ComEd and PECO would have positive net cash flows related to
these agreements if any fees are paid to the tax consultant. These potential tax
benefits and associated fees could be material to the financial position,
results of operations and cash flows of ComEd and PECO. ComEd and PECO cannot
predict the timing of the final resolution of these refund claims.
9. MERGER-RELATED COSTS (Exelon, ComEd, PECO and Generation)
In association with the Merger, Exelon recorded certain reserves for
restructuring costs. The reserves associated with PECO were charged to expense
pursuant to 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
Corporation 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".
At December 31, 2002, Exelon, ComEd, PECO and Generation had
liabilities of $28 million, $13 million, $1 million and $7 million,
respectively, for certain benefits such as outplacement services, continuation
of health care coverage and educational benefits associated with the merger
separation plans. At March 31, 2003, Exelon, ComEd, PECO and Generation's
applicable liabilities were $15 million, $5 million, $1 million and $5 million,
respectively.
46
10. LONG-TERM DEBT AND PREFERRED SECURITIES (Exelon, ComEd and PECO)
On January 22, 2003, ComEd issued $350 million of 3.70% First Mortgage
Bonds, due in 2008 and $350 million of 5.875% First Mortgage Bonds, due in 2033.
These bond issuances were used to refinance long-term debt which had been
previously retired during the third and fourth quarters of 2002.
On March 17, 2003, ComEd issued $200 million of trust preferred
securities, with an annual distribution rate of 6.35% that are mandatorily
redeemable in 2033.
On March 18, 2003, ComEd redeemed $236 million of its First Mortgage
Bonds, at a redemption price of 103.863% of the principal amount, plus accrued
interest. The bonds, which carried an interest rate of 8.375%, were refinanced
with long-term debt issued on April 7, 2003.
On March 20, 2003, ComEd redeemed $200 million of its trust preferred
securities at a redemption price of 100% of the principal amount, plus accrued
distributions. The preferred securities, which carried an interest rate of
8.48%, were refinanced with trust preferred securities as discussed below.
During the three months ended March 31, 2003, Exelon Corporate and
ComEd retired $215 million and $52 million of commercial paper classified as
long-term debt, respectively.
In 2003, ComEd entered into forward-starting interest rate swaps with
an aggregate notional amount of $240 million to manage interest rate exposure
associated with anticipated debt issuance. In connection with the 2003 issuance
of First Mortgage Bonds, forward-starting interest rate swaps with an aggregate
notional amount of $870 million were settled with net proceeds to counterparties
of $51 million ($30 million, after income taxes) 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.
During the three months ended March 31, 2003, ComEd recorded prepayment
premiums of $9 million and net unamortized premiums, discounts and debt issuance
expenses of $23 million, associated with the early retirement of debt in 2003
that have been deferred by ComEd in regulatory assets and will be amortized to
interest expense over the life of the related new debt issuance consistent with
regulatory recovery.
During the three months ended March 31, 2003, PECO issued $250 million
of commercial paper which has been classified as long-term debt (see Note 14 -
Subsequent Events).
11. SALE OF ACCOUNTS RECEIVABLE (Exelon and PECO)
PECO is party to an agreement, which expires in November 2005, 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. As of March 31, 2003, PECO had sold a $225 million interest
in accounts receivable, consisting of a $158 million interest in
47
accounts receivable that PECO accounted for as a sale under SFAS No. 140,
"Accounting for Transfers and Servicing of Financial Assets and Extinguishments
of Liabilities, a Replacement of FASB Statement No. 125" and a $67 million
interest in special-agreement accounts receivable which were accounted for as a
long-term note payable. 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 March
31, 2003, PECO met this requirement.
12. RELATED-PARTY TRANSACTIONS (Exelon, ComEd, PECO and Generation) Exelon and
Generation
Exelon and Generation's financial statements reflect related-party
transactions with unconsolidated affiliates as reflected in the tables below.
Three Months Ended March 31,
-----------------------------
2003 2002
- --------------------------------------------------------------------------------
Purchased Power from AmerGen (1) $ 67 $ 56
Interest Income from AmerGen (2) -- --
Interest Expense to Sithe (3) 3 --
Services Provided to AmerGen (4) 17 14
Services Provided to Sithe (5) -- --
Services Provided by Sithe (6, 7) 4 1
- --------------------------------------------------------------------------------
48
March 31, 2003 December 31, 2002
- --------------------------------------------------------------------------------
Net Receivable from AmerGen (1,2,4) $ 26 $ 39
Net Payable to Sithe (5,6,7) 6 7
Note Payable to Sithe (3) 534 534
- --------------------------------------------------------------------------------
(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. The 1999
PPA will be extended through 2026. In accordance with the terms of the
AmerGen partnership agreement, Generation has agreed to purchase from
AmerGen all of the residual energy from Clinton. Currently, the residual
output is approximately 31% of the total output of Clinton.
(2) In February 2002, Generation entered into an agreement to loan AmerGen up
to $75 million at an interest rate equal to the one-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 March 31, 2003, the outstanding principal balance of the loan
was $35 million. Total interest earned on the loan was less than $1 million
during the three months ended March 31, 2003 and 2002.
(3) Under the terms of the agreement to acquire Exelon 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 March 31, 2003 was $5
million.
(4) 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 at cost.
(5) 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 at cost. Total revenue earned under this service
agreement was less than $1 million for the three months ended March 31,
2003 and 2002.
(6) Under a service agreement dated December 18, 2000, Sithe provides
Generation certain fuel and project development services. Sithe is
compensated for these services at cost.
(7) Under a service agreement dated November 1, 2002, Sithe provides Generation
certain transition services related to the transition of the New England
acquisition which occurred on November 1, 2002.
Generation's additional related-party transactions are discussed in the
"Generation" section of this note.
49
ComEd
ComEd's financial statements reflect related-party transactions as
reflected in the tables below.
Three Months Ended March 31,
---------------------------------
2003 2002
- --------------------------------------------------------------------------------
Operating Revenues from Affiliates
Generation (1) $ 11 $ 9
Enterprises (1) 2 2
Purchased Power from Affiliate
Generation (2) 572 532
Operations & Maintenance from Affiliates
BSC (3) 27 39
Enterprises (4, 5) 3 3
Interest Income from Affiliates
UII (6) 6 8
Other 1 --
Capitalized costs
BSC (3) 1 1
Enterprises (5) 6 7
Cash Dividends Paid to Parent 120 118
- --------------------------------------------------------------------------------
March 31, 2003 December 31, 2002
- --------------------------------------------------------------------------------
Receivables from Affiliates (current)
UII (6) $ 6 $ 15
Receivables from Affiliates (noncurrent)
UII (6) 1,284 1,284
Generation (9) 920 --
Other 17 16
Payables to Affiliates, net (current)
Generation Decommissioning (8) 29 59
Generation (1, 2, 7) 154 339
BSC (3, 7) 13 18
Other 4 --
Payables to Affiliates (noncurrent)
Generation Decommissioning obligation (8) -- 218
Other 7 6
Shareholders' Equity - Receivable from Parent (10) 584 615
- --------------------------------------------------------------------------------
(1) ComEd provides electric, transmission, and other ancillary services to
Generation and Enterprises.
(2) Effective January 1, 2001, ComEd entered into a PPA with Generation. See
Note 8 - Commitments and Contingencies for further information regarding
the PPA. The Generation payable primarily consists of services related to
the PPA.
(3) ComEd receives a variety of corporate support services from Exelon Business
Services Company (BSC), including legal, human resource, financial,
information technology, supply management and corporate governance
services. A portion of such services, provided at cost including applicable
overhead, is capitalized.
(4) ComEd has contracted with Exelon Services to provide energy conservation
services to ComEd customers.
(5) ComEd receives substation and transmission engineering and construction
services under contracts with InfraSource. A portion of such services is
capitalized.
(6) ComEd has a note and interest receivable from Unicom Investments Inc. (UII)
relating to the December 1999 fossil plant sale.
(7) In order to benefit from economics of scale, ComEd processes certain
invoice payments on behalf of Generation and BSC.
50
(8) ComEd has a short-term and had a long-term payable to Generation, primarily
representing ComEd's legal requirements to remit collections of nuclear
decommissioning costs from customers to Generation.
(9) ComEd has a receivable from Generation, offset by a regulatory liability,
as a result of the adoption of SFAS No. 143. For further information see
Note 2 - New Accounting Principles and Accounting Changes.
(10) ComEd has a non-interest bearing receivable from Exelon related to Exelon's
agreement to fund future income tax payments resulting from the collection
by ComEd of instrument funding changes. The receivable is expected to be
settled over the years 2003 through 2008.
PECO
PECO's financial statements reflect a number of related-party
transactions as reflected in the table below.
Three Months Ended March 31,
----------------------------
2003 2002
- ---------------------------------------------------------------------------------------------
Operating Revenues from Affiliate
Generation (1) $ 3 $ 3
Purchased Power from Affiliate
Generation (2) 357 303
Operations & Maintenance from Affiliates
BSC (3) 10 17
Enterprises (4) 2 8
Capitalized Costs
BSC (3) 3 2
Enterprises (4) 6 4
Cash Dividends Paid to Parent 89 85
- ---------------------------------------------------------------------------------------------
March 31, 2003 December 31, 2002
- ---------------------------------------------------------------------------------------------
Payables to Affiliates (current)
Generation (2) $ 116 $ 124
BSC (3) 27 26
Enterprises (4) 2 19
Other 1 1
Payable to Affiliate (noncurrent)
Generation (5) 39 --
Shareholders' Equity - Receivable from Parent (6) 1,728 1,758
- ---------------------------------------------------------------------------------------------
(1) PECO provides energy to Generation for Generation's own use.
(2) Effective January 1, 2001, PECO entered into a PPA with Generation. See
Note 8 - Commitments and Contingencies for further information regarding
the PPA.
(3) PECO provides services to BSC related to invoice processing. PECO receives
a variety of corporate support services from BSC, including legal, human
resource, financial, information technology, supply management and
corporate governance services. Such services are provided at cost,
including applicable overhead. Some of these costs are capitalized.
(4) PECO receives services from Enterprises for construction, which are
capitalized, and the deployment of automated meter reading technology,
which is expensed.
(5) PECO has a payable to Generation offset by a regulatory asset as a result
of the adoption of SFAS No. 143. See Note 2 - New Accounting Principles and
Accounting Changes for further discussion of the adoption of SFAS No. 143.
(6) PECO has a non-interest bearing receivable from Exelon related to Exelon's
agreement to fund future income tax payments resulting from the collection
of PECO's stranded costs recovery. The receivable is expected to be settled
over the years 2001 through 2010.
51
Generation
In addition to the transactions described in the "Exelon and
Generation" section of this note, Generation's financial statements reflect a
number of related-party transactions as reflected in the tables below.
Three Months Ended March 31,
----------------------------
2003 2002
- -------------------------------------------------------------------------------------------
Operating Revenues from Affiliates
ComEd (1) $ 572 $ 532
PECO (1) 357 303
Exelon Energy (2) 64 57
Purchased Power from Affiliates
ComEd (4) 7 6
PECO (4) -- 2
Exelon Energy (4) 6 2
Operations & Maintenance from Affiliates
ComEd (4) 4 3
PECO (4) 3 1
BSC (6) 35 53
Interest Expense - Affiliate
Exelon (3) 1 --
- -------------------------------------------------------------------------------------------
March 31, 2003 December 31, 2002
- -------------------------------------------------------------------------------------------
Receivables from Affiliates (current)
ComEd (1) $ 154 $ 339
ComEd Decommissioning Receivable (7) 29 59
PECO (1) 116 124
BSC (6) -- 14
Exelon Energy (2) 18 19
Receivables from Affiliates (noncurrent)
ComEd Decommissioning Receivable (7) -- 218
PECO (5) 39 --
Other 2 2
Payables to Affiliates (current)
Exelon (3) 1 3
BSC (6) 26 --
Payable to Affiliate (noncurrent)
ComEd Decommissioning (5) 920 --
Notes Payable to Affiliate
Exelon (3) 323 329
- -------------------------------------------------------------------------------------------
(1) Effective January 1, 2001, Generation entered into PPAs with ComEd and
PECO. See Note 8 - Commitments and Contingencies for further information on
the PPAs.
(2) Generation sells power to Exelon Energy.
(3) Generation had a payable to Exelon related to Generation's short-term
liquidity requirements. As of March 31, 2003, the outstanding principal
balance was $323 million.
(4) Generation purchases power from PECO for Generation's own use, buys back
excess power from Exelon Energy and purchases transmission and ancillary
services from ComEd and PECO.
52
(5) Generation has a long-term payable to ComEd and a long-term receivable from
PECO as a result of the adoption of SFAS No. 143. See Note 2 - New
Accounting Principles and Accounting Changes for further discussion of the
adoption of SFAS No. 143.
(6) Generation receives a variety of corporate support services from BSC,
including legal, human resource, financial, information technology, supply
management and corporate governance services. Such services are provided at
cost, including applicable overhead. Some third party reimbursements due
Generation are recovered through BSC.
(7) Generation has a short-term and had a long-term receivable from ComEd,
primarily representing ComEd's legal requirements to remit collections of
nuclear decommissioning costs from customers to Generation resulting from
the 2001 corporate restructuring.
13. SUPPLEMENTAL FINANCIAL INFORMATION (Exelon, ComEd and PECO)
Exelon and ComEd
March 31, December 31,
--------- -----------
2003 2002
- ----------------------------------------------------------------------------------------------------------------------
Regulatory Assets (Liabilities)
Nuclear decommissioning
(see Note 2 - New Accounting Principles and Accounting Changes) $ (920) $ --
Nuclear decommissioning costs for retired plants -- 248
Recoverable transition costs 164 175
Reacquired debt costs and interest rate swap settlements 166 84
Recoverable deferred income taxes (64) (68)
Other 21 8
- ----------------------------------------------------------------------------------------------------------------------
Total $ (633) $ 447
======================================================================================================================
Exelon and PECO
March 31, December 31,
--------- -----------
2003 2002
- ----------------------------------------------------------------------------------------------------------------------
Regulatory Assets
Competitive transition charge $ 4,558 $ 4,639
Recoverable deferred income taxes 735 729
Non-pension postretirement benefits 63 64
Nuclear decommissioning
(see Note 2 - New Accounting Principles and Accounting Changes) 39 --
Reacquired debt costs 51 53
Compensated absences 13 6
- ----------------------------------------------------------------------------------------------------------------------
Long-Term Regulatory Assets 5,459 5,491
Deferred energy costs (current asset) 56 31
- ----------------------------------------------------------------------------------------------------------------------
Total $ 5,515 $ 5,522
======================================================================================================================
Exelon's long-term regulatory assets as of December 31, 2002 were
$5,938 million.
14. SUBSEQUENT EVENTS (Exelon, ComEd and PECO)
On April 7, 2003, ComEd issued $395 million of 4.70% First Mortgage
Bonds, due on April 15, 2015. The proceeds of these bonds were used to refund
other First Mortgage Bonds.
53
On April 15, 2003, ComEd redeemed $160 million of its First Mortgage
Bonds, at a redemption price of 103.664% of the principal amount, plus accrued
interest. The bonds, which carried an interest rate of 8%, were refinanced with
long-term debt issued on April 7, 2003.
On April 28, 2003, PECO issued $450 million of 3.50% First and
Refunding Mortgage Bonds due on May 1, 2008. The proceeds from the sale of the
bonds were used to repay commercial paper that was used to refinance long-term
debt As part of these bond issuances, PECO settled various interest rate swaps
for $1 million, before income taxes, which will be recorded in other
comprehensive income and will be amortized over the life of the associated debt
issuance.
54
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
(Dollars in millions, unless otherwise noted)
EXELON CORPORATION
- ------------------
GENERAL
Exelon Corporation (Exelon), a registered public utility holding
company, through its subsidiaries, operates in three business segments:
o Energy Delivery, whose businesses include the regulated sale of electricity
and distribution and transmission services by Commonwealth Edison Company
(ComEd) in northern Illinois and PECO Energy Company (PECO) in southeastern
Pennsylvania and the sale of natural gas and distribution services by PECO
in the Pennsylvania counties surrounding the City of Philadelphia.
o Generation, consisting of Exelon Generation Company, LLC's (Generation)
owned and contracted for electric generating facilities, energy marketing
operations, and equity interests in Sithe Energies, Inc. (Sithe) and
AmerGen Energy Company, LLC (AmerGen).
o Enterprises, consisting of Exelon Enterprises Company, LLC's (Enterprises)
competitive retail energy sales, energy and infrastructure services,
communications and other investments (primarily weighted towards the energy
services and retail services industries).
See Note 6 of the Condensed Combined Notes to Consolidated Financial
Statements for further segment information.
RESULTS OF OPERATIONS
Three Months Ended March 31, 2003 Compared To Three Months Ended March 31, 2002
Net Income and Earnings Per Share
Exelon's net income for the three months ended March 31, 2003 increased
$353 million, compared to the same period in 2002. Diluted earnings per common
share on the same basis increased $1.09 per share. Net income for the three
months ended March 31, 2003 reflects $112 million of income for the cumulative
effect of a change in accounting principle as a result of the adoption of
Financial Accounting Standards Board (FASB) Statement of Financial Accounting
Standards (SFAS) SFAS No. 143, "Asset Retirement Obligations" (SFAS No. 143),
while net income for the three months ended March 31, 2002 reflects a $230
million charge for the cumulative effect of a change in accounting principle as
a result of the adoption of SFAS No. 142, "Goodwill and Other Intangible Assets"
(SFAS No. 142). See Note 2 of the Condensed Combined Notes to Consolidated
Financial Statements for further information regarding the adoption of SFAS No.
143 and SFAS No. 142.
55
Income Before Cumulative Effect of Changes in Accounting Principles for
the three months ended March 31, 2003 increased $11 million, or 5%, compared to
the same period in 2002. Diluted earnings per common share on the same basis
increased $0.04 per share, or 5%. The increase in income before cumulative
effect of changes in accounting principles reflects an overall increase in
revenue net fuel due to colder weather conditions and increased recoveries of
competitive transition charges (CTCs), reduced nuclear refueling outage costs,
reduced depreciation expense resulting from lower depreciation rates at Energy
Delivery, and decreased interest expense. This increase was partially offset by
the impairment of an investment in Sithe Energies, Inc. held by Generation, a
one-time charge at Energy Delivery (see Note 4 of the Condensed Combined Notes
to Consolidated Financial Statements) and increased operating and maintenance
expenses at Generation due to plant acquisitions after the first quarter of
2002.
Results of Operations by Business Segment
Exelon evaluates its performance on a business segment basis. The
comparisons presented under this heading are comparisons of operating results
and other statistical information for the three months ended March 31, 2003 to
operating results and other statistical information for the same period in 2002.
These results reflect intercompany transactions, which are eliminated in our
consolidated financial statements.
Corporate provides the business segments a variety of support services
including legal, human resources, financial, information technology, supply
management and corporate governance services. These costs are allocated to the
business segments. Additionally, Corporate costs reflect costs for strategic
long-term planning, certain governmental affairs, and interest costs and income
from various investment and financing activities.
Income (Loss) Before Cumulative Effect of Changes in Accounting Principles by
Business Segment
Three Months Ended March 31,
---------------------------
2003 2002 Variance % Change
- -------------------------------------------------------------------------------------------------------------------
Energy Delivery $ 325 $ 215 $ 110 51.2%
Generation (52) 66 (118) (178.8%)
Enterprises (17) (28) 11 (39.3%)
Corporate (7) (15) 8 (53.3%)
- -------------------------------------------------------------------------------------------------
Total $ 249 $ 238 $ 11 4.6%
=================================================================================================
Net Income (Loss) by Business Segment
Three Months Ended March 31,
---------------------------
2003 2002 Variance % Change
- -------------------------------------------------------------------------------------------------------------------
Energy Delivery $ 330 $ 215 $ 115 53.5%
Generation 56 79 (23) (29.1%)
Enterprises (18) (271) 253 (93.4%)
Corporate (7) (15) 8 (53.3%)
- -------------------------------------------------------------------------------------------------
Total $ 361 $ 8 $ 353 n.m.
=================================================================================================
n.m. - not meaningful
56
Results of Operations - Energy Delivery
Three Months Ended March 31,
----------------------------
Energy Delivery 2003 2002 Variance % Change
- -------------------------------------------------------------------------------------------------------------------
Operating Revenues $ 2,642 $ 2,335 $ 307 13.1%
Revenue, net of Purchased Power & Fuel Expense 1,451 1,311 140 10.7%
Operating Income 694 559 135 24.2%
Income Before Income Taxes and Cumulative Effect of a
Change in Accounting Principle 517 341 176 51.6%
Net Income Before Cumulative Effect of a Change in
Accounting Principle 325 215 110 51.2%
Net Income 330 215 115 53.5%
- -------------------------------------------------------------------------------------------------------------------
The changes in Energy Delivery's revenue, net of purchased power and
fuel expense, for the three months ended March 31, 2003 compared to the same
period in 2002, included the following:
o changes in customer rates resulting in an $82 million increase,
o increases in weather normalized volumes of $31 million as a result of
increases in the number of customers and additional average usage per
customer, primarily residential customers,
o favorable weather impacts of $78 million, primarily the results of colder
winter weather,
o net unfavorable changes due to customer choice of $8 million, including
ComEd's customers electing to purchase energy from alternative energy
suppliers or electing ComEd's Power Purchase Option (PPO), under which
non-residential customers can purchase power from ComEd at a market-based
rate, partially offset by customers returning to PECO as their energy
supplier,
o pricing changes related to ComEd's PPA with Generation resulting in a $17
million decrease,
o increase of $16 million in purchases under the ComEd PPA with Generation
related to decommissioning collections associated with the adoption of SFAS
No. 143 in 2003, which were not recorded in purchased power in 2002, (see
Note 2 of the Condensed Combined Notes to Consolidated Financial
Statements), and
o higher PJM ancillary purchased power charges resulted in a decrease of $17
million.
The changes in operating income, other than changes in revenue net of
purchased power and fuel expense, for the three months ended March 31, 2003
compared to the same period in 2002, included the following:
o a net one-time charge of $41 million in 2003 at ComEd as the result of an
agreement described in Note 4 - Regulatory Issues,
o reduction in depreciation expense of $24 million due to the impact of lower
depreciation rates at ComEd effective July 1, 2002,
o reduction of amortization expense of $16 million for nuclear
decommissioning of retired plants at ComEd due to the adoption of SFAS No.
143 (see Note 2 of the Condensed Combined Notes to Consolidated Financial
Statements),
o increased depreciation expense in 2003 of $10 million due to higher plant
in service balances,
57
o lower corporate allocations and executive severance costs partially offset
by higher pension and postretirement benefit costs totaling $10 million in
2003, and
o additional gross receipts tax expense of $7 million related to additional
revenues (gross receipts taxes are recorded in Revenues and Taxes Other
Than Income and have no net impact on operating income).
The changes in income before income taxes and cumulative effect of a
change in accounting principle for the three months ended March 31, 2003
compared to the same period in 2002, included the following:
o a decrease in interest expense of $25 million primarily attributable to
less outstanding debt and refinancing of existing debt at lower
interest rates, and
o the reversal in 2003 of a $12 million reserve for a potential plant
disallowance as the result of an agreement described in Note 4 -
Regulatory Issues.
Energy Delivery's effective income tax rate was 37.1% for the three
months ended March 31, 2003, compared to 37.0% for the same period in 2002.
Due to the adoption of SFAS No. 143, ComEd recorded cumulative effect
of a change in accounting principle of $5 million, net of income taxes, in the
three months ended March 31, 2003. See Note 2 of the Condensed Combined Notes to
Consolidated Financial Statements for further discussion of these effects.
58
Energy Delivery Operating Statistics and Revenue Detail
Energy Delivery's electric sales statistics and revenue detail are as
follows:
Three Months Ended March 31,
---------------------------
Retail Deliveries - (in gigawatthours (GWhs))(1) 2003 2002 Variance % Change
- --------------------------------------------------------------------------------------------------------
Bundled Deliveries (2)
Residential 10,001 8,465 1,536 18.1%
Small Commercial & Industrial 7,407 7,207 200 2.8%
Large Commercial & Industrial 4,966 5,307 (341) (6.4%)
Public Authorities & Electric Railroads 1,669 1,994 (325) (16.3%)
- -----------------------------------------------------------------------------------------
Total Bundled Deliveries 24,043 22,973 1,070 4.7%
- -----------------------------------------------------------------------------------------
Unbundled Deliveries (3)
Alternative Energy Suppliers
Residential 264 792 (528) (66.7%)
Small Commercial & Industrial 1,550 1,100 450 40.9%
Large Commercial & Industrial 2,042 1,489 553 37.1%
Public Authorities & Electric Railroads 282 138 144 104.3%
- -----------------------------------------------------------------------------------------
4,138 3,519 619 17.6%
- -----------------------------------------------------------------------------------------
PPO (ComEd Only)
Small Commercial & Industrial 794 763 31 4.1%
Large Commercial & Industrial 1,433 1,311 122 9.3%
Public Authorities & Electric Railroads 537 242 295 121.9%
- -----------------------------------------------------------------------------------------
2,764 2,316 448 19.3%
- -----------------------------------------------------------------------------------------
Total Unbundled Deliveries 6,902 5,835 1,067 18.3%
- -----------------------------------------------------------------------------------------
Total Retail Deliveries 30,945 28,808 2,137 7.4%
=========================================================================================
(1) One GWh is the equivalent of one million kilowatthours (kWh).
(2) Bundled service reflects deliveries to customers taking electric generation
service under tariffed rates.
(3) Unbundled service reflects customers electing to receive electric
generation service from an alternative energy supplier or ComEd's PPO.
59
Three Months Ended March 31,
----------------------------
Electric Revenue 2003 2002 Variance % Change
- -------------------------------------------------------------------------------------------------------------------
Bundled Revenues (1)
Residential $ 905 $ 761 $ 144 18.9%
Small Commercial & Industrial 591 580 11 1.9%
Large Commercial & Industrial 340 346 (6) (1.7%)
Public Authorities & Electric Railroads 106 110 (4) (3.6%)
- -----------------------------------------------------------------------------------------------------
Total Bundled Revenues 1,942 1,797 145 8.1%
- -----------------------------------------------------------------------------------------------------
Unbundled Revenues (2)
Alternative Energy Suppliers
- ----------------------------
Residential 17 54 (37) (68.5%)
Small Commercial & Industrial 51 17 34 n.m.
Large Commercial & Industrial 54 13 41 n.m.
Public Authorities & Electric Railroads 9 2 7 n.m.
- -----------------------------------------------------------------------------------------------------
131 86 45 52.3%
- -----------------------------------------------------------------------------------------------------
PPO (ComEd Only)
- ----------------
Small Commercial & Industrial 49 43 6 14.0%
Large Commercial & Industrial 72 64 8 12.5%
Public Authorities & Electric Railroads 28 13 15 115.4%
- -----------------------------------------------------------------------------------------------------
149 120 29 24.2%
- -----------------------------------------------------------------------------------------------------
Total Unbundled Revenues 280 206 74 35.9%
- -----------------------------------------------------------------------------------------------------
Total Electric Retail Revenues 2,222 2,003 219 10.9%
- -----------------------------------------------------------------------------------------------------
Wholesale and Miscellaneous Revenue (3) 132 123 9 7.3%
- -----------------------------------------------------------------------------------------------------
Total Electric Revenue $ 2,354 $ 2,126 $ 228 10.7%
=====================================================================================================
(1) Bundled revenue reflects deliveries to customers taking electric service
under tariffed rates, which include the cost of energy and the delivery
cost of the transmission and the distribution of the energy. PECO's
tariffed rates also include a CTC charge.
(2) Unbundled revenue reflects revenue from customers electing to receive
electric generation service from an alternative energy supplier or ComEd's
PPO. Revenue from customers choosing an alternative energy supplier
includes a distribution charge and a CTC. Revenues from customers choosing
ComEd's PPO includes an energy charge at market rates, transmission and
distribution charges and a CTC. Transmission charges received from
alternative energy suppliers are included in wholesale and miscellaneous
revenue.
(3) Wholesale and miscellaneous revenues include transmission revenue, sales to
municipalities and other wholesale energy sales.
n.m. - not meaningful
The differences in three months ended March 31, 2003 electric retail
revenues as compared to the same period in 2002 were attributable to the
following:
Variance
- --------------------------------------------------------------------
Weather $ 101
Rate Changes 82
Volume 50
Customer Choice (20)
Other Effects 6
- --------------------------------------------------------------------
Electric Retail Revenue $ 219
====================================================================
o Weather. The demand for electricity is impacted by weather conditions. Very
warm weather in summer months and very cold weather in other months is
referred to as "favorable weather conditions," because these weather
conditions result in increased sales of electricity.
60
Conversely, mild weather reduces demand. The weather impact for the three
months ended March 31, 2003 was favorable compared to the same period in
2002 as a result of colder winter weather in 2003. Heating degree-days in
the ComEd and PECO service territories were 17% higher and 33% higher,
respectively, in 2003 as compared to 2002.
o Rate Changes. The increase in revenues attributable to rate changes
reflects the collection of additional CTC's in 2003 by ComEd of $105
million due to an increase in the number of customers choosing an
alternative energy supplier and changes in the wholesale market price of
electricity, net of increased mitigation factors. Increased wholesale
market prices decreased revenue received under ComEd's PPO by $23 million.
o Volume. Revenues from higher delivery volume, exclusive of the effect of
weather, increased due to an increased number of customers and increased
usage per customer, primarily residential and large commercial and
industrial customers.
o Customer Choice. All ComEd and PECO customers have the choice to purchase
energy from alternative suppliers. This affects revenues from the sale of
energy but not revenue from the delivery of electricity since ComEd and
PECO continue to deliver electricity that is purchased from alternative
suppliers. As of March 31, 2003, 13% of energy delivered to Energy
Delivery's customers was provided by alternative electric suppliers. The
decrease in electric retail revenues includes a decrease in revenues of $39
million from customers in Illinois electing to purchase energy from an
alternative retail electric supplier (ARES) or ComEd's PPO, partially
offset by an increase in revenues of $19 million from customers in
Pennsylvania who selected or returned to PECO as their electric supplier.
The Pennsylvania Utility Commission's (PUC) Final Electric
Restructuring Order established market share thresholds (MST) for PECO to
promote competition. The MST requirements provide that, if as of January 1,
2003, less than 50% of residential and commercial customers have chosen an
alternative electric generation supplier, the number of customers
sufficient to meet the MST shall be randomly selected and assigned to an
alternative electric generation supplier through a PUC determined process.
On January 1, 2003, the number of customers choosing an alternative
electric generation supplier did not meet the MST. In January 2003, PECO
submitted to the PUC a MST plan to meet the 50% threshold requirement for
its commercial customers, which was approved by the PUC in February 2003.
As of March 31, 2003, an auction had been completed for the commercial
customers and the customer enrollment phase is currently in process. The
randomly selected customers will be transferred to the alternative electric
generation suppliers in May 2003, if they do not choose the option to not
participate in the program. In February 2003, PECO filed a residential
customer MST plan, and on May 1, 2003, the PUC approved the plan. The
approved plan provides for a two-step process with a total of up to 400,000
residential customers being assigned to winning alternative electric
generation supplier bidders: up to 100,000 in July 2003, and another
300,000 in December 2003. Any customer transferred would have the right to
return to PECO at any time. PECO does not expect the transfer of customers
pursuant to the MST plan to have a material impact on its results of
operations, financial position or cash flows.
61
Energy Delivery's gas sales statistics and revenue detail were as
follows:
Three Months Ended March 31,
----------------------------
2003 2002 Variance % Change
- -------------------------------------------------------------------------------------------------------------
Deliveries in million cubic feet (mmcf) 39,626 31,357 8,269 26.4%
Revenue $ 288 $ 209 $ 79 37.8%
- --------------------------------------------------------------------------------------------
The changes in gas revenue for the three months ended March 31, 2003 as
compared to the same period in 2002, were as follows:
Variance
- --------------------------------------------------------------------------
Weather $ 59
Volume 17
Rate Changes 3
- --------------------------------------------------------------------------
Gas Revenue $ 79
- --------------------------------------------------------------------------
o Weather. The demand for gas is impacted by weather conditions. Very cold
weather in non-summer months is referred to as "favorable weather
conditions," because these weather conditions result in increased sales of
gas. Conversely, mild weather reduces demand. The weather impact was
favorable compared to the prior year as a result of colder winter weather.
Heating degree-days increased 33% in the three months ended March 31, 2003
compared to the same period in 2002.
o Volume. Exclusive of weather impacts, higher delivery volume increased
revenue in the three months ended March 31, 2003 compared to the same
period in 2002 resulting from customer growth. Deliveries to customers,
excluding the effects of weather, increased 5% in the three months ended
March 31, 2003 compared to the same period in 2002.
o Rate Changes. The favorable variance in rates is attributable to a 15%
increase in the purchased gas adjustment by the PUC effective March 1,
2003. The average rate per million cubic feet for the three months ended
March 31, 2003 was 9% higher than the rate in the same 2002 period. PECO's
gas rates are subject to periodic adjustments by the PUC and are designed
to recover from or refund to customers the difference between actual cost
of purchased gas and the amount included in base rates and to recover or
refund increases or decreases in certain state taxes not recovered in base
rates.
62
Results of Operations - Generation
In the second quarter of 2002, Generation early adopted FASB Emerging
Issues Task Force (EITF) Issue 02-3, "Accounting for Contracts Involved in
Energy Trading and Risk Management Activities" (EITF 02-3). EITF 02-3 was issued
by the EITF in June 2002 and required revenues and energy costs related to
energy trading contracts to be presented on a net basis in the income statement.
For comparative purposes, energy costs related to energy trading have been
reclassified as revenue for prior periods to conform to the net basis of
presentation required by EITF 02-3.
Three Months Ended March 31,
----------------------------
2003 2002 Variance % Change
- ------------------------------------------------------------------------------------------------------------------
Operating Revenues $ 1,879 $ 1,461 $ 418 28.6%
Revenue, net of Purchased Power & Fuel Expense 674 633 41 6.5%
Operating Income 94 89 5 5.6%
Income (Loss) Before Income Taxes and Cumulative Effect
of Changes in Accounting Principles (73) 111 (184) (165.8%)
Income (Loss) Before Cumulative Effect of Changes in
Accounting Principles (52) 66 (118) (178.8%)
Net Income 56 79 (23) (29.1%)
- ------------------------------------------------------------------------------------------------------------------
The changes in Generation's revenue, net of purchased power and fuel
expense, for the three months ended March 31, 2003 compared to the same period
in 2002, included the following:
o increased demand due to customers returning to PECO from alternative energy
suppliers and favorable weather conditions in the ComEd and PECO service
territories in 2003 resulting in net volume and price increases of $34
million,
o increases of $32 million for generation from plants acquired after the
first quarter of 2002 resulting in higher market sales,
o increased revenue to ComEd of $16 million associated with the adoption of
SFAS No. 143, which was not included in revenue in 2002,
o mark-to-market losses on hedging activities of $31 million in 2003 compared
to mark-to-market gains of $6 million on hedging activities in 2002, and
o write-down of nuclear fuel of $6 million in 2003 resulting from
underperforming fuel at the Quad Cities Unit 1.
The changes in operating income, other than changes in revenue net of
purchased power and fuel expense, for the three months ended March 31, 2003
compared to the same period in 2002, included the following:
o higher costs of $27 million for employee medical, pension and other
benefits in 2003, partially offset by a one-time executive severance charge
of $19 million in 2002,
o increased O&M costs of $19 million due to asset acquisitions made after the
first quarter of 2002,
o reduced refueling outage costs of $32 million resulting from fewer
refueling outage days in 2003,
o additional depreciation of $15 million due to capital additions placed in
service and plant acquisitions made after the first quarter of 2002, and
63
o increased accretion expense of $57 million primarily due to asset
retirement obligation accretion due to the adoption of SFAS No. 143,
partially offset by reduced decommissioning expense of $33 million.
The changes in income before income taxes and cumulative effect of
changes in accounting principles for the three months ended March 31, 2003
compared to the same period in 2002, included the following:
o a pre-tax impairment charge of $200 million related to Generation's equity
investment in Sithe,
o increased decommissioning trust investment income of $20 million,
o reduced equity in earnings of unconsolidated affiliates of $4 million, and
o increased interest expense of $2 million primarily due to the note payable
to Sithe.
Generation's effective income tax rate was 28.8% for the three months
ended March 31, 2003 compared to 40.5% for the same period in 2002. This
decrease was primarily attributable to the impact of the impairment of
Generation's investment in Sithe and other tax benefits recorded in 2003.
Cumulative effect of changes in accounting principles recorded in the
three months ended March 31, 2003 and 2002 included income of $108 million, net
of income taxes, recorded in 2003 related to the adoption of SFAS No. 143 and
income of $13 million, net of income taxes, recorded in 2002 related to the
adoption of SFAS No. 141, "Business Combinations" (SFAS No. 141) and SFAS No.
142. See Note 2 of the Condensed Combined Notes to Consolidated Financial
Statements for further discussion of these effects.
Generation Operating Statistics
Generation's sales and the supply of these sales, excluding the trading
portfolio, were as follows:
Three Months Ended March 31,
----------------------------
Sales (in GWhs) 2003 2002 Variance % Change
- ----------------------------------------------------------------------------------------------------
Energy Delivery 29,346 27,750 1,596 5.8%
Exelon Energy 1,248 1,250 (2) (0.2%)
Market Sales 23,815 19,324 4,491 23.2%
- -------------------------------------------------------------------------------------
Total Sales 54,409 48,324 6,085 12.6%
=====================================================================================
Three Months Ended March 31,
----------------------------
Supply of Sales (in GWhs) 2003 2002 Variance % Change
- ----------------------------------------------------------------------------------------------------
Nuclear Generation (1) 29,330 27,533 1,797 6.5%
Purchases - non-trading portfolio (2) 20,029 18,093 1,936 10.7%
Fossil and Hydro Generation 5,050 2,698 2,352 87.2%
- -------------------------------------------------------------------------------------
Total Supply 54,409 48,324 6,085 12.6%
=====================================================================================
(1) Excluding AmerGen.
(2) Including purchased power agreements with AmerGen.
Trading volume of 9,527 GWhs and 14,239 GWhs for the three months ended
March 31, 2003 and 2002, respectively, is not included in the table above.
64
Generation's average margin and other operating data for the three
months ended March 31, 2003 and 2002 were as follows:
Three Months Ended March 31,
----------------------------
($/MWh) 2003 2002 % Change
- -------------------------------------------------------------------------------------------------------------------
Average Revenue
Energy Delivery $ 30.87 $ 29.98 3.0%
Exelon Energy 43.28 45.60 (5.1%)
Market Sales 37.05 28.15 31.6%
Total - excluding the trading portfolio 33.96 29.63 14.6%
Average Supply Cost (1) - excluding the trading portfolio $ 21.29 $ 16.74 27.2%
Average Margin - excluding the trading portfolio $ 12.67 $ 12.89 (1.7%)
- -------------------------------------------------------------------------------------------------------------------
(1) Average supply cost includes purchased power and fuel costs.
Three Months Ended March 31,
----------------------------
2003 2002
- -------------------------------------------------------------------------------------------------------------------
Nuclear fleet capacity factor (1) 94.4% 90.3%
Nuclear fleet production cost per MWh (1) $ 12.80 $ 14.26
Average purchased power cost for wholesale operations per MWh $ 41.75 $ 34.26
- -------------------------------------------------------------------------------------------------------------------
(1) Including AmerGen and excluding Salem.
Generation's MWh deliveries increased 12.6% in the three months ended
March 31, 2003 as compared to the same period in 2002. Increased deliveries were
a result of favorable weather conditions, which increased the demand for Energy
Delivery and higher market sales attributable to the increased supply from
acquired generation and power uprates at existing facilities.
The factors below contributed to the overall reduction in Generation's
average margin for the three months ended March 31, 2003 as compared to the same
period in 2002.
Generation's average revenue per MWh was affected by:
o increased weighted average on and off-peak prices per MWh for supply
agreements with ComEd,
o higher prices per MWh on sales under supply agreements with PECO, and
o higher market prices.
Generation's supply mix changed due to:
o increased nuclear generation due to a lower number of refueling and
unplanned outages during 2003 compared to 2002,
o increased fossil generation due to the effect of the acquisition of
two generating plants in Texas in April 2002, a peaking facility
placed in service in July 2002 and the Sithe New England (currently
known as Exelon New England) plants acquired in November 2002, which
in total account for an increase of 2,500 GWhs, and
o increased quantity of purchased power at higher prices to service
greater than anticipated customer loads.
65
Higher nuclear capacity factors and decreased nuclear production costs
are primarily due to 30 fewer planned refueling outage days, resulting in a $32
million decrease in outage costs, in the three months ended March 31, 2003 as
compared to the same period in 2002. Additionally, the three months ended March
31, 2003 included three unplanned outages compared to five unplanned outages
during the three months ended March 31, 2002.
Results of Operations - Enterprises
Three Months Ended March 31,
----------------------------
2003 2002 Variance % Change
- --------------------------------------------------------------------------------------------------------------------
Operating Revenues $ 580 $ 490 $ 90 18.4%
Operating Income (Loss) (27) (34) 7 (20.6%)
Income (Loss) Before Income Taxes and Cumulative Effect
of Changes in Accounting Principles (30) (47) 17 (36.2%)
Income (Loss) Before Cumulative Effect of Changes in
Accounting Principles (17) (28) 11 (39.3%)
Net Income (Loss) (18) (271) 253 (93.4%)
- ---------------------------------------------------------------------------------------------------------
The changes in Enterprises' operating income (loss) for the three
months ended March 31, 2003 compared to the same period in 2002, included the
following:
o lower revenues of $14 million from Exelon Services as a result of reduced
construction projects offset by lower construction costs of $13 million,
o higher gross margins at InfraSource Inc. of $2 million primarily resulting
from bad debt expense recorded in 2002 as a result of the downturn in the
telecommunications industry,
o lower gross margins at Exelon Energy of $12 million resulting from the
reversal of mark-to-market adjustments of $7 million and additional gas
supply costs of $11 million attributable to purchases at spot rates for gas
in the Northeast, offset by higher gross margins of $6 million in the
Midwest attributable to increased unit margins and higher volumes due to
colder weather,
o reductions in general and administrative expenses of $10 million primarily
resulting from Exelon's 2002 Cost Management Initiative, and
o accelerated depreciation of assets in 2002 relating to Exelon Energy's
discontinuance of retail sales in the PJM region of $7 million.
The changes in income (loss) before income taxes and cumulative effect
of changes in accounting principles for the three months ended March 31, 2003
compared to the same period in 2002, included the following:
o lower interest expense of $2 million,
o higher equity in earnings of unconsolidated affiliates of $4 million
resulting from the discontinuance of losses from the AT&T Wireless
investment as a result of its sale in the second quarter of 2002, and $3
million resulting from lower costs at a communications joint venture, and
o impairment of a software-related investment of $5 million due to an other
than temporary decline in value. In the first quarter of 2002, Enterprises
had a $2 million net realized loss on a communications investment and a $2
million impairment of a communications investment.
66
The effective income tax rate was 43.3% for the three months ended
March 31, 2003, compared to 40.4% for the same period in 2002. This increase in
the effective tax rate was attributable to various income tax related items
totaling $1 million.
The cumulative effect of a change in accounting principles recorded in
the three months ended March 31, 2003 due to the adoption of SFAS No. 143
reduced net income by $1 million, net of income taxes. The cumulative effect of
a change in accounting principle recorded in the three months ended March 31,
2002 due to the adoption of SFAS No. 142 reduced net income by $243 million, net
of income taxes (see Note 2 of the Condensed Combined Notes to Consolidated
Financial Statements).
Enterprises continues to pursue the divestiture of certain businesses;
however, it may be unable to successfully implement its divestiture strategy of
certain businesses for a number of reasons, including an inability to locate
appropriate buyers or to negotiate acceptable terms for the transactions. In
addition, the amount that Enterprises may realize from a divestiture is subject
to fluctuating market conditions that may contribute to pricing and other terms
that are materially different than expected and could result in a loss on the
sale. Timing of any divestitures may positively or negatively affect the results
of operations as Exelon expects certain businesses to be profitable going
forward.
General
Due to revenue needs in the states in which Exelon operates, various
state income tax and fee increases have been proposed or are being contemplated.
If these changes are enacted, they could increase Exelon's state income tax
expense. At this time, however, Exelon cannot predict whether legislation or
regulation will be introduced, the form of any legislation or regulation,
whether any such legislation or regulation will be passed by the state
legislatures or regulatory bodies, and, if enacted, whether any such legislation
or regulation would be effective retroactively or prospectively. As a result,
Exelon cannot currently estimate the effect of these potential changes in tax
laws or regulation.
LIQUIDITY AND CAPITAL RESOURCES
Exelon's businesses are capital intensive and require considerable
capital resources. These capital resources are primarily provided by internally
generated cash flows from Energy Delivery and Generation's operations. When
necessary, Exelon obtains funds from external sources in the capital markets and
through bank borrowings. Exelon's access to external financing at reasonable
terms depends on Exelon's and its subsidiaries' credit ratings and general
business conditions, as well as that of the utility industry in general. If
these conditions deteriorate to where Exelon no longer has access to external
financing sources at reasonable terms, Exelon has access to a $1.5 billion
revolving credit facility that Exelon currently utilizes
67
to support its commercial paper program. See the Credit Issues section of
Liquidity and Capital Resources for further discussion. Exelon primarily uses
its capital resources to fund capital requirements, including construction, to
invest in new and existing ventures, to repay maturing debt and to pay common
stock dividends. Future acquisitions that Exelon may undertake may require
external financing, which might include Exelon issuing common stock.
Cash Flows from Operating Activities
Cash flows provided by operations for the three months ended March 31,
2003 were $383 million compared to $826 million in the three months ended March
31, 2002. The decrease in cash flows was primarily attributable to a $305
million decrease in working capital. In the first quarter of 2003, approximately
40% of cash flows provided by operations were provided by Energy Delivery and
60% were provided by Generation. Enterprises' cash flows from operations were
immaterial to Exelon for the three months ended March 31, 2003. Energy
Delivery's cash flow from operating activities primarily results from sales of
electricity and gas to a stable and diverse base of retail customers at fixed
prices. Energy Delivery's future cash flows will depend upon the ability to
achieve cost savings in operations and the impact of the economy, weather and
customer choice on its revenues. Generation's cash flows from operating
activities primarily result from the sale of electric energy to wholesale
customers, including Energy Delivery and Enterprises. Generation's future cash
flow from operating activities will depend upon future demand and market prices
for energy and the ability to continue to produce and supply power at
competitive costs. Although the amounts may vary from period to period as a
result of the uncertainties inherent in business, Exelon expects that Energy
Delivery and Generation will continue to provide a reliable and steady source of
internal cash flow from operations for the foreseeable future.
Cash Flows from Investing Activities
Cash flows used in investing activities for the three months ended
March 31, 2003 were $457 million, compared to $630 million for the three months
ended March 31, 2002. The decrease is primarily attributable to a decrease in
capital expenditures due to two scheduled refueling outages occurring during the
three months ended March 31, 2003 compared to four outages in the same period in
the prior year and $70 million related to liquidated damages from Raytheon (see
Note 8 of the Condensed Combined Notes to Consolidated Financial Statements).
Capital expenditures by business segment for the three months ended March 31,
2003 and 2002 were as follows:
Three Months Ended March 31,
-----------------------------
2003 2002
- ----------------------------------------------------------------------
Energy Delivery $ 239 $ 250
Generation 175 308
Enterprises 6 18
Corporate and Other 7 10
- ----------------------------------------------------------------------
Total Capital Expenditures $ 427 $ 586
======================================================================
Energy Delivery's capital expenditures for 2003 reflect the
continuation of efforts to
68
further improve the reliability of its distribution system. Exelon anticipates
that Energy Delivery's capital expenditures will be funded by internally
generated funds, borrowings, the issuance of preferred securities, or capital
contributions from Exelon.
Generation's capital expenditures for 2003 reflect the construction of
three Exelon New England generating facilities with projected capacity of 2,421
MWs of energy, additions to and upgrades of existing facilities (including
nuclear refueling outages), and nuclear fuel. In February 2002, Generation
entered into an agreement to loan AmerGen up to $75 million at an interest rate
of one-month LIBOR plus 2.25%. In July 2002, the loan agreement and the loan
were increased to $100 million and the maturity date was extended to July 1,
2003. As of March 31, 2003, the balance of the loan to AmerGen was $35 million.
Exelon anticipates that Generation's capital expenditures will be funded by
internally generated funds, borrowings or capital contributions from Exelon.
Enterprises' capital expenditures for 2003 are primarily for additions
to or upgrades of existing facilities. All of Enterprises' capital expenditures
are expected to be funded by capital contributions or borrowings from Exelon.
Cash Flows from Financing Activities
Cash flows provided by financing activities were $108 million for the
three months ended March 31, 2003 compared to $15 million for the three months
ended March 31, 2002. The increase is primarily attributable to an increase in
net borrowings. See Notes 10 and 14 of the Condensed Combined Notes to
Consolidated Financial Statements for further discussion of Exelon's debt and
preferred securities financing activities in 2003.
Credit Issues
Exelon meets its short-term liquidity requirements primarily through
the issuance of commercial paper by the Exelon corporate holding company (Exelon
Corporate) and by ComEd, PECO and Generation. Exelon Corporate participates,
along with ComEd, PECO and Generation, in a $1.5 billion unsecured 364-day
revolving credit facility with a group of banks. The credit facility became
effective on November 22, 2002 and includes a term-out option that allows any
outstanding borrowings at the end of the revolving credit period to be repaid on
November 21, 2004. Exelon Corporate may increase or decrease the sublimits of
each of the participants upon written notification to the banks. As of March 31,
2003, Exelon Corporate's sublimit was $800 million, ComEd's was $100 million,
PECO's was $600 million and there was no sublimit for Generation. The credit
facility is used principally to support the commercial paper programs of Exelon
Corporate, ComEd, PECO and Generation. At March 31, 2003, Exelon's Consolidated
Balance Sheet reflected $1,150 million of commercial paper outstanding of which
$250 million was classified as long-term debt. For the three months ended March
31, 2003, the average interest rate on notes payable was approximately 1.41%.
69
The credit facility requires Exelon Corporate, ComEd, PECO and
Generation to maintain a cash from operations to interest expense ratio for the
twelve-month period ended on the last day of any quarter. The ratios exclude
revenues and interest expenses attributable to securitization debt, certain
changes in working capital, distributions on preferred securities of
subsidiaries and, in the case of Exelon Corporate and Generation, revenues from
Exelon New England and interest on the debt of Exelon New England's project
subsidiaries. Exelon Corporate is measured at the Exelon consolidated level. At
March 31, 2003, Exelon Corporate, ComEd, PECO and Generation were in compliance
with the credit agreement thresholds. The following table summarizes the
threshold reflected in the credit agreement that the ratio cannot be less than
for the twelve-month period ended March 31, 2003:
Exelon Corporate ComEd PECO Generation
- -------------------------------------------------------------------------------------------------------
Credit Agreement Threshold 2.65 to 1 2.25 to 1 2.25 to 1 3.25 to 1
- -------------------------------------------------------------------------------------------------------
To provide an additional short-term borrowing option that will
generally be more favorable to the borrowing participants than the cost of
external financing, Exelon operates an intercompany money pool. Participation in
the money pool is subject to authorization by Exelon's corporate treasurer.
ComEd and its subsidiary, Commonwealth Edison Company of Indiana, Inc., PECO,
Generation and Exelon Business Services Company (BSC) may participate in the
money pool as lenders and borrowers, and Exelon Corporate as a lender.
Contributions to and permitted borrowings from the money pool are based on
whether the contributions and borrowings result in economic benefits to all the
participants. Interest on borrowings is based on short-term market rates of
interest, or, if from an external source, specific borrowing rates. During the
first quarter 2003, ComEd had various loans to Generation under the money pool.
The maximum amount of loans outstanding at any time during the quarter was $335
million. As of March 31, 2003, there was no outstanding balance on these loans.
Exelon's access to the capital markets, including the commercial paper
market, and its financing costs in those markets depend on the securities
ratings of the entity that is accessing the capital markets. None of Exelon's
borrowings is subject to default or prepayment as a result of a downgrading of
securities ratings although such a downgrading could increase fees and interest
charges under Exelon's $1.5 billion credit facility and certain other credit
facilities. From time to time, Exelon enters into energy commodity and other
contracts that require the maintenance of investment grade ratings. Failure to
maintain investment grade ratings would allow counterparties to certain energy
commodity contracts to terminate the contracts and settle the transactions on a
net present value basis.
Exelon obtained an order from the United States Securities and Exchange
Commission (SEC) under PUHCA authorizing through March 31, 2004 financing
transactions, including the issuance of common stock, preferred securities,
long-term debt and short-term debt, in an aggregate amount not to exceed $4
billion. As of March 31, 2003, there was $2.1 billion of financing authority
remaining under the SEC order. Exelon's request for an additional $4 billion in
financing authorization is pending with the SEC. The current order limits
Exelon's short-term debt outstanding to $3 billion of the $4 billion total
financing authority. Exelon's request that the short-term debt sub-limit
restriction be eliminated is pending with the SEC. The SEC order also authorized
Exelon to issue guarantees of up to $4.5 billion outstanding at any one time. At
70
March 31, 2003, Exelon had provided $1.5 billion of guarantees under the SEC
order. See Contractual Obligations, Commercial Commitments and Off-Balance Sheet
Obligations in this section for further discussion of guarantees. The SEC order
requires Exelon and ComEd to maintain a ratio of common equity to total
capitalization (including securitization debt) on and after June 30, 2002 of not
less than 30%. At March 31, 2003, Exelon and ComEd's common equity ratios were
32% and 46%, respectively. Exelon and ComEd expect that they will maintain a
common equity ratio of at least 30%.
Under PUHCA, Exelon, ComEd, PECO and Generation can pay dividends only
from retained, undistributed or current earnings. However, the SEC order granted
permission to ComEd, and to Exelon, to the extent Exelon receives dividends from
ComEd paid from ComEd additional paid-in-capital, to pay up to $500 million in
dividends out of additional paid-in capital, although Exelon may not pay
dividends out of paid-in capital after December 31, 2002 if its common equity is
less than 30% of its total capitalization. At March 31, 2003, Exelon had
retained earnings of $2.3 billion, including ComEd's retained earnings of $652
million, PECO's retained earnings of $447 million and Generation's undistributed
earnings of $980 million. Exelon is also limited by order of the SEC under PUHCA
to an aggregate investment of $4 billion in exempt wholesale generators (EWGs)
and foreign utility companies (FUCOs). At March 31, 2003, Exelon had invested
$2.2 billion in EWGs, leaving $1.8 billion of investment authority under the
order. Exelon's request for an additional $1.5 billion in EWG investment
authorization is pending with the SEC.
Contractual Obligations, Commercial Commitments and Off-Balance Sheet
Obligations
Contractual obligations represent cash obligations that are considered
to be firm commitments and commercial commitments represent commitments
triggered by future events. Exelon's contractual obligations and commercial
commitments as of March 31, 2003 were materially unchanged, other than the
normal course of business, from the amounts set forth in the 2002 Form 10-K
except for the following:
o On March 3, 2003, ComEd entered into an agreement with various
Illinois electric retail market suppliers, key customer groups and
governmental parties regarding several matters affecting ComEd's rates
for electric service (Agreement). The Agreement addressed, among other
things, issues related to ComEd's residential delivery services rate
proceeding, market value index proceeding, the process for competitive
service declarations for large-load customers and an extension of the
purchased power agreement (PPA) with Generation. The parties to the
Agreement agreed to make and support a series of coordinated filings
intended to lead to the issuance by the Illinois Commerce Commission
(ICC) of orders consistent with the Agreement. Those orders, which
were issued on March 28, 2003, are subject to rehearing. Rehearing
requests have been filed with the ICC. Rehearing requests may be
considered through the middle of May 2003. The Agreement will not
become effective as long as the ICC orders are subject to any
rehearing request or if a stay is issued with respect to any of those
orders.
The Agreement provides for a modification of the methodology used
to determine ComEd's market value energy credit. That credit is used
to determine the price for specified market-based rate offerings and
the amount of the CTC that ComEd is allowed
71
to collect from customers who select an ARES or the PPO. The credit
will be adjusted upward through agreed upon "adders," which will take
effect in June 2003 and will have the effect of reducing ComEd's CTC
charges to customers. The estimated annual revenue impact of the
reduction in CTC revenues under the Agreement is approximately $65
million to $70 million. In addition, customers will be offered an
option to lock in CTC charges for longer periods. Currently, those
charges are subject to change annually.
During first quarter of 2003, ComEd recorded a charge to earnings
associated with the funding of specified programs and initiatives
associated with the Agreement of $51 million on a present value basis
before income taxes. This amount is partially offset by the reversal
of a $12 million (before income taxes) reserve established in the
third quarter of 2002 for a potential capital disallowance in ComEd's
delivery services rate proceeding and a credit of $10 million (before
income taxes) related to the capitalization of employee incentive
payments provided for in the delivery services order. The net one-time
charge for these items is $29 million (before income taxes).
o ComEd and PECO have entered into several agreements with a tax
consultant related to the filing of refund claims with the Internal
Revenue Service (IRS). The fees for these agreements are contingent
upon a successful outcome and are based upon a percentage of the
refunds recovered from the IRS, if any. As such, ComEd and PECO would
have positive net cash flows related to these agreements if any fees
are paid to the tax consultant. These potential tax benefits and
associated fees could be material to the financial position, results
of operations and cash flows of Energy Delivery. Energy Delivery
cannot predict the timing of the final resolution of these refund
claims.
o See Notes 10 and 14 to the Condensed Combined Notes to Consolidated
Financial Statements for discussion of material changes in Exelon's
debt and preferred securities obligations from those set forth in the
2002 Form 10-K.
o See Note 8 of the Condensed Combined Notes to Consolidated Financial
Statements for commercial commitments tables representing Exelon's
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 their
obligations.
72
COMMONWEALTH EDISON COMPANY
- ---------------------------
GENERAL
ComEd operates in a single business segment and its operations consist
of the regulated sale of electricity and distribution and transmission services
in northern Illinois.
RESULTS OF OPERATIONS
Three Months Ended March 31, 2003 Compared to Three Months Ended March 31, 2002
Significant Operating Trends - ComEd
Three Months Ended March 31,
----------------------------
2003 2002 Variance % Change
- ------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 1,424 $ 1,315 $ 109 8.3%
OPERATING EXPENSES
Purchased Power 578 538 40 7.4%
Operating and Maintenance 261 237 24 10.1%
Depreciation and Amortization 94 135 (41) (30.4%)
Taxes Other Than Income 80 73 7 9.6%
- -----------------------------------------------------------------------------------------------------
Total Operating Expenses 1,013 983 30 3.1%
- -----------------------------------------------------------------------------------------------------
OPERATING INCOME 411 332 79 23.8%
OTHER INCOME AND DEDUCTIONS
Interest Expense (110) (126) 16 (12.7%)
Distributions on Company-Obligated Mandatorily
Redeemable Preferred Securities of Subsidiary Trusts
Holding Solely the Company's Subordinated Debt Securities (7) (7) -- --
Other, Net 22 14 8 57.1%
- -----------------------------------------------------------------------------------------------------
Total Other Income and Deductions (95) (119) 24 (20.2%)
- -----------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES AND CUMULATIVE
EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE 316 213 103 48.4%
INCOME TAXES 126 84 42 50.0%
- -----------------------------------------------------------------------------------------------------
NET INCOME BEFORE CUMULTIVE EFFECT OF A CHANGE IN
ACCOUNTING PRINCIPLE 190 129 61 47.3%
CUMULTIVE EFFECT OF A CHANGE IN ACCOUNTING
PRINCIPLE 5 -- 5 n.m.
- -----------------------------------------------------------------------------------------------------
NET INCOME $ 195 $ 129 $ 66 51.2%
=====================================================================================================
n.m. -not meaningful
Net Income
Net income increased $66 million, or 51% for the three months ended
March 31, 2003 as compared to the same period in 2002. Net income was positively
impacted by higher operating revenues and lower interest expense, partially
offset by higher operating expenses.
73
Operating Revenues
ComEd's electric sales statistics are as follows:
Three Months Ended March 31,
-----------------------------
Retail Deliveries - (in GWhs) 2003 2002 Variance % Change
- ----------------------------------------------------------------------------------------
Bundled Deliveries (1)
Residential 6,886 6,409 477 7.4%
Small Commercial & Industrial 5,627 5,450 177 3.2%
Large Commercial & Industrial 1,484 1,956 (472) (24.1%)
Public Authorities & Electric Railroads 1,416 1,801 (385) (21.4%)
- ----------------------------------------------------------------------------------------
15,413 15,616 (203) (1.3%)
- ----------------------------------------------------------------------------------------
Unbundled Deliveries (2)
ARES
Small Commercial & Industrial 1,348 1,004 344 34.3%
Large Commercial & Industrial 1,832 1,386 446 32.2%
Public Authorities & Electric Railroads 282 138 144 104.3%
- ----------------------------------------------------------------------------------------
3,462 2,528 934 36.9%
- ----------------------------------------------------------------------------------------
PPO
Small Commercial & Industrial 793 763 30 3.9%
Large Commercial & Industrial 1,433 1,311 122 9.3%
Public Authorities & Electric Railroads 537 242 295 121.9%
- ----------------------------------------------------------------------------------------
2,763 2,316 447 19.3%
- ----------------------------------------------------------------------------------------
Total Unbundled Deliveries 6,225 4,844 1,381 28.5%
- ----------------------------------------------------------------------------------------
Total Retail Deliveries 21,638 20,460 1,178 5.8%
========================================================================================
(1) Bundled service reflects deliveries to customers taking electric service
under tariffed rates.
(2) Unbundled service reflects customers electing to receive electric generation
service from an ARES or the PPO.
74
Three Months Ended March 31,
---------------------------
Electric Revenue 2003 2002 Variance % Change
- ----------------------------------------------------------------------------------------
Bundled Revenues (1)
Residential $ 546 $ 518 $ 28 5.4%
Small Commercial & Industrial 397 391 6 1.5%
Large Commercial & Industrial 74 102 (28) (27.5%)
Public Authorities & Electric Railroads 84 92 (8) (8.7%)
- ----------------------------------------------------------------------------------------
1,101 1,103 (2) (0.2%)
- ----------------------------------------------------------------------------------------
Unbundled Revenues (2)
ARES
Small Commercial & Industrial 41 12 29 n.m.
Large Commercial & Industrial 49 10 39 n.m.
Public Authorities & Electric Railroads 9 2 7 n.m.
- ----------------------------------------------------------------------------------------
99 24 75 n.m.
- ----------------------------------------------------------------------------------------
PPO
Small Commercial & Industrial 50 43 7 16.3%
Large Commercial & Industrial 72 64 8 12.5%
Public Authorities & Electric Railroads 27 13 14 107.7%
- ----------------------------------------------------------------------------------------
149 120 29 24.2%
- ----------------------------------------------------------------------------------------
Total Unbundled Revenues 248 144 104 72.2%
Total Electric Retail Revenues 1,349 1,247 102 8.2%
Wholesale and Miscellaneous Revenue (3) 75 68 7 10.3%
- ----------------------------------------------------------------------------------------
Total Electric Revenue $ 1,424 $ 1,315 $ 109 8.3%
========================================================================================
(1) Bundled revenue reflects deliveries to customers taking electric service
under tariffed rates, which include the cost of energy and the delivery
cost of the transmission and the distribution of the energy.
(2) Revenue from customers choosing an ARES includes a distribution charge and
a CTC charge. Transmission charges received from ARES are included in
wholesale and miscellaneous revenue. Revenue from customers choosing the
PPO includes an energy charge at market rates, transmission and
distribution charges, and a CTC charge.
(3) Wholesale and miscellaneous revenues include transmission revenue, sales to
municipalities and other wholesale energy sales.
n.m. - not meaningful
The changes in electric retail revenues for the three months ended
March 31, 2003, as compared to the same period in 2002, are attributable to the
following:
Variance
- --------------------------------------------------------
Rate Changes $ 82
Weather 54
Customer Choice (39)
Volume 7
Other Effects (2)
- --------------------------------------------------------
Electric Retail Revenue $ 102
- --------------------------------------------------------
o Rate Changes. The increase in revenues attributable to rate changes
reflects the collection of additional CTC's in 2003 by ComEd of $105
million due to an increase in the number of customers choosing an
alternative energy supplier and changes in the wholesale market price
of electricity, net of increased mitigation factors. Increased
wholesale market prices decreased revenue received under ComEd's PPO
by $23 million.
75
o Weather. The demand for electricity is impacted by weather conditions.
Very warm weather in summer months and very cold weather in other
months is referred to as "favorable weather conditions," because these
weather conditions result in increased sales of electricity.
Conversely, mild weather reduces demand. The weather impact for the
three months ended March 31, 2003 was favorable compared to the same
period in 2002 as a result of colder winter weather in 2003. Heating
degree-days increased 17% in the three months ended March 31, 2003
compared to the same period in 2002.
o Customer Choice. All ComEd customers have the choice to purchase
energy from other suppliers. This choice generally does not impact the
volume of deliveries, but affects revenue collected from customers
related to energy supplied by ComEd. However, as of March 31, 2003, no
alternative electric supplier has sought approval from the ICC, and no
electric utilities have chosen to enter the ComEd residential market
for the supply of electricity.
The decrease in revenues reflects customers in Illinois electing
to purchase energy from an ARES or the PPO. As of March 31, 2003,
approximately 22,700 retail customers had elected to purchase energy
from an ARES or the ComEd PPO. This represents an increase in
delivered MWhs to such customers from approximately 4.8 million for
the three months ended March 31, 2002 to 6.2 million for the three
months ended March 31, 2003, or from 24% to 29% of total quarterly
retail deliveries.
o Volume. Revenues from higher delivery volume, exclusive of weather,
increased due to an increased number of customers and increased usage
per customer, primarily small commercial and industrial.
The $7 million increase in wholesale and miscellaneous revenue for the
three months ended March 31, 2003 as compared to the three months ended March
31, 2002 was due primarily to a $5 million increase in sales for resale to
municipalities and others as a result of a 17% increase in heating degree-days
in 2003.
Purchased Power
Purchased power expense increased $40 million, or 7% for the three
months ended March 31, 2003. The increase in purchased power expense was
primarily attributable to a $20 million increase due to favorable weather
conditions, an increase of $12 million due to higher volume, $17 million due to
pricing changes related to ComEd's PPA with Generation and an increase of $16
million under the PPA related to decommissioning collections associated with the
adoption of SFAS No. 143 that were not included in purchased power in 2002,
offset by a $28 million decrease as a result of customers choosing to purchase
energy from an ARES. The $16 million increase in purchased power expense related
to SFAS No. 143 is offset by lower regulatory asset amortization.
Operating and Maintenance
Operating and maintenance (O&M) expense increased $24 million, or 10%,
for the three months ended March 31, 2003. The increase in O&M expense was
primarily attributable to a net one-time charge of $41 million in 2003 as the
result of the Agreement as more fully described in Note 4 - Regulatory Issues,
offset by higher corporate allocations in 2002 due to executive severance.
76
Depreciation and Amortization
Depreciation and amortization expense decreased $41 million, or 30%,
for the three months ended March 31, 2003 as follows:
Three Months Ended March 31,
----------------------------
2003 2002 Variance % Change
- -------------------------------------------------------------------------------------------------------------------
Depreciation Expense $ 75 $ 91 $ (16) (17.6%)
Recoverable Transition Costs Amortization 11 23 (12) (52.2%)
Other Amortization Expense 8 21 (13) (61.9%)
- --------------------------------------------------------------------------------------------------
Total Depreciation and Amortization $ 94 $ 135 $ (41) (30.4%)
==================================================================================================
The decrease in depreciation expense is primarily due to lower
depreciation rates effective July 1, 2002, partially offset by higher property,
plant and equipment balances. ComEd completed a depreciation study and
implemented lower depreciation rates effective July 1, 2002. The new
depreciation rates reflect ComEd's 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 annual reduction in
depreciation expense is estimated to be approximately $100 million ($60 million,
net of income taxes) based on December 31, 2001 plant balances. As a result of
the change, depreciation expense decreased $24 million ($14 million, net of
income taxes) for the three months ended March 31, 2003.
Recoverable transition costs amortization decreased in the three months
ended March 31, 2003 compared to the same period in 2002. The decrease is a
result of the extension of the rate freeze through 2006 which occurred in June
2002. ComEd expects to fully recover its recoverable transition costs regulatory
asset balance of $164 million by 2006. Consistent with the provision 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 decrease in other amortization primarily relates to the
reclassification of a regulatory asset for nuclear decommissioning as a result
of the adoption of SFAS No. 143 in 2003 (see Note 2 of the Condensed Combined
Notes to Consolidated Financial Statements). This decrease is offset by
increased purchased power expense from Generation.
Taxes Other Than Income
Taxes other than income increased by $7 million or 10%, as a result of
a $4 million increase in real estate and municipal taxes and $1 million in
Illinois Public Utility Fund taxes which were not charged in 2002.
77
Interest Charges
Interest charges consist of interest expense and distributions on
Company-Obligated Mandatorily Redeemable Preferred Securities of Subsidiary
Trusts. Interest charges decreased $16 million, or 13%, for the three months
ended March 31, 2003. The decrease in interest expense was primarily
attributable to the impact of lower interest rates for the three months ended
March 31, 2003 as compared to the three months ended March 31, 2002 and the
annual retirement of $340 million in Transitional Trust Notes.
Other, Net
Other, Net increased income by $8 million for the three months ended
March 31, 2003. The increase was primarily attributable to the reversal of a $12
million reserve in 2003 for a potential plant disallowance as the result of the
Agreement as more fully described in Note 4 to the Condensed Combined Notes to
Consolidated Financial Statements.
Income Taxes
The effective income tax rate was 39.9% for the three months ended
March 31, 2003, compared to 39.4% for the three months ended March 31, 2002.
Due to revenue needs in the states in which ComEd operates, various
state income tax and fee increases have been proposed or are being contemplated.
If these changes are enacted, they could increase ComEd's state income tax
expense. At this time, however, ComEd cannot predict whether legislation or
regulation will be introduced, the form of any legislation or regulation,
whether any such legislation or regulation will be passed by the state
legislatures or regulatory bodies, and, if enacted, whether any such legislation
or regulation would be effective retroactively or prospectively. As a result,
ComEd cannot currently estimate the effect of these potential changes in tax
laws or regulation.
Cumulative Effect of a Change in Accounting Principle
On January 1, 2003, ComEd adopted SFAS No. 143, resulting in income of
$5 million.
LIQUIDITY AND CAPITAL RESOURCES
ComEd's business is capital intensive and requires considerable capital
resources. ComEd's capital resources are primarily provided by internally
generated cash flows from operations and, to the extent necessary, external
financing including the issuance of commercial paper or participation in the
intercompany money pool. ComEd's access to external financing at reasonable
terms is dependent on its credit ratings and general business conditions, as
well as that of the utility industry in general. If these conditions deteriorate
to where ComEd no longer has access to external financing sources at reasonable
terms, ComEd has access to a revolving credit facility that ComEd currently
utilizes to support its commercial paper program. See the Credit Issues section
of Liquidity and Capital Resources for further discussion. Capital resources are
used primarily to fund ComEd's capital requirements, including construction,
repayments of maturing debt and the payment of dividends.
78
Cash Flows from Operating Activities
Cash flows provided by operations were $67 million for the three months
ended March 31, 2003 compared to $278 million for the three months ended March
31, 2002. The decrease in cash flows in 2003 was primarily attributable to a
$216 million decrease in working capital as a result of the paydown of
intercompany payables to affiliates and other outstanding liabilities, a
decrease in depreciation and amortization of $41 million offset by an increase
in net income of $66 million. ComEd's future cash flows will depend upon the
ability to achieve cost savings in operations and the impact of the economy,
weather, and customer choice on its revenues. Although the amounts may vary from
period to period as a result of uncertainties inherent in the business, ComEd
expects to continue to provide a reliable and steady source of internal cash
flow from operations for the foreseeable future.
Cash Flows from Investing Activities
Cash flows used in investing activities were $164 million for the three
months ended March 31, 2003 compared to $175 million for the three months ended
March 31, 2002. The decrease in cash flows used in investing activities in 2003
was primarily attributable to an $8 million decrease in capital expenditures.
ComEd estimates that it will spend approximately $720 million in total
capital expenditures for 2003. Approximately two-thirds of the budgeted 2003
expenditures are for continuing efforts to further improve the reliability of
its transmission and distribution systems. The remaining one third is for
capital additions to support new business and customer growth. ComEd anticipates
that its capital expenditures will be funded by internally generated funds,
borrowings, the issuance of preferred securities, or capital contributions from
Exelon. ComEd's proposed capital expenditures and other investments are subject
to periodic review and revision to reflect changes in economic conditions and
other factors.
Cash Flows from Financing Activities
Cash flows from financing activities were $113 million for the three
months ended March 31, 2003 as compared to cash flows used in financing of $44
million for the three months ended March 31, 2002. Cash flows from financing
activities were primarily attributable to debt issuance partially offset by
retirements and redemptions and payments of dividends to Exelon. The increase in
cash flows from financing activities is primarily attributable to increased debt
and preferred securities issuances of $500 million partially offset by increased
debt and preferred securities redemptions of $306 million and increased interest
rate swap settlement payments of $34 million. See Notes 10 and 14 of the
Condensed Combined Notes to Consolidated Financial Statements for further
discussion of ComEd's debt and preferred securities financing activities. ComEd
paid a $120 million dividend to Exelon during the three months ended March 31,
2003 compared to a $118 million dividend for the three months ended March 31,
2002.
79
Credit Issues
ComEd meets its short-term liquidity requirements primarily through the
issuance of commercial paper and borrowings from Exelon's intercompany money
pool. ComEd, along with Exelon, PECO, and Generation, participates in a $1.5
billion unsecured 364-day revolving credit facility with a group of banks. The
credit facility that became effective on November 22, 2002 includes a term-out
option that allows any outstanding borrowings at the end of the revolving credit
period to be repaid on November 21, 2004. Exelon may increase or decrease the
sublimits of each of the participants upon written notification to the banks. As
of March 31, 2003, ComEd's sublimit was $100 million. The credit facility is
used principally to support ComEd's commercial paper program. At March 31, 2003,
ComEd's Consolidated Balance Sheet reflects $45 million in commercial paper
outstanding. For the three months ended March 31, 2003, the average interest
rate on notes payable was approximately 1.48%.
The credit facility requires ComEd to maintain a cash from operations
to interest expense ratio for the twelve-month period ended on the last day of
any quarter. The ratio excludes revenues and interest expenses attributable to
securitization debt, certain changes in working capital, and distributions on
preferred securities of subsidiaries. ComEd's threshold for the ratio reflected
in the credit agreement cannot be less than 2.25 to 1 for the twelve-month
period ended March 31, 2003. At March 31, 2003, ComEd was in compliance with the
credit agreement thresholds.
To provide an additional short-term borrowing option that will
generally be more favorable to the borrowing participants than the cost of
external financing, Exelon operates an intercompany money pool. Participation in
the money pool is subject to authorization by the Exelon corporate treasurer.
ComEd and its subsidiary Commonwealth Edison of Indiana, Inc., PECO, Generation
and BSC may participate in the money pool as lenders and borrowers, and Exelon
as a lender. Funding of, and borrowings from, the money pool are predicated on
whether such funding results in mutual economic benefits to each of the
participants, although Exelon is not permitted to be a net borrower from the
money pool. Interest on borrowings is based on short-term market rates of
interest or specific borrowing rates if the funds are provided by external
financing. There were no material money pool transactions in 2002. During the
first quarter 2003, ComEd had various loans to Generation under the money pool.
The maximum amount of outstanding loans at any time during the quarter was $335
million. As of March 31, 2003, there was no outstanding balance on these loans.
ComEd's access to the capital markets, including the commercial paper
market, and its financing costs in those markets are dependent on its securities
ratings. None of ComEd's borrowings is subject to default or prepayment as a
result of a downgrading of securities ratings although such a downgrading could
increase interest charges under certain bank credit facilities.
Under PUHCA, ComEd can only pay dividends from retained or current
earnings. However, the SEC has authorized ComEd to pay up to $500 million in
dividends out of additional paid-in capital, provided ComEd may not pay
dividends out of paid-in capital after December 31, 2002 if its common equity is
less than 30% of its total capitalization (including
80
transitional trust notes). At March 31, 2003, ComEd had retained earnings of
$652 million and its common equity ratio was 46%.
Long-term debt included $1.9 billion of transitional trust notes.
Contractual Obligations, Commercial Commitments and Off-Balance Sheet
Obligations
Contractual obligations represent cash obligations that are considered
to be firm commitments and commercial commitments represent commitments
triggered by future events. ComEd's contractual obligations and commercial
commitments as of March 31, 2003 were materially unchanged, other than in the
normal course of business, from the amounts set forth in the 2002 Form 10-K
except for the following:
o On March 3, 2003, ComEd entered into the Agreement with various
Illinois electric retail market suppliers, key customer groups and
governmental parties regarding several matters affecting ComEd's rates
for electric service. The Agreement addressed, among other things,
issues related to ComEd's residential delivery services rate
proceeding, market value index proceeding, the process for competitive
service declarations for large-load customers and an extension of the
PPA with Generation. The parties to the Agreement agreed to make and
support a series of coordinated filings intended to lead to the
issuance by the ICC of orders consistent with the Agreement. Those
orders, which were issued on March 28, 2003, are subject to rehearing.
Rehearing requests have been filed with the ICC. Rehearing requests
may be considered through the middle of May 2003. The Agreement will
not become effective as long as the ICC orders are subject to any
rehearing request or if a stay is issued with respect to any of those
orders.
The Agreement provides for a modification of the methodology used
to determine ComEd's market value energy credit. That credit is used to
determine the price for specified market-based rate offerings and the
amount of the CTC that ComEd is allowed to collect from customers who
select an ARES or the PPO. The credit will be adjusted upward through
agreed upon "adders," which will take effect in June 2003, and would have
the effect of reducing ComEd's CTC charges to customers. The estimated
annual revenue impact of the reduction in CTC revenues under the Agreement
would be approximately $65 million to $70 million. In addition, customers
will be offered an option to lock in CTC charges for longer periods.
Currently, those charges are subject to change annually.
In the first quarter of 2003, ComEd recorded a charge to earnings
associated with the funding of specified programs and initiatives
associated with the Agreement of $51 million on a present value basis
before income taxes. This amount is partially offset by the reversal of a
$12 million (before income taxes) reserve established in the third quarter
of 2002 for a potential capital disallowance in ComEd's delivery services
rate proceeding and a credit of $10 million (before income taxes) related
to the capitalization of employee incentive payments provided for in the
delivery services order. The net one-time charge for these items is $29
million (before income taxes).
o ComEd has entered into several agreements with a tax consultant
related to the filing of refund claims with the IRS. The fees for
these agreements are contingent upon a successful outcome and are
based upon a percentage of the refunds recovered from the IRS, if any.
As
81
such, ComEd would have positive net cash flows related to these
agreements if any fees are paid to the tax consultant. These potential
tax benefits and associated fees could be material to the financial
position, results of operations and cash flows of ComEd. ComEd cannot
predict the timing of the final resolution of these refund claims.
o See Notes 10 and 14 to the Condensed Combined Notes to Consolidated
Financial Statements for discussion of material changes in ComEd's
debt and preferred securities obligations from those set forth in the
2002 Form 10-K.
o See Note 8 of the Condensed Combined Notes to Consolidated Financial
Statements for commercial commitments tables representing ComEd's
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 their
obligations.
82
PECO ENERGY COMPANY
- -------------------
GENERAL
PECO operates in a single business segment, and its operations consist
of the regulated sale of electricity and distribution and transmission in
southeastern Pennsylvania and the sale of natural gas and distribution services
in the Pennsylvania counties surrounding the City of Philadelphia.
RESULTS OF OPERATIONS
Three Months Ended March 31, 2003 Compared to Three Months Ended March 31, 2002
Significant Operating Trends - PECO
Three Months Ended March 31,
---------------------------
2003 2002 Variance % Change
- -------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 1,217 $1,020 $ 197 19.3%
OPERATING EXPENSES
Purchased Power 422 351 71 20.2%
Fuel 191 135 56 41.5%
Operating and Maintenance 139 136 3 2.2%
Depreciation and Amortization 120 112 8 7.1%
Taxes Other Than Income 63 59 4 6.8%
- ------------------------------------------------------------------------------------------------------
Total Operating Expenses 935 793 142 17.9%
- ------------------------------------------------------------------------------------------------------
OPERATING INCOME 282 227 55 24.2%
- ------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (86) (95) 9 (9.5%)
Distributions on Company-Obligated Mandatorily
Redeemable Preferred Securities of a Partnership
which Holds Solely Subordinated Debentures of
the Company (2) (2) -- --
Other, Net 9 1 8 n.m.
- ------------------------------------------------------------------------------------------------------
Total Other Income and Deductions (79) (96) 17 (17.7%)
- ------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 203 131 72 55.0%
INCOME TAXES 66 42 24 57.1%
- ------------------------------------------------------------------------------------------------------
NET INCOME 137 89 48 53.9%
Preferred Stock Dividends (2) (2) -- --
- ------------------------------------------------------------------------------------------------------
NET INCOME ON COMMON STOCK $ 135 $ 87 $ 48 55.2%
======================================================================================================
n.m. - not meaningful
83
Net Income
Net income on common stock increased $48 million, or 55% for the three
months ended March 31, 2003 as compared to the same period in 2002. The increase
was a result of higher sales volume and lower interest expense on debt,
partially offset by increased income taxes and depreciation and amortization
expense.
Operating Revenue
PECO's electric sales statistics are as follows:
Three Months Ended March 31,
----------------------------
Retail Deliveries - (in GWhs) 2003 2002 Variance % Change
- -------------------------------------------------------------------------------------------------------------------
Bundled Deliveries (1)
Residential 3,115 2,056 1,059 51.5%
Small Commercial & Industrial 1,780 1,757 23 1.3%
Large Commercial & Industrial 3,482 3,351 131 3.9%
Public Authorities & Electric Railroads 253 193 60 31.1%
- -------------------------------------------------------------------------------------------------------------------
8,630 7,357 1,273 17.3%
- -------------------------------------------------------------------------------------------------------------------
Unbundled Deliveries (2)
Residential 264 792 (528) (66.7%)
Small Commercial & Industrial 202 96 106 110.4%
Large Commercial & Industrial 210 103 107 103.9%
Public Authorities & Electric Railroads (3) -- -- -- 0.0%
- -------------------------------------------------------------------------------------------------------------------
676 991 (315) (31.8%)
- -------------------------------------------------------------------------------------------------------------------
Total Retail Deliveries 9,306 8,348 958 11.5%
===================================================================================================================
(1) Bundled service reflects deliveries to customers taking electric service
under tariffed rates.
(2) Unbundled service reflects customers electing to receive electric
generation service from an alternative energy supplier.
(3) PECO's sales to Public Authorities and Electric Railroads were less than
one GWh per quarter.
84
Three Months Ended March 31,
----------------------------
Electric Revenue 2003 2002 Variance % Change
- --------------------------------------------------------------------------------------
Bundled Revenue (1)
Residential $ 359 $ 243 $ 116 47.7%
Small Commercial & Industrial 194 189 5 2.6%
Large Commercial & Industrial 266 244 22 9.0%
Public Authorities & Electric Railroads 22 18 4 22.2%
- --------------------------------------------------------------------------------------
841 694 147 21.2%
- --------------------------------------------------------------------------------------
Unbundled Revenue (2)
Residential 17 54 (37) (68.5%)
Small Commercial & Industrial 10 5 5 100.0%
Large Commercial & Industrial 6 3 3 100.0%
Public Authorities & Electric Railroads (3) -- -- -- --
- --------------------------------------------------------------------------------------
33 62 (29) (46.8%)
- --------------------------------------------------------------------------------------
Total Electric Retail Revenues 874 756 118 15.6%
Wholesale and Miscellaneous Revenue (4) 55 55 -- --
- --------------------------------------------------------------------------------------
Total Electric Revenue $ 929 $ 811 $ 118 14.5%
======================================================================================
(1) Bundled revenue reflects revenue from customers taking electric service
under tariffed rates, which includes the cost of energy, the delivery cost
of the transmission and the distribution of the energy and a CTC charge.
(2) Unbundled revenue reflects revenue from customers electing to receive
generation from an alternative supplier, which includes a distribution
charge and a CTC charge.
(3) PECO's sales to Public Authorities and Electric Railroads were less than $1
million per quarter.
(4) Wholesale and miscellaneous revenues include
transmission revenue and other wholesale energy sales.
The changes in electric retail revenues for the three months ended
March 31, 2003, as compared to the same period in 2002, are as follows:
Variance
- ----------------------------------------------------------------
Weather $47
Volume 43
Customer Choice 19
Other Effects 9
- -----------------------------------------------------------------
Retail Revenue $118
- -----------------------------------------------------------------
o Weather. The weather impact was favorable compared to the prior year
as a result of colder winter weather. Heating degree-days increased
33% for the three months ended March 31, 2003 compared to the same
period in 2002.
o Volume. Exclusive of weather impacts, higher delivery volume affected
PECO's revenue by $43 million compared to the same period in 2002
primarily related to increases in the residential and large commercial
and industrial customer classes.
o Customer Choice. All PECO customers may choose to purchase energy from
other suppliers. This choice generally does not impact kWh deliveries,
but reduces revenue collected from customers because they are not
obtaining generation supply from PECO.
As of March 31, 2003, the customer load served by alternative suppliers
was 1,062 MWs or 13.1% as compared to 1,010 MWs or 13.1% as of March 31, 2002.
For the three months ended March 31, 2003, the percent of PECO's total retail
deliveries for which PECO was the electric supplier was 92.8% compared to 88.2%
in 2002. As of March 31, 2003, the
85
number of customers served by alternative suppliers was 273,724 or 17.9% as
compared to 357,789 or 23.4% as of March 31, 2002. The increases in customers
and the percentage of load served by PECO primarily resulted from customers
selecting or returning to PECO as their electric generation supplier.
The PUC's Final Electric Restructuring Order established MST to promote
competition. The MST requirements provide that if, as of January 1, 2003, less
than 50% of residential and commercial customers have chosen an alternative
electric generation supplier, the number of customers sufficient to meet the MST
shall be randomly selected and assigned to an alternative electric generation
supplier through a PUC determined process. On January 1, 2003, the number of
customers choosing an alternative electric generation supplier did not meet the
MST. In January 2003, PECO submitted to the PUC an MST plan to meet the 50%
threshold requirement for its commercial customers, which was approved by the
PUC in February 2003. As of March 31, 2003, an auction had been completed for
the commercial customers and the customer enrollment phase is currently in
process. The randomly selected customers will be transferred to the alternative
electric generation suppliers in May 2003, if they do not choose the option to
not participate in the program. In February 2003, PECO filed a residential
customer MST plan, and on May 1, 2003, the PUC approved the plan. The approved
plan provides for a two-step process with a total of up to 400,000 residential
customers being assigned to winning alternative electric generation supplier
bidders: up to 100,000 in July 2003, and another 300,000 in December 2003. Any
customer transferred would have the right to return to PECO at any time. PECO
does not expect the transfer of customers pursuant to the MST plan to have a
material impact on its results of operations, financial position or cash flows.
o Other Effects. The increase in revenues attributable to rate changes
primarily reflects an increase in the average price mix related to the
large commercial and industrial customer class as compared to the same
period in 2002.
86
PECO's gas sales statistics for the three months ended March 31, 2003
as compared to the same period in 2002 are as follows:
Three Months Ended March 31,
----------------------------
2003 2002 Variance % Change
- ----------------------------------------------------------------------------------------------------
Deliveries in mmcf 39,626 31,357 8,269 26.4%
Revenue $ 288 $ 209 $ 79 37.8%
- ---------------------------------------------------------------------------------------
The changes in gas revenue for the three months ended March 31, 2003,
as compared to the same period in 2002, are as follows:
Variance
- ----------------------------------------------------------------------------------------
Weather $ 59
Volume 17
Rate Changes 3
- ----------------------------------------------------------------------------------------
Gas Revenue $ 79
========================================================================================
o Weather. The weather impact was favorable compared to the prior year
as a result of colder winter weather. Heating degree-days increased
33% in the three months ended March 31, 2003 compared to the same
period in 2002.
o Volume. Exclusive of weather impacts, higher delivery volume increased
revenue in the three months ended March 31, 2003 compared to the same
period in 2002 resulting from customer growth. Deliveries to
customers, excluding the effects of weather, increased 5% in the three
months ended March 31, 2003 compared to the same period in 2002.
o Rate Changes. The favorable variance in rates is attributable to a 15%
increase in the purchased gas adjustment by the PUC effective March 1,
2003. The average rate per million cubic feet for the three months
ended March 31, 2003 was 9% higher than the same 2002 period. PECO's
gas rates are subject to periodic adjustments by the PUC and are
designed to recover from or refund to customers the difference between
actual cost of purchased gas and the amount included in base rates and
to recover or refund increases or decreases in certain state taxes not
recovered in base rates.
Purchased Power
Purchased power expense for the three months ended March 31, 2003
increased $71 million as compared to the same period in 2002. The increase in
purchased power expense was primarily attributable to $22 million as a result of
favorable weather conditions, $17 million related to higher PJM ancillary
charges, $16 million from customers in Pennsylvania selecting or returning to
PECO as their electric generation supplier and $16 million attributable to
higher electric delivery volume.
Fuel
Fuel expense for the three months ended March 31, 2003 increased $56
million as compared to the same period in 2002. This increase was primarily
attributable to $40 million as a result of favorable weather conditions, $8
million attributable to higher delivery volumes and $3 million from higher gas
prices.
87
Operating and Maintenance
O&M expense for the three months ended March 31, 2003 increased $3
million, or 2%, as compared to the same period in 2002. The increase in O&M
expense was primarily attributable to $4 million of incremental storm costs in
2003, $4 million of additional employee benefits costs and $8 million of
additional miscellaneous other net positive impacts partially offset by $7
million related to lower corporate allocations and $6 million of lower costs
associated with the deployment of automated meter reading technology.
Depreciation and Amortization
Depreciation and amortization expense for the three months ended March
31, 2003 increased $8 million, or 7%, as compared to the same period in 2002 as
follows:
Three Months Ended March 31,
----------------------------
2003 2002 Variance % Change
- --------------------------------------------------------------------------------------------------------------------
Competitive Transition Charge Amortization $ 81 $ 75 $ 6 8.0%
Depreciation Expense 33 32 1 3.1%
Other Amortization Expense 6 5 1 20.0%
- ----------------------------------------------------------------------------------------------------
Total Depreciation and Amortization $ 120 $ 112 $ 8 7.1%
====================================================================================================
The additional amortization of the CTC is in accordance with PECO's
original settlement under the Pennsylvania Competition Act and the increase in
depreciation expense resulted from additional plant in service.
Taxes Other Than Income
Taxes other than income for the three months ended March 31, 2003
increased $4 million, or 7%, as compared to the same period in 2002. The
increase was primarily attributable to $7 million of additional gross receipts
tax related to additional revenues, partially offset by a $2 million decrease in
real estate taxes.
Interest Charges
Interest charges consist of interest expense and distributions on
Company-Obligated Mandatorily Redeemable Preferred Securities of a Partnership
(COMRPS). Interest charges decreased $9 million, or 10%, in the three months
ended March 31, 2003 as compared to the same period in 2002. The decrease was
primarily attributable to lower interest expense on long-term debt of $9 million
as a result of scheduled principal payments and refinancing of existing debt at
lower interest rates.
Other, Net
Other, Net increased income by $8 million in the three months ended
March 31, 2003 as compared to the same period in 2002. The increase in other
income was primarily attributable to higher interest income of $5 million and
the favorable settlement of a customer contract of $3 million.
88
Income Taxes
The effective tax rate was 32.5% for the three months ended March 31,
2003 as compared to 32.1% for the same period in 2002.
Due to revenue needs in the states in which PECO operates, various
state income tax and fee increases have been proposed or are being contemplated.
If these changes are enacted, they could increase PECO's state income tax
expense. At this time, however, PECO cannot predict whether legislation or
regulation will be introduced, the form of any legislation or regulation,
whether any such legislation or regulation will be passed by the state
legislatures or regulatory bodies, and, if enacted, whether any such legislation
or regulation would be effective retroactively or prospectively. As a result,
PECO cannot currently estimate the effect of these potential changes in tax laws
or regulation.
Preferred Stock Dividends
Preferred stock dividends for the three months ended March 31, 2003
were consistent as compared to the same period in 2002.
LIQUIDITY AND CAPITAL RESOURCES
PECO's business is capital intensive and requires considerable capital
resources. PECO's capital resources are primarily provided by internally
generated cash flows from operations and, to the extent necessary, external
financing including the issuance of commercial paper or participation in the
intercompany money pool. PECO's access to external financing at reasonable terms
is dependent on its credit ratings and general business conditions, as well as
that of the utility industry in general. If these conditions deteriorate to
where PECO no longer has access to external financing sources at reasonable
terms, PECO has access to a revolving credit facility that PECO currently
utilizes to support its commercial paper program. See the Credit Issues section
of Liquidity and Capital Resources for further discussion. Capital resources are
used primarily to fund PECO's capital requirements, including construction,
repayments of maturing debt and payment of dividends.
Cash Flows from Operating Activities
Cash flows provided by operations for the three months ended March 31,
2003 and 2002 were $126 million and $100 million, respectively. The increase in
cash flows was primarily attributable to a $99 million increase in working
capital and a $48 million increase to net income, partially offset by a $66
million decrease in deferred taxes and a $62 million change in deferred energy
costs. PECO's cash flow from operating activities primarily results from sales
of electricity and gas to a stable and diverse base of retail customers at fixed
prices. PECO's future cash flows will depend upon the ability to achieve
operating cost reductions and the impact of the economy, weather and customer
choice on its revenues. Although the amounts may vary from period to period as a
result of the uncertainties inherent in its business, PECO expects that it will
continue to provide a reliable and steady source of internal cash flow from
operations for the foreseeable future.
89
Cash Flows from Investing Activities
Cash flows used in investing activities for the three months ended
March 31, 2003 were $59 million, compared to $65 million for the three months
ended March 31, 2002. The decrease in cash flows used in investing activities
was primarily attributable to a decrease in capital expenditures.
PECO's projected capital expenditures for 2003 are $270 million.
Approximately one half of the budgeted 2003 expenditures are for capital
additions to support customer and load growth and the remainder for additions
and upgrades to existing facilities. PECO anticipates that its capital
expenditures will be funded by internally generated funds, borrowings, the
issuance of preferred securities, or capital contributions from Exelon. PECO's
proposed capital expenditures and other investments are subject to periodic
review and revision to reflect changes in economic conditions and other factors.
Cash Flows from Financing Activities
Cash flows used in financing activities for the three months ended
March 31, 2003 and 2002 were $26 million and $36 million, respectively. Cash
flows used in financing activities are primarily attributable to debt service
and payment of dividends to Exelon. The decrease in cash flows used in financing
activities is primarily attributable to additional issuances of long-term debt
in the first quarter of 2003 of $250 million, partially offset by additional
debt service of $204 million. See Notes 10 and 14 of the Condensed Combined
Notes to Consolidated Financial Statements for further discussion of PECO's debt
financing activities. For the three months ended March 31, 2003, PECO paid
Exelon $89 million in common stock dividends compared to $85 million for the
three months ended March 31, 2002.
90
Credit Issues
PECO meets its short-term liquidity requirements primarily through the
issuance of commercial paper and borrowings from Exelon's intercompany money
pool. PECO, along with Exelon, ComEd and Generation, participates in a $1.5
billion unsecured 364-day revolving credit facility with a group of banks. The
credit facility became effective November 22, 2002 and includes a term-out
option that allows any outstanding borrowings at the end of the revolving credit
period to be repaid on November 21, 2004. Exelon may increase or decrease the
sublimits of each of the participants upon written notification to the banks. As
of March 31, 2003, PECO's sublimit was $600 million. The credit facility is used
by PECO principally to support its commercial paper program. At March 31, 2003,
PECO's Consolidated Balance Sheet reflects $493 million in commercial paper
outstanding, of which $243 million is classified as notes payable and $250
million is classified as long-term debt. For the three months ended March 31,
2003, the average interest rate on notes payable was approximately 1.33%.
The credit facility requires PECO to maintain a cash from operations to
interest expense ratio for the twelve-month period ended on the last day of any
quarter. The ratio excludes revenues and interest expenses attributable to
securitization debt, certain changes in working capital and distributions on
preferred securities of subsidiaries. PECO's threshold for the ratio reflected
in the credit agreement cannot be less than 2.25 to 1 for the twelve-month
period ended March 31, 2003. At March 31, 2003, PECO was in compliance with the
credit agreement thresholds.
None of PECO's borrowings is subject to default or prepayment as a
result of a downgrading of securities ratings although such a downgrading could
increase interest charges under certain bank credit facilities.
To provide an additional short-term borrowing option that will
generally be more favorable to the borrowing participants than the cost of
external financing, Exelon operates an intercompany money pool. Participation in
the money pool is subject to authorization by Exelon's corporate treasurer.
ComEd and its subsidiary Commonwealth Edison of Indiana, Inc., PECO, Generation
and BSC may participate in the money pool as lenders and borrowers, and Exelon
as a lender. Funding of, and borrowings from, the money pool are predicated on
whether such funding results in mutual economic benefits to each of the
participants, although Exelon is not permitted to be a net borrower from the
money pool. Interest on borrowings is based on short-term market rates of
interest, or, if from an external source, specific borrowing rates. There were
no material money pool transactions by PECO in the first quarter of 2003.
Under PUHCA, PECO is precluded from lending or extending credit or
indemnity to Exelon and can pay dividends only from retained or current
earnings. At March 31, 2003, PECO had retained earnings of $447 million.
Long-term debt included $4.1 billion of transition bonds.
91
Contractual Obligations, Commercial Commitments and Off-Balance Sheet
Obligations
Contractual obligations represent cash obligations that are considered
to be firm commitments and commercial commitments represent commitments
triggered by future events. PECO's contractual obligations and commercial
commitments as of March 31, 2003 were materially unchanged, other than in the
normal course of business, from the amounts set forth in the 2002 Form 10-K
except for the following:
o PECO has entered into several agreements with a tax consultant related
to the filing of refund claims with the IRS. The fees for these
agreements are contingent upon a successful outcome and are based upon
a percentage of the refunds recovered from the IRS, if any. As such,
PECO would have positive net cash flows related to these agreements if
any fees are paid to the tax consultant. These potential tax benefits
and associated fees could be material to the financial position,
results of operations and cash flows of PECO. PECO cannot predict the
timing of the final resolution of these refund claims.
o See Notes 10 and 14 of the Condensed Combined Notes to Consolidated
Financial Statements for further discussion of material changes in
PECO's debt obligations from those set forth in the 2002 Form 10-K.
o See Note 8 of the Condensed Combined Notes to Consolidated Financial
Statements for commercial commitments tables representing PECO's
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 their
obligations.
92
EXELON GENERATION COMPANY, LLC
- ------------------------------
GENERAL
Generation operates as a single segment and its operations consist of
electric generating facilities, energy marketing operations and equity interests
in Sithe and AmerGen.
In the second quarter of 2002, Generation early adopted EITF 02-3. EITF
02-3 was issued by the FASB EITF in June 2002 and required revenues and energy
costs related to energy trading contracts to be presented on a net basis in the
income statement. For comparative purposes, energy costs related to energy
trading have been reclassified as revenue for prior periods to conform to the
net basis of presentation required by EITF 02-3.
RESULTS OF OPERATIONS
Three Months Ended March 31, 2003 Compared to Three Months Ended March 31, 2002
Significant Operating Trends - Generation
Three Months Ended March 31,
----------------------------
2003 2002 Variance % Change
- -------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 1,879 $1,461 $ 418 28.6%
OPERATING EXPENSES
Purchased Power 841 619 222 35.9%
Fuel 364 209 155 74.2%
Operating and Maintenance 487 432 55 12.7%
Depreciation and Amortization 45 63 (18) (28.6%)
Taxes Other Than Income 48 49 (1) (2.0%)
- ----------------------------------------------------------------------------------------------------------
Total Operating Expenses 1,785 1,372 413 30.1%
- ----------------------------------------------------------------------------------------------------------
OPERATING INCOME 94 89 5 5.6%
- ----------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (19) (17) (2) 11.8%
Equity in Earnings of Unconsolidated Affiliates, net 19 23 (4) (17.4%)
Other, Net (167) 16 (183) n.m.
- ----------------------------------------------------------------------------------------------------------
Total Other Income and Deductions (167) 22 (189) n.m.
- ----------------------------------------------------------------------------------------------------------
INCOME (LOSS) BEFORE INCOME TAXES AND CUMULATIVE
EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES (73) 111 (184) (165.8%)
INCOME TAXES (21) 45 (66) (146.7%)
- ----------------------------------------------------------------------------------------------------------
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGES IN
ACCOUNTING PRINCIPLES (52) 66 (118) (178.8%)
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING
PRINCIPLES, NET OF INCOME TAXES 108 13 95 n.m.
- ----------------------------------------------------------------------------------------------------------
NET INCOME $ 56 $ 79 $ (23) (29.1%)
==========================================================================================================
n.m. - not meaningful
93
Net Income
Generation's net income decreased by $23 million, or 29%, for the three
months ended March 31, 2003 compared to the same period in 2002. Income (loss)
before cumulative effect of changes in accounting principles decreased by $118
million for the three months ended March 31, 2003 compared to the same period in
2002 primarily due to the after-tax impairment charge for Generation's equity
investment in Sithe of $130 million and higher operating expenses, partially
offset by higher revenues and investment income.
Operating Revenues
Revenues increased by $418 million, or 29% for the three months ended
March 31, 2003 compared to the same period in 2002. This increase resulted
primarily from a $295 million increase in energy market sales, due to regional
weather-related demand. Market sales also increased $9 million for increased
generation, from the fossil plants acquired after the first quarter of 2002,
related to gas purchase obligations. In addition, sales to Energy Delivery
increased by $85 million due to increased demand related to favorable weather in
ComEd and PECO's service territories during the first quarter of 2003 compared
to 2002, and customers returning to PECO from alternative energy suppliers.
Revenues from Energy Delivery for the first quarter of 2003 also included $16
million from ComEd related to nuclear decommissioning cost recoveries associated
with the adoption of SFAS No. 143 that was not included in 2002. Trading
activity reduced revenue by $2 million during the first quarter of 2003 compared
to the same period of 2002.
For the three months ended March 31, 2003 and 2002, Generation's sales
and the supply of these sales were as follows:
Three Months Ended March 31,
----------------------------
Sales (in GWhs) 2003 2002 Variance % Change
- -----------------------------------------------------------------------------------------------------------------------
Energy Delivery 29,346 27,750 1,596 5.8%
Exelon Energy 1,248 1,250 (2) (0.2%)
Market Sales 23,815 19,324 4,491 23.2%
- ----------------------------------------------------------------------------------------------------------
Total Sales 54,409 48,324 6,085 12.6%
==========================================================================================================
Three Months Ended March 31,
----------------------------
Supply of Sales (in GWhs) 2003 2002 Variance % Change
- -----------------------------------------------------------------------------------------------------------------------
Nuclear Generation (1) 29,330 27,533 1,797 6.5%
Purchases - non-trading portfolio (2) 20,029 18,093 1,936 10.7%
Fossil and Hydro Generation 5,050 2,698 2,352 87.2%
- ----------------------------------------------------------------------------------------------------------
Total Supply 54,409 48,324 6,085 12.6%
==========================================================================================================
(1) Excluding AmerGen.
(2) Including purchased power agreements with AmerGen.
Trading volume of 9,527 GWhs and 14,239 GWhs for the three months ended
March 31, 2003 and 2002, respectively, is not included in the table above.
94
Generation's average margin and other operating data for the three
months ended March 31, 2003 and 2002 were as follows:
Three Months Ended March 31,
----------------------------
($/MWh) 2003 2002 % Change
- -------------------------------------------------------------------------------------------------------------------
Average Revenue
Energy Delivery $ 30.87 $ 29.98 3.0%
Exelon Energy 43.28 45.60 (5.1%)
Market Sales 37.05 28.15 31.6%
Total - excluding the trading portfolio 33.96 29.63 14.6%
Average Supply Cost (1) - excluding trading portfolio $ 21.29 $ 16.74 27.2%
Average Margin - excluding the trading portfolio $ 12.67 $ 12.89 (1.7%)
(1) Average supply cost includes purchased power and fuel costs.
Three Months Ended March 31,
----------------------------
2003 2002
- -------------------------------------------------------------------------------------------------------------------
Nuclear fleet capacity factor (1) 94.4% 90.3%
Nuclear fleet production cost per MWh (1) $ 12.80 $ 14.26
Average purchased power cost for wholesale operations per MWh $ 41.75 $ 34.26
- -------------------------------------------------------------------------------------------------------------------
(1) Including AmerGen and excluding Salem.
Generation's MWh deliveries increased 12.6% in the three months ended
March 31, 2003 compared to the same period in 2002. Increased deliveries were a
result of favorable weather conditions, which increased the demand for Energy
Delivery, and higher market sales attributable to the increased supply from
acquired generation and power uprates at existing facilities.
The factors below contributed to the overall reduction in Generation's
average margin for the three months ended March 31, 2003 as compared to the same
period in 2002.
Generation's average revenue per MWh was affected by:
o increased weighted average on and off-peak prices per MWh for supply
agreements with ComEd,
o higher prices per MWh on sales under supply agreements with PECO, and
o higher market prices.
Generation's supply mix changed due to:
o increased nuclear generation due to a lower number of refueling and
unplanned outages during 2003 compared to 2002,
o increased fossil generation due to the effect of the acquisition of
two generating plants in Texas in April 2002, a peaking facility
placed in service in July 2003 and the Exelon New England plants
acquired in November 2002, which in total account for an increase of
2,500 GWhs, and
o increased quantity of purchased power at higher prices to service
greater customer loads as compared to 2002.
The higher nuclear capacity factor and decreased nuclear production
costs are primarily due to 30 fewer planned refueling outage days, resulting in
a $32 million decrease in outage
95
costs, in the three months ended March 31, 2003 as compared to the same period
in 2002. Additionally, the three months ended March 31, 2003 included three
unplanned outages compared to five unplanned outages during the three months
ended March 31, 2002.
Purchased Power
Purchased power increased $222 million, or 36%, for the three months
ended March 31, 2003 compared to the same period in 2002 due to $185 million
related to higher market prices and increased purchases. Increased purchases
were due to higher market sales and increased demand from ComEd and PECO. The
increase in purchased power also reflects a $31 million loss on mark-to-market
hedging activity for the three months ended March 31, 2003 compared to a $6
million gain in the same period in 2002.
Fuel
Fuel expense increased $155 million, or 74%, for the three months ended
March 31, 2003 compared to the same period in 2002. This increase is primarily
due to the higher generation to meet increased demand from ComEd and PECO and
higher market sales. Fossil and other fuel expense increased $140 million, as a
result of operating the generation plants acquired after the first quarter of
2002. Increased fossil fuel expense includes $9 million related to increased
market sales, from the generating plants acquired after the first quarter of
2002, related to gas purchase obligations. Nuclear fuel expense increased $19
million, reflecting higher nuclear generation and $6 million due to additional
fuel amortization resulting from under performing fuel at the Quad Cities Unit
1, which will be completely replaced in May 2003. The second quarter of 2003
will include approximately $13 million of additional fuel amortization related
to Quad Cities Unit 1. These increases in fuel expense were partially offset by
a $4 million loss on emissions allowance sales recorded in 2002.
Operating and Maintenance
O&M expense increased $55 million, or 13%, for the three months ended
March 31, 2003 compared to the same period in 2002. The increase in O&M expense
was primarily attributable to $39 million of accretion expense which was
recorded as depreciation and amortization expense prior to the adoption of SFAS
No. 143, $18 million of accretion expense related to SFAS No. 143 to adjust the
earnings impact of the net of decommissioning revenues, investment income, the
accretion of the asset retirement obligation and depreciation of the Asset
Retirement Cost asset (ARC) to zero, $27 million of additional employee benefits
costs, and $19 million of additional expenses due to asset acquisitions made
after the first quarter of 2002. This increase was partially offset by $32
million of lower nuclear refueling outage costs and a one-time executive
severance expense recorded in 2002 of $19 million. For a further discussion of
SFAS No. 143 see Note 2 of the Condensed Combined Notes to Consolidated
Financial Statements.
Depreciation and Amortization
Depreciation and amortization expense decreased $18 million, or 29%,
for the three months ended March 31, 2003 compared to the same period in 2002.
The decrease was primarily attributable to a $33 million reduction in
decommissioning expense as these costs are included in operating and maintenance
expense after the adoption of SFAS No. 143, partially offset by $6 million of
additional depreciation expense on capital additions placed in service after the
first quarter of 2002, $9 million related to plant acquisitions made after the
first quarter of 2002, and $1 million of depreciation for the ARC asset related
to SFAS No. 143. For a further discussion of SFAS No. 143 see Note 2 of the
Condensed Combined Notes to Consolidated Financial Statements.
96
Taxes Other Than Income
Taxes other than income decreased $1 million, or 2%, for the three
months ended March 31, 2003 compared to the same period in 2002 primarily due to
a $4 million decrease in payroll taxes partially offset by a $3 million increase
in property taxes related to asset acquisitions made after the first quarter of
2002.
Interest Expense
Interest expense increased $2 million, or 12%, for the three months
ended March 31, 2003 compared to the same period in 2002. The increase was
primarily due to $3 million of additional interest expense on the $534 million
note payable issued to Sithe in November 2002.
Equity in Earnings of Unconsolidated Affiliates
Equity in earnings of unconsolidated affiliates decreased $4 million,
or 17%, for the three months ended March 31, 2003 compared to the same period in
2002. The decrease was due to a $6 million decrease in Generation's equity
earnings in Sithe, primarily due to Sithe's sale of Exelon New England to
Generation in November 2002. This decrease was partially offset by a $2 million
increase in Generation's equity earnings of AmerGen.
Other, Net
Other, Net decreased $183 million for the three months ended March 31,
2003 compared to the same period in 2002. This decrease is primarily a result of
the $200 million impairment charge related to Generation's equity investment in
Sithe due to an other than temporary decline in value. This charge was partially
offset by higher investment income related to the decommissioning trust funds.
Income Taxes
The effective income tax rate was 28.8% for the three months ended
March 31, 2003 compared to 40.5% for the same period in 2002. The decrease was
primarily attributed to the impact of the impairment of Generation's investment
in Sithe and other tax benefits recorded in 2003.
Due to revenue needs in the states in which Generation operates,
various state income tax and fee increases have been proposed or are being
contemplated. If these changes are enacted, they could increase Generation's
state income tax expense. At this time, however, Generation cannot predict
whether legislation or regulation will be introduced, the form of any
legislation or regulation, whether any such legislation or regulation will be
passed by the state legislatures or regulatory bodies, and, if enacted, whether
any such legislation or regulation would be effective retroactively or
prospectively. As a result, Generation cannot currently estimate the effect of
potential changes in tax law or regulation.
Cumulative Effect of Changes in Accounting Principles
On January 1, 2003, Generation adopted SFAS No. 143 resulting in a
benefit of $108 million, net of income taxes of $70 million.
On January 1, 2002, Generation adopted SFAS No. 141 resulting in a
benefit of $13 million, net of income taxes of $9 million.
97
LIQUIDITY AND CAPITAL RESOURCES
Generation's business is capital intensive and requires considerable
capital resources. Generation's capital resources are primarily provided by
internally generated cash flows from operations and, to the extent necessary,
external financings including the issuance of commercial paper and borrowings or
capital contributions from Exelon. Generation's access to external financing at
reasonable terms is dependent on its credit ratings and general business
conditions, as well as that of the utility industry in general. If these
conditions deteriorate to where Generation no longer has access to external
financing sources at reasonable terms, Generation has access to a revolving
credit facility. See the Credit Issues section of Liquidity and Capital
Resources for further discussion. Capital resources are used primarily to fund
Generation's capital requirements, including construction, investments in new
and existing ventures, repayments of maturing debt and the payment of dividends.
Any future acquisitions could require external financing or borrowings or
capital contributions from Exelon.
Cash Flows from Operating Activities
Cash flows provided by operations were $278 million for the three
months ended March 31, 2003, compared to $509 million for the same period in
2002. The decrease in cash flows from operating activities was primarily
attributable to a $184 million decrease in working capital. Generation's cash
flows from operating activities primarily result from the sale of electric
energy to wholesale customers, including Generation's affiliated companies, as
well as settlements arising from Generation's trading activities. Generation's
future cash flow from operating activities will depend upon future demand and
market prices for energy and the ability to continue to produce and supply power
at competitive costs.
Cash Flows from Investing Activities
Cash flows used in investing activities were $216 million for the three
months ended March 31, 2003, compared to $379 million for the same period in
2002. The decrease in cash flows used in investing activities was primarily
attributable to a decrease in capital expenditures. Capital expenditures
decreased $70 million related to liquidated damages from Raytheon (see Note 8 of
the Condensed Combined Notes to Consolidated Financial Statements). The
liquidated damages were partially offset by a $58 million increase in
expenditures related to the plants acquired after the first quarter of 2002.
Nuclear fuel expenditures decreased due to two refueling outages that occurred
during the three months ended March 31, 2003 compared to four outages in the
same period in the prior year. Generation's proposed capital expenditures and
other investments are subject to periodic review and revision to reflect changes
in economic conditions and other factors.
Generation's capital expenditures for 2003 reflect the construction of
three Exelon New England generating facilities with projected capacity of 2,421
MWs of energy and additions to
98
and upgrades of existing facilities (including nuclear refueling outages) and
nuclear fuel. In February 2002, Generation entered into an agreement to loan
AmerGen up to $75 million at an interest rate of one-month LIBOR plus 2.25%. In
July 2002, the loan agreement and the loan were increased to $100 million and
the maturity date was extended to July 1, 2003. As of March 31, 2003, the
balance of the loan to AmerGen was $35 million. Exelon anticipates that
Generation's capital expenditures will be funded by internally generated funds,
borrowings or capital contributions from Exelon.
Cash Flows from Financing Activities
Cash flows used in financing activities were $63 million for the three
months ended March 31, 2003, compared to cash flows provided by financing
activities of $1 million for the same period in 2002. The increase in cash used
in financing was primarily due to a $56 million increase in restricted cash as a
result of liquidating damage proceeds received from Raytheon in 2003 (see Note 8
of the Condensed Combined Notes to Consolidated Financial Statements).
Credit Issues
Generation meets its short-term liquidity requirements primarily
through intercompany borrowings from Exelon, the issuance of commercial paper
and participation in the intercompany money pool. Generation, along with Exelon,
ComEd and PECO, participates in a $1.5 billion unsecured 364-day revolving
credit facility with a group of banks. The credit facility became effective on
November 22, 2002 and includes a term-out option that allows any outstanding
borrowings at the end of the revolving credit period to be repaid on November
21, 2004. Exelon may increase or decrease the sublimits of each of the
participants upon written notification to these banks. As of March 31, 2003,
there was no sublimit for Generation. The credit facility is expected to be used
by Generation principally to support its commercial paper program.
The credit facility requires Generation to maintain a cash from
operations to interest expense ratio for the twelve-month period ended on the
last day of any quarter. The ratio excludes certain changes in working capital,
revenues from Exelon New England and interest on the debt of Exelon New
England's project subsidiaries. Generation's threshold for the ratio reflected
in the credit agreement cannot be less than 3.25 to 1 for the twelve-month
period ended March 31, 2003. At March 31, 2003, Generation was in compliance
with the credit agreement thresholds.
To provide an additional short-term borrowing option that will
generally be more favorable to the borrowing participants than the cost of
external financing, Exelon operates an intercompany money pool. Participation in
the money pool is subject to authorization by the Exelon corporate treasurer.
ComEd and its subsidiary Commonwealth Edison of Indiana, Inc., PECO, Generation
and Business Services Company may participate in the money pool as lenders and
borrowers, and Exelon as a lender. Funding of, and borrowings from, the money
pool are predicated on whether such funding results in mutual economic benefits
to each of the participants, although Exelon is not permitted to be a net
borrower from the money pool. Interest on borrowings is based on short-term
market rates of interest, or specific borrowing rates if the funds are provided
by external financing. During the first quarter 2003, Generation had various
99
borrowings from ComEd under the money pool. The maximum amount of loans
outstanding at any time during the quarter was $335 million. As of March 31,
2003, there were no outstanding loan balances.
Generation's access to the capital markets and its financing costs in
those markets are dependent on its securities ratings. None of Generation's
borrowings is subject to default or prepayment as a result of a downgrading of
securities ratings although such a downgrading could increase interest charges
under certain bank credit facilities. From time to time Generation enters into
energy commodity and other derivative transactions that require the maintenance
of investment grade ratings. Failure to maintain investment grade ratings would
allow the counterparty to terminate the derivative and settle the transaction on
a net present value basis.
Under PUHCA, Generation can only pay dividends from undistributed or
current earnings. Generation is precluded from lending or extending credit or
indemnity to Exelon. At March 31, 2003, Generation had undistributed earnings of
$980 million.
Contractual Obligations, Commercial Commitments and Off-Balance Sheet
Obligations
Contractual obligations represent cash obligations that are considered
to be firm commitments and commercial commitments represent commitments
triggered by future events. Generation's contractual obligations and commercial
commitments as of March 31, 2003 were materially unchanged from the amounts set
forth in the 2002 Form 10-K except for the following:
o See Note 8 of the Condensed Combined Notes to Consolidated Financial
Statements for commercial commitments tables representing Generation's
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 their obligations.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
Commodity Price Risk
Generation
Commodity price risk is associated with market price movements
resulting from excess or insufficient generation, changes in fuel costs, market
liquidity and other factors. Trading activities and non-trading marketing
activities include the purchase and sale of electric capacity and energy and
fossil fuels, including oil, gas, coal and emission allowances. The availability
and prices of energy and energy-related commodities are subject to fluctuations
due to factors such as weather, governmental environmental policies, changes in
supply and demand, state and Federal regulatory policies and other events.
100
Normal Operations and Hedging Activities
Electricity available from Generation's owned or contracted generation
supply in excess of its obligations to customers, including Energy Delivery's
retail load, is sold into the wholesale markets. To reduce price risk caused by
market fluctuations, Generation enters into physical contracts as well as
derivative contracts, including forwards, futures, swaps, and options, with
approved counterparties to hedge its anticipated exposures. The maximum length
of time over which cash flows related to energy commodities are currently being
hedged is four years. Generation has an estimated 88% hedge ratio in 2003 for
its energy marketing portfolio. This hedge ratio represents the percentage of
Generation's forecasted aggregate annual generation supply that is committed to
firm sales, including sales to ComEd and PECO's retail load. ComEd and PECO's
retail load assumptions are based on forecasted average demand. The hedge ratio
is not fixed and will vary from time to time depending upon market conditions,
demand, and energy market option volatility and actual loads. During peak
periods, the amount hedged declines to meet the commitment to ComEd and PECO.
Market price risk exposure is the risk of a change in the value of unhedged
positions. Absent any opportunistic efforts to mitigate market price exposure,
the estimated market price exposure for Generation's non-trading portfolio
associated with a ten percent reduction in the annual average around-the-clock
market price of electricity is an approximately $39 million decrease in net
income, or approximately $0.12 per share. This sensitivity assumes an 88% hedge
ratio and that price changes occur evenly throughout the year and across all
markets. The sensitivity also assumes a static portfolio. Generation expects to
actively manage its portfolio to mitigate market price exposure. Actual results
could differ depending on the specific timing of, and markets affected by, price
changes, as well as future changes in Generation's portfolio.
Proprietary Trading Activities
Generation uses financial contracts for proprietary trading purposes.
Proprietary trading includes all contracts entered into purely to profit from
market price changes as opposed to hedging an exposure. These activities are
accounted for on a mark-to-market basis. The proprietary trading activities are
a complement to Generation's energy marketing portfolio and represent a very
small portion of its overall energy marketing activities. For example, the limit
on open positions in electricity for any forward month represents less than 1%
of Generation's owned and contracted supply of electricity. The trading
portfolio is subject to stringent risk management limits and policies, including
volume, stop-loss and value-at-risk limits.
Generation's energy contracts are accounted for under SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133).
Most non-trading contracts qualify for the normal purchases and normal sales
exemption to SFAS No. 133 discussed in the Critical Accounting Estimates section
of Management's Discussion and Analysis of Financial Condition and Result of
Operations of the 2002 Form 10-K. Those that do not are recorded as assets or
liabilities on the balance sheet at fair value. Changes in the fair value of
qualifying hedge contracts are recorded in Other Comprehensive Income (OCI), and
gains and losses are recognized in earnings when the underlying transaction
occurs. Changes in the fair value of derivative contracts that do not meet hedge
criteria under SFAS No. 133 and the ineffective portion of hedge contracts are
recognized in earnings on a current basis.
101
The following detailed presentation of the trading and non-trading
marketing activities at Generation is included to address the recommended
disclosures by the energy industry's Committee of Chief Risk Officers.
Generation does not consider its proprietary trading to be a significant
activity in its business; however, Generation believes it is important to
include these risk management disclosures.
The following table describes the drivers of Generation's energy
trading and marketing business and gross margin included in the income statement
for the three months ended March 31, 2003. Normal operations and hedging
activities represent the marketing of electricity available from Generation's
owned or contracted generation, including ComEd and PECO's retail load, sold
into the wholesale market. As the information in this table highlights,
mark-to-market activities represent a small portion of the overall gross margin
for Generation. Accrual activities, including normal purchases and sales,
account for the majority of the gross margin. The mark-to-market activities
reported here are those relating to changes in fair value due to external
movement in prices. Further delineation of gross margin by the type of
accounting treatment typically afforded each type of activity is also presented
(i.e., mark-to-market vs. accrual accounting treatment).
Normal Operations and Proprietary
Hedging Activities (a) Trading Total
- ------------------------------------------------------------------------------------------------------------
Mark-to-Market Activities:
- --------------------------
Unrealized Mark-to-Market Gain/(Loss)
Origination Unrealized Gain/(Loss) at Inception $ -- $ -- $ --
Changes in Fair Value Prior to Settlements 26 (2) 24
Changes in Valuation Techniques and Assumptions -- -- --
Reclassification to Realized at Settlement of Contracts (57) -- (57)
- ------------------------------------------------------------------------------------------------------------
Total Change in Unrealized Fair Value (31) (2) (33)
Realized Net Settlement of Transactions Subject to Mark-to-Market 57 -- 57
- ------------------------------------------------------------------------------------------------------------
Total Mark-to-Market Activities Gross Margin $ 26 $ (2) $ 24
- ------------------------------------------------------------------------------------------------------------
Accrual Activities:
- -------------------
Accrual Activities Revenue $ 1,352 $ -- $ 1,352
Hedge Gains/(Losses) Reclassified from OCI 398 -- 398
- ------------------------------------------------------------------------------------------------------------
Total Revenue - Accrual Activities 1,750 -- 1,750
- ------------------------------------------------------------------------------------------------------------
Purchased Power and Fuel 597 -- 597
Hedges of Purchased Power and Fuel Reclassified from OCI 503 -- 503
- ------------------------------------------------------------------------------------------------------------
Total Purchased Power and Fuel 1,100 -- 1,100
- ------------------------------------------------------------------------------------------------------------
Total Accrual Activities Gross Margin 650 -- 650
- ------------------------------------------------------------------------------------------------------------
Total Gross Margin $ 676 $ (2) $ 674 (b)
============================================================================================================
(a) Normal Operations and Hedging Activities only include derivative contracts
Power Team enters into to hedge anticipated exposures related to its owned
and contracted generation supply, but excludes its owned and contracted
generating assets.
(b) Total Gross Margin represents revenue, net of purchased power and fuel
expense for Generation.
The following table provides detail on changes in Generation's
mark-to-market net asset or liability balance sheet position from January 1,
2003 to March 31, 2003. It indicates the drivers behind changes in the balance
sheet amounts. This table will incorporate the mark-to-market activities that
are immediately recorded in earnings, as shown in the previous table, as well as
the settlements from OCI to earnings and changes in fair value for the hedging
activities
102
that are recorded in Accumulated Other Comprehensive Income on the
March 31, 2003 Consolidated Balance Sheet.
Normal Operations and Proprietary
Hedging Activities Trading Total
- -------------------------------------------------------------------------------------------------------------------
Total Mark-to-Market Energy Contract Net Assets at January 1, 2003 $ (168) $ 5 $ (163)
Total Change in Fair Value for the Three Months Ended March 31, 2003
of Contracts Recorded in Earnings 26 (2) 24
Reclassification to Realized at Settlement of Contracts Recorded in Earnings (57) -- (57)
Reclassification to Realized at Settlement from OCI 105 -- 105
Effective Portion of Changes in Fair Value - Recorded in OCI (390) -- (390)
Purchase/Sale of Existing Contracts or Portfolios Subject to Mark-to-Market -- -- --
- -------------------------------------------------------------------------------------------------------------------
Total Mark-to-Market Energy Contract Net Assets (Liabilities)
at March 31, 2003 $ (484) $ 3 $ (481)
===================================================================================================================
The following table details the balance sheet classification of the
mark-to-market energy contract net assets recorded as of March 31, 2003:
Normal Operations and Proprietary
Hedging Activities Trading Total
- -------------------------------------------------------------------------------------------------------------------
Current Assets $ 219 $ 4 $ 223
Noncurrent Assets 54 -- 54
- -------------------------------------------------------------------------------------------------------------------
Total Mark-to-Market Energy Contract Assets 273 4 277
- -------------------------------------------------------------------------------------------------------------------
Current Liabilities (572) -- (572)
Noncurrent Liabilities (185) (1) (186)
- -------------------------------------------------------------------------------------------------------------------
Total Mark-to-Market Energy Contract Liabilities (757) (1) (758)
- -------------------------------------------------------------------------------------------------------------------
Total Mark-to-Market Energy Contract Net Assets (Liabilities) $ (484) $ 3 $ (481)
===================================================================================================================
The majority of Generation's contracts are non-exchange traded
contracts valued using prices provided by external sources, primarily price
quotations available through brokers or over-the-counter, on-line exchanges.
Prices reflect the average of the bid-ask midpoint prices obtained from all
sources that Generation believes provide the most liquid market for the
commodity. The terms for which such price information is available varies by
commodity, by region and by product. The remainder of the assets represents
contracts for which external valuations are not available, primarily option
contracts. These contracts are valued using the Black model, an industry
standard option valuation model. The fair values in each category reflect the
level of forward prices and volatility factors as of March 31, 2003 and may
change as a result of changes in these factors. Management uses its best
estimates to determine the fair value of commodity and derivative contracts it
holds and sells. These estimates consider various factors including closing
exchange and over-the-counter price quotations, time value, volatility factors
and credit exposure. It is possible, however, that future market prices could
vary from those used in recording assets and liabilities from energy marketing
and trading activities and such variations could be material.
The following table, which presents maturity and source of fair value
of mark-to-market energy contract net assets, provides two fundamental pieces of
information. First, the table provides the source of fair value used in
determining the carrying amount of Generation's total
103
mark-to-market asset or liability. Second, this table provides the maturity, by
year, of Generation's net assets/liabilities, giving an indication of when these
mark-to-market amounts will settle and generate or require cash.
Maturities within
---------------------------------------------- Total
2008 and Fair
2003 2004 2005 2006 2007 Beyond Value
- -------------------------------------------------------------------------------------------------------------------
Normal Operations, qualifying cash flow hedge contracts (1):
Prices provided by other external sources $(315) $ (134) $ (15) $ (7) $ -- $ -- $ (471)
- -------------------------------------------------------------------------------------------------------------------
Total $(315) $ (134) $ (15) $ (7) $ -- $ -- $ (471)
===================================================================================================================
Normal Operations, other derivative contracts (2):
Actively quoted prices $ 19 $ -- $ -- $ -- $ -- $ -- $ 19
Prices provided by other external sources (14) 12 2 5 -- -- 5
Prices based on model or other valuation methods 8 (28) (5) (9) (3) -- (37)
- -------------------------------------------------------------------------------------------------------------------
Total $ 13 $ (16) $ (3) $ (4) $ (3) $ -- $ (13)
===================================================================================================================
Proprietary Trading, other derivative contracts (3):
Actively quoted prices $ 5 $ 1 $ -- $ -- $ -- $ -- $ 6
Prices provided by other external sources (5) (4) -- -- -- -- (9)
Prices based on model or other valuation methods 5 1 -- -- -- -- 6
- -------------------------------------------------------------------------------------------------------------------
Total $ 5 $ (2) $ -- $ -- $ -- $ -- $ 3
- -------------------------------------------------------------------------------------------------------------------
Average tenor of proprietary trading portfolio (4) 1.5 years
===================================================================================================================
(1) Mark-to-market gains and losses on contracts that qualify as cash flow
hedges are recorded in other comprehensive income.
(2) Mark-to-market gains and losses on other non-trading derivative
contracts that do not qualify as cash flow hedges are recorded in
earnings.
(3) Mark-to-market gains and losses on trading contracts are recorded in
earnings.
(4) Following the recommendations of the Committee of Chief Risk Officers,
the average tenor of the proprietary trading portfolio measures the
average time to collect value for that portfolio. Generation measures
the tenor by separating positive and negative mark-to-market values in
its proprietary trading portfolio, estimating the mid-point in years
for each and then reporting the highest of the two mid-points
calculated. In the event that this methodology resulted in
significantly different absolute values of the positive and negative
cash flow streams, Generation would use the mid-point of the portfolio
with the largest cash flow stream as the tenor.
The table below provides details of effective cash flow hedges under
SFAS No. 133 included in the balance sheet as of March 31, 2003. The data in the
table gives an indication of the magnitude of SFAS No. 133 hedges Generation has
in place, however, given that under SFAS No. 133 not all hedges are recorded in
OCI, the table does not provide an all-encompassing picture of Generation's
hedges. The table also includes a roll-forward of Accumulated Other
Comprehensive Income on the Consolidated Balance Sheets related to cash flow
hedges for the three months ended March 31, 2003, providing insight into the
drivers of the changes (new hedges entered into during the period and changes in
the value of existing hedges). Information related to energy merchant activities
is presented separately from interest rate hedging activities.
104
Total Cash Flow Hedge Other Comprehensive Income Activity,
Net of Income Tax
--------------------------------------------------------------
Power Team
Normal Operations and Interest Rate and Total Cash
Hedging Activities Other Hedges (1) Flow Hedges
- -------------------------------------------------------------------------------------------------------------------
Accumulated OCI, January 1, 2003 $ (114) $ (8) $ (122)
Changes in Fair Value (237) (7) (244)
Reclassifications from OCI to Net Income 64 -- 64
- -------------------------------------------------------------------------------------------------------------------
Accumulated OCI Derivative Gain/(Loss)
at March 31, 2003 $ (287) $ (15) $ (302)
===================================================================================================================
(1) Includes interest rate hedges at Generation.
Generation uses a Value-at-Risk (VaR) model to assess the market risk
associated with financial derivative instruments entered into for proprietary
trading purposes. The measured VaR represents an estimate of the potential
change in value of Generation's proprietary trading portfolio.
The VaR estimate includes a number of assumptions about current market
prices, estimates of volatility and correlations between market factors. These
estimates, however, are not necessarily indicative of actual results, which may
differ because actual market rate fluctuations may differ from forecasted
fluctuations and because the portfolio may change over the holding period.
Generation estimates VaR using a model based on the Monte Carlo
simulation of commodity prices that captures the change in value of forward
purchases and sales as well as option values. Parameters and values are back
tested daily against daily changes in mark-to-market value for proprietary
trading activity. VaR assumes that normal market conditions prevail and that
there are no changes in positions. Generation uses a 95% confidence interval,
one-day holding period, one-tailed statistical measure in calculating its VaR.
This means that Generation may state that there is a one in 20 chance that if
prices move against its portfolio positions, its pre-tax loss in liquidating its
portfolio in a one-day holding period would exceed the calculated VaR. To
account for unusual events and loss of liquidity, Generation uses stress tests
and scenario analysis.
For financial reporting purposes only, Generation calculates several
other VaR estimates. The higher the confidence interval, the less likely the
chance that the VaR estimate would be exceeded. A longer holding period
considers the effect of liquidity in being able to actually liquidate the
portfolio. A two-tailed test considers potential upside in the portfolio in
addition to the potential downside in the portfolio considered in the one-tailed
test. The following table provides the VaR for all proprietary trading positions
of Generation as of March 31, 2003.
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Proprietary
Trading VaR
- ----------------------------------------------------------------------------
95% Confidence Level, One-Day Holding Period, One-Tailed
Period End $ 0.1
Average for the Period 0.1
High 0.3
Low 0.1
95% Confidence Level, Ten-Day Holding Period, Two-Tailed
Period End $ 0.5
Average for the Period 0.5
High 1.2
Low 0.3
99% Confidence Level, One-Day Holding Period, Two-Tailed
Period End $ 0.5
Average for the Period 0.6
High 1.4
Low 0.4
- ----------------------------------------------------------------------------
Credit Risk
Generation
Generation has credit risk associated with counterparty performance on
energy contracts which includes, but is not limited to, the risk of financial
default or slow payment. Generation manages counterparty credit risk through
established policies, including counterparty credit limits, and in some cases,
requiring deposits and letters of credit to be posted by certain counterparties.
Generation's counterparty credit limits are based on a scoring model that
considers a variety of factors, including leverage, liquidity, profitability,
credit ratings and risk management capabilities. Generation has entered into
payment netting agreements or enabling agreements that allow for payment netting
with the majority of its large counterparties, which reduce Generation's
exposure to counterparty risk by providing for the offset of amounts payable to
the counterparty against amounts receivable from the counterparty. The credit
department monitors current and forward credit exposure to counterparties and
their affiliates, both on an individual and an aggregate basis.
The following table provides information on Generation's credit
exposure, net of collateral, as of March 31, 2003. It further delineates that
exposure by the credit rating of the counterparties and provides guidance on the
concentration of credit risk to individual counterparties and an indication of
the maturity of a company's credit risk by credit rating of the counterparties.
The table below does not include sales to Generation's affiliates or exposure
through Independent System Operators.
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Total Number Of Net Exposure Of
Exposure Counterparties Counterparties
Before Credit Credit Net Greater than 10% Greater than 10%
Rating Collateral Collateral Exposure of Net Exposure of Net Exposure
- -------------------------------------------------------------------------------------------------------------------------
Investment Grade $ 99 $ -- $ 99 3 $ 55
Split Rating -- -- -- -- --
Non-Investment Grade 19 16 3 -- --
No External Ratings
Internally Rated - Investment Grade 9 -- 9 -- --
Internally Rated - Non-Investment Grade 4 -- 4 -- --
- -------------------------------------------------------------------------------------------------------------------------
Total $ 131 $ 16 $ 115 3 $ 55
=========================================================================================================================
Maturity of Credit Risk Exposure
- -------------------------------------------------------------------------------------------------------------------------
Exposure Total Exposure
Less than Greater than Before Credit
Rating 2 Years 2-5 Years 5 Years Collateral
- -------------------------------------------------------------------------------------------------------------------------
Investment Grade $ 88 $ 11 $ -- $ 99
Split Rating -- -- -- --
Non-Investment Grade 18 1 -- 19
No External Ratings
Internally Rated - Investment Grade 9 -- -- 9
Internally Rated - Non-Investment Grade 3 1 -- 4
- -------------------------------------------------------------------------------------------------------------------------
Total $ 118 $ 13 $ -- $ 131
=========================================================================================================================
Generation is a counterparty to Dynegy in various energy transactions.
In early July 2002, the credit ratings of Dynegy were downgraded to below
investment grade by two credit rating agencies. As of March 31, 2003, Generation
had a net receivable from Dynegy of approximately $4 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 March 31, 2003, 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. Generation estimates, as a 49.9%
owner of Sithe, that the impairment would result in an after-tax reduction of
Generation's equity earnings of approximately $13 million.
In addition to the impairment of the financial swap asset, if Dynegy
were unable to fulfill its obligations under the financial swap agreement and
the tolling agreement, Generation may incur a further impairment associated with
Independence.
Additionally, the future economic value of AmerGen's purchased power
arrangement with Illinois Power Company, a subsidiary of Dynegy, could be
impacted by events related to Dynegy's financial condition.
107
Interest Rate Risk
ComEd
ComEd uses a combination of fixed rate and variable rate debt to reduce
interest rate exposure. Interest rate swaps may be used to adjust exposure when
deemed appropriate based upon market conditions. ComEd also utilizes
forward-starting interest rate swaps and treasury rate locks to lock in interest
rate levels in anticipation of future financing. These strategies are employed
to maintain the lowest cost of capital. At March 31, 2003, ComEd had settled all
of its forward-starting interest rate swaps.
ComEd has entered into fixed-to-floating interest rate swaps in order
to maintain its targeted percentage of variable rate debt, associated with debt
issuances in the aggregate amount of $485 million fixed-rate obligation. At
March 31, 2003, these interest rate swaps, designated as fair value hedges, had
an aggregate fair market value of $42 million based on the present value
difference between the contract and market rates at March 31, 2003.
The aggregate fair value of the interest rate swaps, designated as fair
value hedges, that would have resulted from a hypothetical 50 basis point
decrease in the spot yield at March 31, 2003 is estimated to be $49 million. If
these derivative instruments had been terminated at March 31, 2003, this
estimated fair value represents the amount that would be paid by the
counterparties to ComEd.
The aggregate fair value of the interest rate swaps, designated as fair
value hedges, that would have resulted from a hypothetical 50 basis point
increase in the spot yield at March 31, 2003 is estimated to be $34 million. If
these derivative instruments had been terminated at March 31, 2003, this
estimated fair value represents the amount to be paid by the counterparties to
ComEd.
PECO
In February 2003, PECO entered into forward-starting interest rate
swaps in the aggregate amount of $360 million to lock in interest rate levels in
anticipation of future financings. At March 31, 2003, these interest rate swaps,
designated as cash flow hedges, had a fair market value exposure of $2 million.
The debt issuances that these swaps are hedging are considered probable
therefore, PECO has accounted for these interest rate swap transactions as
hedges. In connection with PECO's April 28, 2003 issuance of $450 million in
First and Refunding Mortgage Bonds, PECO settled the swaps for a payment of $1
million, which will be recorded in other comprehensive income and amortized over
the life of the debt issuance.
PECO has entered into interest rate swaps to manage interest rate
exposure associated with the floating rate series of transition bonds issued to
securitize PECO's stranded cost recovery. At March 31, 2003, these interest rate
swaps had an aggregate fair market value exposure of $16 million based on the
present value difference between the contract and market rates at March 31,
2003.
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-
108
to-market if there is a difference in their values. Since these swaps offset
each other, a mark-to-market adjustment is not expected to occur.
The aggregate fair value exposure of the interest rate swaps that would
have resulted from a hypothetical 50 basis point decrease in the spot yield at
March 31, 2003 is estimated to be $17 million. If these derivative instruments
had been terminated at March 31, 2003, this estimated fair value represents the
amount that would be paid by PECO to the counterparties.
The aggregate fair value exposure of the interest rate swaps that would
have resulted from a hypothetical 50 basis point increase in the spot yield at
March 31, 2003 is estimated to be $14 million. If these derivative instruments
had been terminated at March 31, 2003, this estimated fair value represents the
amount to be paid by PECO to the counterparties.
Generation
Generation uses a combination of fixed rate and variable rate debt to
reduce interest rate exposure. Generation also uses interest rate swaps when
deemed appropriate to adjust exposure based upon market conditions. These
strategies are employed to achieve a lower cost of capital. As of March 31,
2003, a hypothetical 10% increase in the interest rates associated with variable
rate debt would not have a material impact on pre-tax earnings for the first
quarter of 2003.
Under the terms of the Sithe Boston Generation, LLC (currently known as
Exelon Boston Generating, LLC (EBG)) credit facility, EBG is required to
effectively fix the interest rate on 50% of borrowings under the facility
through its maturity in 2007. As of March 31, 2003, Generation has entered into
interest rate swap agreements, which have effectively fixed the interest rate on
$861 million of notional principal, or 83% of borrowings outstanding under the
EBG credit facility at March 31, 2003. The fair market value exposure of these
swaps, designated as cash flow hedges, is $92 million.
The aggregate fair value exposure of the interest rate swaps designated
as cash flow hedges that would have resulted from a hypothetical 50 basis point
decrease in the spot yield at March 31, 2003 is estimated to be $108 million. If
the derivative instruments had been terminated at March 31, 2003, this estimated
fair value represents the amount Generation would pay to the counterparties.
The aggregate fair value exposure of the interest rate swaps designated
as cash flow hedges that would have resulted from a hypothetical 50 basis point
increase in the spot yield at March 31, 2003 is estimated to be $77 million. If
the derivative instruments had been terminated at March 31, 2003, this estimated
fair value represents the amount Generation would pay to the counterparties.
109
Equity Price Risk
Generation
Generation maintains trust funds, as required by the NRC, to fund
certain costs of decommissioning its nuclear plants. As of March 31, 2003,
decommissioning trust funds are reflected at fair value on Exelon and
Generation's Consolidated Balance Sheets. The mix of securities in the trust
funds is designed to provide returns to be used to fund decommissioning and to
compensate for inflationary increases in decommissioning costs. However, the
equity securities in the trust funds are exposed to price fluctuations in equity
markets, and the value of fixed rate, fixed income securities are exposed to
changes in interest rates. Generation actively monitors the investment
performance of the trust funds and periodically reviews asset allocation in
accordance with Generation's nuclear decommissioning trust fund investment
policy. A hypothetical 10% increase in interest rates and decrease in equity
prices would result in a $175 million reduction in the fair value of the trust
assets.
ITEM 4. CONTROLS AND PROCEDURES
Exelon
Within the 90 days prior to the date of this Report, Exelon's
management, including the principal executive officer and principal financial
officer, evaluated Exelon's disclosure controls and procedures related to the
recording, processing, summarization and reporting of information in Exelon's
periodic reports that it files with the SEC. These disclosure controls and
procedures have been designed to ensure that (a) material information relating
to Exelon, including its consolidated subsidiaries, is made known to Exelon's
management, including these officers, by other employees of Exelon and its
subsidiaries, and (b) this information is recorded, processed, summarized,
evaluated and reported, as applicable, within the time periods specified in the
SEC's rules and forms. Due to the inherent limitations of control systems, not
all misstatements may be detected. These inherent limitations include the
realities that judgments in decision-making can be faulty and that breakdowns
can occur because of simple error or mistake. Additionally, controls could be
circumvented by the individual acts of some persons or by collusion of two or
more people. Exelon's controls and procedures can only provide reasonable, not
absolute, assurance that the above objectives have been met. Also, Exelon does
not control or manage certain of its unconsolidated entities and as such, the
disclosure controls and procedures with respect to such entities are more
limited than those it maintains with respect to its consolidated subsidiaries.
As of the date of their evaluation, these officers concluded that,
subject to limitations noted above, the design of the disclosure controls and
procedures provide reasonable assurance that they can accomplish their
objectives. Exelon continually strives to improve its disclosure controls and
procedures to enhance the quality of its financial reporting and to maintain
dynamic systems that change as conditions warrant.
There have been no significant changes in Exelon's internal controls or
in other factors that could significantly affect these controls subsequent to
the date of their evaluation.
110
ComEd
Within the 90 days prior to the date of this Report, ComEd's
management, including the principal executive officer and principal financial
officer, evaluated ComEd's disclosure controls and procedures related to the
recording, processing, summarization and reporting of information in ComEd's
periodic reports that it files with the SEC. These disclosure controls and
procedures have been designed to ensure that (a) material information relating
to ComEd, including its consolidated subsidiaries, is made known to ComEd's
management, including these officers, by other employees of ComEd and its
subsidiaries, and (b) this information is recorded, processed, summarized,
evaluated and reported, as applicable, within the time periods specified in the
SEC's rules and forms. Due to the inherent limitations of control systems, not
all misstatements may be detected. These inherent limitations include the
realities that judgments in decision-making can be faulty and that breakdowns
can occur because of simple error or mistake. Additionally, controls could be
circumvented by the individual acts of some persons or by collusion of two or
more people. ComEd's controls and procedures can only provide reasonable, not
absolute, assurance that the above objectives have been met. Also, ComEd does
not control or manage certain of its unconsolidated entities and as such, the
disclosure controls and procedures with respect to such entities are more
limited than those it maintains with respect to its consolidated subsidiaries.
As of the date of their evaluation, these officers concluded that,
subject to limitations noted above, the design of the disclosure controls and
procedures provide reasonable assurance that they can accomplish their
objectives. ComEd continually strives to improve its disclosure controls and
procedures to enhance the quality of its financial reporting and to maintain
dynamic systems that change as conditions warrant.
There have been no significant changes in ComEd's internal controls or
in other factors that could significantly affect these controls subsequent to
the date of their evaluation.
PECO
Within the 90 days prior to the date of this Report, PECO's management,
including the principal executive officer and principal financial officer,
evaluated PECO's disclosure controls and procedures related to the recording,
processing, summarization and reporting of information in PECO's periodic
reports that it files with the SEC. These disclosure controls and procedures
have been designed to ensure that (a) material information relating to PECO,
including its consolidated subsidiaries, is made known to PECO's management,
including these officers, by other employees of PECO and its subsidiaries, and
(b) this information is recorded, processed, summarized, evaluated and reported,
as applicable, within the time periods specified in the SEC's rules and forms.
Due to the inherent limitations of control systems, not all misstatements may be
detected. These inherent limitations include the realities that judgments in
decision-making can be faulty and that breakdowns can occur because of simple
error or mistake. Additionally, controls could be circumvented by the individual
acts of some persons or by collusion of two or more people. PECO's controls and
procedures can only provide reasonable, not absolute, assurance that the above
objectives have been met. Also, PECO does not control or manage certain of its
unconsolidated entities and as such, the disclosure controls and procedures with
respect to such entities are more limited than those it maintains with respect
to its consolidated subsidiaries.
As of the date of their evaluation, these officers concluded that,
subject to limitations noted above, the design of the disclosure controls and
procedures provide reasonable assurance
111
that they can accomplish their objectives. PECO continually strives to improve
its disclosure controls and procedures to enhance the quality of its financial
reporting and to maintain dynamic systems that change as conditions warrant.
There have been no significant changes in PECO's internal controls or in other
factors that could significantly affect these controls subsequent to the date of
their evaluation.
Generation
Within the 90 days prior to the date of this Report, Generation's
management, including the principal executive officer and principal financial
officer, evaluated Generation's disclosure controls and procedures related to
the recording, processing, summarization and reporting of information in
Generation's periodic reports that it files with the SEC. These disclosure
controls and procedures have been designed to ensure that (a) material
information relating to Generation, including its consolidated subsidiaries, is
made known to Generation's management, including these officers, by other
employees of Generation and its subsidiaries, and (b) this information is
recorded, processed, summarized, evaluated and reported, as applicable, within
the time periods specified in the SEC's rules and forms. Due to the inherent
limitations of control systems, not all misstatements may be detected. These
inherent limitations include the realities that judgments in decision-making can
be faulty and that breakdowns can occur because of simple error or mistake.
Additionally, controls could be circumvented by the individual acts of some
persons or by collusion of two or more people. Generation's controls and
procedures can only provide reasonable, not absolute, assurance that the above
objectives have been met. Also, Generation does not control or manage certain of
its unconsolidated entities and as such, the disclosure controls and procedures
with respect to such entities are more limited than those it maintains with
respect to its consolidated subsidiaries.
As of the date of their evaluation, these officers concluded that,
subject to limitations noted above, the design of the disclosure controls and
procedures provide reasonable assurance that they can accomplish their
objectives. Generation continually strives to improve its disclosure controls
and procedures to enhance the quality of its financial reporting and to maintain
dynamic systems that change as conditions warrant.
There have been no significant changes in Generation's internal
controls or in other factors that could significantly affect these controls
subsequent to the date of their evaluation.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Generation
As previously reported in the 2002 Form 10-K, 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 June 2001, a trial for a sub-group of plaintiffs was
completed, and the jury returned a verdict against Cotter and awarded $16
million in various damages. In November 2001, the District Court entered an
amended final judgment, which included an award of both
112
pre-judgment and post-judgment interests, costs, and medical monitoring
expenses, which total $43 million. In November 2000, another trial involving a
separate sub-group of 13 plaintiffs was completed in Federal district court in
Denver. The jury awarded nominal damages of $42,500 to 11 of 13 plaintiffs and
required Cotter to perform periodic medical monitoring at a cost of $241,000. On
April 22, 2003, the Tenth Circuit Court of Appeals reversed both judgments and
remanded the cases for retrial.
On June 1, 2001, the U.S. Environmental Protection Agency (EPA) issued
to EBG a Notice of Violation (NOV) and Reporting Requirement pursuant to
Sections 113 and 114 of the Clean Air Act, alleging numerous exceedances of
opacity limits and violations of opacity-related monitoring, recording and
reporting requirements at Mystic Station in Everett, Massachusetts. On January
8, 2002, the EPA indicated that it had decided to resolve the NOV through an
administrative compliance order and a judicial civil penalty action. In March
2002, the EPA issued and Sithe Mystic LLC, a wholly owned subsidiary of EBG,
voluntarily entered a Compliance Order and Reporting Requirement (Compliance
Order) regarding Mystic Station, under which Mystic Station installed new
ignition equipment on three of the four units at the plant. Mystic Station also
undertook an extensive opacity monitoring and testing program for all four units
at the plant to help determine if additional compliance measures were needed.
Pursuant to the requirements of the Compliance Order, EBG switched three of the
four units to a lower sulfur fuel oil by June 1, 2002. The Compliance Order does
not address civil penalties. By a letter dated April 21, 2003, the United States
Department of Justice notified EBG that, at the request of the EPA, it intended
to bring a civil penalty action, but also offered the opportunity to resolve the
matter through settlement discussions. EBG is pursuing settlement discussions
with the EPA and the United States Department of Justice.
ITEM 5. OTHER INFORMATION
ComEd
As previously reported in the 2002 Form 10-K, in July 2002, FERC
conditionally approved ComEd's decision to join PJM. On April 1, 2003, ComEd
received approval from FERC to transfer control of ComEd's transmission assets
to PJM. FERC also accepted for filing the PJM tariff amended to reflect the
inclusion of ComEd and other new members, subject to a compliance filing, which
was made on May 1, 2003, and to hearing on certain issues. After resolution of
these matters and completion of certain implementation work necessary to
integrate ComEd into PJM, ComEd expects to transfer control of its Open Access
Same Time Information System to PJM on June 1, 2003, and to transfer functional
control of its transmission assets to PJM and to integrate fully into PJM's
energy market structures on October 1, 2003.
As previously reported in the 2002 Form 10-K, on March 3, 2003, ComEd
entered into an agreement with various Illinois electric retail market
suppliers, key customer groups and governmental parties regarding several
matters affecting ComEd's rates for electric service. The Agreement addressed,
among other things, issues related to ComEd's residential delivery services rate
proceeding, market value index proceeding, the process for competitive service
declarations for large-load customers and an extension of the PPA with
Generation. On March 28, 2003, the ICC issued orders consistent with the
Agreement. Rehearing requests were filed with the ICC in April 2003. The
Agreement will not become effective as long as any of the ICC orders are subject
to any pending rehearing request.
PECO
As previously reported in the 2002 Form 10-K, on August 15, 2002, the
International Brotherhood of Electrical Workers (IBEW) filed a petition with the
NLRB to conduct a unionization vote of certain of PECO's employees. National
Labor Relations Board (NLRB) hearings were completed and a Decision and
Direction of Election (DD&E) was issued on April 21, 2003. Regulations require
that the election be conducted within 30 days of the DD&E issuance.
As previously reported in the 2002 Form 10-K, the PUC's Final Electric
Restructuring Order established MSTs to promote competition. The MST
requirements provided that, if as of January 1, 2003, less than 50% of
residential customers were taking electric service from alternative electric
generation supplier, the number of customers sufficient to meet the MST would be
randomly selected and assigned to an alternative electric generation suppliers
through a PUC-determined process. On January 1, 2003, the number of customers
choosing an alternative electric generation supplier did not meet the MST. In
February 2003, PECO filed a residential customer MST plan, and on May 1, 2003,
the PUC approved the plan. The approved plan provides for a two-step process
with a total of up to 400,000 residential customers being transferred to winning
alternative electric generation supplier bidders: up to 100,000 in July 2003,
and another 300,000 in December 2003. Any customer transferred would have the
right to return to PECO at any time.
Generation
As previously reported in the December 31, 2002 Form 10-K,
approximately 1,700 of Generation's 7,200 employees are covered by Collective
Bargaining Agreements (CBA) with the IBEW. On April 9, 2003, the IBEW filed a
petition with the NLRB to represent all production and maintenance employees in
Generation's fossil and hydroelectric operations in the Mid-Atlantic operating
group. These
113
employees are not currently covered by a CBA. The IBEW petition estimates that
the number of additional employees represented would be 350 to 400. NLRB
hearings were conducted in April 2003. An election is anticipated in the second
half of 2003.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
4.1 - One Hundredth Supplemental Indenture dated as of April 15, 2003 to PECO Energy Company's
First and Refunding Mortgage.
Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United
States Code (Sarbanes - Oxley Act of 2002) as to the Quarterly Report on
Form 10-Q for the quarterly period ended March 31, 2003 filed by the
following officers for the following companies:
- --------------------------------------------------------------------------------------------
99.1 - Filed by John W. Rowe for Exelon Corporation
99.2 - Filed by Robert S. Shapard for Exelon Corporation
99.3 - Filed by Pamela B. Strobel for Commonwealth Edison Company
99.4 - Filed by Robert S. Shapard for Commonwealth Edison Company
99.5 - Filed by Pamela B. Strobel for PECO Energy Company
99.6 - Filed by Robert S. Shapard for PECO Energy Company
99.7 - Filed by Oliver D. Kingsley for Exelon Generation Company, LLC
99.8 - Filed by Robert S. Shapard for Exelon Generation Company, LLC
- --------------------------------------------------------------------------------------------
(b) Reports on Form 8-K:
Exelon, ComEd, PECO and/or Generation filed Current Reports on
Form 8-K during the three months ended March 31, 2003 regarding the
following items:
Date of Earliest
Event Reported Description of Item Reported
- ------------------------------------------------------------------------------------------------------------
November 11, 2002 "ITEM 2. ACQUISITION OR DISPOSITION OF ASSETS" filed by Exelon and
Generation regarding the acquisition of Sithe New England, "ITEM 5.
OTHER EVENTS" filed by Exelon and Generation regarding the Sithe Boston
credit facility and "ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS" filed
by Exelon and Generation for the financial statements of Sithe New
England.
January 15, 2003 "ITEM 9. REGULATION FD DISCLOSURE" filed by Exelon, ComEd, PECO and
Generation regarding the confirmation of earnings guidance for 2002 and
2003.
January 22, 2003 "ITEM 5. OTHER EVENTS" filed by ComEd regarding the issuance of $700
million in First Mortgage Bonds.
January 29, 2003 "ITEM 9. REGULATION FD DISCLOSURE" filed for Exelon, ComEd, PECO and
Generation regarding the fourth quarter 2002
114
earnings release and items discussed during the Earnings Conference Call.
February 11, 2003 "ITEM 9. REGULATION FD DISCLOSURE" filed for Exelon, ComEd, PECO and
Generation regarding a presentation by John Rowe, Chairman and CEO and
Bob Shapard, Executive Vice President and CFO at the Exelon Corporation
Investor Update conference held in New York City. The exhibit
includes the slides used during the presentation.
February 21, 2003 "ITEM 5. OTHER EVENTS" filed for Exelon regarding certain financial
information of Exelon Corporation and Subsidiary Companies. The
exhibits under "ITEM 7. FINANCIAL STATEMENT AND EXHIBITS" filed for
Exelon include the Consent of the Independent Public Accountants,
Selected Financial Data, Market for Registrant's Common Equity and
Related Stockholder Matters, Management's Discussion and Analysis of
Financial Condition and Results of Operations, and Financial Statements
and Supplementary Data.
February 26, 2003 "ITEM 9. REGULATION FD DISCLOSURE" filed for Exelon, ComEd, PECO and
Generation regarding a presentation by Bob Shapard, Executive Vice
President and CFO and Linda Byus, Vice President Investor Relations to
investors and information regarding the small and large commercial
market share threshold auction in Pennsylvania. The exhibits include
the slides used during the presentation and materials made available to
investors attending the conference.
March 3, 2003 "ITEM 5. OTHER EVENTS" filed for Exelon, ComEd, PECO and Generation
regarding the reaffirmation of operating earnings guidance for 2003 and
the discussion of ComEd's agreement regarding rate matters.
March 7, 2003 "ITEM 5. OTHER EVENTS" filed for Exelon and Generation regarding the
announcement of the decision not to sell its interest in AmerGen.
March 13, 2003 "ITEM 9. REGULATION FD DISCLOSURE" filed for Exelon, ComEd, PECO and
Generation regarding a presentation by John Rowe, Chairman and CEO at
the Morgan Stanley Global Electricity & Energy Conference held in New
York City. The exhibit includes the slides used during the
presentation.
115
March 14, 2003 "ITEM 9. REGULATION FD DISCLOSURE" filed for Exelon, ComEd, PECO and
Generation regarding comments and questions at the Morgan Stanley
Global Electricity & Energy Conference.
March 14, 2003 "ITEM 9. REGULATION FD DISCLOSURE" filed for Exelon, ComEd, PECO and
Generation to amend the Current Report filed earlier in the same day,
in order to clarify remarks made regarding British Energy and AmerGen
at the Morgan Stanley Global Electricity & Energy Conference.
March 17, 2003 "ITEM 5. OTHER EVENTS" filed by ComEd regarding the sale of $200
million in Trust Preferred Securities.
March 26, 2003 "ITEM 9. REGULATION FD DISCLOSURE" filed for Exelon, ComEd, PECO and
Generation regarding a presentation by J. Barry Mitchell, Senior Vice
President and Treasurer at the Banc One Capital Markets Fixed Income
Utilities Conference held in Chicago. The exhibit includes the slides
used during the presentation.
March 28, 2003 "ITEM 5. OTHER EVENTS" filed by Exelon and ComEd regarding the issuance
of orders by the Illinois Commerce Commission resolving pending cases
and addressing key issues in Illinois' continued transition to a
competitive electricity marketplace.
- --------------------------------------------------------------------------------
116
SIGNATURES
- --------------------------------------------------------------------------------
Pursuant to requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
EXELON CORPORATION
/s/ John W. Rowe /s/ Robert S. Shapard
- ----------------- ----------------------
JOHN W. ROWE ROBERT S. SHAPARD
Chairman, President and Executive Vice President and Chief
Chief Executive Officer Financial Officer
(Principal Executive Officer) (Principal Financial Officer)
/s/ Matthew F. Hilzinger
- ------------------------
MATTHEW F. HILZINGER
Vice President and Corporate Controller
(Principal Accounting Officer)
May 2, 2003
- --------------------------------------------------------------------------------
Pursuant to requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
COMMONWEALTH EDISON COMPANY
/s/ Pamela B. Strobel /s/ Robert S. Shapard
- ----------------------- -----------------------
PAMELA B. STROBEL ROBERT S. SHAPARD
Chair Executive Vice President and Chief
(Principal Executive Officer) Financial Officer, Exelon
(Principal Financial Officer)
/s/ Duane M. DesParte
- -----------------------
DUANE M. DESPARTE
Vice President and Controller, Energy Delivery
(Principal Accounting Officer)
May 2, 2003
117
- --------------------------------------------------------------------------------
Pursuant to requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
PECO ENERGY COMPANY
/s/ Pamela B. Strobel /s/ Robert S. Shapard
- ----------------------- -----------------------
PAMELA B. STROBEL ROBERT S. SHAPARD
Chair Executive Vice President and Chief
(Principal Executive Officer) Financial Officer, Exelon
(Principal Financial Officer)
/s/ Duane M. DesParte
- -----------------------
DUANE M. DESPARTE
Vice President and Controller, Energy Delivery
(Principal Accounting Officer)
May 2, 2003
- --------------------------------------------------------------------------------
Pursuant to requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
EXELON GENERATION COMPANY, LLC
/s/ Oliver D. Kingsley Jr. /s/ Robert S. Shapard
- ------------------------- -----------------------
OLIVER D. KINGSLEY JR. ROBERT S. SHAPARD
Chief Executive Officer and Executive Vice President and Chief
President Financial Officer, Exelon
(Principal Executive Officer) (Principal Financial Officer)
/s/ Thomas Weir III
- -----------------------
THOMAS WEIR III
Vice President and Controller
(Principal Accounting Officer)
May 2, 2003
118
CERTIFICATIONS
- --------------------------------------------------------------------------------
CERTIFICATION PURSUANT TO RULE 13A-14 AND 15D-14 OF THE SECURITIES AND
EXCHANGE ACT OF 1934
I, John W. Rowe, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Exelon Corporation;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5.The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: May 2, 2003 /s/ John W. Rowe
-----------------------
Chairman, President and Chief Executive Officer
(Principal Executive Officer)
119
CERTIFICATION PURSUANT TO RULE 13A-14 AND 15D-14 OF THE SECURITIES AND
EXCHANGE ACT OF 1934
I, Robert S. Shapard, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Exelon Corporation;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: May 2, 2003 /s/ Robert S. Shapard
--------------------------
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
120
CERTIFICATION PURSUANT TO RULE 13A-14 AND 15D-14 OF THE SECURITIES AND
EXCHANGE ACT OF 1934
I, Pamela B. Strobel, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Commonwealth Edison
Company;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: May 2, 2003 /s/ Pamela B. Strobel
-----------------------
Chair
(Principal Executive Officer)
121
CERTIFICATION PURSUANT TO RULE 13A-14 AND 15D-14 OF THE SECURITIES AND
EXCHANGE ACT OF 1934
I, Robert S. Shapard, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Commonwealth Edison
Company;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the filing date of
this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: May 2, 2003
/s/ Robert S. Shapard
---------------------
Executive Vice President and Chief Financial Officer, Exelon
(Principal Financial Officer)
122
CERTIFICATION PURSUANT TO RULE 13A-14 AND 15D-14 OF THE SECURITIES AND
EXCHANGE ACT OF 1934
I, Pamela B. Strobel, certify that:
1. I have reviewed this quarterly report on Form 10-Q of PECO Energy Company;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: May 2, 2003
/s/ Pamela B. Strobel
--------------------------------
Chair
(Principal Executive Officer)
123
CERTIFICATION PURSUANT TO RULE 13A-14 AND 15D-14 OF THE SECURITIES AND
EXCHANGE ACT OF 1934
I, Robert S. Shapard, certify that:
1. I have reviewed this quarterly report on Form 10-Q of PECO Energy Company;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: May 2, 2003
/s/ Robert S. Shapard
------------------------
Executive Vice President and Chief Financial Officer, Exelon
(Principal Financial Officer)
124
CERTIFICATION PURSUANT TO RULE 13A-14 AND 15D-14 OF THE SECURITIES AND
EXCHANGE ACT OF 1934
I, Oliver D. Kingsley Jr., certify that:
1. I have reviewed this quarterly report on Form 10-Q of Exelon Generation
Company, LLC;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: May 2, 2003 /s/ Oliver D. Kingsley Jr.
----------------------------
Chief Executive Officer and President
(Principal Executive Officer)
125
CERTIFICATION PURSUANT TO RULE 13A-14 AND 15D-14 OF THE SECURITIES AND
EXCHANGE ACT OF 1934
I, Robert S. Shapard, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Exelon Generation
Company, LLC;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls;
and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: May 2, 2003
/s/ Robert S. Shapard
---------------------------------
Executive Vice President and Chief Financial Officer, Exelon
(Principal Financial Officer)
126