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 September 30, 2002March 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) 765-8200765-6900
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
October 15, 2002 was as follows:March 31, 2003 was:
Exelon Corporation Common Stock, without par value 322,984,742324,234,521
Commonwealth Edison Company Common Stock, $12.50 par value 127,016,409127,016,427
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 FormatFILING FORMAT 3
Forward-Looking StatementsFORWARD-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 5155
Exelon Corporation 5155
Commonwealth Edison Company 8073
PECO Energy Company 9483
Exelon Generation Company, LLC 10893
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK 121100
ITEM 4. CONTROLS AND PROCEDURES 124110
PART II. OTHER INFORMATION 126112
ITEM 1. LEGAL PROCEEDINGS 126112
ITEM 5. OTHER INFORMATION 126113
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K 128114
SIGNATURES 131116
CERTIFICATIONS 133118
2
Filing FormatFILING 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 StatementsFORWARD-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 listed in Note 8 of Notes to
Consolidated Financial Statements, those discussed in "Management's(a) the
Registrants' 2002 Annual Report on Form 10-K - ITEM 7. Management's Discussion
and Analysis of Financial Condition and Results of Operations--Outlook"Operations--Business Outlook
and the Challenges in Managing Our Business for Exelon, Corporation's 2001ComEd, PECO and
Generation, (b) the Registrants' 2002 Annual Report those discussed in "Risk Factors" in
PECO Energy Company's Registration Statement on Form S-3, Reg. No. 333-99361,
those discussed in "Risk Factors"10-K - ITEM 8.
Financial Statements and "Management's DiscussionSupplementary Data: Exelon - Note 19, ComEd - Note 16,
PECO - Note 18 and Analysis of
Financial ConditionGeneration - Note 13 and Results of Operations" in Exelon Generation Company,
LLC's Registration Statement on Form S-4, Reg. No. 333-85496, those discussed in
"Risk Factors" in Commonwealth Edison Company's Registration Statement of Form
S-3, Reg. No. 333-99363 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 undertakeundertakes 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 Nine Months Ended
September 30, September 30,March 31,
----------------------------
(in millions, except per share data) 2003 2002
2001 2002 2001
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $4,370 $4,185 $ 11,2454,074 $ 11,6253,357
OPERATING EXPENSES
Purchased Power 1,233 1,249 2,543 2,634840 612
Purchased Power from Unconsolidated Affiliate 104 26 220 4867 56
Fuel 373 356 1,233 1,455830 496
Operating and Maintenance 1,114 1,101 3,252 3,2931,109 1,067
Depreciation and Amortization 345 369 1,012 1,109274 335
Taxes Other Than Income 201 172 568 493197 186
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Operating Expense 3,370 3,273 8,828 9,032Expenses 3,317 2,752
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 1,000 912 2,417 2,593757 605
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (225) (249) (283) (739) (864)
Distributions on Preferred Securities of Subsidiaries (12) (11) (11) (34) (34)
Equity in Earnings of Unconsolidated Affiliates, net 92 52 114 7718 13
Other, net 16 (51) 239 48Net (141) 28
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Other Income and Deductions (152) (293) (420) (773)(360) (219)
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT
OF CHANGES IN ACCOUNTING PRINCIPLES 848 619 1,997 1,820397 386
INCOME TAXES 297 243 724 742148 148
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN
ACCOUNTING PRINCIPLES 551 376 1,273 1,078249 238
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING
PRINCIPLES (net of income taxes of ($90)$69 and $8$(90) for the ninethree
months ended September 30,March 31, 2003 and 2002, and 2001, respectively) -- --112 (230)
12
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
NET INCOME 551 376 1,043 1,090$ 361 $ 8
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
OTHER COMPREHENSIVE INCOME (LOSS) (net of income taxes)
SFAS 133 Transition Adjustment -- -- -- 44
Cash Flow Hedge Fair Value Adjustment (28) 13 (109) (17)(146) (53)
Foreign Currency Translation Adjustment 1 --
Unrealized Gain (Loss) on Marketable Securities, net (73) (30) (158) (154)163 (15)
Interest in Other Comprehensive Income (Loss) of Unconsolidated Affiliates (20) (3) (21) (1)(9) --
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Other Comprehensive Income (Loss) (121) (20) (288) (128), net 9 (68)
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
TOTAL COMPREHENSIVE INCOME (LOSS) $ 430370 $ 356 $ 755 $ 962
=====================================================================================================================(60)
=====================================================================================================
AVERAGE SHARES OF COMMON STOCK OUTSTANDING - Basic 323324 321
322 320
==========================================================================================================================================================================================================================
AVERAGE SHARES OF COMMON STOCK OUTSTANDING - Diluted 324326 323
324 323
==========================================================================================================================================================================================================================
EARNINGS PER AVERAGE COMMON SHARE:
BASIC:
Income Before Cumulative Effect of Changes in Accounting Principles $ 1.710.77 $ 1.17 $ 3.95 $ 3.360.74
Cumulative Effect of Changes in Accounting Principles -- -- (0.71) 0.040.34 (0.72)
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Net Income $ 1.711.11 $ 1.17 $ 3.24 $ 3.40
=====================================================================================================================0.02
=====================================================================================================
DILUTED:
Income Before Cumulative Effect of Changes in Accounting Principles $ 1.700.77 $ 1.16 $ 3.93 $ 3.330.73
Cumulative Effect of Changes in Accounting Principles -- --0.34 (0.71)
0.04
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Net Income $ 1.701.11 $ 1.16 $ 3.22 $ 3.37
=====================================================================================================================0.02
=====================================================================================================
DIVIDENDS PER COMMON SHARE $ 0.46 $ 0.44
$ 0.42 $ 1.32 $ 1.40
==========================================================================================================================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
5
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine
Three Months Ended September 30,March 31,
----------------------------
(in millions) 2003 2002
2001
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 1,043361 $ 1,0908
Adjustments to Reconcile Net Income to Net Cash Flows
Provided by Operating Activities:
Depreciation and Amortization, including nuclear fuel 1,284 1,481423 427
Cumulative Effect of a ChangeChanges in Accounting PrinciplePrinciples (net of income taxes) (112) 230 (12)
Net Gain on Sale of Investments (net of income taxes) (199) --
Provision for Uncollectible Accounts 107 9531 29
Deferred Income Taxes 293 (101)
Deferred Energy Costs 50 21(64) 67
Equity in Earnings(Earnings) Losses of Unconsolidated Affiliates, net (114) (77)(18) (13)
Writedown of Investments 205 2
Net Realized (Gains) Losses on Nuclear Decommissioning Trust Funds 32 90(6) 10
Other Operating Activities 162 (76)(16) 8
Changes in Working Capital:Assets and Liabilities:
Accounts Receivable (320) (163)(57) 58
Inventories (31) 4143 13
Accounts Payable, Accrued Expenses and Other Current Liabilities (6) 572
Changes in Receivables and Payables to Unconsolidated Affiliates, net 46 --(99) (7)
Other Current Assets 24 (4)(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 2,601 2,957383 826
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures (1,534) (1,352)
Acquisition of Generating Plants (443) --
Enterprises Acquisitions, net of cash acquired -- (39)
Proceeds from the Sale of Investments 287 --(427) (586)
Proceeds from Nuclear Decommissioning Trust Funds 1,184 1,077572 580
Investment in Nuclear Decommissioning Trust Funds (1,330) (1,128)(622) (605)
Note Receivable from Unconsolidated Affiliate (42) -- (46)
Other Investing Activities 81 (143)20 27
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Net Cash Flows used in Investing Activities (1,797) (1,585)(457) (630)
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Long-Term Debt 956 2,126951 408
Retirement of Long-Term Debt (1,946) (1,433)(963) (471)
Issuance of Preferred Securities of Subsidiaries 200 --
Retirement of Preferred Securities of Subsidiaries (200) --
Change in Short-Term Debt 428 (957)219 78
Dividends Paid on Common Stock (420) (448)(145) (141)
Change in Restricted Cash 81 12574 135
Proceeds from Employee Stock Plans 64 52
Contribution from Minority Interest of Consolidated Subsidiary 43 --
Redemption of Preferred Securities of Subsidiaries (18) (18)31 18
Other Financing Activities (16) 32(59) (12)
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Net Cash Flows used inprovided by Financing Activities (828) (521)108 15
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
INCREASE IN CASH AND CASH EQUIVALENTS (24) 85134 211
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 461 526469 485
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 490503 $ 1,377
=====================================================================================================================
SUPPLEMENTAL CASH FLOW INFORMATION
Non-cash Investing and Financing Activities:
Contribution of Land from Minority Interest of Consolidated Subsidiary $ 12 --
Regulatory Asset Fair Value Adjustment -- $ 347
Purchase Accounting Estimate Adjustments -- $ 63696
====================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
6
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30,
March 31, December 31,
(in millions) 2003 2002
2001
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 461503 $ 485469
Restricted Cash 291 372322 396
Accounts Receivable, net
Customer 2,007 1,6872,121 2,095
Other 210 428243 265
Receivable from Unconsolidated Affiliate 40 4420 32
Inventories, at average cost
Fossil Fuel 189 222163 218
Materials and Supplies 312 249317 306
Deferred Income Taxes 101 2310 6
Other 300 272625 331
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Current Assets 3,911 3,7824,324 4,118
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT, NET 14,926 13,78120,237 17,134
DEFERRED DEBITS AND OTHER ASSETS
Regulatory Assets 6,111 6,4235,459 5,938
Nuclear Decommissioning Trust Funds 2,997 3,1653,032 3,053
Investments 1,665 1,6231,171 1,393
Goodwill, net 4,964 5,3354,788 4,992
Other 662 708890 850
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 16,399 17,25415,340 16,226
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS $ 35,236 $ 34,817
=====================================================================================================================$39,901 $37,478
================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
7
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30,
March 31, December 31,
(in millions) 2003 2002
2001
- --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Notes Payable $ 788900 $ 360681
Note Payable to Unconsolidated Affiliate 534 534
Long-Term Debt Due withinWithin One Year 1,501 1,4061,147 1,402
Accounts Payable 1,304 9641,815 1,563
Accrued Expenses 942 1,182 1,311
Other 495 505481 483
- --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Current Liabilities 5,030 4,4176,059 5,974
- --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT 11,904 12,87913,368 13,127
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred Income Taxes 4,506 4,3883,849 3,702
Unamortized Investment Tax Credits 305 316298 301
Nuclear Decommissioning Liability for Retired Plants 1,389 1,353-- 1,395
Asset Retirement Obligation 2,406 --
Pension Obligation 315 3341,848 1,959
Non-Pension Postretirement Benefits Obligation 893 847911 877
Spent Nuclear Fuel Obligation 854 843861 858
Regulatory Liabilities 633 --
Other 859 694976 871
- --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 9,121 8,77511,782 9,963
- ---------------------------------------------------------------------------------------------------------------------
PREFERRED SECURITIES OF SUBSIDIARIES 595 613-----------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES
MINORITY INTEREST OF CONSOLIDATED SUBSIDIARIES 75 31
COMMITMENTS AND CONTINGENCIES78 77
PREFERRED SECURITIES OF SUBSIDIARIES 610 595
SHAREHOLDERS' EQUITY
Common Stock 6,995 6,9307,099 7,059
Deferred Compensation -- (1) (2)
Retained Earnings 1,830 1,2002,254 2,042
Accumulated Other Comprehensive Income (Loss) (313) (26)(1,349) (1,358)
- --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Shareholders' Equity 8,511 8,1028,004 7,742
- --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 35,23639,901 $ 34,817
=====================================================================================================================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 Nine Months Ended
September 30, September 30,March 31,
----------------------------
(in millions) 2003 2002
2001 2002 2001
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES
Operating Revenues $1,912 $1,905 $ 4,6851,411 $ 4,8261,304
Operating Revenues from Affiliates 26 14 49 6913 11
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 1,938 1,919 4,734 4,8951,424 1,315
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Purchased Power 8 6 20 86
Purchased Power from Affiliate 967 948 2,046 2,141572 532
Operating and Maintenance 234 229 620 625231 195
Operating and Maintenance from Affiliates 33 36 104 10630 42
Depreciation and Amortization 129 178 397 51294 135
Taxes Other Than Income 77 82 223 22380 73
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Operating Expense 1,448 1,479 3,410 3,615Expenses 1,013 983
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 490 440 1,324 1,280411 332
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (122) (137) (374) (423)
Interest Expense from Affiliate -- (10) -- (10)(110) (126)
Distributions on Company-Obligated
Mandatorily Redeemable Preferred Securities of
Subsidiary Trusts Holding Solely the Company's
Subordinated Debt Securities (7) (7)
(22) (22)
Interest Income from Affiliates 7 8
24 23 70
Other, net (8) 9Net 15 6
24
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Other Income and Deductions (129) (121) (367) (361)(95) (119)
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 361 319 957 919AND CUMULATIVE EFFECT OF
A CHANGE IN ACCOUNTING PRINCIPLE 316 213
INCOME TAXES 146 141 381 412126 84
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
NET INCOME 215 178 576 507BEFORE 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 (LOSS) (net of income taxes):
Cash Flow Hedge Fair Value Adjustment (15)31 3
Foreign Currency Translation Adjustment 1 --
(31) --
Unrealized Gain (Loss) on Marketable Securities (1) (1) (3) (5)
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Other Comprehensive Income (Loss) (16) (1) (34) (5)32 3
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
TOTAL COMPREHENSIVE INCOME $ 199227 $ 177 $ 542 $ 502
=====================================================================================================================132
=====================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
9
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
NineThree Months Ended September 30,March 31,
----------------------------
(in millions) 2003 2002
2001
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 576195 $ 507129
Adjustments to Reconcile Net Income to Net Cash Flows
Provided by Operating Activities:
Depreciation and Amortization 397 51294 135
Cumulative Effect of a Change in Accounting Principle (net of income taxes) (5) --
Provision for Uncollectible Accounts 29 3112 11
Deferred Income Taxes 92 2663 53
Other Operating Activities 86 (27)(3) 13
Changes in Working Capital:Assets and Liabilities:
Accounts Receivable (198) (80)(5) --
Inventories (4) 25(1) 10
Accounts Payable, Accrued Expenses and Other Current Liabilities 64 324(143) 1
Changes in Receivables and Payables to Affiliates, net 449 (279)(146) (90)
Pension and Non-Pension Postretirement Benefits Obligations (36) 7
Other CurrentNoncurrent Assets (2) 4and Liabilities 42 9
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Net Cash Flows provided by Operating Activities 1,489 1,04367 278
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures (549) (631)
Notes Receivable from Affiliate 14 400(174) (182)
Other Investing Activities 9 --10 7
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Net Cash Flows used in Investing Activities (526) (231)(164) (175)
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Short-Term Borrowings 94 --
Issuance of Long-Term Debt 701 --700 400
Retirement of Long-Term Debt (1,365) (260)(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 (353) (253)(120) (118)
Change in Restricted Cash (37) (5) (20)
Other Financing Activities (10) --(59) (9)
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Net Cash Flows used inprovided by (used in) Financing Activities (970) (518)113 (44)
- ---------------------------------------------------------------------------------------------------------------------
(DECREASE)-------------------------------------------------------------------------------------------------------------------
INCREASE IN CASH AND CASH EQUIVALENTS (7) 29416 59
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 16 23
141
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 1632 $ 435
=====================================================================================================================
SUPPLEMENTAL CASH FLOW INFORMATION
Non-cash Investing and Financing Activities:
Net Assets Transferred as a result of Restructuring, net of Note Payable -- $ 1,307
Receivable from Parent -- $ 1,062
Purchase Accounting Estimate Adjustment -- $ 63
Regulatory Asset Fair Value Adjustment -- $ 347
Retirement of Treasury Shares $ 1,344 $ 2,023
82
===================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
10
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30,
March 31, December 31,
(in millions) 2003 2002
2001
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 1632 $ 2316
Restricted Cash 78 4170 65
Accounts Receivable, net
Customer 914 745759 782
Other 89 87
Receivables from Affiliates 8 688 72
Inventories, at average cost 60 5666 65
Deferred Income Taxes 40 5220 20
Receivables from Affiliates 6 15
Other 17 1514 14
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Current Assets 1,222 1,0251,055 1,049
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT, NET 7,610 7,3517,840 7,744
DEFERRED DEBITS AND OTHER ASSETS
Regulatory Assets 583 667-- 447
Investments 48 54 64
Goodwill, net 4,888 4,902
Notes Receivable4,711 4,916
Receivables from Affiliates 2,221 1,300
1,314
Other 311 304355 320
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 7,136 7,2517,335 7,037
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS $ 15,96816,230 $ 15,627
=====================================================================================================================15,830
===================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
11
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30,March 31, December 31,
(in millions) 2003 2002
2001
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Short-Term BorrowingsNotes Payable $ 9445 $ --71
Long-Term Debt Due withinWithin One Year 798 849871 698
Accounts Payable 200 144192 201
Accrued Expenses 396 374352 477
Payables to Affiliates 615 218200 416
Customer Deposits 82 81
Other 183 21270 79
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Current Liabilities 2,286 1,7971,812 2,023
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT 5,295 5,8505,421 5,268
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred Income Taxes 1,749 1,6711,739 1,650
Unamortized Investment Tax Credits 52 5550 51
Pension Obligation 167 15146 91
Non-Pension Postretirement Benefits Obligation 145 146147 138
Payables to Affiliates 2517 224
Regulatory Liabilities 633 --
Other 345 297
Other 322 248
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 2,686 2,5682,967 2,451
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES
COMPANY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED
SECURITIES OF SUBSIDIARY TRUSTS HOLDING SOLELY THE COMPANY'S
SUBORDINATED DEBT SECURITIES 329 329
COMMITMENTS AND CONTINGENCIES344 330
SHAREHOLDERS' EQUITY
Common Stock 1,588 2,0481,588
Preference Stock 7 7
Other Paid-inPaid in Capital 4,181 5,0574,029 4,239
Receivable from Parent (845) (937)(584) (615)
Retained Earnings 480 257
Treasury Stock, at cost -- (1,344)652 577
Accumulated Other Comprehensive Income (Loss) (39) (5)(6) (38)
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Shareholders' Equity 5,372 5,0835,686 5,758
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 15,96816,230 $ 15,627
=====================================================================================================================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 Nine Months Ended
September 30, September 30,March 31,
--------------------------------
(in millions) 2003 2002
2001 2002 2001
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES
Operating Revenues $1,221 1,048 $ 3,2301,214 $ 2,9991,017
Operating Revenues from Affiliates 3 3
9 9
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 1,224 1,051 3,239 3,0081,217 1,020
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Purchased Power 68 57 175 14765 48
Purchased Power from Affiliate 441 363 1,090 872357 303
Fuel 40 51 228 335191 135
Operating and Maintenance 125 134 350 352127 111
Operating and Maintenance from Affiliates 15 22 57 6112 25
Depreciation and Amortization 127 115 348 315120 112
Taxes Other Than Income 85 51 207 13563 59
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Operating Expense 901Expenses 935 793
2,455 2,217
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 323 258 784 791282 227
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (93) (105) (280) (324)
Interest Expense from Affiliate -- -- -- (8)(86) (95)
Company-Obligated Mandatorily Redeemable Preferred
Securities of a Partnership, which holdsHolds Solely
Subordinated Debentures of the Company (2) (2)
(7) (7)
Interest Income from Affiliates --Other, Net 9 -- 10
Other, net 5 3 7 201
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Other Income and Deductions (90) (95) (280) (309)(79) (96)
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 233 163 504 482203 131
INCOME TAXES 76 59 166 17166 42
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
NET INCOME 157 104 338 311137 89
Preferred Stock Dividends (2) (2)
(6) (7)
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
NET INCOME ON COMMON STOCK $ 155135 $ 102 $ 332 $ 304
=====================================================================================================================87
==========================================================================================
OTHER COMPREHENSIVE INCOME (net of income taxes)
Net Income $ 157137 $ 104 $ 338 $ 31189
Other Comprehensive Income (Loss) (net of income taxes):
SFAS 133 Transition Adjustment -- -- -- 40
Cash Flow Hedge Fair Value Adjustment (5) (10) (10) (20)
Unrealized Gain (Loss) on Marketable Securities (1) -- 2
- ------------------------------------------------------------------------------------------
Total Other Comprehensive Income -- --2
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
TOTAL COMPREHENSIVE INCOME $ 151137 $ 94 $ 328 $ 331
=====================================================================================================================91
==========================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
13
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine
Three Months Ended September 30,March 31,
----------------------------
(in millions) 2003 2002
2001
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 338137 $ 31189
Adjustments to Reconcile Net Income to Net Cash Flows
Provided by Operating Activities:
Depreciation and Amortization 348 315120 112
Provision for Uncollectible Accounts 48 5017 19
Deferred Income Taxes (64) (49)
Deferred Energy Costs 50 14(20) 46
Other Operating Activities 15 (23)3 (2)
Changes in Working Capital:Assets and Liabilities:
Accounts Receivable (69) (64)(37) (3)
Changes in Receivables and Payables to Affiliates, net (27) 1546 (17)
Inventories (8) (21)45 35
Accounts Payable, Accrued Expenses and Other Current Liabilities (107) 9214 (83)
Prepaid Taxes (131) (133)
Deferred Energy Costs (28) 34
Other Current Assets (51) (35)-- (1)
Pension and Non-Pension Postretirement Benefits Obligations 8 2
Other Noncurrent Assets and Liabilities (8) 2
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Net Cash Flows provided by Operating Activities 473 744126 100
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures (180) (153)(65) (68)
Other Investing Activities 6 3
(1)
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Net Cash Flows used in Investing Activities (177) (154)(59) (65)
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Long-Term Debt 250 --
Retirement of Long-Term Debt (571) (1,167)
Issuance of Long-Term Debt 225 805
Contribution from Parent 30 121(364) (160)
Change in Short-Term Debt 274 (161)43 58
Dividends on Preferred and Common Stock (261) (176)(91) (87)
Change in Restricted Cash 113 98
Change in Receivable and Payable to Affiliate, net -- (41)
Retirement of Mandatorily Redeemable Preferred Stock (19) (18)
Settlement of Interest Rate Swap Agreements (5) 31136 153
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Net Cash Flows used in Financing Activities (214) (508)(26) (36)
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 82 82
Cash Transferred in Restructuring -- (31)41 (1)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 63 32
49
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 114104 $ 100
=====================================================================================================================
SUPPLEMENTAL CASH FLOW INFORMATION Non-cash Investing and Financing Activities:
Net Assets Transferred as a result of Restructuring,
net of Receivable from Affiliates -- $ 1,577
Contribution of Receivable from Parent -- $ 1,98331
===================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
14
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30,
March 31, December 31,
(in millions) 2003 2002
2001
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 114104 $ 3263
Restricted Cash 210 323195 331
Accounts Receivable, net
Customer 310 286389 379
Other 30 33
Receivables from Affiliates 17 149 39
Inventories, at average cost
Fossil Fuel 79 7221 67
Materials and Supplies 7 79 8
Deferred Energy Costs 59 31
Prepaid Taxes 50132 1
Other 10 588 8
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Current Assets 827 813966 927
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT, NET 4,121 4,0474,199 4,179
DEFERRED DEBITS AND OTHER ASSETS
Regulatory Assets 5,527 5,7565,459 5,491
Investments 21 2419 19
Prepaid Pension Asset 37 1350 41
Other 83 8561 63
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 5,668 5,8785,589 5,614
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS $ 10,61610,754 $ 10,738
=====================================================================================================================10,720
=============================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
15
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30,March 31, December 31,
(in millions) 2003 2002
2001
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Notes Payable $ 375243 $ 101200
Payables to Affiliates 130 187146 170
Long-Term Debt Due withinWithin One Year 264 689 548
Accounts Payable 61 54117 87
Accrued Expenses 277 397354 370
Deferred Income Taxes 27 27
Other 37 2135 33
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Current Liabilities 1,596 1,3351,186 1,576
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT 4,950 5,4385,262 4,951
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred Income Taxes 2,881 2,9382,890 2,903
Unamortized Investment Tax Credits 25 2724 24
Non-Pension Postretirement Benefits Obligation 271 239268 251
Payable to Affiliate 39 --
44
Other 118 110120 126
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 3,295 3,3583,341 3,304
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES
COMPANY-OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES OF A PARTNERSHIP,
WHICH HOLDS SOLELY SUBORDINATED
DEBENTURES OF THE COMPANY 128 128
MANDATORILY REDEEMABLE PREFERRED STOCK -- 19
COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS' EQUITY
Common Stock 1,942 1,9121,976 1,976
Receivable from Parent (1,788) (1,878)(1,728) (1,758)
Preferred Stock 137 137
Retained Earnings 347 270447 401
Accumulated Other Comprehensive Income 9 195 5
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Shareholders' Equity 647 460837 761
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 10,61610,754 $ 10,738
=====================================================================================================================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 Nine Months Ended
September 30, September 30,March 31,
----------------------------
(in millions) 2003 2002
2001 2002 2001
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES
Operating Revenues $ 750886 $ 787 $1,924 $ 2,180569
Operating Revenues from Affiliates 1,463 1,404 3,309 3,223993 892
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 2,213 2,191 5,233 5,4031,879 1,461
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Purchased Power 1,251 1,209 2,555 2,504761 553
Purchased Power from Affiliates 6 59 26 8580 66
Fuel 273 242 706 691364 209
Operating and Maintenance 351 322 1,098 1,046445 375
Operating and Maintenance Expense from Affiliates 40 42 136 12757
Depreciation and Amortization 68 57 197 22445 63
Taxes Other Than Income 37 36 126 12148 49
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Operating Expense 2,026 1,967 4,844 4,798Expenses 1,785 1,372
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 187 224 389 60594 89
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (22) (27) (48) (62)(15) (17)
Interest Expense from- Affiliates (1) (14) (3) (38)(4) --
Equity in Earnings of Unconsolidated Affiliates 87 60 119 99
Interest Income from Affiliates -- 10 -- 1019 23
Other, net 14 (35) 54 (17)Net (167) 16
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Other Income and Deductions 78 (6) 122 (8)(167) 22
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
INCOME (LOSS) BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF
CHANGES IN ACCOUNTING PRINCIPLES 265 218 511 597(73) 111
INCOME TAXES 102 78 198 228(21) 45
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGES IN
ACCOUNTING PRINCIPLES 163 140 313 369(52) 66
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES -- --(net of income taxes
of $70 and $9 for the three months ended March 31, 2003 and 2002, respectively) 108 13
12
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
NET INCOME 163 140 326 381$ 56 $ 79
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
OTHER COMPREHENSIVE INCOME (LOSS) (net of income taxes)
Unrealized Gain (Loss) on Marketable Securities (69) (54) (151) (134)
SFAS 133 Transition Adjustment -- -- -- 4163 (9)
Cash Flow Hedge Fair Value Adjustment (11) 50 (79) 14(180) (74)
Interest in Other Comprehensive Income (Loss) of Unconsolidated Affiliates (20) (3) (21) (1)(9) 6
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Other Comprehensive Income (Loss) (100) (7) (251) (117)(26) (77)
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
TOTAL COMPREHENSIVE INCOME $ 6330 $ 133 $ 75 $ 264
=====================================================================================================================2
===================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
17
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine
Three Months Ended September 30,March 31,
----------------------------
(in millions) 2003 2002
2001
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 32656 $ 38179
Adjustments to Reconcile Net Income (Loss) to Net Cash Flows
Provided by Operating Activities:
Depreciation and Amortization including nuclear fuel 475 531195 155
Cumulative Effect of a ChangeChanges in Accounting PrinciplePrinciples (net of income taxes) (108) (13) (12)
Provision for Uncollectible Accounts 20 31 2
Deferred Income Taxes 246 (84)(106) (2)
Equity in (Earnings) LossesEarnings of Unconsolidated Affiliates (119) (99)(19) (23)
Writedown of Investment 200 --
Net Realized (Gains) Losses on Nuclear Decommissioning Trust Funds 32 90(6) 10
Other Operating Activities 109 (162)4 9
Changes in Working Capital:Assets and Liabilities:
Accounts Receivable (90) (4)(57) 53
Changes in Receivables and Payables to Affiliates, net (325) 13244 144
Inventories (22)(10) (37)
Accounts Payable, Accrued Expenses and Other Current Liabilities 174 14519 127
Other Current Assets (42) 17(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 771 782278 509
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures (715) (497)
Acquisition of Generating Plants (443) --(175) (308)
Proceeds from Nuclear Decommissioning Trust Funds 1,184 1,077572 580
Investment in Nuclear Decommissioning Trust Funds (1,330) (1,128)(622) (605)
Note Receivable from Affiliate (42) -- (46)
Other Investing Activities 3 69 --
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Net Cash Flows used in Investing Activities (1,343) (542)(216) (379)
- -------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Change in Note Payable, Affiliate 348 (696)
Contribution from Minority Interest in Consolidated Subsidiary 43 --
Issuance of Long-Term Debt 30 8211 --
Retirement of Long-Term Debt (4) (3)
Distribution to Member (30) (156)(2) 1
Change in Intercompany Payable, Affiliate (6) --
Change in Restricted Cash (56) --
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Net Cash Flows provided by (used in) Financing Activities 387 (34)(63) 1
- -------------------------------------------------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (185) 206(1) 131
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 58 224
4
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 3957 $ 210
=====================================================================================================================
SUPPLEMENTAL CASH FLOW INFORMATION
Non-cash Investing and Financing Activities:
Contribution of Land from Minority Interest of Consolidated Subsidiary $ 12 --355
===================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
18
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30,
March 31, December 31,
(in millions) 2003 2002
2001
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 3957 $ 22458
Restricted Cash 56 --
Accounts Receivable, net
Customer 443 316588 587
Other 63 15080 57
Receivables from Affiliates 783 373343 594
Inventories, at average cost
Fossil Fuel 101 105140 140
Materials and Supplies 228 202226 217
Deferred Income Taxes 7 --7
Other 113 65263 145
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Current Assets 1,777 1,4351,760 1,805
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT, NET 2,796 2,0037,788 4,800
DEFERRED DEBITS AND OTHER ASSETS
Nuclear Decommissioning Trust Funds 2,997 3,1653,032 3,053
Investments 922 816
Note438 657
Receivable from Affiliate 246 29141 220
Deferred Income Taxes 340 212196 271
Prepaid Pension Asset 13 --
Other 202 223210 201
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 4,707 4,7073,930 4,402
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS $ 9,28013,478 $ 8,145
=====================================================================================================================11,007
========================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
19
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30,
March 31, December 31,
(in millions) 2003 2002
2001
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
LIABILITIES AND MEMBER'S EQUITY
CURRENT LIABILITIES
Long-Term Debt Due within One Year $ 65 $ 45
Accounts Payable 892 5851,304 1,089
Payables to Affiliates 33 34
Note10
Notes Payable to Affiliate 348 --Affiliates 857 863
Accrued Expenses 257 303
Deferred Income Taxes -- 7516 480
Other 194 171207 216
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Current Liabilities 1,730 1,1042,922 2,663
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT 1,096 1,0212,131 2,132
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred Income Taxes 247 --
Unamortized Investment Tax Credits 228 234224 226
Nuclear Decommissioning Liability for Retired Plants 1,389 1,353-- 1,395
Asset Retirement Obligation 2,402 --
Pension Obligation 100 118-- 37
Non-Pension Postretirement Benefits Obligation 404 384428 410
Spent Nuclear Fuel Obligation 854 843861 858
Payables to Affiliate, net 920 --
Other 324 280396 333
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 3,546 3,2125,231 3,259
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES
MINORITY INTEREST OF CONSOLIDATED SUBSIDIARY 55 --
COMMITMENTS AND CONTINGENCIES54 54
MEMBER'S EQUITY
Membership Interest 2,286 2,3162,507 2,296
Undistributed Earnings 850 523980 924
Accumulated Other Comprehensive Income (Loss) (283) (31)(347) (321)
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Member's Equity 2,853 2,8083,140 2,899
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND MEMBER'S EQUITY $ 9,28013,478 $ 8,145
=====================================================================================================================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 September 30,
2002March 31, 2003
and for the three and nine months then ended are unaudited, but include all
adjustments thatin the opinion of
management of Exelon Corporation (Exelon), Commonwealth Edison Company (ComEd),
PECO Energy Company (PECO) and Exelon Generation Company, LLC (Generation)
considerinclude 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, 20012002
consolidated balance sheets were derived from audited financial statements but
do not include all disclosures required by accounting principles generally
accepted accounting principlesin 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 PECOGeneration included in or incorporated by reference in
ItemITEM 8 of their Annual Report on Form 10-K for the year ended December 31, 20012002.
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 Notesrelated nuclear decommissioning trust fund investments were transferred to
Consolidated Financial StatementsGeneration by ComEd and PECO in Generation's Form S-4
registration statement No. 333-85496 declared effectiveconnection with the Exelon corporate
restructuring on April 24,January 1, 2001.
Generation had decommissioning assets of $3,053 million and $3,032
million as of December 31, 2002 by the
Securities and Exchange Commission (SEC), (Generation's Form S-4). See ITEM 6.
Exhibits and Reports on Form 8-K.
The consolidated financial statements contained herein include the
accounts of majority-owned subsidiaries after the elimination of intercompany
transactions. Investments and joint venturesMarch 31, 2003, respectively, in which a 20% to 50% interest is
owned and a significant influence is exerted are accounted for under the equity
method of accounting. The proportionate interests in jointly owned electric
utility plants are consolidated. Investments in which less than a 20% interest
is owned are accounted for under the cost method of accounting. Exelon owns 100%
of all significant consolidated subsidiaries, either directly or indirectly,
except for ComEd of which Exelon owns 99%, InfraSource of which Exelon owns 95%
and Southeast Chicago Energy Project, LLC of which Exelon owns 70% through
Generation.trust
accounts. Exelon and Generation have reflectedanticipate that all trust fund assets will
ultimately be used to decommission its nuclear plants.
After considering recent interpretation of the third-party intereststransitional 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
above majority owned investments as minority interests21
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 their Consolidated
Statementsaccounting 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 Cash Flows, Consolidated Balance Sheets and in Other, Netthe 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
Comprehensive Income.
2. ADOPTION OF NEW ACCOUNTING PRINCIPLES (Exelon,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 Generation)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 Financial Accounting Standards Board (FASB)FASB issued Statement of Accounting Standard (SFAS)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
isbecame effective for business combinations initiated after June 30, 2001. In
addition, SFAS No. 141 requiresrequired that unamortized negative goodwill related to
21
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, Energy Company, LLC
(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.
Under SFAS No. 142, goodwill is no longer subject to amortization, however,
goodwill is subject to an assessment for impairment using a two-step fair value
based test, the first step of which must be performed at least annually, or more
frequently if events or circumstances indicate that goodwill might be impaired.
The first step compares the fair value of a reporting unit to its carrying
amount, including goodwill. If the carrying amount of the reporting unit exceeds
its fair value, the second step is performed. The second step compares the
carrying amount of the goodwill to the fair value of the goodwill. If the fair
value of goodwill is less than the carrying amount, an impairment loss is
reported as a reduction to goodwill and a charge to operating expense, except at
the transition date, when the loss is reflected as a cumulative effect of a
change in accounting principle.
As of December 31, 2001, Exelon's Consolidated Balance Sheets reflected
approximately $5.3 billion in goodwill net of accumulated amortization,
including $4.9 billion of net goodwill related to the 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 acquisitions by 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. Exelon's infrastructure
services businessInfraSource 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 fair value of the Enterprises'
reporting units was determined using discounted cash flow models reflecting the
expected range of future cash flow outcomes related to each of the Enterprises
reporting units over the life of the investment. These cash flows were
discounted to 2002 using a risk-adjusted discount rate. The impairment was recorded as a cumulative effect of a change in
accounting principle in the first quarter of 2002.
22
The changes in the carrying amount of goodwill by reportable segment
(see Note 6 for further discussion of reportable segments) for the nine months
ended September 30, 2002 are as follows:
Energy
Delivery Enterprises Total
- ---------------------------------------------------------------------------------------------------------------------
Balance as of January 1, 2002 $ 4,902 $ 433 $ 5,335
Impairment losses -- (357) (357)
Settlement of pre-Merger income tax contingencies (7) -- (7)
Merger severance adjustment (7) -- (7)
- ---------------------------------------------------------------------------------------------------------------------
Balance as of September 30, 2002 $ 4,888 $ 76 $ 4,964
=====================================================================================================================
The September 30, 2002, Energy Delivery goodwill relates to ComEd and
the remaining Enterprises goodwill relates to the InfraSource and Exelon
Services reporting units. Consistent with SFAS No. 142, the remaining goodwill
will be reviewed for impairment on an annual basis, or more frequently if
significant events occur that could indicate an impairment exists. ComEd and
Enterprises plan to perform an impairment review in the fourth quarter of 2002.
Such future review would be consistent with the review conducted related to the
implementation of SFAS No. 142 (implementation review), which required estimates
of numerous items with varying degrees of uncertainty, such as discount rates,
terminal value earnings multiples, future revenue levels and estimated future
expenditure levels for ComEd and Enterprises; load growth and the resolution of
future rate proceedings for ComEd; and customer base and construction back logs
for Enterprises. Significant changes from the assumptions used in the
implementation review could possibly result in a future impairment loss. The
Illinois legislation provides that reductions to ComEd's common equity resulting
from goodwill impairments will not impact ComEd's earnings through 2006 under
the earnings provisions of the legislation.
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:
Exelon
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Enterprises goodwill impairment (net of income taxes of $103 million)$(103)) $ (254)
Minority interest (net of income taxes of $4 million)$4) 11
Elimination of AmerGen negative goodwill (net of income taxes of $9 million)$9) 13
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total cumulative effect of a change in accounting principle $ (230)
=====================================================================================================================
Generation
- ---------------------------------------------------------------------------------------------------------------------
Elimination of AmerGen negative goodwill (net of income taxes of $9 million)
recorded as cumulative effect of a change in accounting principle $ 13
- ---------------------------------------------------------------------------------------------------------------------=================================================================================================
23
The following tables set forth Exelon's net income and earnings per
common share and ComEd's net income for the three and nine months ended
September 30, 2002 and 2001, respectively, adjusted to exclude 2001 amortization
expense related to goodwill that is no longer being amortized.At March 31, 2003, Exelon
Three Months Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
Reported income before cumulative effect
of changes in accounting principles $ 551 $ 376 $ 1,273 $ 1,078
Cumulative effect of changes in
accounting principles -- -- (230) 12
- ---------------------------------------------------------------------------------------------------------------------
Reported net income 551 376 1,043 1,090
Goodwill amortization -- 37 -- 114
- ---------------------------------------------------------------------------------------------------------------------
Adjusted net income $ 551 $ 413 $ 1,043 $ 1,204
- ---------------------------------------------------------------------------------------------------------------------
Basic earnings per common share:
Reported income before cumulative effect
of changes in accounting principles $ 1.71 $ 1.17 $ 3.95 $ 3.36
Cumulative effect of changes in
accounting principles -- -- (0.71) 0.04
- ---------------------------------------------------------------------------------------------------------------------
Reported net income 1.71 1.17 3.24 3.40
Goodwill amortization -- 0.12 -- 0.36
- ---------------------------------------------------------------------------------------------------------------------
Adjusted net income $ 1.71 $ 1.29 $ 3.24 $ 3.76
- ---------------------------------------------------------------------------------------------------------------------
Diluted earnings per common share:
Reported income before cumulative effect
of changes in accounting principles $ 1.70 $ 1.16 $ 3.93 $ 3.33
Cumulative effect of changes in
accounting principles -- -- (0.71) 0.04
- ---------------------------------------------------------------------------------------------------------------------
Reported net income 1.70 1.16 3.22 3.37
Goodwill amortization -- 0.11 -- 0.35
- ---------------------------------------------------------------------------------------------------------------------
Adjusted net income $ 1.70 $ 1.27 $ 3.22 $ 3.72
- ---------------------------------------------------------------------------------------------------------------------
ComEd
Three Months Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
Reported net income $ 215 $ 178 $ 576 $ 507
Goodwill amortization -- 32 -- 97
- ---------------------------------------------------------------------------------------------------------------------
Adjusted net income $ 215 $ 210 $ 576 $ 604
- ---------------------------------------------------------------------------------------------------------------------
Generation
The cessation of the amortization of negativehad goodwill of AmerGen$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 January 1,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 have a material impact on Generation's reported net
income for the three or nine months ended September 30, 2002.
24
identify any goodwill impairment.
Other Accounting Principles and Accounting Changes
EITF Issue 02-3
In the third quarter of 2002, Exelon and Generation early adopted the
provisionprovisions of FASB Emerging IssuesIssue Task Force (EITF) Issue No. 02-3, "Accounting
for Contracts Involved in Energy Trading and Risk Management Activities" (EITF
02-3) issued by the FASB EITF in June 2002 that requires revenues and energy costs
related to energy trading contracts to be presented on a net basis in the income
statement. Prior to the
second quarter of 2002,adoption, revenues from trading activity were presented in
Revenue and the energy costs related to energy trading were presented as either
Purchased Power or Fuel expense on Exelon and Generation's Consolidated
Statements of Income. For comparative purposes, energy costs related to energy
trading have been reclassified in prior periods to revenue 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.
For the three and nine months ended
September 30, 2001, $93 million and $123 million of purchased power expense,
respectively, and $7 million and $12 million of fuel expense, respectively, was
reclassified and reflected as a reduction to revenue. The three months ended
March 31, 2002 included $504 million of purchased power expense and $9 million
of fuel expense that has been reclassified and reflected as a reduction to
revenue in the nine months ended September 30, 2002.
SFAS No. 144146
In September 2001,July 2002, the FASB issued SFAS No. 144,146, "Accounting for the
ImpairmentCosts
Associated with Exit or Disposal of Long-Lived Assets"Activities" (SFAS No. 144)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 SFASthe
disclosure requirements under FIN No. 144 on January 1, 2002. SFAS No. 144 establishes
accounting and reporting standards for both the impairment and disposal of
long-lived assets. SFAS No. 144 is45, which were effective for fiscal years beginningfinancial
statements for periods ended after December 15, 20012002. The recognition and
itsmeasurement provisions are generally applied prospectively.of FIN No. 45 were effective for guarantees issued or
modified after December 31, 2002. The adoption of this statementFIN No. 45 had no material
effect on Exelon, ComEd, PECO or Generation's reported financial positions, results of operations or cash flows.operations. Liabilities
associated with guarantees entered into during the first quarter of 2003 are
reflected in Note 8 - Commitments and Contingencies.
27
SFAS No. 145148
In AprilDecember 2002, the FASB issued SFAS No. 145, "Rescission of FASB
Statements No. 4, 44148, "Accounting for
Stock-Based Compensation - Transition and 64, AmendmentDisclosure - an amendment of FASB
Statement No. 13, and Technical
Corrections"123" (SFAS No. 145)148). SFAS No. 145 eliminates148 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. 4 "Reporting Gains
and Losses from Extinguishment of Debt" (SFAS No. 4) and thus allows148 was effective for only
those gains or losses onfinancial statements for fiscal years ended after
December 15, 2002. Exelon adopted the extinguishment of debt that meet the criteria of
extraordinary items to be treated as such in the financial statements. SFAS No.
145 also amends Statement of Financial Accounting Standards No. 13, "Accounting
for Leases" (SFAS No. 13) to require sale-leaseback accounting for certain lease
modifications that have economic effects that are similar to sale-leaseback
transactions. The adoptionadditional disclosure requirements of SFAS
No. 145148 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 no effectExelon 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 orand Generation's reportedconsolidated financial positions,position, results of
operations orand cash flows.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) applies. 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 all derivativeSFAS No.
133, (2) in connection with other FASB projects dealing with financial
instruments, and requires(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 such instrumentsrelate to SFAS No. 133
implementation issues that have been effective for fiscal quarters that began
prior to June 15, 2003 should continue to be recorded on the balance sheet either as an assetapplied in accordance with their
respective effective dates. In addition, certain provisions relating to forward
purchases or a
liability measured at their fair value through earnings, with special accounting
permitted for certain qualifying hedges. On January 1, 2001,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 adoptedare currently determining the impact of
the adoption of SFAS No. 133. Generation recognized149 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
non-cash gaindepreciation study reflecting its significant construction program in recent
years, changes in and development of $12new 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 of income taxes, in earnings and deferred a non-cash gain of
$4for the three months ended March 31, 2003
increased approximately $24 million net of($14 million, after income taxes, in accumulated other comprehensive income and
25
PECO deferred a non-cash gain of $40 million, net of income taxes, in
accumulated other comprehensive 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-megawatt893-MW Mountain Creek Steam Electric Station in Dallas and
the 1,441-megawatt1,441-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 will makehas agreed to fixed capacity payments,and variable
expense payments, and willto provide fuel to Exelon in return for exclusive rights
to the energy and capacity of the generation plants. Substantially all of the
purchase price has been allocated to property, plant and equipment.
Sale of AT&T Wireless
On April 1, 2002, Enterprises sold its 49% interest in AT&T Wireless
PCS of Philadelphia, LLC to a subsidiary of AT&T Wireless Services for $285
million in cash. Enterprises recorded an after-taxa gain of $116$201 million ($116 million after
income taxes) in other, net on the $84 million investment, which had been reflected in Deferred
DebitsOther Income and Other AssetsDeductions on Exelon's Consolidated Balance Sheets.
Sithe New England Holdings Acquisition
On June 26, 2002, Generation agreed to purchase Sithe New England
Holdings, LLC (Sithe New England), a subsidiaryStatements
of Sithe Energies Inc. (Sithe),
and related power marketing operations in exchange for a $543 million note. In
addition, Generation will assume various Sithe guarantees related to an equity
contribution agreement between Sithe New England and Sithe Boston Generation
(Boston Generation), a project subsidiary of Sithe New England. The equity
contribution agreement requires, among other things, that Sithe New England,
upon the occurrence of certain events, contribute up to $38 million of equity
for the purpose of completing the construction of two generating facilities.
Boston Generation established a $1.2 billion credit facility in order to finance
the construction of these two generating facilities. The approximately $1.1
billion expected to be outstanding under the facility at the transaction closing
date, will be reflected on Exelon's Consolidated Balance Sheet. Sithe New
England has provided security interests in and has pledged the stock of its
other project subsidiaries to Boston Generation. If the closing conditions are
satisfied, the transaction could be completed in November 2002.
The purchase involves approximately 4,471 megawatts (MWs) of generation
capacity, consisting of 1,670 MWs in operation and 2,421 MWs under construction,
which would increase Generation's net assets by approximately $1.6 billion.
Sithe New England's generation facilities are located primarily in
Massachusetts.
Generation is a 49.9% owner of Sithe and accounts for the investment as
an unconsolidated equity investment. The Sithe New England purchase would not
affect the accounting for Sithe as an equity investment. Separate from the Sithe
New England transaction, Generation is subject to a Put and Call Agreement (PCA)
that gives Generation the right to purchase (Call) the remaining 50.1% of Sithe,
and gives the other Sithe shareholders the right to sell (Put) their interest to
26Income.
31
Generation. If the Put option is exercised, Generation has the obligation to
complete the purchase. The PCA provides that the Put and Call options become
exercisable as of December 18, 2002 and expire in December 2005. The Sithe New
England purchase is a separate transaction from the PCA in that it is intended
to enable Generation to acquire only the Sithe assets that fit Generation's
strategy, accelerate the realization of synergies, and reduce the amount of debt
needed to finance the transaction.
See ITEM 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations - Exelon Corporation - for further discussion of the
PCA.
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 PECO)
On June 1, 2001, ComEdgovernmental 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 Illinois Commerce Commission (ICC)
to establish delivery service charges for residential customers in preparation
for residential customer choice, which began in May 2002. The filing also
updated delivery service charges for non-residential customers.
On April 1, 2002, the ICC issued an interim order in ComEd's Delivery
Services Rate Case. The interim order is subject to an audit of test year (2000)
expenditures, including capital plant expenditures, with a final order toICC.
Rehearing requests may be issued in 2003. The order sets delivery rates for residential customers choosing
a new retail electric supplier. The new rates became effective May 1, 2002 when
residential customers became eligible to choose their supplier of electricity.
Traditional bundled rates paid by customers that retain ComEd as their
electricity supplier are not affected by this order. Bundled rates will remain
frozenconsidered through 2006, as a result of the June 6, 2002 amendments to the Illinois
Restructuring Act that extended the freeze on bundled rates for an additional
two years. Delivery service rates for non-residential customers are not affected
by the order. The potential revenue impact of the interim order is not expected
to be material in 2002.
On October 10, 2002, ComEd received the audit report on the audit of
test year expenditures by the Liberty Consulting Group (Liberty), a consulting
firm engaged by the ICC in conjunction with the audit of test year expenditures.
Using the interim order as a starting point, Liberty recommends certain
additional disallowances to test year expenditures and rate base levels, which,
if ultimately approved by the ICC would result in lower residential delivery
service charges and higher non-residential delivery service charges. The ICC
will hold hearings on the Liberty audit report and responses from ComEd and
other parties. A final decision is expected in the middle of May 2003. ComEd intends to contest the Liberty audit findings in the reopened
hearings and cannot currently determine what portion, ifThe
Agreement will not become effective as long as any of the Liberty
audit recommendationsICC orders are subject
to any pending rehearing request or if a stay is issued with respect to any of
those orders.
During the ICC will accept. If the ICC ultimately determines that
all or some portionfirst quarter of ComEd's distribution plant is not recoverable through
rates, ComEd may be required to write-off some or all of the amount of its
investment that the ICC determines is not recoverable. The estimated potential
write-off, before income taxes, could be up to approximately $100 million if the
Liberty audit recommendations were to be accepted by the ICC in their entirety.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,taxes.
This amount is partially offset by the reversal of a $12 million (before income
taxes) reserve established in the third quarter of 2002 representing the estimated minimum probable write-off
exposure resulting from the audit findings.
27
As permitted by the Pennsylvania Electric Competition Act, the
Pennsylvania Departmentfor a potential capital
disallowance in ComEd's delivery services rate proceeding, and a credit of Revenue calculated a 2002 Revenue Neutral
Reconciliation (RNR) adjustment$10
million (before income taxes) related to the gross receipts tax rate in order to
neutralize the impactcapitalization of electric restructuring on its tax revenues. In January
2002, the Pennsylvania Public Utility Commission (PUC) approved the RNR
adjustment to the gross receipts tax rate collected from customers. Effective
January 1, 2002, PECO implemented the changeemployee
incentive payments provided for in the gross receipts tax rate.delivery services order. The RNR adjustment increases the gross receipts tax rate, which will increase PECO's
annual revenues and tax obligations by approximately $50net one-time
charge for these items was $29 million in 2002. The
RNR adjustment was under appeal. The case was remanded to the PUC and in August
2002, the PUC ruled that PECO is properly authorized to recover these costs.(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 Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
Average common shares outstanding 323 321 322 320
Assumed exerciseThree 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 1 2 2 3
- ---------------------------------------------------------------------------------------------------------------------
Average diluted common shares outstanding 324 323 324 323
=====================================================================================================================
Stock options not included in average common
shares used in calculating diluted earnings per share due to their antidilutive
effect were five million
for the three and nine months ended September 30, 2002March 31, 2003 and four million and one
million for the three and nine months ended September 30, 2001, respectively.
282002.
32
6. SEGMENT INFORMATION (Exelon, ComEd, PECO and PECO)Generation)
Exelon operates in three business segments: energy delivery (including
ComEd and PECO), generation (includes Generation) and enterprises. Beginning in 2002, Exelon
evaluates the performance of its business segments on the basis of net income.
ComEd, PECO and PECOGeneration each operate in onea single business segment, Energy Delivery.segment. Exelon's
segment information for the three months ended March 31, 2003 and nine months ended September 30, 2002 as compared to the same periods
in 2001 and at
September 30, 2002March 31, 2003 and December 31, 2001 are2002 is as follows:
Three Months Ended September 30, 2002 as compared to Three Months Ended
September 30, 2001
Corporate and
Energy Intersegment
Delivery Generation Enterprises Eliminations Consolidated
- -------------------------------------------------------------------------------------------------------------------
Revenues(1):
2002 $ 3,162 $ 2,213 $ 509 $ (1,514) $ 4,370
2001 2,970 2,191 529 (1,505) 4,185
Intersegment Revenues:
2002 $ 29 $ 1,463 $ 22 $ (1,514) $ --
2001 17 1,404 84 (1,505) --
Operating Expenses(1):
2002 $ 2,350 $ 2,026 $ 494 $ (1,500) $ 3,370
2001 2,272 1,967 529 (1,495) 3,273
Net Income/(Loss)
2002 $ 370 $ 163 $ 15 $ 3 $ 551
2001 280 140 (33) (11) 376
- -------------------------------------------------------------------------------------------------------------------
29
Nine Months Ended September 30, 2002 as compared to Nine Months Ended September 30, 2001
Corporate and
Energy Intersegment
Delivery Generation Enterprises Eliminations Consolidated
- --------------------------------------------------------------------------------------------------------------------
Revenues(2)Total Revenues (1):
2003 $ 2,642 $ 1,879 $ 580 $ (1,027) $ 4,074
2002 $ 7,973 $ 5,233 $ 1,475 $(3,436) $ 11,245
2001 7,903 5,403 1,742 (3,423) 11,6252,335 1,461 490 (929) 3,357
Intersegment Revenues:
20022003 $ 5916 $ 3,309993 $ 72 $(3,440)19 $ (1,028) $ --
2001 78 3,223 124 (3,425)2002 14 892 25 (931) --
Operating Expenses(2):
2002Income (Loss) Before Income Taxes and the Cumulative Effect of Changes in Accounting Principles:
2003 $ 5,865517 $ 4,844(73) $ 1,510 $ (3,391) $ 8,828
2001 5,833 4,798 1,794 (3,393) 9,032
Net Income/(Loss):
2002 $ 908 $ 326 $(174)(30) $ (17) $1,043
2001 810 381 (63) (38) 1,090
- --------------------------------------------------------------------------------------------------------------------$ 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:
September 30, 2002March 31, 2003 $ 26,584 $9,280 $1,310 $(1,938)26,984 $ 35,23613,478 $ 1,283 $ (1,844) $ 39,901
December 31, 2001 26,365 8,145 1,790 (1,483) 34,817
- --------------------------------------------------------------------------------------------------------------------
(1) $59 million and $58 million in utility taxes are included in the Revenues
and Expenses for the three months ended September 30, 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 2001,
respectively, for ComEd. $64 million and $50 million in utility taxes are
included in the Revenues and Expenses for the three months ended September
30, 2002, and 2001, respectively, for PECO.
(2) $157 million and $156 million in utility taxes are included in the Revenues
and Expenses for the nine months ended September 30, 2002 and 2001,
respectively, for ComEd. $157 million and $103 million in utility taxes are
included in the Revenues and Expenses for the nine months ended September
30, 2002 and 2001, respectively, for PECO.
7. FAIR VALUE OF FINANCIAL ASSETS AND LIABILITIES (Exelon, ComEd, PECO and
Generation)
During the three and nine months ended September 30,March 31, 2003 and 2002, and 2001, Exelon recorded
pre-tax gains and losses(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 September 30, 2002March 31, 2003 $ (36)1 $ --3 $ (24)(294) $ 4 $ (56)(286)
Three months ended September 30, 2001 -- (12) 84 9 81
Nine months ended September 30,March 31, 2002 (42) (1) (132) 19 (156)
Nine months ended September 30, 2001 -- (4) (23) 11 (16)$ (2) $ 6 $ (122) $ 17 $ (101)
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
During the three months ended September 30, 2002 and 2001, and the nine
months ended September 30, 2002 and 2001,
Generation recognized net MTM gainslosses on non-trading energy derivative
contracts not designated as cash flow hedges, in operating revenues as follows:
2002 2001
- ---------------------------------------------------------------------------------------------------------------------
Three months ended September 30, $ 1 $ 7
Nine months ended September 30, 11 29
- ---------------------------------------------------------------------------------------------------------------------
30Purchased 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 September 30,March 31, 2003 and 2002, and 2001, and the nine
months ended September 30, 2002 and 2001, Generation recognized net MTM gains
and losses on energy trading contracts, in earnings as follows:
2002 2001
- ---------------------------------------------------------------------------------------------------------------------
Three months ended September 30, $ -- $ 4
Nine months ended September 30, (13) (2)
- ---------------------------------------------------------------------------------------------------------------------
During the three months ended September 30, 2002 and 2001 and the nine
months ended September 30, 2002 and 2001, PECOno 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 occurringoccurring.
During the three months ended March 31, 2003 and 2002, Generation did
not reclassify any amounts from accumulated other comprehensive income into
earnings as follows:
2002 2001
- ---------------------------------------------------------------------------------------------------------------------
Three months ended September 30, $ -- $ --
Nine months ended September 30, -- 6
- ---------------------------------------------------------------------------------------------------------------------
a result of forecasted energy commodity transactions no longer being
probable.
As of September 30, 2002,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 $ (1)-- $ 1514 $ (48)(364) $ 5 $ (29)(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 three months ended September first quarter 2003, ComEd reclassified $51 million ($30 2002 and 2001 and the nine
months ended September 30, 2002 and 2001, Generation did not reclassify any
amountsmillion,
after income taxes) from accumulated other comprehensive income to regulatory assets for
cash flow swaps settled during the quarter.
ComEd has also entered into earningsinterest 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 forecasted energy commodity transactions no longer being probable.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.
3134
September 30, 2002
-------------------------------------------------------------------------March 31, 2003
----------------------------------------------------------
Gross Gross
Amortized Unrealized Unrealized Estimated
Cost Gains Losses Fair Value
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Equity securities $ 1,7541,852 $ 5953 $ (557)(532) $ 1,2561,373
Debt securities
Government obligations 989 73 -- 1,062916 55 (2) 969
Other debt securities 674693 33 (28) 679(36) 690
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total debt securities 1,663 106 (28) 1,7411,609 88 (38) 1,659
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total available-for-sale securities $ 3,4173,461 $ 165141 $ (585)(570) $ 2,997
=====================================================================================================================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
================================================================================================
Unrealized gainsNet 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 areof
$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 Generation'sthe Consolidated Balance Sheet.
ForSheets 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 September 30,March 31, 2003 and 2002 proceeds from the sale
of decommissioning trust investmentsrespectively, were recorded
in other income and gross realized gains and losses on
those sales were $295 million, $12 million and $21 million, respectively. For
the nine months ended September 30, 2002, proceeds from the sale of
decommissioning trust investments and gross realized gains and losses on those
sales were $1,184 million, $43 million and $77 million, respectively.
For the nine months ended September 30, 2002, netdeductions. Net realized losses of $2$4 million for the three
months ended March 31, 2002 were recognized in Accumulated Depreciation in Generation's Consolidated
Balance Sheets and $32 million of net realized losses were recognized in Other
Income and Deductions in Generation's Consolidated Statements of Income and
Comprehensive Income.Depreciation. The
available-for-sale securities held at September 30,
2002March 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 Noteand Nuclear
Decommissioning and Spent Fuel Storage Notes in the Notes to Consolidated
Financial Statements of Exelon, ComEd, PECO and PECOGeneration for the year ended
December 31, 20012002. See Note 4 - New Accounting Principles and Generation's S-4.Accounting Changes
for further discussion of nuclear decommissioning commitments and contingencies.
Environmental Liabilities
Exelon has identified 71 sites where former manufactured gas plant
(MGP) activities have or may have resulted in actual site contamination. As of September 30, 2002,March 31, 2003, Exelon had accrued $150$143 million for
environmental investigation and remediation costs that currently can be
reasonably estimated, including $127$114 million for MGPmanufactured 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 September 30, 2002,March 31, 2003, ComEd had accrued $107$92 million (discounted) for environmental
investigation and remediation costs that currently can be reasonably estimated.
This reserve included $103$87 million (discounted) for MGP investigation and
remediation.
The MGP reserve was increased by $17 million in the third
quarter of 2002 as the result of a delay in implementing the ongoing remediation
for a MGP site in Oak Park, Illinois.
As of September 30, 2002,March 31, 2003, PECO had accrued $34$37 million (undiscounted) for
environmental investigation and remediation costs that currently can be
reasonably estimated, including $24$27 million for MGP investigation and
remediation.
32
As of September 30, 2002,March 31, 2003, Generation had accrued $9$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)
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
2002
2003 $ 191543 $2,367 $ 850187 $1,625 $ 47 $ 796 $ 32
2003 597 1,954 261 1,467 7564
2004 642 944765 1,356 315 7441,036 93
2005 357 231 489 212426 431 488 319 84
2006 329 92 494 177397 124 493 243 3
2007 475 31 227 212 --
Thereafter 4,150 22 2,003 9013,821 1 1,590 843 --
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total $6,427 $4,310 $3,300 $4,278 $ 6,266 $ 4,093 $ 3,609 $ 4,297 $ 287
- ---------------------------------------------------------------------------------------------------------------------
(1) Net Capacity Purchases includes Midwest Generation commitments as of
October 2, 2002. On October 2, 2002, Generation notified Midwest Generation
of its exercise of termination options under the existing Collins
Generating Station (Collins) and Peaking Unit (Peaking) Purchase Power
Agreements. Generation exercised its termination options on 1,727 MWs in
2003 and 2004. In 2003, Generation will take 1,778 MWs of option capacity
under the Collins and Peaking Unit Agreements as well as 1,265 MWs of
option capacity under the Coal Generation Purchase Power Agreement. Net
capacity purchases in 2004 include 3,474 MWs of optional capacity from
Midwest Generation. Net Capacity Purchases also include capacity sales to
TXU under the purchase power agreement244
====================================================================================================
(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 commitments.energy commitments:
In connection with the 2001 corporate restructuring, ComEdGeneration entered
into a purchase power agreement (PPA)PPA with GenerationComEd 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.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 33
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, PECOGeneration entered
into a PPA with GenerationPECO under which Generation has agreed to supply PECO obtainswith
substantially all of itsPECO's electric supply from Generationneeds 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
Chicago Franchise. In March 1999, ComEd reached a settlement agreement
with the City of Chicago (Chicago) to end the arbitration proceeding between
ComEd and Chicago regarding their January 1, 1992 franchise agreement. As part
of the settlement agreement, ComEd and Chicago agreed to a revised combination
of ongoing work under the franchise agreement and new initiatives that will
result in defined transmission and distribution expenditures by ComEd to improve
electric services in Chicago. The settlement agreement provides that ComEd would
be subject to liquidated damages if the projects are not completed by various
dates, unless it was prevented from doing so by events beyond its reasonable
control. In addition, ComEd and Chicago established an Energy Reliability and
Capacity Account, into which ComEd paid $25 million during each of the years
1999 through 2001 and has conditionally agreed to pay $25 million at the end of
2002, to help ensure an adequate and reliable electric supply for Chicago.
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
34
third quarter of 1998, FERC granted the complaint and directed that refunds be
made, with interest. ComEd filed a request for rehearing. On April 30, 2001,
FERC issued an order granting rehearing in which it determined that its 1998
order had been erroneous and that no refunds were due from ComEd to the
municipal customers. On June 29, 2001, FERC denied the customers' requests for
rehearing of the order granting rehearing. In August 2001, each of the three wholesale municipal
customers appealed the April 30, 2001 FERC order to the Federal circuit court,
which consolidated the appeals for the purposes of briefing and decision. 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 August 4, 1999,November 25, 2002, the Illinois Appellate Court held
thatcourt granted the
developers' claims againstmotions for summary
38
judgment. The judge also entered a permanent injunction enjoining ComEd from
refusing to pay the state were premature,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 Illinois
Supreme Court denied leave to appealruling. ComEd believes that ruling. Developers of both facilities
have since filed amended complaints repeating their allegations that ComEd
breachedit did not breach the
contracts in question and requestingthat the damages claimed far exceed any loss that any
project incurred by reason of its ineligibility for such breach
reflecting the state-subsidized ratesubsidized rate. ComEd
intends to which the developers claim they were
entitled under their contracts. These matters are in the discovery phase. ComEd
is contestingprosecute its appeal and defend each case.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.
Enron. As a result of Enron Corp.'s bankruptcy proceeding, ComEd has
potential monetary exposure for 366 of its customer accounts that were served by
Enron Energy Services (EES) as a billing agent. EES has rejected its contracts
with these accounts, with the exception of approximately 100 accounts for which
EES retains its billing agency. ComEd is working to ensure that customers know
what amounts are owed to ComEd on accounts for which EES has been removed as
billing agent, and has obtained updated billing addresses for these accounts.
With regard to the accounts for which EES retains its billing agency, ComEd's
total amount outstanding is not material. Because that amount is owed to ComEd
by individual customers, it is not part of the bankrupt Enron's estate. The ICC
has rescinded EES's authority to act as an alternative retail energy supplier in
Illinois. However, EES never served as a supplier, as opposed to a billing
agent, to any of ComEd's retail accounts.
35
Generation
Godley Park District Litigation. On April 18, 2001, the Godley Park
District filed suit in Will County Circuit Court against ComEd and Generation
alleging that oil spills at Braidwood Station have contaminated the Park
District's water supply. The complaint sought actual damages, punitive damages
of $100 million and statutory penalties. The court dismissed all counts seeking
punitive damages and statutory penalties, and the plaintiff has filed an amended
complaint before the court. The amended complaint added counts under the
Illinois Public Utility Act (PUA), which provides for statutory penalties and
allows recovery of attorney's fees. On April 20, 2002, the Court denied ComEd
and Generation's motion to dismiss the additional counts under the PUA. ComEd
and Generation are contesting the liability and damages sought by the plaintiff.
As a result of the 2001 corporate restructuring, Generation has responsibility
for this matter.
Cotter Corporation Litigation. During 1989 and 1991, actions were
brought in Federal and state courts in Colorado against ComEd and its
subsidiary, Cotter Corporation (Cotter), seeking unspecified damages and
injunctive relief based on allegations that Cotter permitted radioactive and
other hazardous material to be released from its mill into areas owned or
occupied by the plaintiffs, resulting in property damage and potential adverse
health effects. In 1994, a Federal jury returned nominal dollar verdicts against
Cotter on eight plaintiffs' claims in the 1989 cases, which verdicts were upheld
on appeal. The remaining claims in the 1989 actions were settled or dismissed.
In 1998, a jury verdict was rendered against Cotter in favor of 14 of the
plaintiffs in the 1991 cases, totaling approximately $6 million in compensatory
and punitive damages, interest and medical monitoring. On appeal, the Tenth
Circuit Court of Appeals reversed the jury verdict, and remanded the case for
new trial. These plaintiffs' cases were consolidated with the remaining 26
plaintiffs' cases, which had not been tried. The consolidated trial was
completed on June 28, 2001. The jury returned a verdict against Cotter and
awarded $16.3$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
$43.3$43 million. This matter is being appealed by Cotter in the Tenth
Circuit Court of Appeals. Cotter is vigorously contesting the award. In November 2000, another trial involving a separate sub-group of
13 plaintiffs, seeking $19 million in damages plus interest was completed in
Federal District Court in Denver. The jury awarded nominal damages of $42,500 to
11 of 13 plaintiffs, but awarded no damages for any personal injury or health
claims, other than requiring Cotter to perform periodic medical monitoring at
minimal cost. Cotter and the plaintiffs both appealed the verdictthese 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.
36
The United StatesU.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), is
reviewinghas submitted a draft feasibility
study that recommends cappingaddressing 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 are $10 millionrange from $0 to $15$87 million. Once a final feasibility studyremedy is complete and a remedy
selected, it is expected that the PRPs will agree on an allocation of
responsibility for the costs. Until an agreement is reached, 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), and one of its fossil facilities,
Eddystone (Delaware County, PA). 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.
GeneralExelon, 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
Generation is a counterparty to Dynegy Inc. (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 to below investment grade.agencies. As of September 30,
2002,March 31, 2003, Generation
had a net receivable from Dynegy of approximately $7$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 MW1,040-MW gas-fired
qualified facility that has an energy onlyenergy-only long-term tolling arrangementagreement with
Dynegy, with a related financial swap arrangement. As of September 30, 2002,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-marketmarked 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 write-offimpair this financial swap asset.
Generation estimates, as a 49.9% owner of Sithe, that the fair value asset, which
Generation estimatesimpairment would
result in an approximate $22 millionafter-tax reduction inof its equity earnings from Sithe, based on Generation's current 49.9% investment
ownership in Sithe.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 Sithe's
investment in the Independence Station and AmerGen's purchased power arrangementPPA with Illinois
Power Company, a subsidiary of Dynegy, could be impacted by events related to
Dynegy's financial condition.
3745
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."Combination".
At December 31, 2002, Exelon, ComEd, PECO and Generation Merger costs charged to expense. PECO's merger-related costs charged to
expense in 2000 were $248had
liabilities of $28 million, consisting of $116$13 million, for PECO employee
costs$1 million and $132$7 million,
of direct incremental costs incurred by PECO in
conjunction with the merger transaction. Direct incremental costs represent
expenses directly associated with completing the Merger, including professional
fees, regulatory approval and settlement costs, and settlement of compensation
arrangements. Employee costs represent estimated severance costs and pension and
postretirement benefits provided under Exelon's merger separation plans for
eligible employees who are expected to be involuntarily terminated before
December 2002 due to integration activities of the merged companies. Additional
employee severance costs of $48 million, primarily related to PECO employees,
were charged to operating and maintenance expense in 2001, and a $10 million
reduction in the estimated liability related to Generation employees was
recorded in operating and maintenance expense in the first quarter of 2002.
Employee costs are being paid from the Exelon's pension and post-retirement
benefit plans, exceptrespectively, for certain benefits such as outplacement services, continuation
of health care coverage and educational benefits. As of September
30, 2002 a liability of $7 million is reflected on Exelon's balance sheet for
payment of these benefits, of which $2 million is reflected on PECO's balance
sheet and $3 million is reflected on Generation's balance sheet.
A total of 960 PECO positions are expected to be eliminated as a result
of the merger, 274 of which related to generation, 230 of which related to PECO
energy delivery and the remainder from the enterprises and corporate support
areas of the company. As of September 30, 2002, 788 of the positions had been
eliminated, of which 162 related to PECO energy delivery, and 181 related to
generation and the remainder to enterprises and corporate support. The remaining
positions are expected to be eliminated in the fourth quarter of 2002.
Additionally, in the third quarter of 2000, approximately $20 million
of closing costs and $8 million of stock compensation costs associated with
Unicom were charged to expense.
Exelon, ComEd and Generation
Merger Costs Included in Purchase Price Allocation. The purchase price
allocation as of December 31, 2000 included a liability of $307 million for
Unicom employee costs and liabilities of approximately $39 million for estimated
costs of exiting various business activities of former Unicom activities that
were not compatible with the strategic business direction of Exelon.
38
During 2001, Exelon, ComEd and Generation finalized plans for
consolidation of functions, including negotiation of an agreement with the
International Brotherhood of Electrical Workers Local 15 regarding severance
benefits to union employees. Also, in January of 2001, ComEd transferred a
portion of its employee related liabilities to Generation, Enterprises and
Business Services Company (BSC) as part of the corporate restructuring. In the
third quarter of 2002, Exelon reduced its reserve by $12 million due to the
elimination of identified positions through normal attrition, which did not
require payments under Exelon's merger separation plans, and a determination
that certain positions would not be eliminated by the end of 2002 as originally
planned due to a change in certain business plans. The reduction in the reserve
was recorded as a purchase price adjustment to goodwill. In 2001 and through
September 30, 2002, Exelon, ComEd and Generation recorded adjustments to the
purchase price allocation as follows:
Exelon
Original Adjustments Adjusted
Estimate 2001 2002 Liabilities
- -----------------------------------------------------------------------------------------------------------------------
Employee severance payments $ 128 $ 33 $ (10) $ 151 (a)
Other benefits 21 9 (2) 28 (a)
- -----------------------------------------------------------------------------------------------------------------------
Employee severance payments and other benefits 149 42 (12) 179
Actuarially determined pension and postretirement costs 158 (11) -- 147 (b)
- -----------------------------------------------------------------------------------------------------------------------
Total Unicom employee cost $ 307 $ 31 $ (12) $ 326
=======================================================================================================================
(a) The increase is a result of the identification in 2001 of additional
positions to be eliminated, partially offset by the 2002 elimination of
identified positions through normal attrition and changes in certain
business plans.
(b) The reduction results from lower estimated pension and post retirement
welfare benefits reflecting revised actuarial estimates.
The following table provides a reconciliation of the reserve for
employee severance and other benefits associated with the Merger:
- ---------------------------------------------------------------------------------------------------------------------
Adjusted employee severance and other benefits reserve $ 179
Payments to employees (October 2000-June 2002) (125)
Payments to employees (July 2002-September 2002) (10)
- ---------------------------------------------------------------------------------------------------------------------
Employee severance and other benefits reserve as of September 30, 2002 $ 44
=====================================================================================================================
ComEd
Original Adjustments Adjusted
Estimate Transfer 2001 2002 Liabilities
- ------------------------------------------------------------------------------------------------------------------------
Employee severance payments $ 128 $ (68) $ 17 $ (7) $ 70 (a)
Other benefits 21 (14) 8 (2) 13 (a)
- ------------------------------------------------------------------------------------------------------------------------
Employee severance payments
and other benefits 149 (82) 25 (9) 83
Actuarially determined pension
and postretirement costs 158 (82) 10 -- 86 (b)
- ------------------------------------------------------------------------------------------------------------------------
Unicom employee cost - ComEd $ 307 $ (164) $ 35 $ (9) $ 169
========================================================================================================================
(a) The increase is a result of the identification in 2001 of additional
positions to be eliminated, partially offset by the 2002 elimination of
identified positions through normal attrition and changes in certain
business plans.
(b) The reduction results from lower estimated pension and post retirement
welfare benefits reflecting revised actuarial estimates.
39
The following table provides a reconciliation of ComEd's reserve for
employee severance and other benefits associated with the Merger:
- ---------------------------------------------------------------------------------------------------------------------
Adjusted employee severance and other benefits reserve $ 83
Payments to employees (October 2000-June 2002) (54)
Payments to employees (July 2002-September 2002) (5)
- ---------------------------------------------------------------------------------------------------------------------
Employee severance and other benefits reserve as of September 30, 2002 $ 24
=====================================================================================================================
Generation
Original Adjustments Adjusted
Estimate 2001 2002 Liabilities
- ------------------------------------------------------------------------------------------------------------------------
Employee severance payments $ 45 $ (12) $ (2) $ 31 (a)
Other benefits 5 2 -- 7 (a)
- ------------------------------------------------------------------------------------------------------------------------
Employee severance payments and other benefits 50 (10) (2) 38
Actuarially determined pension and postretirement costs 71 (25) -- 46 (b)
- ------------------------------------------------------------------------------------------------------------------------
Unicom employee cost - Generation $ 121 $ (35) $ (2) $ 84
========================================================================================================================
(a) The increase is a result of the identification in 2001 of additional
positions to be eliminated, partially offset by the 2002 elimination of
identified positions through normal attrition and changes in certain
business plans.
(b) The reduction results from lower estimated pension and post retirement
welfare benefits reflecting revised actuarial estimates.
The following table provides a reconciliation of the reserve for
employee severance and other benefits associated with the Merger:
- ---------------------------------------------------------------------------------------------------------------------
Adjusted employee severance and other benefits reserve $ 38
Payments to employees (October 2000-June 2002) (26)
Payments to employees (July 2002-September 2002) (3)
- ---------------------------------------------------------------------------------------------------------------------
Employee severance and other benefits reserve as of September 30, 2002 $ 9
=====================================================================================================================
merger
separation plans. At March 31, 2003, Exelon, ComEd, PECO and Generation
The following table provides the status of the former Unicom positions
identified to be eliminated as a result of the Merger:
Corporate
& Other ComEd Generation Total
- ---------------------------------------------------------------------------------------------------------------------
Estimate at October 20, 2000 180 1,022 1,073 2,275
2001 adjustments (a) 109 206 (197) 118
Total estimated positions to be eliminated 289 1,228 876 2,393
Terminated employees (October 2000-June 2002) (241) (648) (699) (1,588)
Terminated employees (July 2002-September 2002) (9) (49) (13) (71)
Normal attrition (9) (148) (75) (232)
Business plan changes (b) (2) (99) (49) (150)
- ---------------------------------------------------------------------------------------------------------------------
Remaining positions to be eliminated by the end of 2002 28 284 40 352
=====================================================================================================================
(a) The increase is a result of the identification of additional positions to
be eliminated in 2001.
(b) The reduction is due to a determination in the third quarter of 2002, that
certain positions would not be eliminated by the end of 2002 as originally
planned due to a change in certain business plans.
40Generation'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 September 30, 2002,March 17, 2003, ComEd paid on maturityissued $200 million of variabletrust preferred
securities, with an annual distribution rate senior notes due September 30, 2002.of 6.35% that are mandatorily
redeemable in 2033.
On September 16, 2002,March 18, 2003, ComEd paid on maturity $200redeemed $236 million of 7.375%its First Mortgage
Bonds, Series 85, due September 15, 2002. On September 16, 2002,
ComEd also redeemed $200 million of 8.375% First Mortgage Bonds, Series 86, at a redemption price of 103.425%103.863% of the principal amount. Theseamount, plus accrued
interest. The bonds, had a maturity
datewhich carried an interest rate of September 15, 2022.8.375%, were refinanced
with long-term debt issued on April 7, 2003.
On June 13, 2002,March 20, 2003, ComEd issuedredeemed $200 million of 6.15% First Mortgage
Bonds, Series 98, due March 15, 2012. The $200 million bond issuance was a
refinancing of the $200 million of 8.5% First Mortgage Bonds, Series 84 redeemed
on July 15, 2002its trust preferred
securities at a redemption price of 103.915%100% of the principal amount.
These redeemed bonds had a maturity dateamount, plus accrued
distributions. The preferred securities, which carried an interest rate of
July 15, 2022.8.48%, 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 the $200 million
of First Mortgage Bonds, ComEd settled a forward startingforward-starting interest rate swap in theswaps with an aggregate
notional amount of $75$870 million resultingwere settled with net proceeds to counterparties
of $51 million ($30 million, after income taxes) that has been deferred in
a $1 million pre-tax loss recorded in other
comprehensive income, whichregulatory assets and is being amortized over the expected remaining life of the related debt.
On June 4, 2002, ComEd issued $100 million of Illinois Development
Finance Authority floating-rate Pollution Control Revenue Refunding Bonds,
Series 2002 due April 15, 2013. The $100 million bond issuance was used to
redeem $100 million of 7.25% Illinois Development Finance Authority Pollution
Control Revenue Refunding Bonds, Series 1991. These redeemed bonds had a
maturity date of June 1, 2011.
On March 21, 2002, ComEd redeemed $200 million of 8.625% First Mortgage
Bonds Series 81, at a redemption price of 103.84% of the principal amount.
These bonds had a maturity date of February 1, 2022.
On March 13, 2002, ComEd issued $400 million of 6.15% First Mortgage
Bonds, Series 98, due March 15, 2012. This $400 million bond issuance refinanced
other First Mortgage Bonds. In connection with the bond issuance, ComEd settled
forward startingas an increase to interest rate swaps in the aggregate notional amount of $375
million, resulting in a $9 million pre-tax loss recorded in other comprehensive
income, which is being amortized over the expected remaining life of the related
debt.expense.
During the ninethree months ended September 30, 2002,March 31, 2003, ComEd recorded prepayment
premiums of $24$9 million and net unamortized premiums, discounts and debt issuance
expenses of $3$23 million, associated with the early retirement of debt in 20022003
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.
PECO
On September 23, 2002,During the three months ended March 31, 2003, PECO issued $225$250 million
of 4.75% First and
Refunding Mortgage Bonds, due October 1, 2012. This bond issuance repaid
commercial paper that was used to pay at maturity $222 million of First and
Refunding Mortgage Bonds with a weighted average interest rate of 7.30%. In
41
connection with the issuance of the First and Refunding Mortgage Bonds, PECO
settled forward starting interest rate swaps in the aggregate notional amount of
$200 million resulting in a $5 million pre-tax loss recorded in other
comprehensive income, which is being amortized over the expected remaining life
of the related debt.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 September 30, 2002,March 31, 2003, PECO had sold a $225 million interest
in accounts receivable, consisting of a $164$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 $61$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 September 30, 2002,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 Nine Months
Ended September 30, Ended September 30,
2002 2001 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
Purchased Power from AmerGen (1) $ 104 $ 26 $ 220 $ 48
Interest Income from AmerGen (2) 1 -- 2 --
Services Provided to AmerGen (3) 16 18 46 50
Services Provided to Sithe (4) -- -- 1 --
Services Provided by Sithe (5) 3 -- 5 --
- ---------------------------------------------------------------------------------------------------------------------
42
September 30, 2002 December 31, 2001
- ---------------------------------------------------------------------------------------------------------------------
Net Receivable from AmerGen (1,2,3) $ 42 $ 44
Net Payable to Sithe (4,5) 3 --
- ---------------------------------------------------------------------------------------------------------------------
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 has agreed to purchase from AmerGen all of the residual
energy from Clinton Nuclear Power Station (Clinton), 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. Currently, the residual output approximates 29% of the total output
of Clinton. In accordance with the terms of the AmerGen partnership
agreement, the 1999 PPA will be extended through the end of the AmerGen
partnership agreement.
(2) In February 2002, Generation entered into an agreement to loan AmerGen up
to $75 million at an interest rate equal to the 1-month London Interbank
Offering Rate plus 2.25%. In July 2002, the limit of the loan agreement
was increased to $100 million and the maturity date was extended to July
1, 2003. As of September 30 2002, the outstanding principal balance of
the loan was $42 million.
(3) 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 on 90 days notice.
Generation is compensated for these services in an amount agreed to in
the work order, which is not less than the higher of its fully allocated
cost for performing each service or the market price for such service.
(4) Under a service agreement dated December 18, 2000, Generation provides
certain engineering and environmental services for fossil fuels
facilities owned by Sithe and for certain developmental projects.
Generation is compensated for these services in the amount agreed to in
the work order, but not less than the higher of fully allocated costs for
performing such services or the market price.
(5) Under a service agreement dated December 18, 2000, Sithe provides
Generation certain fuel and project development services. Sithe is
compensated for these services in the amount agreed to in the work order,
but not less than the higher of fully allocated costs for performing such
services or the market price.
Generation's additional related-party transactions are discussed in the
"Generation" section of this note.
4349
ComEd
ComEd's financial statements reflect related-party transactions as
reflected in the tables below.
Three Months Nine Months
Ended September 30, Ended September 30,
2002 2001 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
Operating Revenues from Affiliates
Generation (1) $ 22 $ 9 $ 41 $ 30
Enterprises (1) 4 5 8 39
Purchased Power from Affiliate
PPA with Generation (2) 967 948 2,046 2,141
O&M from Affiliates
BSC (3) 29 32 94 90
Exelon Services (4) 3 4 9 16
InfraSource (7) 1 -- 1 --
Interest Income from Affiliates
UII (5) 8 14 23 51
PECO (6) -- -- -- 8
Generation (8) -- 9 -- 9
Other -- 1 -- 2
Interest Expense from Affiliate
Generation (12) -- 10 -- 10
Capitalized costs
BSC (3) 3 1 6 6
InfraSource (7) 3 3 16 21
Cash Dividends Paid to Parent 118 105 353 253
- ---------------------------------------------------------------------------------------------------------------------
44
September 30,2002 December 31, 2001
- ---------------------------------------------------------------------------------------------------------------------
Receivables from Affiliates
UII (5) $ 8 $ --
BSC (3,8) -- 6
Notes Receivable from Affiliates
UII (5) 1,284 1,297
Other 16 17
Payables to Affiliates
Generation Decommissioning (9) 59 59
Generation (1,2,8) 544 136
BSC (3,8) 12 --
Exelon Corporate (11) -- 13
Other -- 10
Deferred Credits and Other Liabilities
Generation Decommissioning obligation (9) 244 291
Other 7 6
Shareholders' Equity - Receivable from Parent (10) 845 937
- ---------------------------------------------------------------------------------------------------------------------
(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 of Combined Notes to Consolidated Financial Statements 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 resources,
financial and information technology 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 has a note and interest receivable from Unicom Investments Inc.
(UII) relating to the December 1999 fossil plant sale. (6) At December
31, 2000, ComEd had a $400 million receivable from PECO, which was repaid
in the second quarter of 2001. (7) ComEd receives substation and
transmission engineering and construction services under contracts with
InfraSource. A portion
of such services is capitalized.
(8) In order to benefit from economies of scale, ComEd processes certain
invoice payments on behalf of Generation and BSC. During 2001, ComEd
earned interest from Generation relating to these invoice payments.
(9) ComEd had a short-term and long-term payable to Generation, primarily
representing ComEd's legal requirements to remit collections of nuclear
decommissioning costs from customers to Generation.
(10) ComEd has a non-interest bearing receivable from Exelon related to the
2001 corporate restructuring. The receivable is expected to be settled
over the yearsThree 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.
(11) ComEd pays Exelon for a variety of corporate expenses including
allocations under a tax sharing agreement and stock options.
(12) In consideration for the net assets transferred as part of the corporate
restructuring effective January 1, 2001, ComEd had a note payable to
affiliates of $463 million. This note payable was repaid during 2001.
45
PECO
PECO's financial statements reflect a number of related-party
transactions as reflected in the table below.
Three Months Nine Months
Ended September 30, Ended September 30,March 31,
----------------------------
2003 2002
2001 2002 2001
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Operating Revenues from Affiliate
Operating Revenues from Affiliate
Generation (1) $ 3 $ 3
$ 9 $ 9
Purchased Power from Affiliate
Generation (2) 441 363 1,090 872
O&M357 303
Operations & Maintenance from Affiliates
BSC (3) 10 15 36 4717
Enterprises (4) 5 7 21 14
Interest Expense from Affiliates
ComEd (5) -- -- --2 8
Interest Income from Affiliates
Generation (7) -- 5 --Capitalized Costs
BSC (3) 3 2
Enterprises (4) 6
Other -- 4 -- 4
Cash Dividends Paid to Parent 89 85
69 255 169
- ---------------------------------------------------------------------------------------------------------------------
September 30, 2002---------------------------------------------------------------------------------------------
March 31, 2003 December 31, 20012002
- ---------------------------------------------------------------------------------------------------------------------
Receivables from Affiliates
BSC (3) $ 17 $ --
Other -- 1---------------------------------------------------------------------------------------------
Payables to Affiliates (current)
Generation (2) 122 117$ 116 $ 124
BSC (3) -- 6127 26
Enterprises (4) 8 9
Deferred Credits and2 19
Other Liabilities
BSC1 1
Payable to Affiliate (noncurrent)
Generation (5) 39 -- 44
Capitalized Costs
Enterprises (4) 16 29
Shareholders' Equity - Receivable from Parent (6) 1,788 1,8781,728 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 of Combined Notes to Consolidated Financial Statements 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 resources, financial and information technology services.
Such services are provided at cost, including applicable overhead.
(4) PECO receives services from Enterprises for construction, which are
capitalized, and the deployment of automated meter reading technology,
which is expensed.
(5) At December 31, 2000, PECO had a $400 million payable to ComEd, which was
repaid in the second quarter of 2001. The average annual interest rate on
this payable for the period outstanding was 6.5%.
(6) PECO has a non-interest bearing receivable from Exelon related to the
2001 corporate restructuring. The receivable is expected to be settled
over the years 2001 through 2010.
(7) PECO received interest income from Generation in 2001 related to a loan.
---------------------------------------------------------------------------------------------
46(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 footnote,note, Generation's financial statements reflect a
number of related-party transactions as reflected in the tables below.
Three Months Nine Months
Ended September 30, Ended September 30,March 31,
----------------------------
2003 2002
2001 2002 2001
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Operating Revenues from Affiliates
Operating Revenues from Affiliates
PPA with ComEd (1) $ 946572 $ 945 $ 2,021 $ 2,133
PPA with532
PECO (1) 441 363 1,090 872
PPA with357 303
Exelon Energy (2) 73 93 190 210
Decommissioning with ComEd 3 3 8 864 57
Purchased Power from Affiliates
ComEd (3) --(4) 7 13 20
PECO(3)6
PECO (4) -- 2
1 4
Exelon Energy (3)(4) 6 50 12 61
O&M2
Operations & Maintenance from Affiliates
ComEd (3)(4) 4 2 11 103
PECO (3)(4) 3 1
8 5
BSC (3) 33 39 117 112(6) 35 53
Interest Expense from Affiliates- Affiliate
Exelon (5,6)(3) 1 --
3 23
ComEd (8) -- 9 -- 9
PECO (9) -- 5 -- 6
Interest Income from Affiliate
ComEd (10) -- 10 -- 10
- ---------------------------------------------------------------------------------------------------------------------
September 30, 2002-------------------------------------------------------------------------------------------
March 31, 2003 December 31, 20012002
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Receivables from Affiliates (current)
ComEd (1,3,8)(1) $ 544154 $ 136339
ComEd Decommissioning Receivable (7) 29 59
PECO (1) 122 117116 124
BSC (6) -- 14
Exelon Energy (2) 18 19
17
Note Receivable from Affiliate
ComEd (7) 59 59
Long-term Notes ReceivableReceivables from Affiliates (noncurrent)
ComEd Decommissioning Receivable (7) 244 291-- 218
PECO (5) 39 --
Other 2 2
Payables to Affiliates (current)
Exelon (3) 1 3
BSC (6) 26 --
Accounts Payable to Affiliate (noncurrent)
ComEd Decommissioning (5) 920 --
Notes Payable to Affiliate
Exelon (6) 14 23
BSC (4) 19 11
Note Payable-Exelon (5) 348 --(3) 323 329
- ---------------------------------------------------------------------------------------------------------------------
(1) Effective January 1, 2001, Generation entered into PPAs with ComEd and
PECO. See Note 8 of Combined Notes to Consolidated Financial Statements
for further information on the PPAs.
(2) Generation sells power to Exelon Energy.
(3) Generation purchases power from AmerGen under PPAs as discussed in the
Exelon and Generation section of this note. Additionally, 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.
(4) Generation receives a variety of corporate support services from BSC,
including legal, human resources, financial and information technology
services. Such services are provided at cost, including applicable
overhead.
(5) Generation had a $348 million payable to Exelon at September 30, 2002,
which includes $331 million related to the acquisition of two generating
plants in April of 2002.
(6) In relation to the December 18, 2001 acquisition of 49.9% of Sithe
common stock, Generation had a $700 million payable to Exelon, which was
repaid in the second quarter of 2001.
(7) Generation had a short-term and 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.
(8) In order to facilitate payment processing, ComEd processes certain
invoice payments on behalf of Generation.
(9) Generation paid interest to PECO in 2001 related to a loan.
(10) In consideration for the net assets transferred as a part-------------------------------------------------------------------------------------------
(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
corporate restructuring effective January 1, 2001, Generation had a note
receivable from ComEd. This note was repaid in 2001.
13. NEW ACCOUNTING PRONOUNCEMENTS (Exelon, ComEd, PECO and Generation)
In June 2001, the FASB issued SFAS No. 143, "Asset Retirement
Obligations" (SFAS No. 143). In July 2002, the FASB issued SFAS No. 146,
"Accounting for Costs Associated with Exit or Disposal Activities" (SFAS No.
146).
SFAS No. 143 provides accounting requirements for retirement
obligations associated with tangible long-lived assets. Exelon expects to adopt
SFAS No. 143 on January 1, 2003. Retirement obligations associated with
long-lived assets included within the scope of SFAS No. 143 are those for which
there is a legal obligation to settle under existing or enacted law, statute,
written or oral contract or by legal construction under the doctrine of
promissory estoppel. Adoption of SFAS No. 143 will change the accounting for the
decommissioning of Generation's nuclear generating plants as well as certain
other long-lived assets.
48
As it relates to nuclear decommissioning, the effect of this cumulative
adjustment will be to change the decommissioning liability to reflect the fair
value of the decommissioning obligation at the balance sheet date. Additionally,
the standard will require the accrual of an asset related to the decommissioning
obligation, which will be amortized over the remaining lives of the plants. The
net difference between the asset recognized and the liability recorded upon adoption of SFAS No. 143 will be charged to earnings143. See Note 2 - New
Accounting Principles and recognized as a
cumulative effect of a change in accounting principle, net of expected
regulatory recovery. The decommissioning liability to be recorded represents an
obligationAccounting Changes for the future decommissioning of the plants and, as a result,
accretion expense will be accrued on this liability until such time as the
obligation is satisfied.
Currently, Generation records the obligation for decommissioning
ratably over the lives of the plants. Exelon, ComEd, PECO and Generation are in
the process of evaluating the impact of adopting SFAS 143 on their financial
condition. Based on the current information and assumptions, Exelon estimates
that the non-cash impact on 2003 earnings per share (EPS) to be up to a negative
ten cents. However, if economic conditions change the assumptions, the EPS
impact could be more or less than ten cents per share. Additionally, the
adoption of the standard is expected to result in a large non-cash one-time
cumulative effect of a change in accounting principle gain of at least $1.5
billion, after tax. Like the EPS impact, the one-time impact could change with a
change in the assumptions or economic conditions. The final determination is in
part a function of the Treasury bond rate at the timefurther discussion of the
adoption of the
standard. Additionally, although over the life of the plant the charges to
earnings for the depreciation of the asset and the interest on the liability
will be equal to the amounts that would have been recognized as decommissioning
expense under the current accounting, the timing of those charges will change
and in the near-term period subsequent to adoption, the depreciation of the
asset and the interest on the liability is expected to result in an increase in
expense.
SFAS No. 146 requires that143.
(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 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.
14. CHANGE IN ACCOUNTING ESTIMATE2001 corporate restructuring.
13. SUPPLEMENTAL FINANCIAL INFORMATION (Exelon, ComEd and Generation) Generation
EffectivePECO)
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 1, 2001, Generation changed7, 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 accounting estimates
related to the depreciation and decommissioningFirst Mortgage
Bonds, at a redemption price of certain generating stations.
The estimated service lives were extended by 20 years for three nuclear
stations, by periods of up to 20 years for certain fossil stations and by 50
years for a pumped storage station. Effective July 1, 2001, the estimated
service lives were extended by 20 years for the remainder of Exelon's operating
nuclear stations. These changes were based on engineering and economic
feasibility studies performed by Generation considering, among other things,
future capital and maintenance expenditures at these plants. The service life
extension is subject to Nuclear Regulatory Commission (NRC) approval of an
extension of existing NRC operating licenses, which are generally 40 years. The
estimated annualized reduction in expense from the change is $132 million ($79
million, net of income taxes). As a result103.664% of the change, net income for the
three months and nine months ended September 30, 2002 increased approximately
49
$37 million ($22 million, netprincipal amount, plus accrued
interest. The bonds, which carried an interest rate of income taxes) and approximately $96 million
($58 million, net of income taxes)8%, respectively.
ComEd
Effectivewere refinanced with
long-term debt issued on April 1, 2002, ComEd changed its accounting estimate related
to the allowance for uncollectible accounts. This change was based on an
independently prepared evaluation of the risk profile of ComEd's customer
accounts receivable. As a result of the new evaluation, the allowance for
uncollectible accounts reserve was reduced by $11 million in the second quarter
of 2002.
Effective July 1, 2002, ComEd has lowered its depreciation rates based
on a new depreciation study reflecting its significant construction program in
recent years, changes in and development of new technologies, and changes in
estimated plant service lives since the last depreciation study. The annualized
reduction in depreciation expense, based on December 31, 2001 plant balances, is
estimated to be approximately $100 million ($60 million, net of income taxes).
As a result of the change, net income for the three months and nine months ended
September 30, 2002 increased approximately $24 million ($14 million, net of
income taxes).
15. SUBSEQUENT EVENTS
ComEd7, 2003.
On October 15, 2002, ComEd paid at maturity $100April 28, 2003, PECO issued $450 million of 9.17%
medium-term notes due October 15, 2002.
PECO
On October 9, 2002, PECO exchanged $250 million of 5.95%3.50% First and
Refunding Mortgage Bonds due Novemberon May 1, 2011, for $250 million of 5.95% First
and Refunding Mortgage Bonds, due November 1, 2011, which are registered under
the Securities Act.2008. The exchange bonds are identical to the outstanding bonds
except for the elimination of certain transfer restrictions and registration
rights pertaining to the outstanding bonds. PECO did not receive any cash proceeds from issuancethe sale of the
exchange bonds.
50bonds 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, consistingwhose businesses include the regulated sale of the retail electricity
and distribution and transmission businesses ofservices by Commonwealth Edison Company
(ComEd) in northern Illinois and PECO Energy Company (PECO) in southeastern
Pennsylvania and the sale of natural gas and distribution business ofservices 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 communications, energy
services and retail services industries.industries).
See Note 6 of the Condensed Combined Notes to Consolidated Financial
Statements for further segment information.
Generation early adopted the provision of Emerging Issues Task Force
(EITF) Issue 02-3 "Accounting for Contracts Involved in Energy Trading and Risk
Management Activities" (EITF 02-3) issued by the Financial Accounting Standards
Board (FASB) EITF in June 2002 that requires revenues and energy costs related
to energy trading contracts to be presented on a net basis in the income
statement. For comparative purposes, energy costs related to energy trading have
been reclassified in prior periods to revenue to conform to the net basis of
presentation required by EITF 02-3.
RESULTS OF OPERATIONS
Three Months Ended September 30, 2002March 31, 2003 Compared To Three Months Ended September
30, 2001March 31, 2002
Net Income and Earnings Per Share
NetExelon's net income increased $175 million, or 47%, for the three months ended September 30,March 31, 2003 increased
$353 million, compared to the same period in 2002. Diluted earnings per common
share on the same basis increased $0.54$1.09 per share,
or 47%. The increaseshare. Net income for the three
months ended March 31, 2003 reflects $112 million of income for the cumulative
effect of a change in net income reflects higher earnings in Energy Delivery,
51
primarily related to an increase in retail sales due to warmer summer weather,
the discontinuationaccounting principle as a result of goodwill amortization at Energy Delivery and Enterprises
required by the adoption of
FASBFinancial 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) and
certain other factors affecting net income, which are discussed in the remainder. See Note 2 of the resultsCondensed Combined Notes to Consolidated
Financial Statements for further information regarding the adoption of operations section.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
analysis below presents thecomparisons presented under this heading are comparisons of operating results
for each of its business segmentsand other statistical information for the three months ended September 30, 2002 comparedMarch 31, 2003 to
operating results and other statistical information for the three months ended
September 30, 2001.same period in 2002.
These results reflect intercompany transactions, which are eliminated in our
consolidated financial statements.
Corporate provides itsthe business segments a variety of support services
including legal, human resources, financial, and 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.
Net Income (Loss) Before Cumulative Effect of Changes in Accounting Principles by
Business Segment
Three Months Ended September 30,
--------------------------------March 31,
---------------------------
2003 2002 2001 Variance % Change
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Energy Delivery $ 370325 $ 280215 $ 90 32.1%110 51.2%
Generation 163 140 23 16.4%(52) 66 (118) (178.8%)
Enterprises 15 (33) 48 (145.5%(17) (28) 11 (39.3%)
Corporate 3 (11) 14 (127.3%(7) (15) 8 (53.3%)
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total $ 551249 $ 376238 $ 175 46.5%
==================================================================================================
52
Results of Operations - Energy Delivery11 4.6%
=================================================================================================
Net Income (Loss) by Business Segment
Three Months Ended September 30,
--------------------------------March 31,
---------------------------
2003 2002 2001 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 REVENUESOperating Revenues $ 3,162 $2,9702,642 $ 192 6.5%
OPERATING EXPENSES2,335 $ 307 13.1%
Revenue, net of Purchased Power 1,485 1,374 111 8.1%& Fuel 40 51 (11) (21.6%)Expense 1,451 1,311 140 10.7%
Operating Income 694 559 135 24.2%
Income Before Income Taxes and Maintenance 407 421 (14) (3.3%)
Depreciation and Amortization 256 293 (37) (12.6%)
Taxes Other ThanCumulative Effect of a
Change in Accounting Principle 517 341 176 51.6%
Net Income 162 133 29 21.8%Before Cumulative Effect of a Change in
Accounting Principle 325 215 110 51.2%
Net Income 330 215 115 53.5%
- -------------------------------------------------------------------------------------------------------
Total Operating Expense 2,350 2,272 78 3.4%
- -------------------------------------------------------------------------------------------------------
OPERATING INCOME 812 698 114 16.3%
- -------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (215) (253) 38 (15.0%)
Distributions on Preferred Securities of Subsidiaries (11) (11) -- --
Other, net 5 46 (41) (89.1%)
- -------------------------------------------------------------------------------------------------------
Total Other Income and Deductions (221) (218) (3) 1.4%
- -------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 591 480 111 23.1%
INCOME TAXES 221 200 21 10.5%
- -------------------------------------------------------------------------------------------------------
NET INCOME $ 370 $ 280 $ 90 32.1%
=======================================================================================================-------------------------------------------------------------------------------------------------------------------
The changes in Energy Delivery's gross margin (revenuerevenue, net of purchased power and
fuel) increased $92 million, $81 million of which was attributable to warmer
summer weather infuel expense, for the third quarter of 2002 asthree months ended March 31, 2003 compared to the third quartersame
period in 2002, included the following:
o changes in customer rates resulting in an $82 million increase,
o increases in weather normalized volumes of 2001,$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
increased retail electric volume.
Lower operating and maintenance expense reflects operating productivity
improvements and lower storm restoration costs,non-residential customers can purchase power from ComEd at a market-based
rate, partially offset by costs
associatedcustomers returning to PECO as their energy
supplier,
o pricing changes related to ComEd's PPA with the deployment of automated meter reading technology and
increased corporate allocations,Generation resulting in a $17
million decrease,
o increase of $16 million in purchases under the reserve for
manufactured gas plant (MGP) investigation and remediation.
Energy Delivery's depreciation and amortization expense decreased by
$37 million reflecting $32 million for the discontinuation of goodwill
amortization dueComEd PPA with Generation
related to decommissioning collections associated with the adoption of SFAS
No. 142143 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 January 1, 2002 and aan
agreement described in Note 4 - Regulatory Issues,
o reduction in depreciation expense of $24 million decrease due to the impact of lower
depreciation rates at ComEd effective July 1, 2002,
partially offset by $6o reduction of amortization expense of $16 million for nuclear
decommissioning of higher regulatory asset amortization and
higherretired 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 relatedin 2003 of $10 million due to higher plant
in service balances.
ComEd completed a depreciation studybalances,
57
o lower corporate allocations and implemented lower depreciation
rates effective July 1, 2002.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 new depreciation rates reflect ComEd's
significant construction program in recent years, changes in income before income taxes and developmentcumulative effect of new technologies, and changesa
change in estimated plant service lives sinceaccounting principle for the last
depreciation study. The annual reductionthree months ended March 31, 2003
compared to the same period in depreciation expense is estimated to
be approximately $100 million based on December 31, 2001 plant balances.
Lower2002, included the following:
o a decrease in interest expense reflects a reduction inof $25 million primarily attributable to
less outstanding debt outstanding and refinancing of existing debt at lower
interest rates, due to debt refinancing. The reductionand
o the reversal in other, net,
primarily reflects lower intercompany interest income reflecting lower interest
53
rates from Generation and from Unicom Investment, Inc. and2003 of a $12 million reserve for a potential plant
disallowance fromas the result of an audit performedagreement described in conjunction with
ComEd's delivery services rate case.Note 4 -
Regulatory Issues.
Energy Delivery's effective income tax rate was 37.4%37.1% for the three
months ended September 30, 2002,March 31, 2003, compared to 41.7%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 September 30, 2001. The decrease inMarch 31, 2003. See Note 2 of the effective tax rate was primarily
attributableCondensed Combined Notes to
the discontinuationConsolidated Financial Statements for further discussion of goodwill amortization as of January 1,
2002, which was not deductible for income tax purposes, and a reduction in state
income taxes.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 September 30,
--------------------------------March 31,
---------------------------
Retail Deliveries - (in gigawatthours (GWh)(GWhs))(1) 2003 2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Bundled Deliveries (1)(2)
Residential 12,543 10,573 1,970 18.6%10,001 8,465 1,536 18.1%
Small Commercial & Industrial 8,095 8,298 (203) (2.4%)7,407 7,207 200 2.8%
Large Commercial & Industrial 6,079 6,341 (262) (4.1%4,966 5,307 (341) (6.4%)
Public Authorities & Electric Railroads 1,836 2,299 (463) (20.1%1,669 1,994 (325) (16.3%)
- -------------------------------------------------------------------------------------------------------
28,553 27,511 1,042 3.8%-----------------------------------------------------------------------------------------
Total Bundled Deliveries 24,043 22,973 1,070 4.7%
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Unbundled Deliveries (2)(3)
Alternative Energy Suppliers
Residential 371 990 (619) (62.5%264 792 (528) (66.7%)
Small Commercial & Industrial 1,794 998 796 79.8%1,550 1,100 450 40.9%
Large Commercial & Industrial 2,428 1,796 632 35.2%2,042 1,489 553 37.1%
Public Authorities & Electric Railroads 299 92 207 n.m.282 138 144 104.3%
- -------------------------------------------------------------------------------------------------------
4,892 3,876 1,016 26.2%-----------------------------------------------------------------------------------------
4,138 3,519 619 17.6%
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
PPO (ComEd Only)
Small Commercial & Industrial 782 827 (45) (5.4%)794 763 31 4.1%
Large Commercial & Industrial 1,249 1,447 (198) (13.7%)1,433 1,311 122 9.3%
Public Authorities & Electric Railroads 345 150 195 130.0%537 242 295 121.9%
- -------------------------------------------------------------------------------------------------------
2,376 2,424 (48) (2.0%)-----------------------------------------------------------------------------------------
2,764 2,316 448 19.3%
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Unbundled Deliveries 7,268 6,300 968 15.4%6,902 5,835 1,067 18.3%
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Retail Deliveries 35,821 33,811 2,010 5.9%
=======================================================================================================
(1) Bundled service reflects deliveries to customers taking electric service
under tariffed rates, which include the cost of energy and the delivery
cost of the transmission and the distribution of the energy. PECO's
tariffed rates also include a Competitive Transition Charge (CTC).
(2) Unbundled service reflects customers electing to receive electric
generation service from an alternative energy supplier or ComEd's Power
Purchase Option (PPO).
n.m. - not meaningful
30,945 28,808 2,137 7.4%
=========================================================================================
54(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 September 30,
--------------------------------March 31,
----------------------------
Electric Revenue 2003 2002 2001 Variance % Change
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Bundled Revenues (1)
Residential $ 1,318905 $ 1,120761 $ 198 17.7%144 18.9%
Small Commercial & Industrial 757 767 (10) (1.3%)591 580 11 1.9%
Large Commercial & Industrial 402 408340 346 (6) (1.5%(1.7%)
Public Authorities & Electric Railroads 125 138 (13) (9.4%106 110 (4) (3.6%)
- -------------------------------------------------------------------------------------------------------
2,602 2,433 169 7.0%-----------------------------------------------------------------------------------------------------
Total Bundled Revenues 1,942 1,797 145 8.1%
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Unbundled Revenues (2)
Alternative Energy Suppliers
- ----------------------------
Residential 32 81 (49) (60.5%17 54 (37) (68.5%)
Small Commercial & Industrial 60 16 4451 17 34 n.m.
Large Commercial & Industrial 67 19 4854 13 41 n.m.
Public Authorities & Electric Railroads 10 1 9 2 7 n.m.
- -------------------------------------------------------------------------------------------------------
169 117 52 44.4%-----------------------------------------------------------------------------------------------------
131 86 45 52.3%
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
PPO (ComEd Only)
- ----------------
Small Commercial & Industrial 57 77 (20) (25.9%)49 43 6 14.0%
Large Commercial & Industrial 74 120 (46) (38.3%)72 64 8 12.5%
Public Authorities & Electric Railroads 1928 13 6 46.2%15 115.4%
- -------------------------------------------------------------------------------------------------------
150 210 (60) (28.6%)-----------------------------------------------------------------------------------------------------
149 120 29 24.2%
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Unbundled Revenues 319 327 (8) (2.4%)280 206 74 35.9%
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Electric Retail Revenues 2,921 2,760 161 5.8%2,222 2,003 219 10.9%
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Wholesale and Miscellaneous Revenue (3) 174 134 40 29.9%132 123 9 7.3%
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Electric Revenue $ 3,0952,354 $ 2,8942,126 $ 201 6.9%
=======================================================================================================
(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. Revenues from customers choosing an alternative energy supplier
include 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 sales to alternative energy
suppliers, transmission revenue, sales to municipalities and other
wholesale energy sales.
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 changesdifferences in three months ended March 31, 2003 electric retail
revenues for the three months ended
September 30, 2002, as compared to the same period in 2001 are2002 were attributable to the
following:
Variance
- -------------------------------------------------------------------------------------------------
Weather $ 146
Rate Changes (29)
Customer Choice (3)
Other Effects 47
- -------------------------------------------------------------------------------------------------
Electric Retail Revenue $ 161
=================================================================================================
Variance
- --------------------------------------------------------------------
Weather $ 101
Rate Changes 82
Volume 50
Customer Choice (20)
Other Effects 6
- --------------------------------------------------------------------
Electric Retail Revenue $ 219
====================================================================
o Weather. The demand for electricity services is impacted by weather conditions. Very
warm weather in summer months and very cold weather in other months is
referred to as "favorable weather conditions," because these weather
conditions result in increased sales of electricity.
60
Conversely, mild weather reduces demand. 55
The weather impact for the three
months ended March 31, 2003 was favorable compared to the prior yearsame period in
2002 as a result of warmer summercolder winter weather during the third quarter of 2002. Cooling
degree daysin 2003. Heating degree-days in
the ComEd and PECO service territories were 26%17% higher and 20%33% higher,
respectively, in the third quarter of 20022003 as compared to the third
quarter of 2001.2002.
o Rate Changes. The decreaseincrease in revenues attributable to rate changes
reflects the 5%collection of additional CTC's in 2003 by ComEd residential rate reduction, effective October 1,
2001, required by the Illinois restructuring legislation partially offset
by $13of $105
million resulting fromdue to an increase in PECO's gross receipts tax
rate. The increasethe number of customers choosing an
alternative energy supplier and changes in PECO's gross receipts tax rate is expectedthe 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 increase PECO's annual revenuean increased number of customers and tax obligation by approximately $50
million in 2002.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 otheralternative suppliers. This choice generally doesaffects revenues from the sale of
energy but not impact kWh
deliveries, but affects revenue collected 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 related to energy
suppliedwas provided by Energy Delivery. On May 1, 2002, all ComEd residential
customers became eligible to choose their supplier of electricity; however,
as of September 30, 2002, no alternative electric supplier has sought
approval from the Illinois Commerce Commission (ICC) and nosuppliers. The
decrease in electric utilities have chosen to enter the ComEd residential market for the supply
of electricity.
The customer choice effect is attributable toretail revenues includes a decrease in revenues of $43$39
million from customers in Illinois electing to purchase energy from an
Alternative Retail Electric Supplieralternative retail electric supplier (ARES) or theComEd's PPO, under which customers can purchase power from ComEd at a market-based rate
(ComEd and PECO continue to collect delivery charges from these customers)partially
offset by increasedan increase in revenues of $40$19 million from customers in
Pennsylvania selectingwho selected or returningreturned 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.
o Other Effects. Exclusivesupplier, the number of weather effects, higher delivery volume
affected Energy Delivery's revenue comparedcustomers
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 same 2001 period.
The increasePUC a MST plan to meet the 50% threshold requirement for
its commercial customers, which was approved by the PUC in wholesale revenueFebruary 2003.
As of March 31, 2003, an auction had been completed for the three months ended September
30, 2002 as comparedcommercial
customers and the customer enrollment phase is currently in process. The
randomly selected customers will be transferred to the three months ended September 30, 2001 was due
primarilyalternative electric
generation suppliers in May 2003, if they do not choose the option to reimbursementnot
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 ComEd from Generation400,000
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 $12 million for
third-party energy reconciliations.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 arewere as
follows:
Three Months Ended September 30,
--------------------------------March 31,
----------------------------
2003 2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Deliveries in million cubic feet (mmcf) 11,347 10,525 82239,626 31,357 8,269 26.4%
Revenue $67 $ 75288 $ (8)209 $ 79 37.8%
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
56
The changes in gas revenue for the quarterthree months ended September 30, 2002,March 31, 2003 as
compared to the same 2001 period arein 2002, were as follows:
(in millions) Variance
- -------------------------------------------------------------------------------------------------
Rate Changes $ (4)
Weather (3)
Volume (1)
- -------------------------------------------------------------------------------------------------
Gas Revenue $ (8)
=================================================================================================
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 unfavorablefavorable variance in rates is attributable to an
adjustment ofa 15%
increase in the purchased gas cost recoveryadjustment by the PUC effective in
December 2001.March 1,
2003. The average rate per million cubic feet for the quarterthree months ended
September 30, 2002March 31, 2003 was 17% lower9% higher than the rate in the same 20012002 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.
o Weather. The demand for gas service is impacted by weather conditions. Very
cold weather in winter months is referred to as a "favorable weather
condition," because this weather condition results in increased sales of
gas. Conversely, mild weather reduces demand. Heating degree-days decreased
92% in the quarter ended September 30, 2002 compared to the same 2001
period.
o Volume. Exclusive of weather impact, delivery volume was consistent for the
quarter ended September 30, 2002 compared to the same 2001 period.
5762
Results of Operations - Generation
Business SegmentIn 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 September 30,
--------------------------------March 31,
----------------------------
2003 2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
OPERATING REVENUESOperating Revenues $ 2,213 $2,1911,879 $ 22 1.0%
OPERATING EXPENSES1,461 $ 418 28.6%
Revenue, net of Purchased Power 1,257 1,268 (11) (0.9%& 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%)
Fuel 273 242 31 12.8%
Operating and Maintenance 391 364 27 7.4%
Depreciation and Amortization 68 57 11 19.3%
Taxes Other Than Income 37 36 1 2.8%
- -------------------------------------------------------------------------------------------------------
Total Operating Expense 2,026 1,967 59 3.0%
- -------------------------------------------------------------------------------------------------------
OPERATING INCOME 187 224 (37) (16.5%(Loss) Before Cumulative Effect of Changes in
Accounting Principles (52) 66 (118) (178.8%)
Net Income 56 79 (23) (29.1%)
- -------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (23) (41) 18 (43.9%)
Equity in Earnings (Losses) of Unconsolidated Affiliates, net 87 60 27 45.0%
Other, net 14 (25) 39 156.0%
- -------------------------------------------------------------------------------------------------------
Total Other Income and Deductions 78 (6) 84 n.m.
- -------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 265 218 47 21.6%
INCOME TAXES 102 78 24 30.8%
- -------------------------------------------------------------------------------------------------------
NET INCOME $ 163 $ 140 $ 23 16.4%
=======================================================================================================------------------------------------------------------------------------------------------------------------------
Net incomeThe changes in Generation's revenue, net of purchased power and fuel
expense, for the three months ended September 30, 2002 was positively
impacted by increased revenue from affiliates, increased revenue from the
acquisition of two generating plants in April 2002, reduced interest expense,
increased equity in earnings of unconsolidated subsidiaries and lower losses on
nuclear decommissioning trust funds, partially offset by depressed wholesale
market prices for energy, increased depreciation expense, and increased
operating and maintenance expenses. Operating revenues, net of fuel and
purchased power, increased by $2 million reflecting a $59 million increase in
revenue from Generation's retail affiliates driven by a weather-driven increase
in sales volume to these affiliates partially offset by the impact of depressed
wholesale market prices for energy. Generation's revenues include $8 million due
to the net effect of the energy reconciliation of certain third-party sales in
ComEd's service territory and the impact of that energy reconciliation on
Generation's PPA with ComEd. Operating and maintenance expense increased by $27
million due to $10 million arising from an increased number of nuclear plant
refueling outage days, $3 million related to increased fossil plant outage work
and $7 million related to the two generating plants acquired in April 2002.
These increases were partially offset by other operating cost reductions
including cost reductions related to Exelon's Cost Management Initiative. The
increase in depreciation expense reflects additional depreciation expense on
routine capital additions, the acquisition of two generating plants acquired in
April 2002 and Southeast Chicago Energy Project, LLC's (Southeast Chicago)
peaking facility (Southeast Chicago Energy Project). The decrease in interest
expense is due to a lower interest rate on the spent nuclear fuel obligation and
lower affiliate interest expense. Equity in earnings of unconsolidated
affiliates increased primarily due to a Sithe mark-to-market adjustment,
partially offset by an impairment adjustment recorded at Sithe. Other, net
increased $39 million for the three months ended September 30, 2002 compared to
58
the same period in the prior year primarily due to lower losses on
decommissioning trust investments during 2002 asMarch 31, 2003 compared to the same period
in 2001. Additionally,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 September 30, 2002
includes a net trading portfolio loss of $12 million compared to a net $5
million gain for the three months ended September 30, 2001.
Generation Operating Statistics:
For the three months ended September 30, 2002 and 2001, Generation's
sales and the supply of these sales exclusive of the trading portfolio were as
follows:
Three Months Ended September 30,
--------------------------------
Sales (in GWhs) 2002 2001 % Change
- ---------------------------------------------------------------------------------------------------------------------
Energy Delivery 34,535 32,692 5.6%
Exelon Energy 1,461 2,038 (28.3%)
Market Sales 21,177 17,781 19.1%
- -------------------------------------------------------------------------------------------------------
Total Sales 57,173 52,511 8.9%
=======================================================================================================
Three Months Ended September 30,
--------------------------------
Supply of Sales (in GWhs) 2002 2001 % Change
- ---------------------------------------------------------------------------------------------------------------------
Nuclear Generation 29,817 28,456 4.8%
Purchases - non-trading portfolio 23,425 20,505 14.2%
Fossil and Hydro Generation 3,931 3,550 10.7%
- -------------------------------------------------------------------------------------------------------
Total Supply 57,173 52,511 8.9%
=======================================================================================================
Trading volume of 28,455 GWhs and 1,832 GWhs for the three months ended
September 30, 2002 and 2001, respectively, is not included in the table above.
Generation's average margin data for the three months ended September
30, 2002 and 2001 were as follows:
Three Months Ended September 30,
--------------------------------
($/MWh) 2002 2001 % Change
- ---------------------------------------------------------------------------------------------------------------------
Average Realized Revenue
Energy Delivery $ 40.18 $ 40.01 0.4%
Exelon Energy 49.72 46.67 6.5%
Market Sales 35.50 42.55 (16.6%)
Total Sales - excluding the trading portfolio 38.69 41.13 (5.9%)
Average Supply Cost (1) - excluding trading portfolio $ 26.66 $ 28.70 (7.1%)
Average Margin - excluding the trading portfolio $ 12.04 $ 12.43 (3.1%)
- ---------------------------------------------------------------------------------------------------------------------
(1) Average Supply costs represent purchased power and fuel costs.
Generation's nuclear fleet, including AmerGen, performed at a capacity
factor of 93.9% for the three months ended September 30, 2002 compared to 93.0%
for the same period in 2001. Generation's nuclear units' production costs,
including AmerGen, for the three months ended September 30, 2002 were $12.40 per
MWh compared to $12.52 per MWh for the same period in 2001. Reduced unit
production costs reflect additional generation due to power uprates, headcount
reductions and Exelon's Cost Management Initiative. Generation's average
purchased power costs for wholesale operations were $53.75 per MWh for the three
59
months ended September 30, 2002, compared to $62.18 per MWh for the same period
in 2001. The decrease in purchased power costs was primarily due to depressed
wholesale power market prices.
Results of Operations - Enterprises Business Segment
Three Months Ended September 30,
--------------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 509 $ 529 $ (20) (3.8%)
OPERATING EXPENSES
Purchased Power 73 88 (15) (17.0%)
Fuel 60 63 (3) (4.8%)
Operating and Maintenance 349 361 (12) (3.3%)
Depreciation and Amortization 11 16 (5) (31.3%)
Taxes Other Than Income 1 1 -- --
- -------------------------------------------------------------------------------------------------------
Total Operating Expense 494 529 (35) (6.6%)
- -------------------------------------------------------------------------------------------------------
OPERATING INCOME 15 -- 15 n.m.
- -------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (3) (9) 6 (66.7%)
Equity in Earnings (Losses) of Unconsolidated Affiliates, net 8 (8) 16 (200.0%)
Other, net -- (34) 34 (100.0%)
- -------------------------------------------------------------------------------------------------------
Total Other Income and Deductions 5 (51) 56 (109.8%)
- -------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 20 (51) 71 (139.2%)
INCOME TAXES 5 (18) 23 (127.8%)
- -------------------------------------------------------------------------------------------------------
NET INCOME $ 15 $ (33) $ 48 (145.4%)
=======================================================================================================
Enterprises' net income increased $48 million for the three months
ended September 30, 2002March 31, 2003
compared to the same period in 2001. The increase2002, included the following:
o higher costs of $27 million for employee medical, pension and other
benefits in net income is primarily attributable2003, partially offset by a one-time executive severance charge
of $19 million in 2002,
o increased O&M costs of $19 million due to increased operating incomeasset 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 higherdue 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 $11$4 million, and
o increased interest expense of $2 million primarily due to the discontinuance of losses on AT&T Wireless PCS of Philadelphia, LLC
(AT&T Wireless) as a result of the sale of Enterprises' 49% interest in AT&T
Wirelessnote payable
to a subsidiary of AT&T Wireless Services, $10 million of equity in
earnings from a communications joint venture relating to its recovery of trade
receivables previously considered uncollectible and a $36 million loss in 2001
from a write-down of a communications investment.
Operating revenues decreased $20 million, or 3.8%,Sithe.
Generation's effective income tax rate was 28.8% for the three months
ended September 30, 2002,March 31, 2003 compared to 40.5% for the same period in 2001. The decrease in
operating revenues was primarily attributable to reduced retail energy sales of
$50 million from Exelon Energy, Inc. (Exelon Energy) due to exiting the retail
energy business in the Pennsylvania, New Jersey and Maryland area (PJM market).2002. This decrease was partially offset by higher electric revenues of $22 million
primarily resulting from higher electric prices in Illinois for Exelon Energy,
higher revenues of $4 million from Exelon Services, Inc. (Exelon Services) from
increased construction project revenues and higher revenues of $4 million from
InfraSource, Inc. (InfraSource) primarily from increased infrastructure and
construction services in the electric line of business.
60
Enterprises' operating and other expenses, net decreased $91 million
for the three months ended September 30, 2002 compared to the same period in
2001. The
decrease was primarily attributable to lower power costs of $34
million resulting from reduced operations of retail energy sales from Exelon
Energy exiting the PJM market, reduced costs at InfraSource of $10 million
relating to construction services in the electric line of business in addition
to overall reductions in administrative expenses, higher equity in earnings of
unconsolidated affiliates of $11 million as a resultimpact of the discontinuanceimpairment of
losses on AT&T Wireless as a result of the AT&T Wireless sale, $10 million of
equityGeneration's investment in earnings from a communications joint venture relating to its recovery
of trade receivables previously considered uncollectible, lower depreciationSithe and amortization of $5 million from the discontinuance of goodwill amortization,
lower interest expense of $6 million and a $36 million lossother tax benefits recorded in 2001 from a
write-down of a communications investment. These decreases were partially offset
by higher electric purchased power costs in Illinois of $19 million and
increased costs relating to construction projects at Exelon Services of $5
million.
The effective income tax rate was 25.0% for the three months ended
September 30, 2002, compared to 35.3% for the three months ended September 30,
2001. The decrease in the effective tax rate was primarily attributable to a $5
million reduction in estimated state income taxes recorded during the quarter
and the discontinuation of goodwill amortization as of January 1, 2002, that was
not deductible for income tax purposes.
Nine Months Ended September 30, 2002 Compared To Nine Months Ended September 30,
2001
Net Income and Earnings Per Share
Exelon's income before the cumulative2003.
Cumulative effect of changes in accounting principles increased $195 million, or 18%, forrecorded in the
ninethree months ended September
30, 2002. Diluted earnings per common share on the same basis increased $0.60
per share, or 18%. The increaseMarch 31, 2003 and 2002 included income of $108 million, net
of income taxes, recorded in income before the cumulative effect of
changes in accounting principles reflects higher earnings due2003 related to the sale of
AT&T Wireless, a 1.6% increase in retail sales reflecting warmer summer weather
partially offset by mild winter weather, the extension of the estimated service
lives of generating stations in 2001 and the discontinuation of goodwill
amortization required by the adoption of SFAS No. 142, partially offset by lower
wholesale energy prices, increased nuclear refueling outage costs, employee
severance costs143 and
certain other factors affectingincome of $13 million, net of income which are
discussedtaxes, recorded in the remainder of the results of operations section. Net income
included net pre-tax charges of $10 million for severance costs, primarily2002 related to executive severance.
Net income decreased $47 million, or 4%, for the nine months ended
September 30, 2002. Diluted earnings per common share decreased $0.15 per share,
or 4%. Net income for the nine months ended September 30, 2002 included a $230
million charge for the cumulative effect of changes in accounting principles,
reflecting goodwill impairment upon the
adoption of SFAS No. 142. Net income for
the nine months ended September 30, 2001 included $12 million of income for the
cumulative effect of adopting141, "Business Combinations" (SFAS No. 141) and SFAS No.
133, "Accounting for Derivative
Instruments and Hedging Activities" (SFAS No. 133).142. See Note 2 of the Condensed Combined Notes to Consolidated Financial
Statements for further information regarding the
adoptiondiscussion of SFAS No. 133.
61
The analysis below presents the operating results for each of Exelon's
business segments for the nine months ended September 30, 2002 compared to the
nine months ended September 30, 2001.
Income Before Cumulative Effect of Changes in Accounting Principles by Business Segment
Nine Months Ended September 30,
-------------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
Energy Delivery $ 908 $ 810 $ 98 12.1%
Generation 313 369 (56) (15.2%)
Enterprises 69 (63) 132 (209.5%)
Corporate (17) (38) 21 55.3%
- -------------------------------------------------------------------------------------------------------
Total $ 1,273 $ 1,078 $ 195 18.1%
=======================================================================================================
Results of Operations - Energy Delivery Business Segment
Nine Months Ended September 30,
-------------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 7,973 $7,903 $ 70 0.9%
OPERATING EXPENSES
Purchased Power 3,331 3,167 164 5.2%
Fuel 228 335 (107) (31.9%)
Operating and Maintenance 1,131 1,145 (14) (1.2%)
Depreciation and Amortization 745 828 (83) (10.0%)
Taxes Other Than Income 430 358 72 20.1%
- -------------------------------------------------------------------------------------------------------
Total Operating Expense 5,865 5,833 32 0.5%
- -------------------------------------------------------------------------------------------------------
OPERATING INCOME 2,108 2,070 38 1.8%
- -------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (654) (759) 105 (13.8%)
Distributions on Preferred Securities of Subsidiaries (34) (34) -- --
Other, net 35 117 (82) (70.1%)
- -------------------------------------------------------------------------------------------------------
Total Other Income and Deductions (653) (676) 23 (3.4%)
- -------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 1,455 1,394 61 4.4%
INCOME TAXES 547 584 (37) (6.3%)
- -------------------------------------------------------------------------------------------------------
NET INCOME $ 908 $ 810 $ 98 12.1%
=======================================================================================================
Energy Delivery's gross margin (revenue net of purchased power and
fuel) increased $13 million, $55 million of which was attributable primarily to
warmer summer weather, which increased retail electric and gas volumes,
partially offset by a warmer winter.
Lower operating and maintenance expense reflects operating productivity
improvements and lower storm restoration costs, a decrease in the provisions for
bad debt expense and a decrease in the provision for obsolete inventory,
partially offset by increased pension and postretirement benefit costs and
increased corporate allocations, including a portion of executive severance
62
charges, an increase in the provision for injuries and damages and an increase
in reserves for MGP investigation and remediation.
Energy Delivery's depreciation and amortization expense decreased by
$83 million reflecting $97 million from the discontinuation of goodwill
amortization due to the adoption of SFAS No. 142 as of January 1, 2002 and a $24
million decrease due to lower depreciation rates at ComEd effective July 1,
2002, partially offset by $14 million of higher regulatory asset amortization
and higher depreciation expense related to higher plant in service balances.
Lower interest expense reflects reductions in the amount of debt
outstanding as well as lower interest rates due to debt refinancing. The
reduction in other, net primarily reflects lower intercompany interest income
reflecting lower interest rates and a $12 million reserve for a potential plant
disallowance resulting from an audit performed in conjunction with ComEd's
delivery service rate case.
Energy Delivery's effective income tax rate was 37.6% for the nine
months ended September 30, 2002, compared to 41.9% for the nine months ended
September 30, 2001. The decrease in the effective tax rate was primarily
attributable to the discontinuation of goodwill amortization as of January 1,
2002, which was not deductible for income tax purposes, and a reduction in state
income taxes.
63
Energy Delivery Operating Statistics and Revenue Detail
Energy Delivery's electric sales statistics and revenue detail are as
follows:
Nine Months Ended September 30,
-------------------------------
Retail Deliveries - (in GWhs) 2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
Bundled Deliveries (1)
Residential 28,984 26,243 2,741 10.4%
Small Commercial & Industrial 22,782 22,289 493 2.2%
Large Commercial & Industrial 17,436 17,682 (246) (1.4%)
Public Authorities & Electric Railroads 5,715 6,574 (859) (13.1%)
- -------------------------------------------------------------------------------------------------------
74,917 72,788 2,129 2.9%
- -------------------------------------------------------------------------------------------------------
Unbundled Deliveries (2)
Alternative Energy Suppliers
Residential 1,720 2,365 (645) (27.3%)
Small Commercial & Industrial 4,075 3,521 554 15.7%
Large Commercial & Industrial 5,551 6,131 (580) (9.5%)
Public Authorities & Electric Railroads 618 235 383 163.0%
- -------------------------------------------------------------------------------------------------------
11,964 12,252 (288) (2.4%)
- -------------------------------------------------------------------------------------------------------
PPO (ComEd Only)
Small Commercial & Industrial 2,384 2,448 (64) (2.6%)
Large Commercial & Industrial 3,952 4,324 (372) (8.6%)
Public Authorities & Electric Railroads 861 734 127 17.3%
- -------------------------------------------------------------------------------------------------------
7,197 7,506 (309) (4.1%)
- -------------------------------------------------------------------------------------------------------
Total Unbundled Deliveries 19,161 19,758 (597) (3.0%)
- -------------------------------------------------------------------------------------------------------
Total Retail Deliveries 94,078 92,546 1,532 1.7%
=======================================================================================================
(1) Bundled service reflects deliveries to customers taking electric service
under tariffed rates, which include the cost of energy and the delivery
cost of the transmission and the distribution of the energy. PECO's
tariffed rates also include a CTC charge.
(2) Unbundled service reflects customers electing to receive electric
generation service from an alternative energy supplier or ComEd's PPO.
64
Nine Months Ended September 30,
-------------------------------
Electric Revenue 2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
Bundled Revenues (1)
Residential $ 2,880 $ 2,659 $ 221 8.3%
Small Commercial & Industrial 2,007 1,910 97 5.1%
Large Commercial & Industrial 1,152 1,095 57 5.2%
Public Authorities & Electric Railroads 356 388 (32) (8.3%)
- -------------------------------------------------------------------------------------------------------
6,395 6,052 343 5.7%
- -------------------------------------------------------------------------------------------------------
Unbundled Revenues (2)
Alternative Energy Suppliers
Residential 129 184 (55) (30.0%)
Small Commercial & Industrial 107 110 (3) (2.8%)
Large Commercial & Industrial 111 121 (10) (8.3%)
Public Authorities & Electric Railroads 18 4 14 n.m.
- -------------------------------------------------------------------------------------------------------
365 419 (54) (12.9%)
- -------------------------------------------------------------------------------------------------------
PPO (ComEd Only)
Small Commercial & Industrial 155 167 (12) (7.2%)
Large Commercial & Industrial 214 267 (53) (19.9%)
Public Authorities & Electric Railroads 48 44 4 9.1%
- -------------------------------------------------------------------------------------------------------
417 478 (61) (12.8%)
- -------------------------------------------------------------------------------------------------------
Total Unbundled Revenues 782 897 (115) (12.8%)
- -------------------------------------------------------------------------------------------------------
Total Electric Retail Revenues 7,177 6,949 228 3.3%
- -------------------------------------------------------------------------------------------------------
Wholesale and Miscellaneous Revenue (3) 438 472 (34) (7.2%)
- -------------------------------------------------------------------------------------------------------
Total Electric Revenue $ 7,615 $ 7,421 $ 194 2.6%
=======================================================================================================
(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 sales to alternative energy
suppliers, transmission revenue, sales to municipalities and other
wholesale energy sales.
The changes in electric retail revenues for the nine months ended
September 30, 2002, as compared to the same period in 2001 are attributable to
the following:
Variance
- -------------------------------------------------------------------------------------------------
Weather $ 115
Customer Choice 84
Rate Changes (54)
Other Effects 83
- -------------------------------------------------------------------------------------------------
Electric Retail Revenue $ 228
=================================================================================================
o Weather. The weather impact was favorable compared to the prior year as a
result of warmer summer weather in ComEd and PECO service territories
partially offset by warmer winter weather in the ComEd and PECO service
territories. Cooling degree days in the ComEd and PECO service territories
were 27% and 14% higher, respectively, in the nine months ended September
30, 2002 as compared to the same period in 2001. Heating degree days in the
65
ComEd and PECO service territories were 7% and 16% lower, respectively, in
the nine months ended September 30, 2002 as compared to the same period in
2001.
o Customer Choice. The increase in electric retail revenues due to customer
choice results from increased revenues of $205 million from customers in
Pennsylvania selecting or returning to PECO as their electric generation
supplier, partially offset by a decrease in revenues of $121 million from
customers in Illinois electing to purchase energy from an ARES or the PPO,
under which customers can purchase power from ComEd at a market-based rate.
ComEd and PECO continue to collect delivery charges from these customers.
o Rate Changes. The decrease in revenues attributable to rate changes
reflects the 5% ComEd residential rate reduction, effective October 1,
2001, required by the Illinois restructuring legislation and the timing of
a $60 million PECO rate reduction in effect for 2001 and 2002, offset by
$39 million due to an increase in PECO's gross receipts tax rate effective
January 1, 2002 and the expiration of a 6% reduction in PECO's rates during
the first quarter of 2001.
o Other Effects. For ComEd, other items impacting revenues were primarily a
strong housing construction market in Chicago which contributed to
residential and small commercial and industrial customer volume growth in
the early portion of the year, partially offset by the unfavorable impact
of a slower economy on large commercial and industrial customers. For PECO,
other items impacting revenues were $53 million from higher delivery
volume, exclusive of weather impacts, partially offset by an $11 million
settlement of CTCs by a large customer in the first quarter of 2001.
The reduction in wholesale revenue for the nine months ended September
30, 2002 as compared to the nine months ended September 30, 2001 was due
primarily to a decrease in off-system sales due to the expiration of wholesale
contracts that were offered by ComEd from June 2000 to May 2001 to support the
open access program in Illinois, and a 2001 reversal of reserve for revenue
refunds related to certain of ComEd's municipal customers as a result of a
favorable FERC ruling, partially offset by an increase of $12 million due
primarily to reimbursement from Generation for third-party energy
reconciliations.
Energy Delivery's gas sales statistics and revenue detail are as
follows:
Nine Months Ended September 30,
-------------------------------
2002 2001 Variance
- ---------------------------------------------------------------------------------------------------------------------
Deliveries in mmcf 56,990 58,536 (1,546)
Revenue $358 $482 $ (124)
- ---------------------------------------------------------------------------------------------------------------------
66
The changes in gas revenue for the nine months ended September 30,
2002, as compared to the same 2001 period, are as follows:
Variance
- -------------------------------------------------------------------------------------------------
Rate Changes $ (67)
Weather (33)
Volume (23)
Other (1)
- -------------------------------------------------------------------------------------------------
Gas Revenue $ (124)
=================================================================================================
o Rate Changes. The unfavorable variance in rates is attributable to an
adjustment of the purchased gas cost recovery by the PUC effective in
December 2001. The average rate per million cubic feet for the nine months
ended September 30, 2002 was 23% lower than the same 2001 period.
o Weather. The unfavorable weather impact is attributable to warmer winter
weather during the nine months ended September 30, 2002 as compared to the
same 2001 period. Heating degree-days decreased 16% in the nine months
ended September 30, 2002 compared to the same 2001 period.
o Volume. Exclusive of weather impacts, lower delivery volume reduced revenue
by $23 million in the nine months ended September 30, 2002 compared to the
same 2001 period. Total deliveries to customers decreased 3% in the nine
months ended September 30, 2002 compared to the same 2001 period, primarily
as a result of slower economic conditions in 2002 offset by increased
customer growth.
67
Results of Operations - Generation Business Segment
Nine Months Ended September 30,
-------------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 5,233 $5,403 $ (170) (3.1%)
OPERATING EXPENSES
Purchased Power 2,581 2,589 (8) (0.3)%
Fuel 706 691 15 2.2%
Operating and Maintenance 1,234 1,173 61 5.2%
Depreciation and Amortization 197 224 (27) (12.1%)
Taxes Other Than Income 126 121 5 4.1%
- -------------------------------------------------------------------------------------------------------
Total Operating Expense 4,844 4,798 46 1.0%
- -------------------------------------------------------------------------------------------------------
OPERATING INCOME 389 605 (216) (35.7%)
- -------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (51) (100) 49 (49.0%)
Equity in Earnings of Unconsolidated Affiliates, net 119 99 20 20.2%
Other, net 54 (7) 61 n.m.
- -------------------------------------------------------------------------------------------------------
Total Other Income and Deductions 122 (8) 130 n.m.
- -------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES AND CUMULATIVE
EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES 511 597 (86) (14.4%)
INCOME TAXES 198 228 (30) (13.2%)
- -------------------------------------------------------------------------------------------------------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN
ACCOUNTING PRINCIPLES 313 369 (56) (15.2%)
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING
PRINCIPLES 13 12 1 8.3%
- -------------------------------------------------------------------------------------------------------
NET INCOME $ 326 $ 381 $ (55) (14.4%)
=======================================================================================================
Net income for the nine months ended September 30, 2002 was adversely
impacted by a lower margin on wholesale energy sales due to depressed market
prices for energy, a reduced supply of low-cost nuclear generation, and
increased operating and maintenance expense, partially offset by an increase in
revenue from affiliates, increased revenue from the acquisition of two
generating plants in April 2002, increased interest income decreased
depreciation and interest expense and lower nuclear decommissioning trust fund
losses. Operating revenues, net of fuel and purchased power, decreased by $177
million reflecting a decrease in margin on market sales attributable to lower
margin from market sales, offset by weather related increases in sales to
affiliates and a decrease trading margins. Market sales margins were negatively
impacted by lower average market sales prices. The effect of the lower sales
prices were partially offset by lower average supply costs and increased market
sales volumes. The decrease in trading margins was principally attributed to
lower purchase power costs associated with lower wholesale market prices
realized and reduced transmission costs. Operating and maintenance expense
increased, primarily due to $65 million of costs incurred for the additional
refueling outages during the nine months ended September 30, 2002 as compared to
the same period in 2001, as well as additional allocated corporate costs
including executive severance. These additional expenses were partially offset
by other operating cost reductions, including $11 million related to headcount
reductions, a $10 million reduction in Generation's severance accrual and cost
68
reductions related to Exelon's Cost Management Initiative. The decline in
depreciation expense reflects extension of the estimated service lives of
generating stations, partially offset by additional depreciation expense on
plant placed in service, including two generating plants in April 2002 and the
Southeast Chicago Energy Project. Lower interest expense is due to capitalized
interest and a lower interest rate on the spent nuclear fuel obligation,
partially offset by an increase in interest expense on long-term debt. Other,
net increased $61 million for the nine months ended September 30, 2002 compared
to the same period in the prior year primarily due to substantial market losses
on decommissioning trust investments during 2001 as compared to the same period
in 2002. Additionally, trading activities were initiated in April 2001. Revenue
for the nine months ended September 30, 2002 includes a net trading portfolio
loss of $27 million compared to a net $1 million loss in the nine months ended
September 30, 2001.effects.
Generation Operating Statistics:
For the nine months ended September 30, 2002 and 2001,Statistics
Generation's sales and the supply of these sales, excluding the trading
portfolio, were as follows:
NineThree Months Ended September 30,
-------------------------------March 31,
----------------------------
Sales (in GWhs) 2003 2002 2001Variance % Change
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Energy Delivery 90,579 90,001 0.6%29,346 27,750 1,596 5.8%
Exelon Energy 4,067 5,044 (19.4%1,248 1,250 (2) (0.2%)
Market Sales 61,089 53,787 13.6%23,815 19,324 4,491 23.2%
- --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Sales 155,735 148,832 4.6%
=======================================================================================================
Nine54,409 48,324 6,085 12.6%
=====================================================================================
Three Months Ended September 30,March 31,
----------------------------
Supply of Sales (in GWhs) 2003 2002 2001Variance % Change
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Nuclear Generation 86,127 87,397 (1.5%)(1) 29,330 27,533 1,797 6.5%
Purchases - non-trading portfolio 59,496 52,459 13.4%(2) 20,029 18,093 1,936 10.7%
Fossil and Hydro Generation 10,112 8,976 12.7%5,050 2,698 2,352 87.2%
- --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Supply 155,735 148,832 4.6%
=======================================================================================================
Trading volume of 51,26054,409 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 2,286 GWhs for the nine months ended
September 30, 2002, and 2001, respectively, is not included in the table above.
69
64
Generation's average margin and other operating data for the ninethree
months ended September
30,March 31, 2003 and 2002 and 2001 were as follows:
NineThree Months Ended September 30,
-------------------------------March 31,
----------------------------
($/MWh) 2003 2002 2001 % Change
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Average Realized Revenue
Energy Delivery $ 34.3330.87 $ 33.37 2.9%29.98 3.0%
Exelon Energy 46.75 42.28 10.6%43.28 45.60 (5.1%)
Market Sales 31.55 39.95 (21.0%)37.05 28.15 31.6%
Total Sales - excluding the trading portfolio 33.56 36.05 (6.9%)33.96 29.63 14.6%
Average Supply Cost (1) - excluding the trading portfolio $ 21.0421.29 $ 21.72 (3.1%)16.74 27.2%
Average Margin - excluding the trading portfolio $ 12.5212.67 $ 14.18 (11.7%12.89 (1.7%)
- ---------------------------------------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------------------------------------
(1) Average supply cost includes purchasepurchased power and fuel cost.
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 nuclear fleet, including AmerGen, performed at a capacity
factor of 92.1% forMWh deliveries increased 12.6% in the ninethree months ended
September 30, 2002March 31, 2003 as compared to 95.1% the same period in 2001.2002. 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
nuclear fleet's production costs,
including AmerGen,average margin for the ninethree months ended September 30, 2002 were $13.05 per
MWhMarch 31, 2003 as compared to $12.40 per MWh for the same
period in 2001. The2002.
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 factorfactors and increased unitdecreased nuclear production costs
are primarily due to 18630 fewer planned refueling outage days, of
plannedresulting in a $32
million decrease in outage timecosts, in the ninethree months ended September 30, 2002 versus 55, days
in the same period in 2001. Increased unit production costs are partially offset
by headcount reductions and Exelon's Cost Management Initiatives. Generation's
average purchased power costs for wholesale operations were $43.60 per MWh for
the nine months ended September 30, 2002, compared to $49.77 per MWh for the
same period in 2001. The decrease in purchased power costs was primarily due to
depressed wholesale power market prices.
70
Results of Operations - Enterprises Business Segment
Nine Months Ended September 30,
-------------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $1,475 $1,742 $ (267) (15.3%)
OPERATING EXPENSES
Purchased Power 181 244 (63) (25.8%)
Fuel 294 429 (135) (31.5%)
Operating and Maintenance 983 1,066 (83) (7.8%)
Depreciation and Amortization 46 47 (1) (2.1%)
Taxes Other Than Income 6 8 (2) (25.0%)
- -------------------------------------------------------------------------------------------------------
Total Operating Expense 1,510 1,794 (284) (15.8%)
- -------------------------------------------------------------------------------------------------------
OPERATING INCOME (35) (52) 17 (32.7%)
- --------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (11) (31) 20 (64.5%)
Equity in Earnings (Losses) of Unconsolidated Affiliates, net 3 (22) 25 (113.6%)
Other, net 158 4 154 n.m.
- -------------------------------------------------------------------------------------------------------
Total Other Income and Deductions 150 (49) 199 n.m.
- -------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES AND CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 115 (101) 216 (213.9%)
INCOME TAXES 46 (38) 84 (221.1%)
- -------------------------------------------------------------------------------------------------------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE 69 (63) 132 (209.5%)
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE (243) -- (243) n.m.
- -------------------------------------------------------------------------------------------------------
NET INCOME $ (174) $ (63) $ (111) 176.2%
=======================================================================================================
Enterprises' net income increased $132 million for the nine months
ended September 30, 2002March 31, 2003 as
compared to the same period in 2001, excluding2002. 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 a changechanges in accounting principle. The increase in net
income is primarily attributableprinciples for the three months ended March 31, 2003
compared to the AT&T Wireless sale that resultedsame period in an
after-tax gain2002, included the following:
o lower interest expense of $116$2 million,
increased operating income of $17 million,o higher equity in earnings of unconsolidated affiliates of $18$4 million
due toresulting from the discontinuationdiscontinuance of losses onfrom the AT&T Wireless
investment as a result of its sale in the AT&T Wireless
sale, $10second quarter of 2002, and $3
million of equity in earningsresulting from lower costs at a communications joint venture, relatingand
o impairment of a software-related investment of $5 million due to its recoveryan other
than temporary decline in value. In the first quarter of trade receivables previously considered
uncollectible2002, Enterprises
had a $2 million net realized loss on a communications investment and a $26$2
million net loss in 2001 from the write-downimpairment of a communications investment.
These increases were partially offset by $40 million
of investment write-downs and $4 million of net asset write-downs66
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 and an
$18 million gain2002. This increase in
2001 from the saleeffective tax rate was attributable to various income tax related items
totaling $1 million.
The cumulative effect of a communications investment.
Enterprises'change in accounting principles recorded in
the three months ended March 31, 2003 due to the adoption of SFAS No. 143
reduced net loss increased $111income by $1 million, after reflecting thenet of income taxes. The cumulative effect of
a change in accounting principle resulting fromrecorded in the three months ended March 31,
2002 due to the adoption of SFAS No. 142 which no longer allows amortization of goodwill but requires testing
goodwill for impairment on an annual basis. The impairment booked during the
first quarter, as a result of transitional impairment testing, wasreduced net income by $243 million, net
of income taxes and minority interest.
Operating revenues decreased $267 million(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 nine months ended
September 30, 2002, comparedtransactions. 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
same period in 2001. The decrease in
operating revenues was attributablesale. Timing of any divestitures may positively or negatively affect the results
of operations as Exelon expects certain businesses to lower gas sales of $110 million primarily
71
resulting from lower gas prices, reduced retail energy sales of $141 million
from Exelon Energy exiting the PJM market, lower revenues of $52 million from
Exelon Services from reduced construction projects and lower revenues of $24
million from InfraSource from the continued declinebe profitable going
forward.
General
Due to revenue needs in the telecommunications
industrystates in which Exelon operates, various
state income tax and reduced construction services in that industry. These decreases
were partially offsetfee 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 higher electric revenues of $60 million primarily
resulting from higher electric prices in Illinois for Exelon Energy.
Enterprises' operatingthe state
legislatures or regulatory bodies, and, other expenses, net decreased $483 million
for the nine months ended September 30, 2002 compared to the same period in
2001. The decrease is primarily attributable to a pre-tax gain of $198 million
recorded on the AT&T Wireless sale, lower gas costs of $109 million primarily
resulting from lower gas prices, lower power costs of $154 million resulting
from reduced operations of retail energy sales from Exelon Energy exiting the
PJM market, reduced costs relating to construction projects at Exelon Services
of $41 million, reduced costs relating to construction services in the
telecommunications industry and overall reductions in administrative expenses at
InfraSource of $35 million, lower interest expense of $20 million, higher equity
in earnings of unconsolidated affiliates of $18 million asif enacted, whether any such legislation
or regulation would be effective retroactively or prospectively. As a result,
Exelon cannot currently estimate the effect of the
discontinuance of losses on AT&T Wireless as a result of the AT&T Wireless sale,
$10 million of equitythese potential changes in earnings from a communications joint venture relating
to its recovery of trade receivables previously considered uncollectible and a
$26 million net loss in 2001 from the write-down of a communications investment.
These decreases were partially offset by higher electric purchased power costs
in Illinois of $68 million for Exelon Energy, write-down of communications
investments of $29 million, write-down of energy related investments of $11
million, a net write-down of other assets of $4 million in 2002 and a $18
million gain in 2001 from the sale of a communications investment.
The effective income tax
rate was 40.0% for the nine months ended
September 30, 2002, compared to 37.6% for the nine months ended September 30,
2001. The increase in the effective tax rate was primarily attributable to the
AT&T Wireless sale offset by the discontinuation of goodwill amortization as of
January 1, 2002, that was not deductible for income tax purposes.laws or regulation.
LIQUIDITY AND CAPITAL RESOURCES
Exelon's businesses are capital intensive and require considerable
capital resources. Exelon'sThese capital resources are primarily provided by internally
generated cash flows from operationsEnergy Delivery and toGeneration's operations. When
necessary, Exelon obtains funds from external sources in the extent necessary,
external financings including the issuance of commercial paper.capital markets and
through bank borrowings. Exelon's access to external financing at reasonable
terms is dependentdepends on theExelon's and its subsidiaries' credit ratings of
Exelon and its subsidiaries and the general
business conditionconditions, as well as that of Exelon and the utility industry.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 are used primarily to fund Exelon's capital requirements, including construction, investmentsto
invest in new and existing ventures, repayments ofto repay maturing debt and preferred securities of subsidiaries and payment
ofto pay common
stock dividends. Any potential futureFuture acquisitions couldthat Exelon may undertake may require
external financing, including the issuance bywhich might include Exelon ofissuing common stock.
72
Cash Flows from Operating Activities
Cash flows provided by operations for the ninethree months ended September
30, 2002March 31,
2003 were $2.6 billion$383 million compared to $3.0 billion$826 million in the ninethree months ended September 30, 2001. Approximately 70%March
31, 2002. The decrease in cash flows was primarily attributable to a $305
million decrease in working capital. In the first quarter of 20022003, approximately
40% of cash flows provided by operations
for the nine months ended September 30, 2002 were provided by Energy Delivery and
approximately 30%60% were provided by Generation. Enterprises' cash flows from operations were
immaterial to Exelon for the ninethree months ended September 30,
2002.March 31, 2003. Energy
Delivery's cash flowsflow from operating activities primarily resultresults from sales of
electricity and gas to a stable and diverse base of retail customers and are weighted toward the third quarter.at fixed
prices. Energy Delivery's future cash flows will depend upon the ability to
achieve operating cost reductions,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 ninethree months ended
September 30, 2002March 31, 2003 were $1.8 billion,$457 million, compared to $1.6 billion$630 million for the ninethree months
ended September 30, 2001.March 31, 2002. The increase wasdecrease is primarily attributable to the
$443 million acquisition of two generating plants from TXU Corp. (TXU) and
increaseda decrease in
capital expenditures partially offset by $285due 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 proceeds from
the AT&T Wireless sale.Condensed Combined Notes to Consolidated Financial Statements).
Capital expenditures other than the TXU acquisition, by business segment for the ninethree months ended September 30,March 31,
2003 and 2002 and 2001 arewere as follows:
Nine Months Ended September 30,
-------------------------------
2002 2001
- ---------------------------------------------------------------------------------------------------------------------
Energy Delivery $ 729 $ 784
Generation 715 497
Enterprises 34 53
Corporate and Other 56 18
- ---------------------------------------------------------------------------------------------------------------------
Total Capital Expenditures $ 1,534 $ 1,352
=====================================================================================================================
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 20022003 reflect the
continuation of efforts to
68
further improve the reliability of its distribution system. Exelon anticipates
that Energy Delivery's investing activities werecapital expenditures will be funded primarily through
operating activities.by internally
generated funds, borrowings, the issuance of preferred securities, or capital
contributions from Exelon.
Generation's capital expenditures for 2002 are for2003 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, and increases in capacity at existing plants. Generation's investing
activities were funded from operating activities, borrowings from Exelon and the
use of available cash.
Generation closed the purchase of the two natural-gas and oil-fired
generating plants from TXU on April 25, 2002. The $443 million purchase was
funded with Exelon commercial paper. Exelon expects to repay the commercial
paper utilizing Generation's internal cash flows.
73
Capital expenditures have increased for the nine months ended September
30, 2002 as compared to 2001 due to higher nuclear fuel expenditures, growth and
an increase in the number of planned refueling outages, during which significant
work is performed on additions to or upgrades of existing facilities.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 September 30, 2002,March 31, 2003, the balance of the loan to AmerGen was $42$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 20022003 are primarily for additions
to or upgrades of existing facilities. On April 1, 2002, Exelon Enterprises
closed on the saleAll of its 49% interest in AT&T Wireless for $285 million in
cash.Enterprises' capital expenditures
are expected to be funded by capital contributions or borrowings from Exelon.
Cash Flows from Financing Activities
Cash flows used inprovided by financing activities were $828 million in the nine
months ended September 30, 2002 compared to $521$108 million for the
same periodthree 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
2001 duenet borrowings. See Notes 10 and 14 of the Condensed Combined Notes to
higher levelsConsolidated Financial Statements for further discussion of net reductions in short-term and long-termExelon's debt and
payments of dividends on common stock of $420 million. Debtpreferred securities financing activities during the nine months ended September 30, 2002 are discussed in the Contractual
Obligations and Commercial Commitments section of Management's Discussion and
Analysis of Financial Condition and Results of Operations.2003.
Credit Issues
Exelon meets its short-term liquidity requirements primarily through
the issuance of commercial paper by the Exelon at thecorporate holding company level,(Exelon
Corporate) and by ComEd, PECO and Generation. Exelon Corporate participates,
along with ComEd, PECO and Generation,
participates in a $1.5 billion unsecured 364-day
revolving credit facility with a group of banks effective December 12, 2001. Under the terms of thisbanks. 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 has the flexibility toCorporate may increase or decrease the sublimits of
each of the participants upon written notification to thesethe banks. As of September 30, 2002, Exelon'sMarch 31,
2003, Exelon Corporate's sublimit is $700was $800 million, at the holding company
level. ThisComEd'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 $700 million
commercial paper program at theprograms of Exelon
holding company level.Corporate, ComEd, PECO and Generation. At September 30,
2002, Exelon had $319March 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 holding
companyExelon consolidated level. At
September 30, 2002,March 31, 2003, Exelon Corporate, ComEd, PECO and Generation were in compliance
with the Exelon Consolidated Balance Sheet
reflectscredit agreement thresholds. The following table summarizes the
$788 million total amount of commercial paper outstanding for all
participantsthreshold reflected in the credit facility.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 the Exelon Corporate Treasurer.
Exelon,Exelon's corporate treasurer.
ComEd and its subsidiary, Commonwealth Edison Company of Indiana, Inc., PECO,
Generation and Exelon Business Services Company currently(BSC) may participate in the
money pool. Funding of,pool as lenders and borrowers, and Exelon Corporate as a lender.
Contributions to and permitted borrowings from the money pool are predicatedbased on
whether such funding resultsthe contributions and borrowings result in mutual economic benefits to each ofall the
participants,
although Exelon is not permitted to be a net borrower from the fund.participants. Interest on borrowings is based on short-term market rates of
interest, or, if from an external source, specific borrowing rates ifrates. During the
funds are provided by external financing. There have beenfirst 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 material money pool transactions in 2002.
74
At September 30, 2002, Exelon had outstanding $788 million of notes
payable consisting principally of commercial paper. For the nine months ended
September 30, 2002, the average interest ratebalance on notes payable was approximately
1.91%. Certain of the credit agreements to which Exelon, ComEd, PECO and
Generation are a party require each of them to maintain a debt to total
capitalization ratio of 65% or less (excluding securitization debt and for PECO,
excluding the receivable from parent recorded in PECO's shareholders' equity).
At September 30, 2002, the debt to total capitalization ratios on that basis for
Exelon, ComEd, PECO and Generation were 46%, 42%, 41% and 34%, respectively.
At September 30, 2002,these loans.
Exelon's capital structure consisted of 58% of
long-term debt, 37% common stock, 3% notes payable and 2% preferred securities
of subsidiaries. Total debt included $6.3 billion of securitization debt
constituting obligations of certain consolidated special purpose entities,
representing 27% of capitalization.
Exelon and its subsidiaries' access to the capital markets, including the commercial paper
market, and theirits financing costs in those markets are
dependentdepend on their respective credit ratings.the securities
ratings of the entity that is accessing the capital markets. None of Exelon's
or its
subsidiaries' borrowings areis subject to default or prepayment as a result of a downgrading of
creditsecurities ratings although such a downgrading could increase fees and interest
charges under Exelon's bank$1.5 billion credit facility. Exelonfacility and its
subsidiaries fromcertain other credit
facilities. From time to time, enterExelon enters into energy commodity and other
derivative
transactionscontracts that require the maintenance of investment grade ratings. Failure to
maintain investment grade ratings would allow the counterpartycounterparties to certain energy
commodity contracts to terminate the derivativecontracts and settle the transactiontransactions 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 the Public Utility Holding Company Act of 1935 (PUHCA) and the
Federal Power Act,PUHCA, Exelon, ComEd, PECO and Generation can pay dividends only
from retained, undistributed or current earnings: however, anearnings. However, the SEC order granted
permission to ComEd, and to Exelon, andto 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, provided thatalthough Exelon agreedmay not to pay
dividends out of paid-in capital after December 31, 2002 if its common equity is
less than 30% of its total capitalization. At September 30, 2002,March 31, 2003, Exelon had
retained earnings of $1.8$2.3 billion, which includes ComEdincluding ComEd's retained earnings of $480$652
million, PECOPECO's retained earnings of $347$447 million and Generation retainedGeneration's undistributed
earnings of $850$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, and 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 September 30, 2002March 31, 2003 were materially unchanged, other than in the
normal course of business, from the amounts set forth in the December 31,
20012002 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 $600 millionon March 28, 2003, are subject to rehearing. Rehearing
requests have been filed with the ICC. Rehearing requests may be
considered through the middle of 6.15% First Mortgage Bonds, Series 98 due
March 15, 2012,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 $100 millionwith respect to any of Illinois Development Finance
Authority floating-rate Pollution Control Revenue Refunding Bonds, Series
2002 due April 15, 2013, redeemed $100 millionthose
orders.
The Agreement provides for a modification of 7.25% Illinois
Development Finance Authority Pollution Control Revenue Refunding Bonds,
Series 1991, due June 1, 2011, redeemed $200 million of 8.625% First
Mortgage Bonds, Series 81 due February 1, 2022, redeemed $200 million of
8.5% First Mortgage Bonds, Series 84 due July 15, 2022, paid at maturity
$200 million of 7.375% First Mortgage Bonds, Series 85 due September 15,
2002, redeemed $200 million of 8.375% First Mortgage Bonds, Series 86 due
75
September 15, 2022, paid at maturity $200 million of variable rate senior
notes due September 30, 2002, paid at maturity $100 million of 9.17%
medium-term notes due October 15, 2002, and retired $254 million of
transitional trust notes. At September 30, 2002, ComEd had $94 million in
short-term borrowings.
o PECO issued $225 million of 4.75% First and Refunding Mortgage Bonds due
October 1, 2012. This bond issuance repaid commercial paper that wasthe methodology used
to pay at maturity $222 million of Firstdetermine ComEd's market value energy credit. That credit is used
to determine the price for specified market-based rate offerings and Refunding Mortgage Bonds. PECO
made principal payments of $326 million on transition bonds and made
additional borrowings of commercial paper of $274 million.
o Guarantees increased approximately $280 million, primarily related to a
$410 million increase in
the amount of performance bonds, bid bondsthe 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 surety bonds required by Enterprises,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 $120 million in
letters of credit on pollution control bonds at Generation being renewed
and no longer required to be guaranteed.
o Insured long-term debt increased $100 million related to ComEd's issuance
of $100 million in variable rate debt that has been credit enhanced through
the purchase of insurance coverage.
o On April 25, 2002 Generation closed the purchase of two generating plants
from TXU. The $443 million purchase was funded primarily with commercial
paper issued by Exelon.
o On June 26, 2002, Generation agreed to purchase Sithe New England Holdings,
LLC (Sithe New England), a subsidiary of Sithe, and related power marketing
operations for a $543 million note. In addition, Generation will assume
various Sithe guarantees related to an equity contribution agreement
between Sithe New England and Sithe Boston Generation (Boston Generation),
a project subsidiary of Sithe New England. The equity contribution
agreement requires, among other things, that Sithe New England, upon the
occurrence of certain events, contribute up to $38 million of equity for
the purpose of completing the construction of two generating facilities.
Boston Generation established a $1.2 billion credit facility in order to
finance the construction of these two generating facilities. The
approximately $1.1 billion expected to be outstanding under the facility at
the transaction closing date, will be reflected on Exelon's Consolidated
Balance Sheet. Sithe New England has provided security interests in and has
pledged the stock of its other project subsidiaries to Boston Generation.
If the closing conditions are satisfied, the purchase could be completed in
November 2002.
o At September 30, 2002, Southeast Chicago, a company 70% owned by
Generation, was obligated to make equity distributions of $55 million over
the next 20 years to the unaffiliated third party owning the remaining 30%
of Southeast Chicago. This amount reflects a return of such third party's
investment in Southeast Chicago's peaking facility in Chicago, IL.
Generation has the right to purchase, generally at a premium, and this
third party has the right to require Generation to purchase, generally at a
discount, its remaining investment in Southeast Chicago. Additionally,
Generation may be required to purchase the third party's remaining
investment in Southeast Chicago upon the occurrence of certain events,
including upon a failure by Generation to maintain an investment grade
rating.
o Purchase obligations increased by $2.3 billion, primarily due to an
increase of $3.8 billion in power only purchases and a $0.1 billion
increase in transmission rights purchases partially offset by a $1.6
billion decrease in net capacity purchase commitments. Approximately $2
billion of the increase in power only purchases is due to Generation's
agreement to purchase all the energy from Unit No. 1 at Three Mile Island
after December 31, 2001 through December 31, 2014 and the remaining $1.8
billion increase is primarily due to purchase contracts entered into in
lieureversal
of a portion of the Midwest Generation options contracts. The increase$12 million (before income taxes) reserve established in transmission rights purchases is primarily due to estimated commitments
in 2004 and 2005 for additional transmission rights that will be required
to fulfill firm sales contracts. The decrease in net capacity purchase
76
commitments is due primarily to the decision not to exercise options to
purchase 4,411 MWs of capacity from Midwest Generation in 2002 through 2004
as well as the increase in capacity sales under the TXU tolling agreement.
Off Balance Sheet Obligations
Generation owns 49.9% of the outstanding common stock of Sithe and has
an option, beginning on December 18, 2002 and expiring in December 2005 to
purchase the remaining common stock outstanding (Remaining Interest) in Sithe.
The purchase option expires on December 18, 2005. In addition, the Sithe
stockholders who own in the aggregate the Remaining Interest have the right to
require Generation to purchase the Remaining Interest (Put Rights) during the
same period in which Generation can exercise its purchase option. At the end of
this exercise period, if Generation has not exercised its purchase option and
the other Sithe stockholders have not exercised their Put Rights, Generation
will have an additional one-time option to purchase shares from the other
stockholders in Sithe to bring Generation's ownership in Sithe from the current
49.9% to 50.1% of Sithe's total outstanding common stock.
If Generation exercises its option to acquire the Remaining Interest,
or if all the other Sithe stockholders exercise their Put Rights, the purchase
price for 70% of the Remaining Interest will be set at fair market value subject
to a floor of $430 million and a ceiling of $650 million. The balance of the
Remaining Interest will be valued at fair market value subject to a floor of
$141 million and a ceiling of $330 million. In either instance, the floor and
ceiling will accrue interest from the beginning of the exercise period.
If Generation increases its ownership in Sithe to 50.1% or more, Sithe
will become a consolidated subsidiary and Exelon's financial results will
include Sithe's financial results from the date of purchase. At September 30,
2002, Sithe had total assets of $4.2 billion and total debt of $2.1 billion,
including $1.6 billion of subsidiary debt incurred to finance the construction
of two new generating facilities of which $1.1 billion is associated with Sithe
New England, $0.4 billion of subordinated debt, $47 million of short-term debt,
$33 million of capital leases, and excluding $430 million of non-recourse
project debt associated with Sithe's equity investments. For the nine months
ended September 30, 2002, Sithe had revenues of $0.9 billion. As of September
30, 2002, Generation had a $722 million equity investment in Sithe.
On June 26, 2002, Generation agreed to purchase Sithe New England, a
subsidiary of Sithe, and related power marketing operations in exchange for a
$543 million note. In addition, Generation will assume various Sithe guarantees
related to an equity contribution agreement between Sithe New England and Boston
Generation, a project subsidiary of Sithe New England. The equity contribution
agreement requires, among other things, that Sithe New England, upon the
occurrence of certain events, contribute up to $38 million of equity for the
purpose of completing the construction of two generating facilities. Boston
Generation established a $1.2 billion credit facility in order to finance the
construction of these two generating facilities. The approximately $1.1 billion
expected to be outstanding under the facility at the transaction closing date,
will be reflected on Exelon's Consolidated Balance Sheet. Sithe New England has
provided security interests in and has pledged the stock of its other project
subsidiaries to Boston Generation. If the closing conditions are satisfied, the
transaction could be completed in November 2002.
Additionally, the debt on the books of Exelon's unconsolidated equity
investments and joint ventures is not reflected on Exelon's Consolidated Balance
77
Sheets. Total investee debt, at September 30, 2002, including the debt of Sithe
described in the preceding paragraph, is currently estimated to be $2.2 billion
($1.1 billion based on Exelon's ownership interest of the investments).
Generation and British Energy plc (British Energy), Generation's joint
venture partner in AmerGen, have each agreed to provide up to $100 million to
AmerGen at any time that the Management Committee of AmerGen determines that in
order to protect the public health and safety and/or to comply with Nuclear
Regulatory Commission (NRC) requirements, such funds are necessary to meet
ongoing operating expenses or to safely maintain any AmerGen plant.
Other Factors
Exelon's costs of providing pension and postretirement benefit plans
are dependent upon a number of factors, such as the rates of return on pension
plan assets, discount rate, and the rate of increase in health care costs. The
market value of plan assets has been affected by sharp declines in the equity
market since the
third quarter of 2000.2002 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 a result, at December 31, 2002,
Exelonsuch, 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 requiredmaterial to recognize an additional minimum liability as
prescribed by SFAS No. 87 "Employers' Accountingthe 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 Pensions"discussion of material changes in Exelon's
debt and SFAS No. 132
"Employers' Disclosures about Pensions and Postretirement Benefits." The
liability would bepreferred 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 as a reduction to common equity, and the equity
would be restored toon the balance sheet inbut potentially
triggered by future periods when the fair value of
plan assets exceeds the accumulated benefit obligations. Based upon the market
value of plan assets at September 30, 2002 and estimated market performance for
the remainder of 2002, the amount of the reduction to common equity (net of
income taxes) is estimated to be in the range of $500 million to $1.0 billion.
This estimate could increase or decrease as a result of actual market
performance in the fourth quarter of 2002. The recording of this reduction would
not affect net income or cash flow in 2002 or compliance with debt covenants;
however, pension cost and cash funding requirements could increase in future
years without a substantial recovery in the equity markets.
Approximately $33 million was included in operating and maintenance
expense in 2001 for the cost of Exelon's pension and post-retirement benefit
plans, exclusive of the 2001 charges for employee severance programs. These
costs are expected to increase in 2002 by approximately $55 million as the
result of the effects of the decline in market value of plan assets and discount
rates, and increases in health care costs. Further increases in pension and
postretirement expense are expected for the year 2003 as a result of the same
factors. Although the 2003 increase will depend on market conditions, Exelon
preliminarily estimates that pension and postretirement benefit costs will
increase by approximately $70 million in 2003 from 2002 cost levels.
Exelon's defined benefit pension plans currently meet the minimum
funding requirements of the Employment Retirement Income Security Act of 1974;
however, Exelon currently expectsevents, including obligations to make a discretionary plan contribution in
the fourth quarterpayment on
behalf of 2002 of $100 millionother parties and financing arrangements to $200 million and a discretionary
plan contribution in 2003 of $300 million to $350 million. These contributions
are expected to be funded primarily by internally generated cash flows from
operations or through external sources.
78
Generation is a counterparty to Dynegy Inc. (Dynegy) in various energy
transactions. In early July 2002, the credit ratings of Dynegy were downgraded
by two credit rating agencies to below investment grade. As of September 30,
2002, Generation had a net receivable from Dynegy of approximately $7 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 arrangement with
Dynegy, with a related financial swap arrangement. As of September 30, 2002,
Sithe had recognized an asset on its balance sheet related to the fair 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 write-off the fair value asset, which
Generation estimates would result in an approximate $22 million reduction in its
equity earnings from Sithe, based on Generation's current 49.9% investment
ownership in Sithe. The fair value of this asset may change over time.
Additionally, the future economic value of Sithe's investment in the
Independence Station and AmerGen's purchased power arrangement with Illinois
Power, a subsidiary of Dynegy, could be impacted by events related to Dynegy's
financial condition.
79secure their
obligations.
72
COMMONWEALTH EDISON COMPANY
- ---------------------------
GENERAL
ComEd operates in a single business segment Energy Delivery, and its operations consist
of its retailthe regulated sale of electricity and distribution and transmission businessservices
in northern Illinois.
RESULTS OF OPERATIONS
Three Months Ended March 31, 2003 Compared to Three Months Ended March 31, 2002
Three Months Ended September 30, 2002 Compared to Three Months Ended September 30, 2001
Significant Operating Trends - ComEd
Three Months Ended September 30,
--------------------------------March 31,
----------------------------
2003 2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 1,938 $1,9191,424 $ 19 1.0%1,315 $ 109 8.3%
OPERATING EXPENSES
Purchased Power 975 954 21 2.2%578 538 40 7.4%
Operating and Maintenance 267 265 2 0.8%261 237 24 10.1%
Depreciation and Amortization 129 178 (49) (27.5%94 135 (41) (30.4%)
Taxes Other Than Income 77 82 (5) (6.1%)80 73 7 9.6%
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Operating Expense 1,448 1,479 (31) (2.1%)Expenses 1,013 983 30 3.1%
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 490 440 50 11.4%
- -------------------------------------------------------------------------------------------------------411 332 79 23.8%
OTHER INCOME AND DEDUCTIONS
Interest Expense (122) (147) 25 (17.0%(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 -- 33 (33) (100.0%)Net 22 14 8 57.1%
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Other Income and Deductions (129) (121) (8) (6.6%(95) (119) 24 (20.2%)
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 361 319 42 13.2%AND CUMULATIVE
EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE 316 213 103 48.4%
INCOME TAXES 146 141126 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 3.5%-- 5 n.m.
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
NET INCOME $ 215195 $ 178129 $ 37 20.8%
=======================================================================================================66 51.2%
=====================================================================================================
n.m. -not meaningful
Net Income
Net income increased $37$66 million, or 21%51% for the three months ended
September 30,March 31, 2003 as compared to the same period in 2002. Net income was positively
impacted by the favorable effect of warmer
than normal summer weather,higher operating revenues and lower depreciation rates, the discontinuation of
goodwill amortization and a lower effective income tax rate,interest expense, partially
offset by the effects of a 5% residential rate reduction and customers electing to
purchase energy from an ARES or the PPO.
80higher operating expenses.
73
Operating Revenues
ComEd's electric sales statistics are as follows:
Three Months Ended September 30,
--------------------------------March 31,
-----------------------------
Retail Deliveries - (in GWh)GWhs) 2003 2002 2001 Variance % Change
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Bundled Deliveries (1)
Residential 9,121 8,398 723 8.6%6,886 6,409 477 7.4%
Small Commercial & Industrial 6,029 6,308 (279) (4.4%)5,627 5,450 177 3.2%
Large Commercial & Industrial 2,073 2,506 (433) (17.3%1,484 1,956 (472) (24.1%)
Public Authorities & Electric Railroads 1,612 2,105 (493) (23.4%1,416 1,801 (385) (21.4%)
- -------------------------------------------------------------------------------------------------------
18,835 19,317 (482) (2.5%----------------------------------------------------------------------------------------
15,413 15,616 (203) (1.3%)
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Unbundled Deliveries (2)
ARES
Small Commercial & Industrial 1,640 898 742 82.6%1,348 1,004 344 34.3%
Large Commercial & Industrial 2,192 1,548 644 41.6%1,832 1,386 446 32.2%
Public Authorities & Electric Railroads 299 91 208 n.m.282 138 144 104.3%
- -------------------------------------------------------------------------------------------------------
4,131 2,537 1,594 62.8%----------------------------------------------------------------------------------------
3,462 2,528 934 36.9%
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
PPO
Small Commercial & Industrial 782 827 (45) (5.4%)793 763 30 3.9%
Large Commercial & Industrial 1,249 1,448 (199) (13.7%)1,433 1,311 122 9.3%
Public Authorities & Electric Railroads 345 150 195 (130.0%)537 242 295 121.9%
- -------------------------------------------------------------------------------------------------------
2,376 2,425 (49) (2.0%)----------------------------------------------------------------------------------------
2,763 2,316 447 19.3%
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Unbundled Deliveries 6,507 4,962 1,545 31.1%6,225 4,844 1,381 28.5%
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Retail Deliveries 25,342 24,279 1,063 4.4%
=======================================================================================================
21,638 20,460 1,178 5.8%
========================================================================================
(1) Bundled service reflects deliveries to customers taking electric service
under tariffed rates, which includerates.
(2) Unbundled service reflects customers electing to receive electric generation
service from an ARES or the cost of energy and the delivery
cost of the transmission and the distribution of the energy.
(2) Unbundled service reflects customers electing to receive electric
generation service from an ARES or the PPO.
n.m. - not meaningful
8174
Three Months Ended September 30,
--------------------------------March 31,
---------------------------
Electric Revenue 2003 2002 2001 Variance % Change
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Bundled Revenues (1)
Residential $ 840546 $ 816518 $ 24 2.9%28 5.4%
Small Commercial & Industrial 506 531 (25) (4.7%)397 391 6 1.5%
Large Commercial & Industrial 106 126 (20) (15.9%74 102 (28) (27.5%)
Public Authorities & Electric Railroads 104 119 (15) (12.6%84 92 (8) (8.7%)
- -------------------------------------------------------------------------------------------------------
1,556 1,592 $ (36) (2.3%----------------------------------------------------------------------------------------
1,101 1,103 (2) (0.2%)
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Unbundled Revenues (2)
ARES
Small Commercial & Industrial 51 10 41 12 29 n.m.
Large Commercial & Industrial 60 12 4849 10 39 n.m.
Public Authorities & Electric Railroads 10 1 9 2 7 n.m.
- -------------------------------------------------------------------------------------------------------
121 23 98----------------------------------------------------------------------------------------
99 24 75 n.m.
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
PPO
Small Commercial & Industrial 57 77 (20) (25.9%)50 43 7 16.3%
Large Commercial & Industrial 74 120 (46) (38.3%)72 64 8 12.5%
Public Authorities & Electric Railroads 1927 13 6 46.2%14 107.7%
- -------------------------------------------------------------------------------------------------------
150 210 (60) (28.6%)----------------------------------------------------------------------------------------
149 120 29 24.2%
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Unbundled Revenues 271 233 38 16.3%
- -------------------------------------------------------------------------------------------------------248 144 104 72.2%
Total Electric Retail Revenues 1,827 1,825 2 0.1%1,349 1,247 102 8.2%
Wholesale and Miscellaneous Revenue (3) 111 94 17 18.1%75 68 7 10.3%
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Electric Revenue $ 1,9381,424 $ 1,9191,315 $ 19 1.0%
=======================================================================================================
(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. Revenues 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 sales to ARES, transmission
revenue, sales to municipalities and other wholesale energy sales.
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
September 30, 2002,March 31, 2003, as compared to the three months ended September 30, 2001,same period in 2002, are attributable to the
following:
Variance
- -------------------------------------------------------------------------------------------------
Weather $ 86
Rate Changes (45)
Customer Choice (43)
Other Effects 4
- -------------------------------------------------------------------------------------------------
Electric Retail Revenue $ 2
=================================================================================================
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 September 30, 2002March 31, 2003 was favorable compared to the three months ended September 30, 2001same
period in 2002 as a result of warmer summercolder winter weather in the third quarter of 2002 as compared to
the third quarter of 2001. Cooling2003. Heating
degree-days increased 26%17% in the three
82
months ended September 30, 2002 compared to the three months ended September 30, 2001.
o Rate Changes. The decrease attributableMarch 31, 2003
compared to rate changes reflects a 5%
residential rate reduction, effective October 1, 2001, required by the Illinois restructuring legislation.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. On May 1, 2002, all ComEd residential customers became
eligible to choose their supplier of electricity. However, as of September
30, 2002,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 September 30, 2002,March 31, 2003,
approximately 22,700 retail customers had elected to purchase energy
from an ARES or the ComEd PPO,PPO. This represents an increase from 15,400 customers at September
30, 2001. Thein
delivered MWhs delivered to such customers increased from approximately 5.04.8 million for
the three months ended September 30, 2001March 31, 2002 to 6.56.2 million for the three
months ended September 30, 2002,March 31, 2003, or a 31% increase from the
previous year.24% to 29% of total quarterly
retail deliveries.
o Other Effects.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 slowing economy both nationally and regionally has
yielded minimal quarterly gains as business uncertainty and unemployment
concerns limit customer activity and electricity sales.
The$7 million increase in wholesale and miscellaneous revenue for the
three months ended September 30, 2002March 31, 2003 as compared to the three months ended September
30, 2001March
31, 2002 was due primarily to reimbursement from Generationa $5 million increase in sales for resale to
municipalities and others as a result of $12 million for
the third-party energy reconciliations.a 17% increase in heating degree-days
in 2003.
Purchased Power Expense
Purchased power expense increased $21$40 million, or 2%7% for the three
months ended September 30, 2002.March 31, 2003. The increase in purchased power expense was
primarily attributable to a $38 million increase associated with additional
increased weather related on-peak sales volume, a $22$20 million increase due to favorable weather
conditions, an increase in the weighted average on-peak/off-peak cost per MWhof $12 million due to higher volume, $17 million due to
pricing changes related to ComEd's PPA with Generation and $20an increase of $16
million
in additional expense resulting from additional energy billed under the PPA related to decommissioning collections associated with Generation as a resultthe
adoption of the third-party energy reconciliations discussedSFAS No. 143 that were not included in the operating revenue section above, partiallypurchased power in 2002,
offset by a $62$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 Expense
Operating and maintenance (O&M) expense increased $2$24 million, or 1%10%,
for the three months ended September 30, 2002.March 31, 2003. The increase in O&M expense reflectswas
primarily attributable to a $17net one-time charge of $41 million increase in the reserve for MGP investigation and
remediation2003 as athe
result of increased coststhe Agreement as more fully described in Note 4 - Regulatory Issues,
offset by higher corporate allocations in 2002 due to delays in the implementation
of ongoing remediation of a MGP site in Oak Park, Illinois partially offset by
operating productivity improvements and a $7 million decrease in other O&M
items.
83executive severance.
76
Depreciation and Amortization Expense
Depreciation and amortization expense decreased $49$41 million, or 28%30%,
for the three months ended September 30, 2002March 31, 2003 as follows:
Three Months Ended September 30,
--------------------------------March 31,
----------------------------
2003 2002 2001 Variance % Change
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Depreciation Expense $ 75 $ 8791 $ (12) (13.8%(16) (17.6%)
Recoverable Transition Costs Amortization 33 35 (2) (5.7%11 23 (12) (52.2%)
Other Amortization Expense 8 21 56 (35) (62.5%(13) (61.9%)
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Depreciation and Amortization $ 12994 $ 178135 $ (49) (27.5%(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, changingchanges 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 month periodmonths ended September 30, 2002.
The decrease in other amortization expense is primarily due to a
decrease of $32 million due to the discontinuation of goodwill amortization
effective January 1, 2002 upon the adoption of SFAS No. 142.March 31, 2003.
Recoverable transition costs amortization was consistentdecreased in the three months
ended September 30, 2002March 31, 2003 compared to the same period in 2001.2002. 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 $202$164 million by 2004.2006. 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 decreased $5increased by $7 million or 6%10%, for the three
months ended September 30, 2002. Taxes other than income were positively
affected in 2002 as a result of
a $4 million increase in real estate tax refundand municipal taxes and $1 million in
the amount of $5
million.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 $25$16 million, or 17%13%, for the three months
ended September 30, 2002.March 31, 2003. The decrease in interest chargesexpense was primarily
attributable to the impact of lower interest rates for the three months ended
September 30, 2002March 31, 2003 as compared to the three months ended September 30, 2001,March 31, 2002 and the
early retirement of the $196 million of First Mortgage Bonds in November of 2001
and theannual retirement of $340 million in transitional trust notes since September
2001 and $10Transitional Trust Notes.
Other, Net
Other, Net increased income by $8 million of intercompany interest expense in 2001 relating to a
payable to Generation, which was repaid during 2001.
84
Other Income and Deductions
Other income and deductions, excluding interest charges, decreased $33
million, or 100%, for the three months ended
September 30, 2002.March 31, 2003. The decreaseincrease was primarily attributable to $9 million in intercompany interest income from
Generation in 2001 on the processingreversal of certain invoice payments on behalf of
Generation, a $6 million reduction in intercompany interest income from Unicom
Investment Inc., reflecting lower interest rates, a $12
million accrualreserve in 20022003 for estimated minimum probable write-off exposure resulting froma potential plant disallowance as the Liberty
audit findings relatedresult of the
Agreement as more fully described in Note 4 to ComEd's delivery services rate case and a $6 million
decrease in various other income and deductions items.the Condensed Combined Notes to
Consolidated Financial Statements.
Income Taxes
The effective income tax rate was 40.4%39.9% for the three months ended
September 30, 2002,March 31, 2003, compared to 44.2%39.4% for the three months ended September 30,
2001. The decreaseMarch 31, 2002.
Due to revenue needs in the effective tax rate was primarily attributable to the
discontinuation of goodwill amortization as of January 1, 2002,states in which was not
deductible forComEd operates, various
state income tax purposes.
Nine Months Ended September 30, 2002 Compared to Nine Months Ended September 30,
2001
Significant Operating Trends -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
Nine Months Ended September 30,
-------------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 4,734 $ 4,895 $ (161) (3.3%)
OPERATING EXPENSES
Purchased Power 2,066 2,149 (83) (3.9%)
Operating and Maintenance 724 731 (7) (1.0%)
Depreciation and Amortization 397 512 (115) (22.5%)
Taxes Other Than Income 223 223 -- --
- -------------------------------------------------------------------------------------------------------
Total Operating Expense 3,410 3,615 (205) (5.7%)
- -------------------------------------------------------------------------------------------------------
OPERATING INCOME 1,324 1,280 44 3.4%
- -------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (374) (433) 59 (13.6%)
Distributions on Company-Obligated Mandatorily
Redeemable Preferred Securities of Subsidiary Trusts
Holding Solely the Company's Subordinated Debt Securities (22) (22) -- --
Other, net 29 94 (65) (69.1%)
- -------------------------------------------------------------------------------------------------------
Total Other Income and Deductions (367) (361) (6) 1.7%
- -------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 957 919 38 4.1%
INCOME TAXES 381 412 (31) (7.5%)
- -------------------------------------------------------------------------------------------------------
NET INCOME $ 576 $ 507 $ 69 13.6%
=======================================================================================================
Net Income
Net income increased $69 million,cannot predict whether legislation or
14% forregulation will be introduced, the nine months ended
September 30, 2002. Net income was primarily impactedform of any legislation or regulation,
whether any such legislation or regulation will be passed by the discontinuation of
goodwill amortizationstate
legislatures or regulatory bodies, and, a lowerif enacted, whether any such legislation
or regulation would be effective income tax rate partially offset by
85
the effects of a 5% residential rate reduction and customers electing to
purchase energy from an ARESretroactively or the PPO.
Operating Revenues
ComEd's electric sales statistics are as follows:
Nine Months Ended September 30,
-------------------------------
Retail Deliveries - (in GWh) 2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
Bundled Deliveries (1)
Residential 21,392 19,936 1,456 7.3%
Small Commercial & Industrial 17,078 17,986 (908) (5. 1%)
Large Commercial & Industrial 6,151 8,144 (1,993) (24.5%)
Public Authorities & Electric Railroads 5,097 6,007 (910) (15.1%)
- -------------------------------------------------------------------------------------------------------
49,718 52,073 (2,355) (4.5%)
- -------------------------------------------------------------------------------------------------------
Unbundled Deliveries (2)
ARES
Small Commercial & Industrial 3,822 2,005 1,817 90.6%
Large Commercial & Industrial 5,200 3,962 1,238 31.2%
Public Authorities & Electric Railroads 618 227 391 172.2%
- -------------------------------------------------------------------------------------------------------
9,640 6,194 3,446 55.6%
- -------------------------------------------------------------------------------------------------------
PPO
Small Commercial & Industrial 2,384 2,448 (64) (2.6%)
Large Commercial & Industrial 3,952 4,324 (372) (8.6%)
Public Authorities & Electric Railroads 861 734 127 17.3%
- -------------------------------------------------------------------------------------------------------
7,197 7,506 (309) (4.1%)
- -------------------------------------------------------------------------------------------------------
Total Unbundled Deliveries 16,837 13,700 3,137 22.9%
- -------------------------------------------------------------------------------------------------------
Total Retail Deliveries 66,555 65,773 782 1.2%
=======================================================================================================
(1) Bundled service reflects deliveries to customers taking electric service
under tariffed rates, which include the cost of energy and the delivery
cost of the transmission and the distribution of the energy.
(2) Unbundled service reflects customers electing to receive electric
generation service from an ARES or the PPO.
86
Nine Months Ended September 30,
-------------------------------
Electric Revenue 2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
Bundled Revenues (1)
Residential $ 1,881 $ 1,852 $ 29 1.6%
Small Commercial & Industrial 1,343 1,410 (67) (4.8%)
Large Commercial & Industrial 324 406 (82) (20.2%)
Public Authorities & Electric Railroads 297 335 (38) (11.3%)
- -------------------------------------------------------------------------------------------------------
3,845 4,003 (158) (3.9%)
- -------------------------------------------------------------------------------------------------------
Unbundled Revenues (2)
ARES
Small Commercial & Industrial 94 36 58 161.1%
Large Commercial & Industrial 101 60 41 68.3%
Public Authorities & Electric Railroads 18 3 15 n.m.
- -------------------------------------------------------------------------------------------------------
213 99 114 115.2%
- -------------------------------------------------------------------------------------------------------
PPO
Small Commercial & Industrial 155 167 (12) (7.2%)
Large Commercial & Industrial 214 267 (53) (19.9%)
Public Authorities & Electric Railroads 48 44 4 9.1%
- -------------------------------------------------------------------------------------------------------
417 478 (61) (12.8%)
- -------------------------------------------------------------------------------------------------------
Total Unbundled Revenues 630 577 53 9.2%
- -------------------------------------------------------------------------------------------------------
Total Electric Retail Revenues 4,475 4,580 (105) (2.3%)
Wholesale and Miscellaneous Revenue (3) 259 315 (56) (17.8%)
- -------------------------------------------------------------------------------------------------------
Total Electric Revenue $ 4,734 $ 4,895 $ (161) (3.3%)
=======================================================================================================
(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. Revenues 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 sales to ARES, transmission
revenue, sales to municipalities and other wholesale energy sales.
The changes in electric retail revenues for the nine months ended
September 30, 2002, as compared to the nine months ended September 30, 2001, are
attributable to the following:
Variance
- -------------------------------------------------------------------------------------------------
Customer Choice $ (121)
Rate Changes (99)
Weather 73
Other Effects 42
- -------------------------------------------------------------------------------------------------
Retail Revenue $ (105)
- -------------------------------------------------------------------------------------------------
o Customer Choice. The decrease in revenues reflects customers in Illinois
electing to purchase energy from an ARES or the PPO.prospectively. As of September 30,
2002, approximately 22,700 retail customers had elected to purchase energy
from an ARES or the ComEd PPO, an increase from 15,400 customers at
September 30, 2001. The MWhs delivered to such customers increased from
approximately 13.7 million for the nine months ended September 30, 2001 to
16.8 million for the nine months ended September 30, 2002, a 23% increase
from the previous year.
87
o Rate Changes. The decrease attributable to rate changes reflects a 5%
residential rate reduction, effective October 1, 2001, required by the
Illinois restructuring legislation.
o Weather. The weather impact for the nine months ended September 30, 2002
was favorable compared to the nine months ended September 30, 2001 as a result,
of warmer summer weather partially offset by warmer winter weather
in 2002 compared to 2001. Cooling degree-days increased 27% and were
partially offset by a 7% decrease in heating degree-days in the nine months
ended September 30, 2002 compared to the nine months ended September 30,
2001.
o Other Effects. A strong housing construction market in Chicago contributed
to residential and small commercial and industrial customer volume growth
in the early portion of the year, partially offset by the unfavorable
impact of a slower economy on large commercial and industrial customers.
The reduction in wholesale and miscellaneous revenue for the nine
months ended September 30, 2002 as compared to the nine months ended September
30, 2001 was due primarily to a $38 million decrease in off-system sales due to
the expiration of wholesale contracts that were offered by ComEd from June 2000
to May 2001 to support the open access program in Illinois, a $15 million
reversal of reserve for revenue refunds in 2001 related to certain of ComEd's
municipal customers as a result of a favorable FERC ruling, and $15 million of
other miscellaneous revenue partially offset by a reimbursement from Generation
of $12 million for third-party energy reconciliations.
Purchased Power Expense
Purchased power expense decreased $83 million, or 4% for the nine
months ended September 30, 2002. The decrease in purchased power expense was
primarily attributable to a $124 million decrease as a result of customers
choosing to purchase energy from an ARES and a $34 million decrease due to the
expiration of the wholesale contracts offered by ComEd to support the open
access program in Illinois partially offset by a $33 million associated with
increased retail demand due to favorable weather conditions, a $5 million
increase due to the effects of a strong housing construction market in Chicago
for residential and small commercial and industrial customers, a $17 million
increase due to an increase in the weighted average on-peak/off-peak cost per
MWh, and $20 million in additional expense as a result of third-party energy
reconciliations.
Operating and Maintenance Expense
The $7 million decrease in O&M expense was primarily due to operating
productivity improvements and the $11 million reduction in the allowance for
uncollectible accounts recorded in the second quarter, partially offset by a $17
million increase in the provision for injury and damages claims and a $16
million increase in environmental investigation and remediation expense.
88
Depreciation and Amortization Expense
Depreciation and amortization expense decreased $115 million, or 23%,
for the nine months ended September 30, 2002 as follows:
Nine Months Ended September 30,
-------------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
Depreciation Expense $ 258 $ 263 $ (5) (1.9)%
Recoverable Transition Costs Amortization 75 89 (14) (15.7%)
Other Amortization Expense 64 160 (96) (60.0)%
- -------------------------------------------------------------------------------------------------------
Total Depreciation and Amortization $ 397 $ 512 $ (115) (22.5)%
=======================================================================================================
The decrease in depreciation expense is due to $24 million related to
lower depreciation rates partially offset bycannot currently estimate the effect of higher property,
plant and equipment balances.
Recoverable transition costs amortization expense is determined using
the expected periodthese potential changes in tax
laws or regulation.
Cumulative Effect of the rate freeze and the expected returnsa Change in the periods
under the rate freeze. The reduction in amortization expense in 2002 is due to
the second quarter of 2002 extension of the rate freeze partially offset by an
increase due to a third quarter of 2002 change in the expected returns during
the rate freeze period.
The decrease in other amortization expense is primarily due to a
decrease of $97 million due to discontinuation of goodwill amortization
effectiveAccounting Principle
On January 1, 2002 upon the adoption of2003, ComEd adopted SFAS No. 142.
Taxes Other Than Income
Taxes other than143, resulting in income remained consistent from period to period.
Interest Charges
Interest charges decreased $59 million, or 14%, for the nine months
ended September 30, 2002. The decrease in interest charges was primarily
attributable to the impact of
lower interest rates for the nine months ended
September 30, 2002 as compared to the nine months ended September 30, 2001, the
early retirement of the $196 million of First Mortgage Bonds in November of
2001, the retirement of $340 million in transitional trust notes since September
2001, and $10 million of intercompany interest expense in 2001 relating to a
payable in Generation, which was repaid during 2001.
Other Income and Deductions
Other income and deductions, excluding interest charges, decreased $65
million, or 69%, for the nine months ended September 30, 2002. The decrease was
primarily attributable to $8 million in intercompany interest income relating to
the $400 million receivable from PECO which was repaid during the second quarter
of 2001, a $28 million reduction in intercompany interest income from Unicom
Investment Inc., reflecting lower interest rates, $9 million in intercompany
interest income from Generation in 2001 on the processing of certain invoice
payments on behalf of Generation, a $12 million reserve for a potential plant
disallowance resulting from an audit performed in conjunction with ComEd's
delivery services rate case, and an $8 million decrease in various other income
and deductions items.
89
Income Taxes
The effective income tax rate was 39.8% for the nine months ended
September 30, 2002, compared to 44.8% for the nine months ended September 30,
2001. The decrease in the effective tax rate was primarily attributable to the
discontinuation of goodwill amortization as of January 1, 2002, which was not
deductible for income tax purposes.$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.paper or participation in the
intercompany money pool. ComEd's access to external financing at reasonable
terms is dependent on its credit ratings and the general business conditionconditions, as
well as that of ComEd and the utility industry.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 ninethree months
ended September
30, 2002 were $1.5 billion asMarch 31, 2003 compared to $1.0 billion$278 million for the ninethree months ended September 30, 2001.March
31, 2002. The increasedecrease in cash flows in 20022003 was primarily attributable to a
$69$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 a $113 million increase in
other operating activities, and a $315 million increase in working capital
partially offset by a decrease of $115 million in depreciation and amortization.$66 million. ComEd's future cash flows will depend upon the
ability to achieve reductionscost savings in operating costs,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 $526$164 million for the ninethree
months ended September 30, 2002March 31, 2003 compared to $231$175 million for the ninethree months ended
September 30, 2001.March 31, 2002. The increasedecrease in cash flows used in investing activities in 20022003
was primarily attributable to the paydown of the $400 million
outstanding receivable with PECO in the second quarter of 2001 partially offset
by an $82$8 million decrease in capital expenditures.
ComEd's investing activities
for the nine months ended September 30, 2002 were funded primarily through
operating activities.
ComEd estimatedestimates that it will spend approximately $781$720 million in total
capital expenditures for 2002.2003. Approximately two thirdstwo-thirds of the budgeted 20022003
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 itits capital expenditures will obtain financing, when necessary, throughbe 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.
90
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 activities for the nine months ended
September 30, 2002 were $970 million as compared to $518of $44
million for the ninethree months ended September 30, 2001.March 31, 2002. Cash flows used infrom financing
activities were primarily attributable to debt serviceissuance 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 for the nine months ended September 30, 2002
reflected the issuance of $600 million of First Mortgage Bonds, the issuance of
$100 million of Illinois Development Finance Authority floating-rate Pollution
Control Revenue Refunding Bonds, the retirement of $254 million of transitional
trust notes, the early retirement of $600 million in First Mortgage Bonds with
available cash, the payment at maturity of $200 million in First Mortgage Bonds,
the payment at maturity of $200 million in variable rate senior notes, and the
redemption of $100 million of 7.25% Illinois Development Finance Authority
Pollution Control Revenue Refunding Bonds. As of September 30, 2002, ComEd had
$94 million in short-term borrowings. For the nine months ended September 30,
2001, ComEd's debt financing activities reflected the retirement of $254 million
of transitional trust notes.activities. ComEd
paid a $353$120 million dividend to Exelon during the ninethree months ended September 30, 2002March 31,
2003 compared to a $253$118 million dividend for the ninethree months ended September 30, 2001.March 31,
2002.
79
Credit Issues
ComEd meets its short-term liquidity requirements primarily through the
issuance of commercial paper borrowings under a bank credit facility 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 effective December 12, 2001. Under the
terms of thisbanks. 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 has the flexibility tomay increase or decrease the
sublimits of each of the participants upon written notification to thesethe banks. As
of September 30, 2002,March 31, 2003, ComEd's sublimit under thiswas $100 million. The credit facility is
$200 million. ComEd expects to use the credit facilityused principally to support itsComEd's commercial paper program. ThisAt 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 total capitalization ratio of 65% or less, excluding
securitization debt.1 for the twelve-month
period ended March 31, 2003. At September 30, 2002, ComEd's debt to total capitalization
ratio on that basisMarch 31, 2003, ComEd was 42%. At September 30, 2002, ComEd has $94 million in commercial paper outstanding.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.
Exelon,corporate treasurer.
ComEd and its subsidiary Commonwealth Edison of Indiana, Inc., PECO, Generation
and Business Services Company currentlyBSC may participate in the money pool.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
fund.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 have beenwere 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 areis subject to default or prepayment as a
result of a downgrading of creditsecurities ratings although such a downgrading could
increase interest charges under certain bank credit facilities.
91
At September 30, 2002, ComEd's capital structure, excluding the
deduction from shareholders' equity of the $845 million receivable from Exelon,
consisted of 48% long-term debt, 49% of common stock, 3% of preferred securities
of subsidiaries, and 1% of notes payable. Long-term debt included $2.1 billion
of transitional trust notes constituting obligations of certain consolidated
special purpose entities representing 16% of capitalization.
Under PUHCA, and the Federal Power Act, ComEd can only pay dividends from retained or current
earnings: however,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 September 30, 2002,March 31, 2003, ComEd had retained earnings of
$480 million.$652 million and its common equity ratio was 46%.
Long-term debt included $1.9 billion of transitional trust notes.
Contractual Obligations, and 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 September 30, 2002March 31, 2003 were materially unchanged, other than in the
normal course of business, from the amounts as set forth in the December 31,
20012002 Form 10-K
except for the issuancefollowing:
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 $600 millionthe
PPA with Generation. The parties to the Agreement agreed to make and
support a series of 6.15% First Mortgage
Bonds, Series 98, due March 15, 2012,coordinated filings intended to lead to the
issuance by the ICC of $100 millionorders 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 Illinois
Development Finance Authority floating-rate Pollution Control Revenue Refunding
Bonds, Series 2002 due April 15, 2013,May 2003. The Agreement will
not become effective as long as the redemptionICC orders are subject to any
rehearing request or if a stay is issued with respect to any of $100 millionthose
orders.
The Agreement provides for a modification of 7.25%
Illinois Development Finance Authority Pollution Control Revenue Refunding
Bonds, Series 1991 due June 1, 2011, the redemption of $200 million of 8.625%
First Mortgage Bonds, Series 81, due February 1, 2022,methodology used
to determine ComEd's market value energy credit. That credit is used to
determine the redemption of $200
million of 8.5% First Mortgage Bonds, Series 84 due July 15, 2022, the payment
at maturity of $200 million of 7.375% First Mortgage Bonds, Series 85, due
September 15, 2002, the redemption of $200 million of 8.375% First Mortgage
Bonds, Series 86, due September 15, 2022, the payment at maturity of $200
million of variableprice for specified market-based rate senior notes due September 30, 2002, the payment at
maturity of $100 million of 9.17% medium-term notes due October 15, 2002,offerings and the
retirementamount of $254the 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 transitional trust notes. At September 30,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 ComEd had $94for a potential capital disallowance in ComEd's delivery services
rate proceeding and a credit of $10 million in short-term borrowings. Insured long-term debt
increased $100 million(before income taxes) related
to the issuancecapitalization of $100employee incentive payments provided for in the
delivery services order. The net one-time charge for these items is $29
million in variable rate
debt that(before income taxes).
o ComEd has been credit enhanced throughentered into several agreements with a tax consultant
related to the purchasefiling of insurance coverage.
Other Factors
ComEd isrefund claims with the IRS. The fees for
these agreements are contingent upon a participant in Exelon's pensionsuccessful outcome and postretirement benefit
plans. ComEd's costs of providing pension and postretirement benefits to its
retirees are
dependentbased upon a number of factors, such as the discount rate, rates of
return on plan assets, and the assumed rate of increase in health care costs.
Approximately $17 million was included in operating and maintenance expense in
2001 for the cost of pension and post-retirement benefit plans, exclusivepercentage of the 2001 charges for employee severance programs.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 costs are expectedpotential
tax benefits and associated fees could be material to remain
consistent in 2002 but are preliminarily expected to increase by approximately
$25 million in 2003 as a resultthe financial
position, results of operations and cash flows of ComEd. ComEd cannot
predict the timing of the effectsfinal 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 decline in market value of
plan assets and discount rates, and increases in health care costs. The actual
amount ofCondensed Combined Notes to Consolidated Financial
Statements for commercial commitments tables representing ComEd's
commitments not recorded on the 2003 increase will depend on market conditions.
92
Exelon's defined benefit pension plans, of which ComEd is a
participant, currently meet the minimum funding requirements of the Employment
Retirement Income Security Act of 1974; however, Exelon currently expectsbalance sheet but potentially
triggered by future events, including obligations to make a discretionary plan contribution in the fourth quarterpayment on
behalf of 2002 of $100
millionother parties and financing arrangements to $200 million and a discretionary plan contribution in 2003 of $300
million to $350 million. These contributions are expected to be funded primarily
by Exelon's internally generated cash flows from operations or through external
sources.
93secure their
obligations.
82
PECO ENERGY COMPANY
- -------------------
GENERAL
PECO operates in a single business segment, Energy Delivery, and its operations consist
of its retailthe regulated sale of electricity and distribution and transmission
business in
southeastern Pennsylvania and itsthe sale of natural gas and distribution businessservices
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 September 30,March 31,
---------------------------
2003 2002 Compared to Three Months Ended September 30, 2001
Significant Operating Trends - PECO Three Months Ended September 30,
--------------------------------
2002 2001 Variance % Change
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 1,224 $1,0511,217 $1,020 $ 173 16.5%197 19.3%
OPERATING EXPENSES
Purchased Power 509 420 89 21.2%422 351 71 20.2%
Fuel 40 51 (11) (21.6%)191 135 56 41.5%
Operating and Maintenance 140 156 (16) (10.3%)139 136 3 2.2%
Depreciation and Amortization 127 115 12 10.4%120 112 8 7.1%
Taxes Other Than Income 85 51 34 66.7%63 59 4 6.8%
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Operating Expense 901Expenses 935 793 108 13.6%142 17.9%
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 323 258 65 25.2%282 227 55 24.2%
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (93) (105) 12 (11.4%(86) (95) 9 (9.5%)
Distributions on Company-Obligated Mandatorily
Redeemable Preferred Securities of a Partnership
which holdsHolds Solely Subordinated Debentures of
the Company (2) (2) -- --
Other, net 5 12 (7) (58.3%)Net 9 1 8 n.m.
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Other Income and Deductions (90) (95) 5 (5.3%(79) (96) 17 (17.7%)
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 233 163 70 42.9%203 131 72 55.0%
INCOME TAXES 76 59 17 28.8%66 42 24 57.1%
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
NET INCOME 157 104 53 51.0%137 89 48 53.9%
Preferred Stock Dividends (2) (2) -- --
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
NET INCOME ON COMMON STOCK $ 155135 $ 10287 $ 53 52.0%
=======================================================================================================48 55.2%
======================================================================================================
n.m. - not meaningful
83
Net Income
Net income on common stock increased $53$48 million, or 52%55% for the quarterthree
months ended September 30, 2002March 31, 2003 as compared to the same 2001 period.period in 2002. The increase
was a result of higher sales volume favorable rate adjustments, lower
operating and maintenance expense related to employee severance costs in 2001
associated with the Merger, and lower interest expense on debt,
partially offset by increased income taxes and depreciation and amortization
expense.
94
Operating RevenuesRevenue
PECO's electric sales statistics are as follows:
Three Months Ended September 30,
--------------------------------March 31,
----------------------------
Retail Deliveries - (in GWh)GWhs) 2003 2002 2001 Variance % Change
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Bundled Deliveries (1)
Residential 3,422 2,175 1,247 57.3%3,115 2,056 1,059 51.5%
Small Commercial & Industrial 2,066 1,990 76 3.8%1,780 1,757 23 1.3%
Large Commercial & Industrial 4,006 3,835 171 4.5%3,482 3,351 131 3.9%
Public Authorities & Electric Railroads 224253 193 31 16.1%60 31.1%
- -------------------------------------------------------------------------------------------------------
9,718 8,193 1,525 18.6%-------------------------------------------------------------------------------------------------------------------
8,630 7,357 1,273 17.3%
- --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Unbundled Deliveries (2)
Residential 371 990 (619) (62.5%264 792 (528) (66.7%)
Small Commercial & Industrial 154 100 54 54.0%202 96 106 110.4%
Large Commercial & Industrial 236 249 (13) (5.2%)210 103 107 103.9%
Public Authorities & Electric Railroads (3) -- -- -- --0.0%
- -------------------------------------------------------------------------------------------------------
761 1,339 (578) (43.2%-------------------------------------------------------------------------------------------------------------------
676 991 (315) (31.8%)
- -------------------------------------------------------------------------------------------------------------------
Total Retail Deliveries 10,479 9,532 947 9.9%
=======================================================================================================
9,306 8,348 958 11.5%
===================================================================================================================
(1) Bundled service reflects deliveries to customers taking electric service
under tariffed rates, which include the cost of energy, the delivery cost
of the transmission and distribution of the energy and a CTC charge.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 September 30,
--------------------------------March 31,
----------------------------
Electric Revenue 2003 2002 2001 Variance %Change% Change
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Bundled Revenue (1)
Residential $ 478359 $ 304243 $ 174 57.2%116 47.7%
Small Commercial & Industrial 251 236 15 6.4%194 189 5 2.6%
Large Commercial & Industrial 296 282 14 5.0%266 244 22 9.0%
Public Authorities & Electric Railroads 21 19 2 10.5%22 18 4 22.2%
- -------------------------------------------------------------------------------------------------------
1,046--------------------------------------------------------------------------------------
841 205 24.4%694 147 21.2%
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Unbundled Revenue (2)
Residential 32 81 (49) (60.5%17 54 (37) (68.5%)
Small Commercial & Industrial 910 5 4 80.0%5 100.0%
Large Commercial & Industrial 7 7 -- --6 3 3 100.0%
Public Authorities & Electric Railroads (3) -- -- -- --
- -------------------------------------------------------------------------------------------------------
48 93 (45) (48.4%--------------------------------------------------------------------------------------
33 62 (29) (46.8%)
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Electric Retail Revenues 1,094 934 160 17.1%874 756 118 15.6%
Wholesale and Miscellaneous Revenue (3) 63 42 21 50.0%(4) 55 55 -- --
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Electric Revenue $ 1,157929 $ 976811 $ 181 18.5%
=======================================================================================================
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 the cost of energy, the delivery cost
of the transmission and distribution of the energy and a CTC charge.
(2) Unbundled revenue reflects revenue from customers electing to receive
generation from an alternate supplier, which include 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 sales to
municipalities and other wholesale energy sales.
95
The changes in electric retail revenues for the quarterthree months ended
September
30, 2002,March 31, 2003, as compared to the same 2001 period in 2002, are as follows:
Variance
- ------------------------------------------------------------------------------------------------------------
Weather $ 60
Customer Choice 40
Rate Changes 16
Other Effects 44
- ------------------------------------------------------------------------------------------------------------
Electric Retail Revenue $ 160
- ------------------------------------------------------------------------------------------------------------
Variance
- ----------------------------------------------------------------
Weather $47
Volume 43
Customer Choice 19
Other Effects 9
- -----------------------------------------------------------------
Retail Revenue $118
- -----------------------------------------------------------------
o Weather. The demand for electricity services is impacted by weather
conditions. Very warm weather in summer months and very cold weather in
other months is referred to as "favorable weather conditions", relative to
revenue because these weather conditions result in increased sales of
electricity. Conversely, mild weather reduces demand. The weather impact was favorable compared to the prior year
as a result of warmer summercolder winter weather. CoolingHeating degree-days increased
20%33% for the quarterthree months ended September 30, 2002March 31, 2003 compared to the same
2001 period.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 have the choicemay 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 September 30, 2002,March 31, 2003, the customer load served by alternatealternative suppliers
was 973 MW1,062 MWs or 12.5%13.1% as compared to 1,042 MW1,010 MWs or 13.6%13.1% as of September 30, 2001.March 31, 2002.
For the quarterthree months ended September 30, 2002,March 31, 2003, the percent of PECO's total retail
deliveries for which PECO was the electric supplier was 92.8% in 2002, a 6.8% increase as compared to 86.0%88.2%
in 2001.2002. As of September 30, 2002,March 31, 2003, the
number of customers served by alternate suppliers
was 285,549 or 18.7% as compared to September 30, 2001 of 397,396 or 26.1%.
The increases in the customer load and the percentage of MWh served by
PECO, and the decrease in the85
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 February 2002, New Power Company (New Power) notifiedJanuary 2003, PECO ofsubmitted to the PUC an MST plan to meet the 50%
threshold requirement for its intent to withdraw from providing Competitive Default Service (CDS) to
approximately 180,000 residential customers. As a result of that
withdrawal, those CDScommercial customers, were returned to PECO in the second quarter
of 2002. Pursuant to a tariff filingwhich was approved by the
Pennsylvania Public
Utility Commission (PUC), PECO is serving those returned customers at the
discount energy rates on generation provided for under the original New
Power CDS AgreementPUC in February 2003. As of March 31, 2003, an auction had been completed for
the remaining term of that contract. Subsequently,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 second quarterprogram. 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 2002, New Power also advised PECO it plannedup to withdraw from serving all of its400,000 residential
customers being assigned to winning alternative electric generation supplier
bidders: up to 100,000 in Pennsylvania, including
approximately 15,000 non-CDS PECO customers. These customers were returnedJuly 2003, and another 300,000 in December 2003. Any
customer transferred would have the right to return to PECO duringat any time. PECO
does not expect the third quartertransfer of 2002.customers pursuant to the MST plan to have a
material impact on its results of operations, financial position or cash flows.
o Rate Changes.Other Effects. The increase in revenues attributable to rate changes
primarily reflects a $13 million increase due to an increase in the gross
receipts tax rate effective January 1, 2002.
As permitted by the Pennsylvania Electric Competition Act, the
Pennsylvania Department of Revenue has calculated a 2002 Revenue Neutral
Reconciliation (RNR) adjustmentaverage price mix related to the
gross receipts tax rate in order to
neutralize the impact of electric restructuring on its tax revenues. In
January 2002, the Pennsylvania Public Utility Commission (PUC) approved the
96
RNR adjustmentlarge commercial and industrial customer class as compared to the gross receipts tax rate collected from customers.
Effective January 1,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 PECO implementedare 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 changeprior year
as a result of colder winter weather. Heating degree-days increased
33% in the gross
receipts tax rate. The RNR adjustment increases the gross receipts tax
rate, which is estimated to increase both PECO's annual revenues and tax
obligations by approximately $50 million in 2002. The RNR adjustment was
under appeal. The case was remandedthree months ended March 31, 2003 compared to the PUC andsame
period in August 2002, the PUC
ruled that PECO is properly authorized to recover these costs.
o Other Effects. Other items affecting revenue during the quarter ended
September 30, 2002 include:2002.
o Volume. Exclusive of weather impacts, higher delivery volume increased
PECO's revenue by $44 millionin the three months ended March 31, 2003 compared to the same
2001 period.
o Other. A paymentperiod in 2002 resulting from customer growth. Deliveries to
customers, excluding the effects of $7 million duringweather, increased 5% in the quarterthree
months ended September 30,
2002 as compared to a payment of $21 million during the quarter ended
September 30, 2001 to Generation related to nuclear decommissioning
cost recovery under an agreement effective September 2001.
PECO's gas sales statistics for the quarter ended September 30, 2002 asMarch 31, 2003 compared to the same 2001 period are as follows:
Three Months Ended September 30,
--------------------------------
2002 2001 Variance
- --------------------------------------------------------------------------------------------------------------------
Deliveries in mmcf 11,347 10,525 822
Revenue $67 $ 75 $ (8)
- --------------------------------------------------------------------------------------------------------------------
The changes in gas revenue for the quarter ended September 30, 2002, as
compared to the same 2001 period, are as follows:
(in millions) Variance
- -------------------------------------------------------------------------------------------------------------
Rate Changes $ (4)
Weather (3)
Volume (1)
- -------------------------------------------------------------------------------------------------------------
Gas Revenue $ (8)
- -------------------------------------------------------------------------------------------------------------
2002.
o Rate Changes. The unfavorablefavorable variance in rates is attributable to an
adjustment ofa 15%
increase in the purchased gas cost recoveryadjustment by the PUC effective in
December 2001.March 1,
2003. The average rate per million cubic feet for the quarterthree months
ended September 30, 2002March 31, 2003 was 17% lower9% higher than the same 20012002 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.
o Weather. The demand for gas service is impacted by weather conditions. Very
cold weather in winter months is referred to as a "favorable weather
condition," because this weather condition results in increased sales of
gas. Conversely, mild weather reduces demand. Heating degree-days decreased
92% in the quarter ended September 30, 2002 compared to the same 2001
period.
o Volume. Exclusive of weather impact, delivery volume was consistent for the
quarter ended September 30, 2002 compared to the same 2001 period.
97
Purchased Power
and Fuel Expense
Purchased power and fuel expense for the quarterthree months ended September 30,
2002March 31, 2003
increased $78$71 million as compared to the same 2001 period.period in 2002. The increase in
fuel and
purchased power expense was primarily attributable to $38$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 $24and $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, $13$8
million primarily attributable to higher delivery volumevolumes and higher PJM
ancillary charges of $11 million. These increases were partially offset by $4$3 million from lowerhigher gas
prices.
87
Operating and Maintenance Expense
O&M expense for the quarterthree months ended September 30, 2002 decreased $16March 31, 2003 increased $3
million, or 10%2%, as compared to the same 2001 period.period in 2002. The decreaseincrease in O&M
expense was primarily attributable to $18 million of employee severance costs
associated with the Merger and $6$4 million of incremental storm costs related to a
storm, bothin
2003, $4 million of which occurred in the third quarteradditional employee benefits costs and $8 million of
2001. The decreases areadditional miscellaneous other net positive impacts partially offset by $7
million related to an increased allocationlower corporate allocations and $6 million of corporate
expense and $3 million related tolower costs
associated with the deployment of automated meter reading technology.
Depreciation and Amortization
Expense
Depreciation and amortization expense for the quarterthree months ended September
30, 2002March
31, 2003 increased $12$8 million, or 10%7%, as compared to the same 2001 period in 2002 as
follows:
Three Months Ended September 30,
--------------------------------March 31,
----------------------------
2003 2002 2001 Variance % Change
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Depreciation Expense $ 31 $ 30 $ 1 3.3%
Competitive Transition Charge Amortization 90 78 12 15.4%$ 81 $ 75 $ 6 8.0%
Depreciation Expense 33 32 1 3.1%
Other Amortization Expense 6 7 (1) (14.3%)5 1 20.0%
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Depreciation and Amortization $ 127120 $ 115112 $ 12 10.4%
=======================================================================================================8 7.1%
====================================================================================================
The increase was primarily attributable to $12 million of additional
amortization of PECO's CTC and an increase of $1 million related to depreciation
expense associated with additional plant in service.
The additional amortization of the CTC is in accordance with PECO's
original settlement under the Pennsylvania Competition Act.Act and the increase in
depreciation expense resulted from additional plant in service.
Taxes Other Than Income
Taxes other than income for the quarterthree months ended September 30, 2002March 31, 2003
increased $34$4 million, or 67%7%, as compared to the same 2001 period.period in 2002. The
increase was primarily attributable to $14$7 million of additional gross receipts
tax related to additional revenues, and an increasepartially offset by a $2 million decrease in the gross receipts tax rate on
electric revenue effective January 1, 2002. The increase was also attributable
to a reduction of $9 million in the state use tax accruals in 2001 and $7
million related to an additional assessment of
real estate taxes in the third
quarter of 2002.
98
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 $12$9 million, or 11%10%, in the quarterthree months
ended September 30, 2002March 31, 2003 as compared to the same 2001 period.period in 2002. The decrease was
primarily attributable to lower interest expense on long-term debt of $15$9 million
as a result of scheduled principal payments and refinancing of existing debt at
lower interest rates.
Other, Income and DeductionsNet
Other, Net increased income and deductions excluding interest charges forby $8 million in the quarterthree months ended
September 30, 2002 decreased $7 million, or 58%,March 31, 2003 as compared to the same 2001 period.period in 2002. The decreaseincrease in other
income and deductions was primarily attributable to intercompanyhigher interest income of $9 million in the third quarter
of 2001.
Income Taxes
The effective tax rate was at 32.6% for the quarter ended September 30,
2002 as compared to 36.2% for the same 2001 period. The decrease in the
effective tax rate was primarily attributable to a favorable adjustment to prior
period income taxes in connection with the completion of the 2001 tax return.
Preferred Stock Dividends
Preferred stock dividends for the quarter ended September 30, 2002 were
consistent as compared to the same 2001 period.
99
Nine Months Ended September 30, 2002 Compared to Nine Months Ended September 30,
2001
Significant Operating Trends - PECO
Nine Months Ended September 30,
--------------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 3,239 $3,008 $ 231 7.7%
OPERATING EXPENSES
Purchased Power 1,265 1,019 246 24.1%
Fuel 228 335 (107) (31.9%)
Operating and Maintenance 407 413 (6) (1.5%)
Depreciation and Amortization 348 315 33 10.5%
Taxes Other Than Income 207 135 72 53.3%
- -------------------------------------------------------------------------------------------------------
Total Operating Expense 2,455 2,217 238 10.7%
- -------------------------------------------------------------------------------------------------------
OPERATING INCOME 784 791 (7) (0.9%)
- -------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (280) (332) 52 (15.7%)
Distributions on Company-Obligated Mandatorily
Redeemable Preferred Securities of a Partnership
which holds Solely Subordinated Debentures of
the Company (7) (7) -- --
Other, net 7 30 (23) (76.7%)
- -------------------------------------------------------------------------------------------------------
Total Other Income and Deductions (280) (309) 29 (9.4%)
- -------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 504 482 22 4.6%
INCOME TAXES 166 171 (5) (2.9%)
- -------------------------------------------------------------------------------------------------------
NET INCOME 338 311 27 8.7%
Preferred Stock Dividends (6) (7) 1 (14.3%)
- -------------------------------------------------------------------------------------------------------
NET INCOME ON COMMON STOCK $ 332 $ 304 $ 28 9.2%
=======================================================================================================
Net Income
Net income on common stock increased $28 million, or 9%, for the nine
months ended September 30, 2002 as compared to the same 2001 period. The
increase was a result of higher sales volume, favorable rate adjustments, lower
operating and maintenance expense related to employee severance costs in 2001
associated with the Merger, and lower interest expense on debt partially offset
by increased depreciation and amortization expense.
100
Operating Revenue
PECO's electric sales statistics are as follows:
Nine Months Ended September 30,
--------------------------------
Deliveries - (in GWh) 2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
Bundled Deliveries (1)
Residential 7,592 6,307 1,285 20.4%
Small Commercial & Industrial 5,704 4,303 1,401 32.6%
Large Commercial & Industrial 11,285 9,538 1,747 18.3%
Public Authorities & Electric Railroads 617 567 50 8.8%
- -------------------------------------------------------------------------------------------------------
25,198 20,715 4,483 21.6%
- -------------------------------------------------------------------------------------------------------
Unbundled Deliveries (2)
Residential 1,720 2,365 (645) (27.3%)
Small Commercial & Industrial 253 1,516 (1,263) (83.3%)
Large Commercial & Industrial 351 2,170 (1,819) (83.8%)
Public Authorities & Electric Railroads -- 7 (7) (100.0%)
- -------------------------------------------------------------------------------------------------------
2,324 6,058 (3,734) (61.6%)
- -------------------------------------------------------------------------------------------------------
Total Retail Deliveries 27,522 26,773 749 2.8%
- -------------------------------------------------------------------------------------------------------
(1) Bundled service reflects deliveries to customers taking electric service
under tariffed rates, which include the cost of energy, the delivery cost
of the transmission and distribution of the energy and a CTC charge.
(2) Unbundled service reflects customers electing to receive electric
generation service from an alternative energy supplier.
Nine Months Ended September 30,
--------------------------------
Electric Revenue 2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
Bundled Revenue (1)
Residential $ 999 $ 807 $ 192 23.8%
Small Commercial & Industrial 664 500 164 32.8%
Large Commercial & Industrial 829 689 140 20.3%
Public Authorities & Electric Railroads 58 53 5 9.4%
- -------------------------------------------------------------------------------------------------------
2,550 2,049 501 24.5%
- -------------------------------------------------------------------------------------------------------
Unbundled Revenue (2)
Residential 129 184 (55) (29.9%)
Small Commercial & Industrial 13 73 (60) (82.2%)
Large Commercial & Industrial 10 61 (51) (83.6%)
Public Authorities & Electric Railroads -- 1 (1) (100.0%)
- -------------------------------------------------------------------------------------------------------
152 319 (167) (52.4%)
- -------------------------------------------------------------------------------------------------------
Total Electric Retail Revenues 2,702 2,368 334 14.1%
Wholesale and Miscellaneous Revenue (3) 179 158 21 13.3%
- -------------------------------------------------------------------------------------------------------
Total Electric Revenue $ 2,881 $ 2,526 $ 355 14.1%
=======================================================================================================
(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 distribution of the energy and a CTC charge.
(2) Unbundled revenue reflects revenue from customers electing to receive
generation from an alternate supplier, which include a distribution charge
and a CTC charge.
(3) Wholesale and miscellaneous revenues include transmission revenue, sales to
municipalities and other wholesale energy sales.
101
The changes in electric retail revenues for the nine months ended
September 30, 2002, as compared to the same 2001 period, are as follows:
Variance
- -----------------------------------------------------------------------------------------------------
Customer Choice $ 205
Rate Changes 45
Weather 42
Other Effects 42
- -----------------------------------------------------------------------------------------------------
Electric Retail Revenue $ 334
=====================================================================================================
o Customer Choice. As of September 30, 2002, the customer load served by
alternate suppliers was 973 MW or 12.5% as compared to 1,042 MW or 13.6% as
of September 30, 2001. For the nine months ended September 30, 2002, the
percent of PECO's total retail deliveries for which PECO was the electric
supplier was 91.6% in 2002, a 14.1% increase as compared to 77.4% in 2001.
As of September 30, 2002, the number of customers served by alternate
suppliers was 285,549 or 18.7% as compared to September 30, 2001 of 397,396
or 26.1%. This increase in the customer load and the percentage of MWh
served by PECO, and the decrease in the number of customers served by
alternative suppliers primarily resulted from customers selecting or
returning to PECO as their electric generation supplier.
o Rate Changes. The increase in revenues attributable to rate changes
primarily reflects the expiration of a 6% reduction in PECO's electric
rates during the first quarter of 2001 and a $39 million increase as a
result of the increase in the gross receipts tax rate effective January 1,
2002. These increases are partially offset by the timing of a $60 million
rate reduction in effect for 2001 and 2002.
o Weather. The weather impact was favorable compared to the prior year as a
result of warmer summer weather partially offset by warmer winter weather.
Cooling degree-days increased 14% for the nine months ended September 30,
2002 compared to the same 2001 period. Heating degree-days decreased 16%
for the nine months ended September 30, 2002 compared to the same 2001
period.
o Other Effects. Other items affecting revenue during the nine months ended
September 30, 2002 include:
o Volume. Exclusive of weather impacts, higher delivery volume increased
PECO's revenue by $53 million compared to the same 2001 period.
o Other. An $11 million settlement of CTCs by a large customer in the
first quarter of 2001.
PECO's gas sales statistics for the nine months ended September 30,
2002 as compared to the same 2001 period are as
follows:
Nine Months Ended September 30,
--------------------------------
2002 2001 Variance
- ---------------------------------------------------------------------------------------------------------------------
Deliveries in mmcf 56,990 58,536 (1,546)
Revenue $358 $482 $ (124)
- ---------------------------------------------------------------------------------------------------------------------
102
The changes in gas revenue for the nine months ended September 30,
2002, as compared to the same 2001 period, are as follows:
Variance
- -----------------------------------------------------------------------------------------------------
Rate Changes $ (67)
Weather (33)
Volume (23)
Other (1)
- -----------------------------------------------------------------------------------------------------
Gas Revenue $ (124)
=====================================================================================================
o Rate Changes. The unfavorable variance in rates is attributable to an
adjustment of the purchased gas cost recovery by the PUC effective in
December 2001. The average rate per million cubic feet for the nine months
ended September 30, 2002 was 23% lower than the same 2001 period.
o Weather. The unfavorable weather impact is attributable to warmer winter
weather during the nine months ended September 30, 2002 as compared to the
same 2001 period. Heating degree-days decreased 16% in the nine months
ended September 30, 2002 compared to the same 2001 period.
o Volume. Exclusive of weather impacts, lower delivery volume reduced revenue
by $23 million in the nine months ended September 30, 2002 compared to the
same 2001 period. Total deliveries to customers decreased 3% in the nine
months ended September 30, 2002 compared to the same 2001 period, primarily
as a result of slower economic conditions in 2002 partially offset by
increased customer growth.
Purchased Power and Fuel Expense
Purchased power and fuel expense for the nine months ended September
30, 2002 increased $139 million as compared to the same 2001 period. The
increase in fuel and purchased power expense was primarily attributable to $187
million from customers in Pennsylvania selecting or returning to PECO as their
electric generation supplier and higher PJM ancillary charges of $28 million.
These increases were partially offset by $67 million from lower gas prices, $8
million from lower delivery volume primarily related to gas and $6 million as a
result of unfavorable weather conditions.
Operating and Maintenance Expense
O&M expense for the nine months ended September 30, 2002 decreased $6
million, or 2%, as compared to the same 2001 period. The decrease in O&M expense
was primarily attributable to $18 million of employee severance costs associated
with the Merger, $12 million of incremental costs related to two storms and $5
million associated with a write-off of excess and obsolete inventory, all of
which occurred in 2001. These decreases are partially offset by $16 million
related to an increased allocation of corporate expense and $15 million related
to the deployment of automated meter reading technology.
103
Depreciation and Amortization Expense
Depreciation and amortization expense for the nine months ended
September 30, 2002 increased $33 million, or 11%, as compared to the same 2001
period as follows:
Nine Months Ended September 30,
--------------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
Depreciation Expense $ 94 $ 89 $ 5 5.6%
Competitive Transition Charge Amortization 236 207 29 14.0%
Other Amortization Expense 18 19 (1) (5.3%)
- -------------------------------------------------------------------------------------------------------
Total Depreciation and Amortization $ 348 $ 315 $ 33 10.5%
=======================================================================================================
The increase was primarily attributable to $29 million of additional
amortization of PECO's CTC and an increase of $5 million related to depreciation
expense associated with additional plant in service. The additional amortization
of the CTC is in accordance with PECO's original settlement under the
Pennsylvania Competition Act.
Taxes Other Than Income
Taxes other than income for the nine months ended September 30, 2002
increased $72 million, or 53%, as compared to the same 2001 period. The increase
was primarily attributable to $54 million of additional gross receipts tax
related to additional revenues and an increase in the gross receipts tax rate on
electric revenue effective January 1, 2002. The increase was also attributable
to a reduction of $9 million in the state use tax accruals in 2001 and $7
million related to an additional assessment of real estate taxes in the third
quarter of 2002.
Interest Charges
Interest charges decreased $52 million, or 16%, for the nine months
ended September 30, 2002 as compared to the same 2001 period. The decrease was
primarily attributable to lower interest expense on long-term debt of $40
million as a result of principal payments and lower interest rates, and $8
million in interest expense on a loan from ComEd in 2001.
Other Income and Deductions
Other income and deductions excluding interest charges decreased $23
million, or 77%, for the nine months ended September 30, 2002 as compared to the
same 2001 period. The decrease in other income and deductions was primarily
attributable to lower interest income of $7 million in 2002. The decrease was
also attributable to intercompany interest income of $10 million, a gain on the
settlement of an interest rate swap of $6 million and
the favorable settlement of a customer contract of $3 million, all of which occurred in 2001.million.
88
Income Taxes
The effective tax rate was 32.9%32.5% for the ninethree months ended September
30, 2002March 31,
2003 as compared to 35.5%32.1% for the same 2001 period. The decreaseperiod 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 rate was primarily attributable to a favorable adjustment to prior
period income taxes in connection with the completion of the 2001 tax return.laws
or regulation.
Preferred Stock Dividends
Preferred stock dividends for the quarterthree months ended September 30, 2002March 31, 2003
were consistent as compared to the same 2001 period.
104
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.paper or participation in the
intercompany money pool. PECO's access to external financing at reasonable terms
is dependent on its credit ratings and the general business conditionconditions, as well as
that of PECO and the utility industry.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 ninethree months ended September
30,March 31,
2003 and 2002 were $473$126 million compared to $744and $100 million, for the nine months ended
September 30, 2001.respectively. The decreaseincrease in
cash flows from operating activities was primarily attributable to higher payments relateda $99 million increase in working
capital and a $48 million increase to accrued expenses of $255
million and changes in intercompany receivables and payables of $181 million.
These decreases werenet income, partially offset by lower payments related to accounts
payable of $54a $66
million higher collection ofdecrease in deferred taxes and a $62 million change in deferred energy
costs as a result
of a change in gas rates of $36 million, higher CTC amortization of $29 million,
higher net income of $27 million and changes in material and supply inventories
of $13 million.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 ninethree months ended
September 30, 2002March 31, 2003 were $177$59 million, compared to $154$65 million for the ninethree months
ended September 30, 2001.March 31, 2002. The increasedecrease in cash flows used in investing activities
was primarily attributable to an increasea decrease in capital expenditures.
PECO's investing activities during the nine months ended September 30, 2002 were
funded primarily by operating activities.
PECO's projected capital expenditures for 20022003 are $279$270 million.
Approximately one half of the budgeted 20022003 expenditures are for capital
additions to support customer and load growth and the remainder for additions
and upgrades to existing facilities. PECO anticipates that itits capital
expenditures will obtain
financing, when necessary, throughbe 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 ninethree months ended
September 30,March 31, 2003 and 2002 were $214$26 million compared to $508and $36 million, for the nine
months ended September 30, 2001.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 a changeadditional issuances of long-term debt
in commercial paper borrowingsthe first quarter of $435 million, a change in
105
intercompany payable2003 of $41 million, lower debt service of $16$250 million, partially offset by lower contributions from Exelonadditional
debt service of $91 million, additional dividends
paid$204 million. See Notes 10 and 14 of the Condensed Combined
Notes to Exelon in 2002Consolidated Financial Statements for further discussion of $86 million, andPECO's debt
financing activities. For the change in settlement of interest
rate swap agreements of $36 million.three months ended March 31, 2003, PECO paid
a $255Exelon $89 million dividendin common stock dividends compared to Exelon
during$85 million for the
ninethree months ended September 30, 2002 compared to a $169 million
dividend for the nine months ended September 30, 2001.March 31, 2002.
90
Credit Issues
PECO meets its short-term liquidity requirements primarily through the
issuance of commercial paper borrowings under a bank credit facility 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 effective December 12, 2001. Under the
terms of thisbanks. 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 has the flexibility tomay increase or decrease the
sublimits of each of the participants upon written notification to thesethe banks. As
of September 30, 2002,March 31, 2003, PECO's sublimit under thewas $600 million. The credit facility is $600 million.used
by PECO expects to use the credit facility principally to support its commercial paper program. ThisAt 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 debtcash from operations to
total capitalizationinterest expense ratio for the twelve-month period ended on the last day of 65% or less, excludingany
quarter. The ratio excludes revenues and interest expenses attributable to
securitization debt, certain changes in working capital and excludingdistributions on
preferred securities of subsidiaries. PECO's threshold for the receivable from parent recordedratio 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 shareholders'
equity. At September 30, 2002, PECO's debtborrowings is subject to total capitalization ratio on that
basis was 41%. At September 30, 2002, PECO has $375 million in commercial paper
outstanding.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 the Exelon Corporate Treasurer.
Exelon,Exelon's corporate treasurer.
ComEd and its subsidiary Commonwealth Edison of Indiana, Inc., PECO, Generation
and Business Services Company currentlyBSC may participate in the money pool.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
fund.money pool. Interest on borrowings is based on short-term market rates of
interest, or, if from an external source, specific borrowing rates if the funds are provided by external financing.rates. There have beenwere
no material money pool transactions in 2002.
PECO's access to the capital markets, including the commercial paper
market, and its financing costs in those markets are dependent on its credit
ratings. None of PECO's borrowings are subject to default or prepayment as a
result of a downgrading of credit ratings although such a downgrading could
increase interest charges under certain bank credit facilities.
At September 30, 2002, PECO's capital structure, excluding the
deduction from shareholders' equity of the $1.8 billion receivable from Exelon,
consisted of 27% common stock, 4% notes payable, 3% preferred securities and
COMRPS (which comprised 2% of PECO's total capitalization structure), and 66%
long-term debt including transition bonds issued by PECO Energy Transition
Trust. Long-term debt included $4.3 billionin the first quarter of transition bonds representing 50%
of capitalization.2003.
Under PUHCA, PECO is precluded from lending or extending credit or
indemnity to Exelon and the Federal Power Act, PECO can pay dividends only from retained or current
earnings. At September 30, 2002,March 31, 2003, PECO had retained earnings of $347$447 million.
106Long-term debt included $4.1 billion of transition bonds.
91
Contractual Obligations, and 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 September 30, 2002March 31, 2003 were materially unchanged, other than in the
normal course of business, from the amounts as set forth in the December 31,
20012002 Form 10-K
except for principal paymentsthe following:
o PECO has entered into several agreements with a tax consultant related
to the filing of $326 million on transition
bonds, additional borrowings of commercial paper of $274 million,refund claims with the issuance
of $225 million of 4.75% FirstIRS. The fees for these
agreements are contingent upon a successful outcome and Refunding Mortgage Bonds, due October 1, 2012
and the payment at maturity of $222 million of First and Refunding Mortgage
Bonds.
Other Factors
PECO isare based upon
a participant in Exelon's pension and postretirement benefit
plans. PECO's costs of providing pension and postretirement benefits to its
retirees is dependent on a number of factors, such as the discount rate, rates
of return on plan assets, and the assumed rate of increase in health care costs.
A credit of approximately $2 million was included as a reduction to operating
and maintenance expense in 2001 for the cost of PECO's pension and
post-retirement benefit plans, exclusivepercentage of the 2001 charges for employees
severance programs.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 costs are expectedpotential tax benefits
and associated fees could be material to increase in 2002 by
approximately $23 million as the resultfinancial position,
results of operations and cash flows of PECO. PECO cannot predict the
timing of the effectsfinal resolution of these refund claims.
o See Notes 10 and 14 of the declineCondensed Combined Notes to Consolidated
Financial Statements for further discussion of material changes in
market
value of plan assets and discount rates, and increasesPECO's debt obligations from those set forth in health care costs.
Further increases in pension and postretirement expense are expected for the year 2003. Although the 2003 increase will depend on market conditions PECO
preliminarily estimates that pension and postretirement benefit costs will
increase by approximately $15 million in 2003 from 2002 cost levels.
Exelon's defined benefit pension plans, of which PECO is a participant,
currently meet the minimum funding requirementsForm 10-K.
o See Note 8 of the Employment Retirement
Income Security Act of 1974, however Exelon currently expectsCondensed 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 a
discretionary plan contribution in the fourth quarterpayment on
behalf of 2002 of $100 millionother parties and financing arrangements to $200 million and a discretionary plan contribution in 2003 of $300 million to
$350 million. These contributions are expected to be funded primarily by
Exelon's internally generated cash flows from operations or through external
sources.
107secure their
obligations.
92
EXELON GENERATION COMPANY, LLC
- ------------------------------
GENERAL
TheGeneration operates as a single segment and its operations of Generation consist of
electric generating facilities, energy marketing operations and equity interests
in Sithe and AmerGen.
In the second quarter of 2002, Generation early adopted the provision ofEITF 02-3. EITF
02-3 that requireswas 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 inas revenue for prior periods to revenue 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 September 30,March 31,
----------------------------
2003 2002 Compared to Three Months Ended September 30, 2001
Significant Operating Trends - Generation
Three Months Ended September 30,
--------------------------------
2002 2001 Variance % Change
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 2,2131,879 $1,461 $ 2,191 $ 22 1.0%418 28.6%
OPERATING EXPENSES
Purchased Power 1,257 1,268 (11) (0.9%)841 619 222 35.9%
Fuel 273 242 31 12.8%364 209 155 74.2%
Operating and Maintenance 391 364 27 7.4%487 432 55 12.7%
Depreciation 68 57 11 19.3%and Amortization 45 63 (18) (28.6%)
Taxes Other Than Income 37 36 1 2.8%48 49 (1) (2.0%)
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Operating Expense 2,026 1,967 59 3.0%Expenses 1,785 1,372 413 30.1%
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 187 224 (37) (16.5%)94 89 5 5.6%
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (23) (41) 18 43.9%(19) (17) (2) 11.8%
Equity in Earnings (Losses) of Unconsolidated Affiliates, net 87 60 27 45.0%19 23 (4) (17.4%)
Other, net 14 (25) 39 156.0%Net (167) 16 (183) n.m.
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Other Income and Deductions 78 (6) 84(167) 22 (189) n.m.
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
INCOME (LOSS) BEFORE INCOME TAXES 265 218 47 21.6%AND CUMULATIVE
EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES (73) 111 (184) (165.8%)
INCOME TAXES 102 78 24 30.8%(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 $ 16356 $ 14079 $ 23 16.4%
===================================================================================================================
(23) (29.1%)
==========================================================================================================
n.m. - not meaningful
93
Net Income
Generation's net income increaseddecreased by $23 million, or 16%29%, for the three
months ended September 30, 2002March 31, 2003 compared to the same period in the prior year.
Net income was positively impacted2002. Income (loss)
before cumulative effect of changes in accounting principles decreased by increased revenue from affiliates,
increased revenue from two generating plants acquired in April 2002, reduced
interest expense and increased equity in earnings of unconsolidated
subsidiaries, partially offset by depressed wholesale market prices for energy,
increased depreciation and increased operating and maintenance expenses.
108
Operating Revenues, Net of Purchased Power and Fuel Expenses
Operating revenues, net of purchased power and fuel were $683$118
million for the three months ended September 30, 2002March 31, 2003 compared to $681 million for the same period in
2001. Excluding the impact of a $16 million decrease in
decommissioning revenues in 2002 primarily due to the timingafter-tax impairment charge for Generation's equity
investment in Sithe of those$130 million and higher operating expenses, partially
offset by higher revenues in 2001,
marketing and trading margininvestment income.
Operating Revenues
Revenues increased by $18 million. The increase in marketing
and trading margins was due to increased margin from sales to affiliates offset
by lower margin on market sales and trading losses. Margin from sales to
affiliates increased by $94 million. This increase was attributable to weather
related increased deliveries to PECO and ComEd, lower average supply costs, and
$8$418 million, for the effects of certain third-party energy reconciliations. The
margin gains from sales to affiliates were offset by $59 million lower margin
from market sales and a $17 million decrease in trading margin. Market sales
margins were negatively impacted by lower average market sales prices of
$7.05/MWh. Excluding the benefit of $58 million of margin associated with the
Texas plant acquisition, average market prices realizedor 29% for the three months ended
September 30, 2002 were $9.79/MWh lower than the same 2001 period. The
effect of the lower sales prices were partially offset by lower average supply
costs and increased market sales volumes. The $17 million decrease in trading
margin reflects a $12 million net loss for the period ended September 30, 2002
as compared to a $5 million net gain in the same 2001 period. Average supply
costs decreased by $2.04/MWh for the period ending September 30, 2002 asMarch 31, 2003 compared to the same 2001 period.period in 2002. This decrease was principally attributedincrease resulted
primarily from a $295 million increase in energy market sales, due to lowerregional
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 power costsobligations. 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 lower wholesale market prices
realized andthe adoption of SFAS No. 143 that was not included in 2002. Trading
activity reduced transmission costs.revenue by $2 million during the first quarter of 2003 compared
to the same period of 2002.
For the three months ended September 30,March 31, 2003 and 2002, and 2001, Generation's sales
and the supply of these sales excluding the trading portfolio, were as follows:
Three Months Ended September 30,
--------------------------------March 31,
----------------------------
Sales (in GWhs) 2003 2002 2001Variance % Change
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Energy Delivery 34,535 32,692 5.6%29,346 27,750 1,596 5.8%
Exelon Energy 1,461 2,038 (28.3%1,248 1,250 (2) (0.2%)
Market Sales 21,177 17,781 19.1%23,815 19,324 4,491 23.2%
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Sales 57,173 52,511 8.9%
=======================================================================================================54,409 48,324 6,085 12.6%
==========================================================================================================
Three Months Ended September 30,
--------------------------------March 31,
----------------------------
Supply of Sales (in GWhs) 2003 2002 2001Variance % Change
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Nuclear Generation 29,817 28,456 4.8%(1) 29,330 27,533 1,797 6.5%
Purchases - non-trading portfolio 23,425 20,505 14.2%(2) 20,029 18,093 1,936 10.7%
Fossil and Hydro Generation 3,931 3,550 10.7%5,050 2,698 2,352 87.2%
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total Supply 57,173 52,511 8.9%
=======================================================================================================54,409 48,324 6,085 12.6%
==========================================================================================================
(1) Excluding AmerGen.
(2) Including purchased power agreements with AmerGen.
109
Trading volume of 28,4559,527 GWhs and 1,83214,239 GWhs for the three months ended
September 30,March 31, 2003 and 2002, and 2001, respectively, is not included in the table above.
94
Generation's average margins on energy salesmargin and other operating data for the three
months ended March 31, 2003 and 2002 were as follows:
September 30, 2002 and 2001 are as follows:
Three Months Ended September 30,
--------------------------------March 31,
----------------------------
($/MWh) 2003 2002 2001 % Change
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Average Realized Revenue
Energy Delivery $ 40.1830.87 $ 40.01 0.4%29.98 3.0%
Exelon Energy 49.72 46.67 6.5%43.28 45.60 (5.1%)
Market Sales 35.50 42.55 (16.6%)37.05 28.15 31.6%
Total Sales - excluding the trading portfolio 38.69 41.13 (5.9%)33.96 29.63 14.6%
Average Supply Cost (1) - excluding trading portfolio $ 26.6621.29 $ 28.70 (7.1%)16.74 27.2%
Average Margin - excluding the trading portfolio $ 12.0412.67 $ 12.43 (3.1%12.89 (1.7%)
- ---------------------------------------------------------------------------------------------------------------------
(1) Average supply cost includes purchasepurchased power and fuel cost.
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 nuclear fleet, including AmerGen, performedMWh 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 a capacity
factor of 93.9%existing facilities.
The factors below contributed to the overall reduction in Generation's
average margin for the three months ended September 30, 2002March 31, 2003 as compared to 93.0%
for the same
period in 2001.2002.
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 fleet'sgeneration 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 including AmerGen, forare primarily due to 30 fewer planned refueling outage days, resulting in
a $32 million decrease in outage
95
costs, in the three months ended September 30, 2002 were $12.40 per
MWhMarch 31, 2003 as compared to $12.52 per MWh for the same period
in 2001. Reduced unit
production costs reflect additional generation due to power uprates and
headcount reductions and Exelon's Cost Management Initiative. Generation's
average purchased power costs for wholesale operations were $53.75 per MWh for2002. Additionally, the three months ended September 30, 2002,March 31, 2003 included three
unplanned outages compared to $62.18 per MWh forfive unplanned outages during the same period in 2001. The decrease in purchasethree months
ended March 31, 2002.
Purchased Power
Purchased power costs was primarily due to
depressed wholesale power market prices.
Operating and Maintenance Expense
Operating and maintenance expenses increased $27$222 million, or 7%36%, for the three months
ended September 30, 2002March 31, 2003 compared to the same period in 2001.2002 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 was primarily due to additional operating and maintenance expenses
of $10in purchased power also reflects a $31 million arising from an increased number of nuclear plant refueling
outage days duringloss on mark-to-market
hedging activity for the three months ended September 30, 2002March 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 2001, additional2002. 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 coststhe generation plants acquired after the first quarter of
$32002. Increased fossil fuel expense includes $9 million related to fossil
plant outage work and $7 million related toincreased
market sales, from the two 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 April 2002.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
other operating cost
reductions, including reductions from Exelon's Cost Management Initiative.
Depreciation Expense
Depreciationa $4 million loss on emissions allowance sales recorded in 2002.
Operating and Maintenance
O&M expense increased $11$55 million, or 19%13%, for the three months ended
September 30, 2002March 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 prior year.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 is duewas 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 $7$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 routine capital additions $2placed in service after the
first quarter of 2002, $9 million related to plant acquisitions made after the
Southeast Chicago Energy
Project,first quarter of 2002, and $2$1 million of depreciation for the ARC asset related
to two generating plants acquired in April 2002.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 was substantially unchangeddecreased $1 million, or 2%, for the three
months ended September 30, 2002March 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 prior year.
110
first quarter of
2002.
Interest Expense
Interest expense decreased $18increased $2 million, or 44%12%, for the three months
ended September 30, 2002,March 31, 2003 compared to the same period in the prior year.2002. The decrease isincrease was
primarily due to $4$3 million of loweradditional interest related to a lower
rateexpense on the spent nuclear fuel obligation and $13$534 million
of lower affiliate
interest expense.note payable issued to Sithe in November 2002.
Equity in Earnings of Unconsolidated Affiliates
Equity in earnings of unconsolidated affiliates increased $27decreased $4 million,
or 45%17%, for the three months ended September 30, 2002March 31, 2003 compared to the same period in
the prior year. This increase2002. The decrease was due to an $18a $6 million increasedecrease in Generation's equity
earnings in Sithe, primarily due to a mark-to-market
adjustment relatedSithe's sale of Exelon New England to
the Dynegy tolling agreement with the Independence
Generating station,Generation in November 2002. This decrease was partially offset by an impairment adjustment for the New
Boston 1 Generating station. The increase is also due to a $9$2 million
increase in Generation's equity earnings in AmerGen, primarily due to better station
capacity performance and the power uprate at TMI conducted in the fourth quarter
of 2001.AmerGen.
Other, netNet
Other, net increased $39Net decreased $183 million for the three months ended September
30, 2002March 31,
2003 compared to the same period in 2002. This decrease is primarily a result of
the prior year primarily$200 million impairment charge related to Generation's equity investment in
Sithe due to substantial market losses on decommissioning trust investments during 2001 as
compared to the same periodan other than temporary decline in 2002,value. This charge was partially
offset by a decrease in affiliate
interest income.higher investment income related to the decommissioning trust funds.
Income Taxes
The effective income tax rate was 38.50%28.8% for the three months ended
September 30, 2002 and 35.78% for the three months ended September 30, 2001. The
higher effective tax rate was the result of realized losses in 2001 on qualified
decommissioning trust investments that are tax effected at a higher rate.
111
Nine Months Ended September 30, 2002 Compared to Nine Months Ended September 30,
2001
Significant Operating Trends - Generation
Nine Months Ended September 30,
--------------------------------
2002 2001 Variance % Change
- ----------------------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 5,233 $ 5,403 $ (170) (3.1%)
OPERATING EXPENSES
Purchased Power 2,581 2,589 (8) (0.3%)
Fuel 706 691 15 2.2%
Operating and Maintenance 1,234 1,173 61 5.2%
Depreciation 197 224 (27) (12.1%)
Taxes Other Than Income 126 121 5 4.1%
- -------------------------------------------------------------------------------------------------------------------
Total Operating Expense 4,844 4,798 46 1.0%
- -------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 389 605 (216) (35.7%)
- -------------------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (51) (100) 49 49.0%
Equity in Earnings (Losses) of Unconsolidated Affiliates, net 119 99 20 20.2%
Other, net 54 (7) 61 n.m.
- -------------------------------------------------------------------------------------------------------------------
Total Other Income and Deductions 122 (8) 130 n.m.
- -------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES AND CUMULATIVE
EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES 511 597 (86) (14.4%)
INCOME TAXES 198 228 (30) (13.2%)
- -------------------------------------------------------------------------------------------------------------------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGES
IN ACCOUNTING PRINCIPLES 313 369 (56) (15.2%)
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING
PRINCIPLES, NET OF INCOME TAXES 13 12 1 8.3%
- -------------------------------------------------------------------------------------------------------------------
NET INCOME $ 326 $ 381 $ (55) (14.4%)
===================================================================================================================
Net Income
Generation's net income decreased by $55 million, or 14%, for the nine
months ended September 30, 2002March 31, 2003 compared to the same period in 2001. Net income
was adversely impacted by a lower margin on wholesale energy sales due to
depressed market prices for energy, a reduced supply of low-cost nuclear
generation, and increased operating and maintenance expense. The decrease was
partially offset by increased revenue from affiliates, increased revenue from
the acquisition of two generating plants in April 2002, increased interest
income, decreased depreciation expense, and decreased interest expense.
Operating Revenues, Net of Purchased Power and Fuel Expenses
Operating revenues, net of purchased power and fuel were $1,946 million
for the nine months ended September 30, 2002 compared to $2,123 million40.5% for the same period in 2002. The decrease was
primarily attributed to the prior year. Marketingimpact of the impairment of Generation's investment
in Sithe and trading margin decreasedother 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 $169
million, which was due to lower margin on market salesthe state legislatures or regulatory bodies, and, trading losses but
partially offset by increased margin from sales to affiliates. Margin from sales
to affiliates increased by $181 million. This increase was attributable to
weather-related increased deliveries to PECO and ComEd, lower average supply
costs, and $8 million for third-party energy reconciliations. The margin gains
112
from sales to affiliates were offset by $324 million lower margin from market
sales andif enacted, whether
any such legislation or regulation would be effective retroactively or
prospectively. As a $26 million decrease in trading margin. Market sales margins were
negatively impacted by lower average market sales prices of $8.40/MWh. Excludingresult, Generation cannot currently estimate the benefit of $99 million of margin associated with the Texas plant
acquisition, average market prices realized for the three months ended September
30, 2002 were $10.02/MWh lower than the same 2001 period. The effect of
the
lower sales prices were partially offset by lower average supply costs and
increased market sales volumes. The $26 million decreasepotential changes in trading margin
reflects a $27 million loss for nine-month period ended September 30, 2002 as
compared to a $1 million loss in the same 2001 period. Average supply costs
decreased by $1.14/MWh for the period ending September 30, 2002 as compared to
the same 2001 period. This decrease was principally attributed to lower purchase
power costs associated with lower wholesale market prices realized and reduced
transmission costs.
For the nine months ended September 30, 2002 and 2001, Generation's
sales and the supply of these sales excluding the trading portfolio were as
follows:
Nine Months Ended September 30,
--------------------------------
Sales (in GWhs) 2002 2001 % Change
- ----------------------------------------------------------------------------------------------------------------------
Energy Delivery 90,579 90,001 0.6%
Exelon Energy 4,067 5,044 (19.4%)
Market Sales 61,089 53,787 13.6%
- -------------------------------------------------------------------------------------------------------
Total Sales 155,735 148,832 4.6%
=======================================================================================================
Nine Months Ended September 30,
--------------------------------
Supply of Sales (in GWhs) 2002 2001 % Change
- ----------------------------------------------------------------------------------------------------------------------
Nuclear Generation 86,127 87,397 (1.5%)
Purchases - non-trading portfolio 59,496 52,459 13.4%
Fossil and Hydro Generation 10,112 8,976 12.7%
- -------------------------------------------------------------------------------------------------------
Total Supply 155,735 148,832 4.6%
=======================================================================================================
Trading volume of 51,260 GWhs and 2,286 GWhs for the nine months ended
September 30, 2002 and 2001, respectively, is not included in the table above.
113
Generation's average margins on energy sales for the nine months ended
September 30, 2002 and 2001 are as follows:
Nine Months Ended September 30,
--------------------------------
($/MWh) 2002 2001 % Change
- ---------------------------------------------------------------------------------------------------------------------
Average Realized Revenue
Energy Delivery $ 34.33 $ 33.37 2.9%
Exelon Energy 46.75 42.28 10.6%
Market Sales 31.55 39.95 (21.0%)
Total Sales - excluding the trading portfolio 33.56 36.05 (6.9%)
Average Supply Cost (1) - excluding trading portfolio $ 21.04 $ 21.72 (3.1%)
Average Margin - excluding the trading portfolio $ 12.52 $ 14.18 (11.7%)
- ---------------------------------------------------------------------------------------------------------------------
(1) Average supply cost includes purchase power and fuel cost.
Generation's nuclear fleet, including AmerGen, performed at a capacity
factor 92.1% for the nine months ended September 30, 2002 compared to 95.1% for
the same period in 2001. Generation's nuclear fleet's production costs,
including AmerGen, for the nine months ended September 30, 2002 were $13.05 per
MWh compared to $12.40 per MWh for the same period in 2001. The lower capacity
factor and increased unit production costs are primarily due to 186 planned
outage days in the nine months ended September 30, 2002, versus 55 days in the
same period in 2001, including AmerGen. Increased unit production costs are
partially offset by headcount reductions and Exelon's Cost Management
Initiatives. Generation's average purchased power costs for wholesale operations
were $43.60 per MWh for the nine months ended September 30, 2002, compared to
$49.77 per MWh for the same period in 2001. The decrease in purchase power costs
was primarily due to depressed wholesale power market prices.
Operating and Maintenance Expense
Operating and maintenance expense increased $61 million,tax law or 5%, for the
nine months ended September 30, 2002 compared to the same period in 2001. The
increase was due to the additional operating and maintenance expense of $65
million arising from an increased number of nuclear plant refueling outages
during the nine months ended September 30, 2002 compared to the same period in
2001, as well as additional allocated corporate costs including executive
severance. These additional expenses were offset by other operating cost
reductions, including $11 million related to headcount reductions, a $10 million
reduction in Generation's severance accrual and cost reductions from Exelon's
Cost Management Initiative. The severance reduction represents a reversal of
costs previously charged to operating expense.
Depreciation Expense
Depreciation expenses decreased $27 million, or 12%, for the nine
months ended September 30, 2002 compared to the same period in 2001. This
decrease is due to a $46 million reduction in depreciation expense arising from
the extension of the useful lives on certain generation facilities, partially
offset by $14 million of additional depreciation expense on capital additions
placed in service, including the Southeast Chicago Energy Project in July 2002,
and two generating plants acquired in April 2002.
114
Taxes Other Than Income
Taxes other than income increased $5 million, or 4%, for the nine
months ended September 30, 2002 compared to the same period in 2001 due
primarily to the Texas franchise taxes related to two generating plants acquired
in April 2002 and an increase in property taxes.
Interest Expense
Interest expense decreased $49 million, or 49%, for the nine months
ended September 30, 2002, compared to the same period in 2001. The decrease is
due to $16 million of capitalized interest, $17 million of lower interest
related to a lower rate on the spent nuclear fuel obligation, and $35 million of
lower affiliate interest expense. This decrease is partially offset by an $18
million increase in interest expense on long-term debt.
Equity in Earnings of Unconsolidated Affiliates
Equity in earnings of unconsolidated affiliates increased $20 million,
or 20%, for the nine months ended September 30, 2002 compared to the same period
in 2001. This increase was due to a $23 million increase in Generation's equity
earnings in Sithe primarily due to a mark-to-market adjustment related to the
Dynegy tolling agreement with the Independence Generating station, partially
offset by an impairment adjustment for the New Boston 1 Generating station. This
increase was partially offset by a decrease of $3 million in Generation's equity
earnings in AmerGen.
Other, net
Other, net increased $61 million for the nine months ended September
30, 2002 compared to the same period in 2001, primarily due to substantial
market losses on decommissioning trust investments during 2001 as compared to
the same period in 2002, partially offset by a decrease in affiliate interest
income.
Income Taxes
The effective income tax rate was substantially unchanged at 38.7% for
the nine months ended September 30, 2002 compared to 38.2% for the same period
in 2001.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, (netnet of income taxes of $9 million).
On January 1, 2001, Generation adopted SFAS No. 133, as amended,
resulting in a benefit of $12 million (net of income taxes of $7 million).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 its general business
condition,conditions, as well as the general business conditionthat of the industry.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
115
Resources for further discussion. Capital resources are used primarily to fund
Generation's capital requirements, including construction, investments in new
and existing ventures, and repayments of maturing debt.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 $771$278 million for the ninethree
months ended September 30, 2002,March 31, 2003, compared to $782$509 million for the same period in
2001.2002. 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 $1,343$216 million for the ninethree
months ended September 30, 2002,March 31, 2003, compared to $542$379 million for the same period in
2001.2002. 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 $363partially offset by a $58 million andincrease in
expenditures related to the investment in
nuclearplants acquired after the first quarter of 2002.
Nuclear fuel was $352 million inexpenditures decreased due to two refueling outages that occurred
during the ninethree months ended September 30, 2002March 31, 2003 compared to capital expenditures of $282 million and investment in nuclear fuel
of $215 millionfour outages in the
same period in 2001. An increased number of nuclear
generating station refueling outages occurred during the nine months ended
September 30, 2002 compared to the same period in 2001. In addition to the 2002prior year. Generation's proposed capital expenditures Generation purchased twoand
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 plants from TXU on
April 25, 2002. The $443 million purchase was fundedfacilities with available cashprojected capacity of 2,421
MWs of energy and borrowings from Exelon. Generation's investing activities were funded from
operating activities, borrowings from Exelonadditions to
98
and the useupgrades of available cash.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 September 30, 2002,March 31, 2003, the
balance of the loan to AmerGen was $42$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 were $387 million for the
nine months ended September 30, 2002, compared to cash used of $34$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 prior year. During 2002, Generation obtained a $348
million loan from Exelon, which included $331 million for the acquisition of two
generating plants. The prior year amount represented net distributions of $156
millionCondensed Combined Notes to Exelon and the issuance of long-term debt of $821 million. Also, in
2001, Generation repaid $696 million it had borrowed from Exelon related to the
acquisition of a 49.9% interest in Sithe.Consolidated Financial Statements).
Credit Issues
Generation meets its short-term liquidity requirements primarily
through intercompany borrowings from Exelon, the issuance of commercial paper
borrowings under a bank credit
facility and borrowings from Exelon'sparticipation 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 effective December 12, 2001.
Under the terms of thisbanks. 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 has the flexibility tomay increase or decrease the sublimits of each of the
participants upon written notification to these banks. As of September 30, 2002, Generation'sMarch 31, 2003,
there was no sublimit under thisfor Generation. The credit facility is zero. Thisexpected to be used
by Generation principally to support its commercial paper program.
The credit facility requires Generation to maintain a 116
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 total capitalization ratio of 65% or less.1 for the twelve-month
period ended March 31, 2003. At September 30, 2002,
Generation's debt to total capitalization ratioMarch 31, 2003, Generation was 34%.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.
Exelon,corporate treasurer.
ComEd and its subsidiary Commonwealth Edison of Indiana, Inc., PECO, Generation
and Business Services Company currently may participate in the money pool.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 fund.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 have beenDuring 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 material money pool transactions in 2002.outstanding loan balances.
Generation's access to the capital markets and its financing costs in
those markets are dependent on its creditsecurities ratings. None of Generation's
borrowings areis subject to default or prepayment as a result of a downgrading of
creditsecurities ratings although such a downgrading could increase interest charges
under certain bank credit facilities.
At September 30, 2002, Generation's capital structure consisted of 66%
common stock, 8% notes payable, and 26% long-term debt. 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, and the Federal Power Act, Generation can only pay dividends from undistributed or
current earnings. Generation is precluded from lending or extending credit or
indemnity to Exelon. At September 30, 2002,March 31, 2003, Generation had undistributed earnings of
$850$980 million.
Contractual Obligations, and 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 September 30, 2002March 31, 2003 were materially unchanged other than in
the normal course of business, from the amounts set
forth in the December 31,
2001 Form10-K2002 Form 10-K except for the following:
o On April 25, 2002, Generation purchased two generating plants from TXU. The
$443 million purchase was funded primarily with borrowings from Exelon.
o On June 26, 2002, Generation agreed to purchase Sithe New England and
related power marketing operations, for a $543 million note. In addition,
Generation will assume various Sithe guarantees related to an equity
contribution agreement between Sithe New England and Boston Generation, a
project subsidiary of Sithe New England. The equity contribution agreement
requires, among other things, that Sithe New England, upon the occurrence
of certain events, contribute up to $38 million of equity for the purpose
of completing the construction of two generating facilities. Boston
Generation established a $1.2 billion credit facility in order to finance
the construction of these two generating facilities. The approximately $1.1
billion expected to be outstanding under the facility at the transaction
closing date, will be reflected on Exelon's Consolidated Balance Sheet.
Sithe New England has provided security interests in and has pledged the
stock of its other project subsidiaries to Boston Generation. If the
closing conditions are satisfied, the transaction could be completed in
November 2002.
117
o Purchase obligations increased by $2.3 billion, primarily due to an
increase of $3.8 billion in power only purchases and a $0.1 billion
increase in transmission rights purchases partially offset by a $1.6
billion decrease in net capacity purchase commitments. Approximately $2
billionSee Note 8 of the increase in power only purchases is dueCondensed Combined Notes to Consolidated Financial
Statements for commercial commitments tables representing Generation's
agreement to purchase allcommitments not recorded on the energy from Unit No. 1 at Three Mile Island
after December 31, 2001 through December 31, 2014 and the remaining $1.8
billion increase is primarily due to purchase contracts entered into in
lieu of a portion of the Midwest Generation options contracts. The increase
in transmission rights purchases is primarily due to estimated commitments
in 2004 and 2005 for additional transmission rights that will be required
to fulfill firm sales contracts. The decrease in net capacity purchase
commitments is due primarily to the decision not to exercise options to
purchase 4,411 MWs of capacity from Midwest Generation in 2002 through 2004
as well as the increase in capacity sales under the TXU tolling agreement.
o At September 30, 2002, Southeast Chicago, a company 70% ownedbalance sheet but potentially triggered
by Generation, was obligatedfuture events, including obligations to make equity distributionspayment on behalf of
$55 million over
the next 20 yearsother parties and financing arrangements to the unaffiliated third party owning the remaining 30%
of Southeast Chicago. This amount reflects a return of such third party's
investment in Southeast Chicago's peaking facility in Chicago, IL.
Generation has the right to purchase, generally at a premium, and this
third party has the right to require Generation to purchase, generally at a
discount, its remaining investment in Southeast Chicago. Additionally,
Generation may be required to purchase the third party's remaining
investment in Southeast Chicago upon the occurrence of certain events,
including upon a failure by Generation to maintain an investment grade
rating.
o Guarantees decreased by approximately $80 million primarily related to $120
million of letters of credit on pollution control bonds being renewed and
no longer required to be guaranteed.
Off Balance Sheet Obligations
Generation owns 49.9% of the outstanding common stock of Sithe and has
an option, beginning on December 18, 2002 and expiring in December 2005 to
purchase the remaining common stock outstanding (Remaining Interest) in Sithe.
The purchase option expires on December 18, 2005. In addition, the Sithe
stockholders who own in the aggregate the Remaining Interest have the right to
require Generation to purchase the Remaining Interest (Put Rights) during the
same period in which Generation can exercise its purchase option. At the end of
this exercise period, if Generation has not exercised its purchase option and
the other Sithe stockholders have not exercisedsecure their Put Rights, Generation
will have an additional one-time option to purchase shares from the other
stockholders in Sithe to bring Generation's ownership in Sithe from the current
49.9% to 50.1% of Sithe's total outstanding common stock.
If Generation exercises its option to acquire the Remaining Interest,
or if all the other Sithe stockholders exercise their Put Rights, the purchase
price for 70% of the Remaining Interest will be set at fair market value subject
to a floor of $430 million and a ceiling of $650 million. The balance of the
Remaining Interest will be valued at fair market value subject to a floor of
$141 million and a ceiling of $330 million. In either instance, the floor and
ceiling will accrue interest from the beginning of the exercise period.
118
If Generation increases its ownership in Sithe to 50.1% or more, Sithe
will become a consolidated subsidiary and Exelon's financial results will
include Sithe's financial results from the date of purchase. At September 30,
2002, Sithe had total assets of $4.2 billion and total debt of $2.1 billion,
including $1.6 billion of subsidiary debt, incurred to finance the construction
of two new generating facilities of which $1.1 billion is associated with Sithe
New England, $0.4 billion of subordinated debt, $47 million of short-term debt,
$33 million of capital leases, and excluding $430 million of non-recourse
project debt associated with Sithe's equity investments. For the nine months
ended September 30, 2002, Sithe had revenues of $0.9 billion. As of September
30, 2002, Generation had a $722 million equity investment in Sithe.
On June 26, 2002, Generation agreed to purchase Sithe New England and
related power marketing operations, for a $543 million note. In addition,
Generation will assume various Sithe guarantees related to an equity
contribution agreement between Sithe New England and Boston Generation, a
project subsidiary of Sithe New England. The equity contribution agreement
requires, among other things, that Sithe New England, upon the occurrence of
certain events, contribute up to $38 million of equity for the purpose of
completing the construction of two generating facilities. Boston Generation
established a $1.2 billion credit facility in order to finance the construction
of these two generating facilities. The approximately $1.1 billion expected to
be outstanding under the facility at the transaction closing date, will be
reflected on Exelon's Consolidated Balance Sheet. Sithe New England has provided
security interests in and has pledged the stock of its other project
subsidiaries to Boston Generation. If the closing conditions are satisfied, the
transaction could be completed in November 2002.
Additionally, the debt on the books of Exelon's unconsolidated equity
investments and joint ventures is not reflected on Exelon's Consolidated Balance
Sheets. Total investee debt, at September 30, 2002 including the debt of Sithe
described in the preceding paragraph, is currently estimated to be $2.2 billion
($1.1 billion based on Exelon's ownership interest of the investments).
Generation and British Energy, Generation's joint venture partner in
AmerGen, have each agreed to provide up to $100 million to AmerGen at any time
that the Management Committee of AmerGen determines that, in order to protect
the public health and safety and/or to comply with NRC requirements, such funds
are necessary to meet ongoing operating expenses or to safely maintain any
AmerGen plant.
Other Factors
Generation is a counterparty to Dynegy in various energy transactions.
In early July 2002, the credit ratings of Dynegy were downgraded by two credit
rating agencies to below investment grade. As of September 30, 2002, Generation
had a net receivable from Dynegy of approximately $7 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 arrangement with Dynegy, with a
related financial swap arrangement. As of September 30, 2002, Sithe had
recognized an asset on its balance sheet related to the fair 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 write-off the fair value asset, which Generation estimates
would result in an approximate $22 million reduction in its equity earnings from
Sithe, based on Generation's current 49.9% investment ownership in Sithe.
Additionally, the future economic value of Sithe's investment in the
119
Independence Station and AmerGen's purchased power arrangement with Illinois
Power, a subsidiary of Dynegy, could be impacted by events related to Dynegy's
financial condition.
Generation is a participant in Exelon's pension and postretirement
benefit plans. Generation's costs of providing pension and postretirement
benefits to its retirees is dependent up a number of factors, such as the
discount rate, rates of return on plan assets, and the assumed rate of increase
in health care costs. Approximately $13 million was included as a reduction to
operating and maintenance expense in 2001 for the cost of Generation's pension
and post-retirement benefit plans, exclusive of the 2001 charges for employees
severance programs. These costs are expected to increase in 2002 by
approximately $24 million as the result of the effects of the decline in market
value of plan assets and discount rates, and increases in health care costs.
Further increases in pension and postretirement expense are expected for the
year 2003. Although the 2003 increase will depend on market conditions,
Generation preliminarily estimates that pension and postretirement benefit costs
will increase by approximately $30 million in 2003 from 2002 cost levels.
Exelon's defined benefit pension plans, of which Generation is a
participant, currently meet the minimum funding requirements of the Employment
Retirement Income Security Act of 1974; however, Exelon currently expects to
make a discretionary plan contribution in the fourth quarter of 2002 of $100
million to $200 million and a discretionary plan contribution in 2003 of $300
million to $350 million. These contributions are expected to be funded primarily
by Exelon's internally generated cash flows from operations or through external
sources.
120
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. 133.133,
"Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133).
Most non-trading contracts qualify for athe normal purchases and normal sales
exception.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 cash-flow
hedge contracts are recorded in accumulated other comprehensive income,Other Comprehensive Income (OCI), and
gains and losses are recognized in earnings when the underlying transaction
matures. Mark-to-market gains and losses on otheroccurs. 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.
Amounts recognized101
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 earnings relatedits business; however, Generation believes it is important to
include these risk management disclosures.
The following table describes the drivers of Generation's energy
contractstrading and marketing business and gross margin included in the income statement
for the three months ended September 30,
2002March 31, 2003. Normal operations and 2001hedging
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 $8 million of realized losses from cash-flow hedge
contract settlements and $1 million in non-cash mark-to-market gains on other 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 nine months ended September 30, 2002 include
$47 million of realized gainsdrivers 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 cash-flow hedge contract settlementsOCI to earnings and $1
million in non-cash mark-to market losses on other derivative contracts.
Outlined below is a summary of the changes in fair value for those
contracts included as assets and liabilitiesthe hedging
activities
102
that are recorded in Exelon and Generation'sAccumulated Other Comprehensive Income on the
March 31, 2003 Consolidated Balance SheetSheet.
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 and nine months ended September
30, 2002:
Three Months Ended September 30, 2002
-------------------------------------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
(in millions) and
Hedging Activities Trading Total
- ---------------------------------------------------------------------------------------------------------------------
Fair value of contracts outstanding as of July 1, 2002-------------------------------------------------------------------------------------------------------------------
Current Assets $ (19)219 $ 1
Change in fair value during the three months ended September 30, 2002:
Contracts settled during period 4 13
Mark-to-market gain/(loss) on contracts settled during the period 12 (10)
Mark-to-market gain/(loss) on other contracts (39) (3)
Changes in fair value attributable to changes in valuation techniques and
assumptions$ 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 change in fair value (23) --Mark-to-Market Energy Contract Liabilities (757) (1) (758)
- ---------------------------------------------------------------------------------------------------------------------
Fair value of contracts outstanding at September 30, 2002-------------------------------------------------------------------------------------------------------------------
Total Mark-to-Market Energy Contract Net Assets (Liabilities) $ (42)(484) $ 1
=====================================================================================================================
The total change in fair value during the three months ended September
30, 2002 is reflected in the 2002 financial statements as follows:
Normal Operations Proprietary
and Hedging Activities Trading
- ---------------------------------------------------------------------------------------------------------------------
Mark-to-market gain/(loss) on trading activities and non-qualifying hedge
contracts or hedge ineffectiveness reflected in earnings3 $ 1 $ --
Mark-to-market gain/(loss) on cash-flow hedge contracts reflected in
Other Comprehensive Income (24) --
- ---------------------------------------------------------------------------------------------------------------------
Total change in fair value $ (23) $ --
=====================================================================================================================
121
Nine Months Ended September 30, 2002
-------------------------------------
Normal Operations Proprietary
(in millions) and Hedging Activities Trading
- ---------------------------------------------------------------------------------------------------------------------
Fair value of contracts outstanding as of January 1, 2002 $ 78 $ 14
Change in fair value during the nine months ended September 30, 2002:
Contracts settled during period (60) 15
Mark-to-market gain/(loss) on contracts settled during the period 33 (17)
Mark-to-market gain/(loss) on other contracts (93) (11)
Changes in fair value attributable to changes in valuation techniques and
assumptions -- --
- ---------------------------------------------------------------------------------------------------------------------
Total change in fair value (120) (13)
- ---------------------------------------------------------------------------------------------------------------------
Fair value of contracts outstanding at September 30, 2002 $ (42) $ 1
=====================================================================================================================
The total change in fair value during the nine months ended September
30, 2002 is reflected in the 2002 financial statements as follows:
Normal Operations Proprietary
and Hedging Activities Trading
- ---------------------------------------------------------------------------------------------------------------------
Mark-to-market gain/(loss) on trading activities and non-qualifying hedge
contracts or hedge ineffectiveness reflected in earnings $ 12 $ (13)
Mark-to-market gain/(loss) on cash-flow hedge contracts reflected in
Other Comprehensive Income (132) --
- ---------------------------------------------------------------------------------------------------------------------
Total change in fair value $ (120) $ (13)
=====================================================================================================================(481)
===================================================================================================================
The majority of Generation's contracts are non-exchange traded
contracts valued using prices provided by external sources, which primarily
represent price
quotations available through brokers or over-the-counter, on-line exchanges.
Prices reflect the average of the bid-ask midpoint prices obtained from all
sources that 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 representrepresents
contracts for which external valuations are not available, primarily option
contracts. These contracts are valued using the Black model, an industry
standard option valuation model, and other valuation techniques and are
discounted using a risk-free interest rate.model. The fair values in each category reflect the
level of forward prices and volatility factors as of September 30,
2002March 31, 2003 and may
change as a result of future changes in these factors. 122
Mark-to market gainsManagement uses its best
estimates to determine the fair value of commodity and losses on qualifying cash-flow hedge contracts
are recorded in accumulated other comprehensive income, and will be reclassified
into earnings when the contract settles. Mark-to-market gains and losses on 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 do not meet hedge criteria under SFAS No. 133future market prices could
vary from those used in recording assets and the
ineffective portion of hedge contracts have been recognized in earnings on a
current basis. The maturities, or expected settlement dates, of the qualifying
cash flow hedge contracts recorded in accumulated other comprehensive income,
and the other non-tradingliabilities from energy marketing
and trading derivative contractsactivities and sourcessuch variations could be material.
The following table, which presents maturity and source of fair value
as of September 30, 2002 are as follows: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
--------------------------------------------
2007---------------------------------------------- Total
2008 and Total Fair
(in millions) 2002
2003 2004 2005 2006 2007 Beyond Value
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Normal Operations, qualifying cash flow hedge contracts (1):
Prices provided by other external sources $(315) $ (4)(134) $ (31)(15) $ (16)(7) $ (2) $ (1) -- $ (54)
- ---------------------------------------------------------------------------------------------------------------------
Total $ (4) $ (31) $ (16) $ (2) $ (1) -- $ (54)
=====================================================================================================================(471)
- -------------------------------------------------------------------------------------------------------------------
Total $(315) $ (134) $ (15) $ (7) $ -- $ -- $ (471)
===================================================================================================================
Normal operations,Operations, other derivative contracts (2):
Actively quoted prices $ 1 -- -- -- --19 $ -- $ 1-- $ -- $ -- $ -- $ 19
Prices provided by other external sources 11 20 4 (10)(14) 12 2 5 -- 27-- 5
Prices based on model or other valuation methods 8 (28) (5) (9) (3) -- -- (5) (4) (7) -- (16)(37)
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total $ 1213 $ 20(16) $ (1) $(14)(3) $ (5)(4) $ (3) $ -- $ 12
=====================================================================================================================(13)
===================================================================================================================
Proprietary Trading, other derivative contracts (3):
Actively quoted prices $ 2 -- -- -- --5 $ 1 $ -- $ 2-- $ -- $ -- $ 6
Prices provided by other external sources (10) 3 (3)(5) (4) -- -- -- (10)-- (9)
Prices based on model or other valuation methods 4 45 1 -- -- -- 9-- 6
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total $ (4) $ 75 $ (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.
105
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.
106
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 =====================================================================================================================
(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.
-- 19
No External Ratings
Internally Rated - Investment Grade 9 -- -- 9
Internally Rated - Non-Investment Grade 3 1 -- 4
- -------------------------------------------------------------------------------------------------------------------------
Total $ 118 $ 13 $ -- $ 131
=========================================================================================================================
Credit Risk
Exelon and Generation
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 to below investment grade.agencies. As of September 30, 2002,March 31, 2003, Generation
had a net receivable from Dynegy of approximately $7$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 MW1,040-MW gas-fired qualified facility
that has an energy onlyenergy-only long-term tolling arrangementagreement with Dynegy, with a related
financial swap arrangement. As of September 30, 2002,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 write-offimpair this financial swap asset. Generation estimates, as a 49.9%
owner of Sithe, that the fair value asset, which Generation estimatesimpairment would result in an approximate $22 millionafter-tax reduction in itsof
Generation's equity earnings from
Sithe, based on Generation's current 49.9% investment ownership in Sithe.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 Sithe's investment in the
Independence Station and AmerGen's purchased power
arrangement with Illinois Power Company, a subsidiary of Dynegy, could be
impacted by events related to Dynegy's financial condition.
123107
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 manage interestmaintain its targeted percentage of variable rate exposuredebt, associated with fixed-rate debt
issuances in the aggregate amount of $485 million.million fixed-rate obligation. At
September 30, 2002,March 31, 2003, these interest rate swaps, designated as fair value hedges, had
aan aggregate fair market value of $40$42 million based on the present value
difference between the contract and market rates at September 30, 2002.
ComEd has forward starting interest rate swaps in the aggregate amount of $550
million to lock in interest rate levels in anticipation of future financing. At
September 30, 2002, these interest rate swaps, designated as cash flow hedges,
had a fair market value exposure of $43 million.March 31, 2003.
The aggregate fair value exposure 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 September 30, 2002March 31, 2003 is estimated to be $49 million. If
thethese derivative instruments had been terminated at September 30, 2002,March 31, 2003, this
estimated fair value represents the amount tothat 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 September 30, 2002March 31, 2003 is estimated to be $32$34 million. If
thethese derivative instruments had been terminated at September 30, 2002,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 September 30, 2002March 31, 2003 is estimated to be $57$108 million. If
the derivative instruments had been terminated at September 30, 2002,March 31, 2003, this estimated
fair value represents the amount to be paid by ComEdGeneration 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 September 30, 2002March 31, 2003 is estimated to be $30$77 million. If
the derivative instruments had been terminated at September 30, 2002,March 31, 2003, this estimated
fair value represents the amount to be paid by ComEdGeneration 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
Over severalWithin the 90 days ending October 29, 2002,prior to the date of this Report, Exelon's
management, including the principal executive officer and principal financial
officer, of Exelon 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 Securities and Exchange Commission (SEC).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 October 29, 2002,the date of their evaluation, these officers concluded that,
subject to limitations noted above, the design of the disclosure controls and
procedures is sufficient toprovide reasonable assurance that they can accomplish their
purposes. In view of the restatement that was required in order to correct
the Other Comprehensive Income portion of Exelon's Consolidated Statements of
Comprehensive Income for the year ended December 31, 2001 and Exelon's and
Generation's Consolidated Statements of Income and Comprehensive Income for the
quarters ended March 31, 2002 and June 30, 2002, these officers directed that
steps be taken to enhance the understanding and implementation of the company's
controls and procedures.objectives. Exelon continually strives to improve its disclosure controls and
procedures to enhance the quality of its financial reporting.
124
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
Over severalWithin the 90 days ending October 29, 2002,prior to the date of this Report, ComEd's
management, including the principal executive officer and principal financial
officer, of ComEd evaluated ComEd's disclosure controls and procedures related to the
recording, processing, summarization and reporting of information in Exelon'sComEd'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 October 29, 2002,the date of their evaluation, these officers concluded that,
subject to limitations noted above, the design of the disclosure controls and
procedures is sufficient toprovide reasonable assurance that they can accomplish their
purposes. In view of the
restatement that was required in order to correct the Other Comprehensive Income
portion of Exelon's Consolidated Statements of Comprehensive Income for the year
ended December 31, 2001 and Exelon's and Generation's Consolidated Statements of
Income and Comprehensive Income for the quarters ended March 31, 2002 and June
30, 2002, these officers directed that steps be taken to enhance the
understanding and implementation of the company's controls and procedures.objectives. ComEd continually strives to improve its disclosure controls and
procedures to enhance the quality of its financial reporting.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
Over severalWithin the 90 days ending October 29, 2002,prior to the date of this Report, PECO's management,
including the principal executive officer and principal financial officer, of PECO
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 Securities and Exchange Commission (SEC).SEC. These disclosure controls and procedures
have been designed to ensure that (a) material information relating to Exelon,PECO,
including its consolidated subsidiaries, is made known to Exelon'sPECO'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 October 29, 2002,the date of their evaluation, these officers concluded that,
subject to limitations noted above, the design of the disclosure controls and
procedures is sufficient toprovide reasonable assurance
111
that they can accomplish their purposes. In view of the restatement that was required in order to correct
the Other Comprehensive Income portion of Exelon's Consolidated Statements of
Comprehensive Income for the year ended December 31, 2001 and Exelon's and
Generation's Consolidated Statements of Income and Comprehensive Income for the
quarters ended March 31, 2002 and June 30, 2002, these officers directed that
steps be taken to enhance the understanding and implementation of the company's
controls and procedures.objectives. PECO continually strives to improve
its disclosure controls and procedures to enhance the quality of its financial
reporting.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
Over severalWithin the 90 days ending October 29, 2002,prior to the date of this Report, Generation's
management, including the principal executive officer and principal financial
officer, of Generation 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 Securities and Exchange Commission (SEC).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 October 29, 2002,the date of their evaluation, these officers concluded that,
subject to limitations noted above, the design of the disclosure controls and
procedures is sufficient toprovide reasonable assurance that they can accomplish their
purposes. In view of the
restatement that was required in order to correct the Other Comprehensive Income
portion of Exelon's Consolidated Statements of Comprehensive Income for the year
ended December 31, 2001 and Exelon's and Generation's Consolidated Statements of
Income and Comprehensive Income for the quarters ended March 31, 2002 and June
30, 2002, these officers directed that steps be taken to enhance the
understanding and implementation of the company's controls and procedures.objectives. Generation continually strives to improve its disclosure controls
and procedures to enhance the quality of its financial reporting.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.
125
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Generation
As previously reported in Exelon's Junethe 2002 Form 10-Q, between May 810-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 14, 2002, several class action lawsuits were filed2001, 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 Federal 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 Chicago asserting nearly identical securities law claims on
behalfFederal district court in
Denver. The jury awarded nominal damages of purchasers$42,500 to 11 of Exelon securities between13 plaintiffs and
required Cotter to perform periodic medical monitoring at a cost of $241,000. On
April 24,22, 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 September
27, 2001 (Class Period). The complaints allege that Exelon violated Federal
securities laws by issuing a seriesReporting Requirement pursuant to
Sections 113 and 114 of materially falsethe Clean Air Act, alleging numerous exceedances of
opacity limits and misleading
statements relating to its 2001 earnings expectations during the Class Period.
The Court consolidated the pending cases into one lawsuitviolations of opacity-related monitoring, recording and
has appointed two
lead plaintiffs as well as lead counsel.reporting requirements at Mystic Station in Everett, Massachusetts. On October 1,January
8, 2002, the plaintiffs filedEPA indicated that it had decided to resolve the NOV through an
administrative compliance order and a consolidated amended
complaint.judicial civil penalty action. In additionMarch
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 original claims, this complaint contains
allegationsrequirements of new factsthe 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 contains several new theoriesthe United States Department of liability. Exelon
believes the lawsuit is without merit and is vigorously contesting this matter.Justice.
ITEM 5. OTHER INFORMATION
Exelon, ComEd, PECO and Generation
FERC issued its standard market design notice of proposed rulemaking
(NOPR) on July 31, 2002 that proposes numerous changes to current wholesale
electric transmission arrangements and energy markets. The NOPR includes a
requirement that all jurisdictional transmission facilities be under the
operational control of an independent transmission provider, creates a new
transmission tariff that would provide a single form of transmission service to
all transmission customers, requires energy markets to operate similar to PJM,
and recognizes needs of load-serving entities.
ComEd
As previously reported in the 20012002 Form 10-K, on December 20, 2000, the
ICC issued an order permitting ComEd to recover decommissioning costs from
customers through 2006. The ICC order was appealed. On August 7,in July 2002, the
Illinois Appellate Court for the Second District issued an opinion affirming in
all respects the ICC's order allowing ComEd to collect from customers $73
million in decommissioning costs through 2004 and up to that amount in 2005 and
2006. Several parties have asked the Illinois Supreme Court to review the case.
The petition for review has been fully briefed and is pending before the
Illinois Supreme Court.
As previously reported in the June 2002 Form 10-Q, on May 28, 2002,
ComEd filed a notice with FERC indicating its intention to join PJM
Interconnection, LLC (PJM) by placing its transmission assets under the control
of an independent transmission company (ITC) that would operate within PJM West. 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 late July 2002.
Amongthe 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 conditions, FERC orderedthings, issues related to ComEd's residential delivery services rate
proceeding, market value index proceeding, the applicable parties to file agreements
relating to the formationprocess for competitive service
declarations for large-load customers and an extension of the ITC under PJM. ComEd, American Electric Power
East (AEP), Dayton Power & Light (Dayton) and National Grid USA (National Grid)
126
subsequentlyPPA with
Generation. On March 28, 2003, the ICC issued orders consistent with the
Agreement. Rehearing requests were filed a non-binding letter of intent and detailed term sheet
relating towith the formationICC in April 2003. The
Agreement will not become effective as long as any of the ITC. National Grid is a subsidiary of National
Grid plc, a company that owns and operates transmission assets in Great Britain.
National Grid and PJM continueICC orders are subject
to negotiate the allocation of functions to an
ITC operating under PJM.
Effective as of September 30, 2002, ComEd, AEP, Dayton and National
Grid entered into a Project Implementation Agreement with PJM (Agreement)
providing for the funding and allocation of responsibilities with respect to the
integration of the parties into PJM West, either directly or through an ITC.
ComEd's share of PJM's expansion expenses under this Agreement is estimated to
be approximately $10 million. This Agreement contemplates that Illinois Power
Company (IP) and Dominion Virginia Power Company (Dominion) would enter into
similar agreements providing for the integration of IP into PJM West and
Dominion into PJM South. By coordinating these projects, PJM expected to
generate synergies and overall savings.any pending rehearing request.
PECO
As a result, if any of these companies
fails to join or withdraws from PJM, the costs to all of the other companies,
including ComEd, may increase. ComEd also faces significant additional expenses
under this Agreement if it withdraws from PJM.
On August 1, 2002, ComEd set a new record for highest peak load
experienced to date of 21,804 MWs.
PECO
In August 2002, Exelon's Audit Committee pre-approved the non-audit
services of its independent accountant, PricewaterhouseCoopers LLP, to:
o Provide a fact witness in a Pennsylvania Department of Revenue
tax matter that is being litigatedpreviously reported in the Commonwealth Court.
o Perform tax compliance services related to PECO for state and
local income and franchise tax returns The cost of such services
is estimated to be $67,000.
On2002 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 August 14, 2002,January 1, 2003, the number of customers
choosing an alternative electric generation supplier did not meet the MST. In
February 2003, PECO setfiled a new recordresidential customer MST plan, and on May 1, 2003,
the PUC approved the plan. The approved plan provides for highest peak load
experienceda two-step process
with a total of up to date of 8,164 MWs.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 2001December 31, 2002 Form 10-K,
in November 2000, eight
utilitiesapproximately 1,700 of Generation's 7,200 employees are covered by Collective
Bargaining Agreements (CBA) with nuclear power plantsthe IBEW. On April 9, 2003, the IBEW filed a
Joint Petition for Reviewpetition with the U.S. Court of Appeals for the Eleventh Circuit seekingNLRB to invalidate a portion
of PECO's agreement with the U.S. Department of Energy (DOE) providing for
credits against Nuclear Waste Fund (NWF) payments on the ground that such
provision is a violation of the Nuclear Waste Policy Act of 1982. To date, Peach
Bottom has been credited approximately $38 million, of which Exelon's share was
approximately $19 million, which was used to offset the cost to constructrepresent all production and operate an on-site storage facility. Credits of approximately $6 million
annually are expectedmaintenance employees in
Generation's fossil and hydroelectric operations in the future, which Generation will recognize its share
of approximately $3 million when received. (The agreement was assigned to
Generation in connection with Exelon's 2001 restructuring.) On September 24,
127Mid-Atlantic operating
group. These
113
2002, the United States Court of Appeals for the Eleventh Circuit issuedemployees are not currently covered by a ruling in which it held that DOE is not authorized to fund the Peach Bottom
credits out of the NWF.CBA. The ruling does not address whether Generation must
repay the NWF the amount of the credits it has received; it only invalidates the
source of funding for the Peach Bottom settlement agreement. The court's ruling
does not purport to affect the validity of the Peach Bottom settlement agreement
as a whole or the ability to enter into the agreement. Under the terms of the
agreement, DOE and Generation are required to meet and discuss alternative
funding sources for the settlement credits. The court's opinion suggestsIBEW petition estimates that
the federal judgment fund shouldnumber of additional employees represented would be available as an alternate source. The
agreement provides that if such negotiations are unsuccessful,350 to 400. NLRB
hearings were conducted in April 2003. An election is anticipated in the agreement
will be null and void.second
half of 2003.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
4.1 - Ninety-Ninth Supplemental Indenture dated as of September 15,
2002 to PECO Energy Company's First and Refunding Mortgage.
4.2 - Ninety-Eighth Supplemental Indenture dated as of October 1,
2002 to PECO Energy Company's First and Refunding Mortgage.
10.1 - Employment Agreement by and among Exelon Corporation, Exelon
Generation Company, LLC and Oliver D. Kingsley, Jr. dated as
of September 5, 2002.
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 September 30, 2002 filed by the
following officers for the following companies:
- --------------------------------------------------------------------------------
99.1 - Filed by John W. Rowe for Exelon Corporation
99.2 - Filed by Ruth Ann M. Gillis for Exelon Corporation
99.3 - Filed by Frank M. Clark for Commonwealth Edison Company
99.4 - Filed by Robert E. Berdelle for Commonwealth Edison Company
99.5 - Filed by Kenneth G. Lawrence for PECO Energy Company
99.6 - Filed by Frank F. Frankowski for PECO Energy Company
99.7 - Filed by Oliver D. Kingsley for Exelon Generation Company, LLC
99.8 - Filed by Ruth Ann M. Gillis for Exelon Generation Company, LLC
99.9 - Management's Discussion and Analysis of Financial Condition
and Results of Operations and Index to Financial Statements of
Exelon Generation Company, LLC, filed by Exelon Generation
Company, LLC with the Securities Exchange Commission on April
24, 2002 on Registration Statement Form S-4 (File No.
333-85496).
128
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 September 30, 2002 as follows:March 31, 2003 regarding the
following items:
Date of Earliest
Event Reported Description of Item Reported
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
July 1,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 Generation's notification to
Midwest Generation, LLC of its exercise of Generation's call option.
July 16, 2002the Sithe Boston
credit facility and "ITEM 5. OTHER EVENTS"7. FINANCIAL STATEMENTS AND EXHIBITS" filed
by Exelon ComEd, PECO and Generation reporting that Exelon's second
quarter 2002 earnings results were expected to be higher than estimates.
July 31, 2002 "ITEM 5. OTHER EVENTS" filed by Exelon, ComEd, PECO and Generation, reporting Exelon's second
quarter 2002 earnings results andfor the financial statements of Sithe New
England.
January 15, 2003 "ITEM 9. REGULATION FD DISCLOSURE" filed by Exelon, ComEd, PECO and
Generation regarding highlightsthe confirmation of earnings guidance for 2002 and
2003.
January 22, 2003 "ITEM 5. OTHER EVENTS" filed by ComEd regarding the Exelon Second Quarter Earnings Conference Call.
August 6, 2002issuance 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 certificationscertain financial
information of Exelon's principal
executive officerExelon Corporation and principal financial officer, as requiredSubsidiary 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 SEC Order No. 4-460.
August 27, 2002Bob 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
letter order from the Federal Energy
Regulatory Commission (FERC) related to the treatment of goodwill associated with the generating
assets and power marketing business that it transferred in January 2001 as part of Exelon's
corporate restructuring.
September 3, 2002 "ITEM 5. OTHER EVENTS" filed by Exelon and ComEd, announcing that ComEd will seek a rehearing of
the order by FERC related to the treatment of goodwill as a part of Exelon's corporate
restructuring in January 2001.
September 3, 2002 "ITEM 9. REGULATION FD DISCLOSURE" filed by Exelon, ComEd and PECO, regarding Exelon's anticipated
savings from its Cost Management Initiative at Energy Delivery.
September 4, 2002 "ITEM 9. REGULATION FD DISCLOSURE" filed by Exelon, ComEd, PECO and Generation, Oliver D.
Kingsley, Jr., Senior Executive Vice President, made a presentation at the Lehman Brothers
Conference. The exhibits include the presentation slides and other materials made available at
the conference.
129
September 4, 2002 "ITEM 5. OTHER EVENTS" filed by Exelon and Generation, regarding Exelon's announcement that it is
in the preliminary stages of exploring the possibility of selling its share of AmerGen Energy
Company, LLC and "ITEM 9. REGULATION FD DISCLOSURE" filed by Exelon and Generation, reporting that
Exelon does not intend, as part of its strategy, to own the international assets of Sithe.
September 18, 2002 "ITEM 9. REGULATION FD DISCLOSURE" filed by Exelon, ComEd, PECO and Generation, John W. Rowe,
Chairman and CEO, made a presentation at Merrill Lynch Global Power and Gas Leaders Conference. The
exhibits include the presentation slides and other materials made available at the conference.
September 18, 2002 "ITEM 9. REGULATION FD DISCLOSURE" filed by Exelon, ComEd, PECO and Generation, during the Power and
Gas Leaders Conference, John W. Rowe commented on the third quarter earnings outlook, the range of
guidance for 2003 earnings and the status of Exelon's discussion with FERC and the SEC regarding the
allocation of goodwill to ComEd's transmission and distribution business.
September 19, 2002 "ITEM 5. OTHER EVENTS" filed by Exelon and ComEd, related to their understanding that the Office of
the Chief Accountant of the SEC will not object to the accounting treatment for goodwill.
September 26, 2002 "ITEM 5. OTHER EVENTS" filed by Exelon and ComEd, related the letter received from FERC which states
that FERC has no objection to ComEd's determination that none of the goodwill was related to assets
transferred to Generation.competitive electricity marketplace.
- --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
130116
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/ Ruth Ann M. GillisRobert S. Shapard
- ----------------------------- -------------------------------------------- ----------------------
JOHN W. ROWE RUTH ANN M. GILLISROBERT S. SHAPARD
Chairman, of the BoardPresident and SeniorExecutive Vice President and Chief
Chief Executive Officer Chief Financial Officer
(Principal Executive Officer) (Principal Financial Officer)
/s/ Matthew F. Hilzinger
- -----------------------------------------------------
MATTHEW F. HILZINGER
Vice President and Corporate Controller
(Principal Accounting Officer)
October 31, 2002May 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/ Frank M. ClarkRobert S. Shapard
- ----------------------------- -------------------------------------------------- -----------------------
PAMELA B. STROBEL FRANK M. CLARKROBERT S. SHAPARD
Chair President
/s/ Robert E. Berdelle
- -----------------------------
ROBERT E. BERDELLEExecutive Vice President Finance and Chief
(Principal Executive Officer) Financial Officer, Exelon
(Principal Financial Officer)
October 31, 2002
131/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/ Kenneth G. LawrenceRobert S. Shapard
- ----------------------------- -------------------------------------------------- -----------------------
PAMELA B. STROBEL KENNETH G. LAWRENCEROBERT S. SHAPARD
Chair President
/s/ Frank F. Frankowski
- -----------------------------
FRANK F. FRANKOWSKIExecutive Vice President Finance and Chief
(Principal Executive Officer) Financial Officer, Exelon
(Principal Financial Officer)
October 31, 2002/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/ Ruth Ann M. GillisRobert S. Shapard
- ----------------------------- ---------------------------------------------------- -----------------------
OLIVER D. KINGSLEY JR. RUTH ANN M. GILLISROBERT S. SHAPARD
Chief Executive Officer and SeniorExecutive Vice President and Chief
President Chief Financial Officer, Exelon
Corporation(Principal Executive Officer) (Principal Financial Officer)
/s/ Thomas Weir III
- ----------------------------------------------------
THOMAS WEIR III
Vice President and Controller
October 31, 2002
132(Principal Accounting Officer)
May 2, 2003
118
CERTIFICATIONS
- --------------------------------------------------------------------------------
Certification Pursuant to Rule 13a-14 and 15d-14 of the Securities
and Exchange Act ofCERTIFICATION 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: October 31, 2002May 2, 2003 /s/ John W. Rowe
-------------------------------
John W. Rowe
Chairman of the Board and ChiefRobert S. Shapard
--------------------------
Executive Officer
133
Certification Pursuant to Rule 13a-14 and 15d-14 of the Securities
and Exchange Act of 1934
- --------------------------------------------------------------------------------
I, Ruth Ann M. Gillis 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: October 31, 2002
/s/ Ruth Ann M. Gillis
-------------------------------
Ruth Ann M. Gillis
Senior Vice President and Chief Financial Officer
134(Principal Financial Officer)
120
Certification Pursuant to Rule 13a-14 and 15d-14 of the Securities
and Exchange Act ofCERTIFICATION PURSUANT TO RULE 13A-14 AND 15D-14 OF THE SECURITIES AND
EXCHANGE ACT OF 1934
- --------------------------------------------------------------------------------
I, Frank M. ClarkPamela 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: October 31, 2002May 2, 2003 /s/ Frank M. Clark
-------------------------------
Frank M. Clark
President
135Pamela B. Strobel
-----------------------
Chair
(Principal Executive Officer)
121
Certification Pursuant to Rule 13a-14 and 15d-14 of the Securities
and Exchange Act ofCERTIFICATION PURSUANT TO RULE 13A-14 AND 15D-14 OF THE SECURITIES AND
EXCHANGE ACT OF 1934
- --------------------------------------------------------------------------------
I, Robert E. BerdelleS. 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: October 31, 2002May 2, 2003
/s/ Robert E. Berdelle
-------------------------------
Robert E. BerdelleS. Shapard
---------------------
Executive Vice President Finance and Chief Financial Officer, 136Exelon
(Principal Financial Officer)
122
Certification Pursuant to Rule 13a-14 and 15d-14 of the Securities
and Exchange Act ofCERTIFICATION PURSUANT TO RULE 13A-14 AND 15D-14 OF THE SECURITIES AND
EXCHANGE ACT OF 1934
- --------------------------------------------------------------------------------
I, Kenneth G. LawrencePamela 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: October 31, 2002May 2, 2003
/s/ Kenneth G. Lawrence
-------------------------------
Kenneth G. Lawrence
President
137Pamela B. Strobel
--------------------------------
Chair
(Principal Executive Officer)
123
Certification Pursuant to Rule 13a-14 and 15d-14 of the Securities
and Exchange Act ofCERTIFICATION PURSUANT TO RULE 13A-14 AND 15D-14 OF THE SECURITIES AND
EXCHANGE ACT OF 1934
- --------------------------------------------------------------------------------
I, Frank F. FrankowskiRobert 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: October 31, 2002May 2, 2003
/s/ Frank F. Frankowski
-------------------------------
Frank F. FrankowskiRobert S. Shapard
------------------------
Executive Vice President Finance and Chief Financial Officer, 138Exelon
(Principal Financial Officer)
124
Certification Pursuant to Rule 13a-14 and 15d-14 of the Securities
and Exchange Act ofCERTIFICATION 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: October 31, 2002May 2, 2003 /s/ Oliver D. Kingsley -------------------------------
Oliver D. Kingsley Jr.
----------------------------
Chief Executive Officer and President
139(Principal Executive Officer)
125
Certification Pursuant to Rule 13a-14 and 15d-14 of the Securities
and Exchange Act ofCERTIFICATION PURSUANT TO RULE 13A-14 AND 15D-14 OF THE SECURITIES AND
EXCHANGE ACT OF 1934
- --------------------------------------------------------------------------------
I, Ruth Ann M. GillisRobert 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: October 31, 2002May 2, 2003
/s/ Ruth Ann M. Gillis
-------------------------------
Ruth Ann M. Gillis
SeniorRobert S. Shapard
---------------------------------
Executive Vice President and Chief Financial Officer, Exelon
Corporation(Principal Financial Officer)
126