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 June 30, 2002
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) 765-8200
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 August 1, 2002 was as follows:
Exelon Corporation Common Stock, without par value 322,874,719
Commonwealth Edison Company Common Stock, $12.50 par value 127,016,398
PECO Energy Company Common Stock, without par value 170,478,507
Exelon Generation Company, LLC not applicable
TABLE OF CONTENTS
Page No.
Filing Format 3
Forward-Looking Statements 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
Combined Notes to Consolidated Financial Statements 21
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS 46
Exelon Corporation 46
Commonwealth Edison Company 72
PECO Energy Company 84
Exelon Generation Company, LLC 96
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK 106
PART II. OTHER INFORMATION 110
ITEM 1. LEGAL PROCEEDINGS 110
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 110
ITEM 5. OTHER INFORMATION 110
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K 111
SIGNATURES 117
2
Filing Format
This combined Form 10-Q is being filed separately by Exelon
Corporation, Commonwealth Edison Company, PECO Energy Company and Exelon
Generation Company, LLC (Registrants). Information contained herein relating to
any individual registrant has been filed by such registrant on its own behalf.
No registrant makes any representation as to information relating to any other
registrant.
Forward-Looking Statements
Except for the historical information contained herein, certain of the
matters discussed in this Report are forward-looking statements that are subject
to risks and uncertainties. The factors that could cause actual results to
differ materially include those discussed herein as well as those listed in Note
8 of Notes to Consolidated Financial Statements, those discussed in
"Management's Discussion and Analysis of Financial Condition and Results of
Operations--Outlook" in Exelon Corporation's 2001 Annual Report, those discussed
in "Risk Factors" and "Management's Discussion and Analysis of Financial
Condition and Results of Operations" in Exelon Generation Company, LLC's
Registration Statement on Form S-4, Reg. No. 333-85496 and other factors
discussed in filings with the Securities and Exchange Commission 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. The
Registrants undertake no obligation to publicly release any revision to
forward-looking statements to reflect events or circumstances after the date of
this Report.
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 June 30, Six Months Ended June 30,
--------------------------- -------------------------
(in millions, except per share data) 2002 2001 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $3,519 $3,616 $ 6,876 $ 7,439
OPERATING EXPENSES
Purchased Power 699 754 1,311 1,385
Purchased Power from Unconsolidated Affiliate 60 12 116 22
Fuel 364 409 860 1,098
Operating and Maintenance 1,070 1,134 2,137 2,192
Depreciation and Amortization 332 362 667 740
Taxes Other Than Income 181 153 367 321
- ---------------------------------------------------------------------------------------------------------------------
Total Operating Expense 2,706 2,824 5,458 5,758
- ---------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 813 792 1,418 1,681
- ---------------------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (241) (289) (490) (581)
Distributions on Preferred Securities of Subsidiaries (11) (12) (23) (23)
Equity in Earnings of Unconsolidated Affiliates, net 9 7 22 25
Other, net 194 44 222 99
- ---------------------------------------------------------------------------------------------------------------------
Total Other Income and Deductions (49) (250) (269) (480)
- ---------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES AND CUMULATIVE
EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES 764 542 1,149 1,201
INCOME TAXES 279 227 427 499
- ---------------------------------------------------------------------------------------------------------------------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN
ACCOUNTING PRINCIPLES 485 315 722 702
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING
PRINCIPLES (net of income taxes of $90 and $8 for the six
months ended June 30, 2002 and 2001, respectively) -- -- (230) 12
- ---------------------------------------------------------------------------------------------------------------------
NET INCOME 485 315 492 714
OTHER COMPREHENSIVE INCOME (LOSS) (net of income taxes)
SFAS 133 Transition Adjustment -- -- -- 44
Cash Flow Hedge Fair Value Adjustment (21) (28) (78) (43)
Unrealized Gain (Loss) on Marketable Securities, net (72) 31 (87) (72)
- ---------------------------------------------------------------------------------------------------------------------
Total Other Comprehensive Income (Loss) (93) 3 (165) (71)
- ---------------------------------------------------------------------------------------------------------------------
TOTAL COMPREHENSIVE INCOME $ 392 $ 318 $ 327 $ 643
- ---------------------------------------------------------------------------------------------------------------------
AVERAGE SHARES OF COMMON STOCK OUTSTANDING - Basic 322 321 322 320
- ---------------------------------------------------------------------------------------------------------------------
AVERAGE SHARES OF COMMON STOCK OUTSTANDING - Diluted 324 324 324 323
- ---------------------------------------------------------------------------------------------------------------------
EARNINGS PER AVERAGE COMMON SHARE:
BASIC:
Income Before Cumulative Effect of Changes in
Accounting Principles $ 1.50 $ 0.98 $ 2.24 $ 2.19
Cumulative Effect of Changes in Accounting Principles -- -- (0.71) 0.04
- ---------------------------------------------------------------------------------------------------------------------
Net Income $ 1.50 $ 0.98 $ 1.53 $ 2.23
- ---------------------------------------------------------------------------------------------------------------------
DILUTED:
Income Before Cumulative Effect of Changes in
Accounting Principles $ 1.50 $ 0.97 $ 2.23 $ 2.17
Cumulative Effect of Changes in Accounting Principles -- -- (0.71) 0.04
- ---------------------------------------------------------------------------------------------------------------------
Net Income $ 1.50 $ 0.97 $ 1.52 $ 2.21
- ---------------------------------------------------------------------------------------------------------------------
DIVIDENDS PER COMMON SHARE $ 0.44 $ 0.42 $ 0.88 $ 0.98
- ---------------------------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements
5
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended June 30,
-----------------------------
(in millions) 2002 2001
- ------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 492 $ 714
Adjustments to Reconcile Net Income to Net Cash Flows
Provided by Operating Activities:
Depreciation and Amortization, including nuclear fuel 848 939
Cumulative Effect of a Change in Accounting Principle (net of income taxes) 230 (12)
Net Gain on Sale of Investments (net of income taxes) (199) --
Provision for Uncollectible Accounts 67 60
Deferred Income Taxes (10) 7
Deferred Energy Costs 49 7
Equity in Earnings of Unconsolidated Affiliates, net (22) (25)
Net Realized Losses on Nuclear Decommissioning Trust Funds 21 24
Other Operating Activities 115 (78)
Changes in Working Capital:
Accounts Receivable (259) 68
Inventories (42) (12)
Accounts Payable, Accrued Expenses and Other Current Liabilities 342 280
Changes in Receivables and Payables to Unconsolidated Affiliates, net 12 --
Other Current Assets (6) (19)
- ------------------------------------------------------------------------------------------------------------------------
Net Cash Flows provided by Operating Activities 1,638 1,953
- ------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures (1,028) (937)
Acquisition of Generating Plants (443) --
Enterprises Acquisitions, net of cash acquired -- (39)
Proceeds from the Sale of Investment 285 --
Proceeds from Nuclear Decommissioning Trust Funds 889 621
Investment in Nuclear Decommissioning Trust Funds (943) (655)
Note Receivable from Unconsolidated Affiliate (75) --
Other Investing Activities 47 12
- ------------------------------------------------------------------------------------------------------------------------
Net Cash Flows used in Investing Activities (1,268) (998)
- ------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Long-Term Debt 701 2,058
Retirement of Long-Term Debt (697) (1,153)
Change in Short-Term Debt 110 (949)
Dividends on Common Stock (280) (312)
Change in Restricted Cash (26) (16)
Proceeds from Employee Stock Plans 60 51
Other Financing Activities (10) --
- ------------------------------------------------------------------------------------------------------------------------
Net Cash Flows used in Financing Activities (142) (321)
- ------------------------------------------------------------------------------------------------------------------------
INCREASE IN CASH AND CASH EQUIVALENTS 228 634
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 485 526
- ------------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 713 $ 1,160
- ------------------------------------------------------------------------------------------------------------------------
SUPPLEMENTAL CASH FLOW INFORMATION
Noncash Investing and Financing Activities:
Regulatory Asset Fair Value Adjustment -- $ 347
See Notes to Consolidated Financial Statements
6
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, December 31,
(in millions) 2002 2001
- -----------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 713 $ 485
Restricted Cash 398 372
Accounts Receivable, net
Customer 1,978 1,687
Other 196 428
Receivable from Unconsolidated Affiliate 107 44
Inventories, at average cost
Fossil Fuel 206 222
Materials and Supplies 308 249
Deferred Income Taxes 76 23
Other 354 272
- -----------------------------------------------------------------------------------------
Total Current Assets 4,336 3,782
- -----------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT, NET 14,654 13,781
DEFERRED DEBITS AND OTHER ASSETS
Regulatory Assets 6,237 6,423
Nuclear Decommissioning Trust Funds 3,060 3,165
Investments 1,658 1,666
Goodwill, net 4,971 5,335
Other 705 708
- -----------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 16,631 17,297
- -----------------------------------------------------------------------------------------
TOTAL ASSETS $ 35,621 $ 34,860
- -----------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements
7
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, December 31,
(in millions) 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Notes Payable $ 470 $ 360
Long-Term Debt Due within One Year 1,772 1,406
Accounts Payable 1,164 964
Accrued Expenses 1,339 1,182
Other 527 505
- ---------------------------------------------------------------------------------------------------------------------
Total Current Liabilities 5,272 4,417
- ---------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT 12,591 12,879
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred Income Taxes 4,204 4,303
Unamortized Investment Tax Credits 308 316
Nuclear Decommissioning Liability for Retired Plants 1,379 1,353
Pension Obligation 313 334
Non-Pension Postretirement Benefits Obligation 878 847
Spent Nuclear Fuel Obligation 851 843
Other 866 725
- ---------------------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 8,799 8,721
- ---------------------------------------------------------------------------------------------------------------------
PREFERRED SECURITIES OF SUBSIDIARIES 613 613
COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS' EQUITY
Common Stock 6,990 6,930
Deferred Compensation (1) (2)
Retained Earnings 1,421 1,200
Accumulated Other Comprehensive Income (Loss) (64) 102
- ---------------------------------------------------------------------------------------------------------------------
Total Shareholders' Equity 8,346 8,230
- ---------------------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 35,621 $ 34,860
- ---------------------------------------------------------------------------------------------------------------------
See 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 June 30, Six Months Ended June 30,
--------------------------- -------------------------
(in millions) 2002 2001 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES
Operating Revenues $1,469 $1,517 $ 2,773 $ 2,921
Operating Revenues from Affiliates 12 13 23 55
- ---------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 1,481 1,530 2,796 2,976
- ---------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Purchased Power 6 1 12 2
Purchased Power from Affiliate 547 585 1,079 1,193
Operating and Maintenance 191 210 386 396
Operating and Maintenance from Affiliates 29 38 71 70
Depreciation and Amortization 133 168 268 334
Taxes Other Than Income 73 69 146 141
- ---------------------------------------------------------------------------------------------------------------------
Total Operating Expense 979 1,071 1,962 2,136
- ---------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 502 459 834 840
- ---------------------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (127) (143) (252) (284)
Distributions on Company-Obligated
Mandatorily Redeemable Preferred Securities of
Subsidiary Trusts Holding Solely the Company's
Subordinated Debt Securities (7) (7) (15) (15)
Interest Income from Affiliates 8 17 16 45
Other, net 6 5 13 14
- ---------------------------------------------------------------------------------------------------------------------
Total Other Income and Deductions (120) (128) (238) (240)
- ---------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 382 331 596 600
INCOME TAXES 151 149 236 271
- ---------------------------------------------------------------------------------------------------------------------
NET INCOME 231 182 360 329
- ---------------------------------------------------------------------------------------------------------------------
OTHER COMPREHENSIVE INCOME (LOSS) (net of income taxes):
Cash Flow Hedge Fair Value Adjustment (14) -- (16) --
Unrealized Gain (Loss) on Marketable Securities (2) -- (2) (4)
- ---------------------------------------------------------------------------------------------------------------------
Total Other Comprehensive Income (Loss) (16) -- (18) (4)
TOTAL COMPREHENSIVE INCOME $ 215 $ 182 $ 342 $ 325
- ---------------------------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements
9
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended June 30,
-----------------------------
(in millions) 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 360 $ 329
Adjustments to Reconcile Net Income to Net Cash Flows
Provided by Operating Activities:
Depreciation and Amortization 268 334
Provision for Uncollectible Accounts 11 18
Deferred Income Taxes 75 38
Other Operating Activities 71 (36)
Changes in Working Capital:
Accounts Receivable (158) (45)
Inventories -- 16
Accounts Payable, Accrued Expenses and Other Current Liabilities 51 320
Changes in Receivables and Payables to Affiliates, net 63 (278)
Other Current Assets (1) 9
- ---------------------------------------------------------------------------------------------------------------------
Net Cash Flows provided by Operating Activities 740 705
- ---------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures (372) (459)
Notes Receivable from Affiliate 13 400
Other Investing Activities 7 1
- ---------------------------------------------------------------------------------------------------------------------
Net Cash Flows used in Investing Activities (352) (58)
- ---------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Long-Term Debt 701 --
Retirement of Long-Term Debt (481) (174)
Dividends on Common Stock (235) (148)
Change in Restricted Cash (32) --
Other Financing Activities (10) --
- ---------------------------------------------------------------------------------------------------------------------
Net Cash Flows used in Financing Activities (57) (322)
- ---------------------------------------------------------------------------------------------------------------------
INCREASE IN CASH AND CASH EQUIVALENTS 331 325
- ---------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 23 141
- ---------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 354 $ 466
- ---------------------------------------------------------------------------------------------------------------------
SUPPLEMENTAL CASH FLOW INFORMATION Noncash Investing and Financing Activities:
Net Assets Transferred as a result of Restructuring, net of Note Payable $ -- $ 1,307
Receivable from Parent $ -- $ 1,062
Regulatory Asset Fair Value Adjustment $ -- $ 347
Retirement of Treasury Shares $ 1,344 $ 2,022
See Notes to Consolidated Financial Statements
10
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, December 31,
(in millions) 2002 2001
- -------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 354 $ 23
Restricted Cash 73 41
Accounts Receivable, net
Customer 886 745
Other 93 87
Receivables from Affiliates 35 95
Inventories, at average cost 56 56
Deferred Income Taxes 16 52
Other 16 15
- -------------------------------------------------------------------------------------
Total Current Assets 1,529 1,114
- -------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT, NET 7,522 7,351
DEFERRED DEBITS AND OTHER ASSETS
Regulatory Assets 614 667
Investments 54 64
Goodwill, net 4,895 4,902
Notes Receivable from Affiliates 1,301 1,314
Other 283 304
- -------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 7,147 7,251
- -------------------------------------------------------------------------------------
TOTAL ASSETS $ 16,198 $ 15,716
- -------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements
11
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, December 31,
(in millions) 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Long-Term Debt Due within One Year $ 848 $ 849
Accounts Payable 184 144
Accrued Expenses 393 374
Payables to Affiliates 272 307
Other 197 212
- ---------------------------------------------------------------------------------------------------------------------
Total Current Liabilities 1,894 1,886
- ---------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT 6,095 5,850
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred Income Taxes 1,725 1,671
Unamortized Investment Tax Credits 53 55
Pension Obligation 163 151
Non-Pension Postretirement Benefits Obligation 149 146
Payables to Affiliates 267 297
Other 263 248
- ---------------------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 2,620 2,568
- ---------------------------------------------------------------------------------------------------------------------
COMPANY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED
SECURITIES OF SUBSIDIARY TRUSTS HOLDING SOLELY THE COMPANY'S
SUBORDINATED DEBT SECURITIES 329 329
COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS' EQUITY
Common Stock 1,588 2,048
Preference Stock 7 7
Other Paid-in Capital 4,181 5,057
Receivable from Parent (875) (937)
Retained Earnings 382 257
Treasury Stock, at cost -- (1,344)
Accumulated Other Comprehensive Income (Loss) (23) (5)
- ---------------------------------------------------------------------------------------------------------------------
Total Shareholders' Equity 5,260 5,083
- ---------------------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 16,198 $ 15,716
- ---------------------------------------------------------------------------------------------------------------------
See 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 June 30, Six Months Ended June 30,
--------------------------- -------------------------
(in millions) 2002 2001 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES
Operating Revenues $ 992 $ 903 $ 2,008 $ 1,952
Operating Revenues from Affiliates 3 3 7 5
- ---------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 995 906 2,015 1,957
- ---------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Purchased Power 59 51 107 90
Purchased Power from Affiliate 346 264 649 508
Fuel 53 79 188 284
Operating and Maintenance 123 122 251 251
Operating and Maintenance from Affiliates 8 4 16 7
Depreciation and Amortization 109 99 221 200
Taxes Other Than Income 63 41 122 84
- ---------------------------------------------------------------------------------------------------------------------
Total Operating Expense 761 660 1,554 1,424
- ---------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 234 246 461 533
- ---------------------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (92) (117) (187) (219)
Interest Expense from Affiliate -- (2) -- (8)
Company-Obligated Mandatorily Redeemable Preferred
Securities of a Partnership, which holds Solely
Subordinated Debentures of the Company (2) (2) (5) (5)
Interest Income from Affiliates -- 1 -- 1
Other, net 2 3 2 17
- ---------------------------------------------------------------------------------------------------------------------
Total Other Income and Deductions (92) (117) (190) (214)
- ---------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 142 129 271 319
INCOME TAXES 49 44 90 112
- ---------------------------------------------------------------------------------------------------------------------
NET INCOME 93 85 181 207
Preferred Stock Dividends (2) (3) (4) (5)
- ---------------------------------------------------------------------------------------------------------------------
NET INCOME ON COMMON STOCK $ 91 $ 82 $ 177 $ 202
- ---------------------------------------------------------------------------------------------------------------------
OTHER COMPREHENSIVE INCOME
Net Income $ 93 $ 85 $ 181 $ 207
Other Comprehensive Income (Loss) (net of income taxes):
SFAS 133 Transition Adjustment -- -- -- 40
Cash Flow Hedge Fair Value Adjustment (6) 8 (4) (10)
- ---------------------------------------------------------------------------------------------------------------------
Total Other Comprehensive Income (6) 8 (4) 30
- ---------------------------------------------------------------------------------------------------------------------
TOTAL COMPREHENSIVE INCOME $ 87 $ 93 $ 177 $ 237
- ---------------------------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements
13
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended June 30,
----------------------------
(in millions) 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 181 $ 207
Adjustments to Reconcile Net Income to Net Cash Flows
Provided by Operating Activities:
Depreciation and Amortization 221 200
Provision for Uncollectible Accounts 32 29
Deferred Income Taxes (19) 13
Deferred Energy Costs 49 7
Other Operating Activities (81) (40)
Changes in Working Capital:
Accounts Receivable (4) (19)
Changes in Receivables and Payables to Affiliates, net 34 75
Inventories 14 6
Accounts Payable, Accrued Expenses and Other Current Liabilities 44 22
Other Current Assets (3) (73)
- ---------------------------------------------------------------------------------------------------------------------
Net Cash Flows provided by Operating Activities 468 427
- ---------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures (123) (122)
Other Investing Activities 1 35
- ---------------------------------------------------------------------------------------------------------------------
Net Cash Flows used in Investing Activities (122) (87)
- ---------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Retirement of Long-Term Debt (207) (978)
Issuance of Long-Term Debt -- 805
Contribution from Parent -- 53
Change in Short-Term Debt 74 (122)
Dividends on Preferred and Common Stock (174) (105)
Change in Restricted Cash 1 (16)
Settlement of Interest Rate Swap Agreements -- 31
- ---------------------------------------------------------------------------------------------------------------------
Net Cash Flows used in Financing Activities (306) (332)
- ---------------------------------------------------------------------------------------------------------------------
INCREASE IN CASH AND CASH EQUIVALENTS 40 8
Cash Transferred in Restructuring -- (31)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 32 49
- ---------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 72 $ 26
- ---------------------------------------------------------------------------------------------------------------------
SUPPLEMENTAL CASH FLOW INFORMATION Noncash Investing and Financing Activities:
Net Assets Transferred as a result of Restructuring,
net of Receivable from Affiliates $ -- $ 1,624
Contribution of Receivable from Parent $ -- $ 1,983
See Notes to Consolidated Financial Statements
14
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, December 31,
(in millions) 2002 2001
- ------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 72 $ 32
Restricted Cash 322 323
Accounts Receivable, net
Customer 261 286
Other 30 33
Receivables from Affiliates 6 8
Inventories, at average cost
Fossil Fuel 59 72
Materials and Supplies 6 7
Prepaid Taxes 98 1
Other 13 58
- ------------------------------------------------------------------------------------
Total Current Assets 867 820
- ------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT, NET 4,098 4,047
DEFERRED DEBITS AND OTHER ASSETS
Regulatory Assets 5,623 5,756
Investments 22 24
Pension Asset 29 13
Other 78 85
- ------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 5,752 5,878
- ------------------------------------------------------------------------------------
TOTAL ASSETS $ 10,717 $ 10,745
- ------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements
15
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, December 31,
(in millions) 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Notes Payable $ 175 $ 101
Payables to Affiliates 190 194
Long-Term Debt Due within One Year 910 548
Accounts Payable 52 54
Accrued Expenses 436 397
Deferred Income Taxes 27 27
Other 33 21
- ---------------------------------------------------------------------------------------------------------------------
Total Current Liabilities 1,823 1,342
- ---------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT 4,869 5,438
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred Income Taxes 2,927 2,938
Unamortized Investment Tax Credits 26 27
Non-Pension Postretirement Benefits Obligation 263 239
Payables to Affiliates 20 44
Other 120 110
- ---------------------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 3,356 3,358
- ---------------------------------------------------------------------------------------------------------------------
COMPANY-OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES OF A PARTNERSHIP,
WHICH HOLDS SOLEY SUBORDINATED
DEBENTURES OF THE COMPANY 128 128
MANDATORILY REDEEMABLE PREFERRED STOCK 19 19
COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS' EQUITY
Common Stock 1,911 1,912
Receivable from Parent (1,818) (1,878)
Preferred Stock 137 137
Retained Earnings 277 270
Accumulated Other Comprehensive Income 15 19
- ---------------------------------------------------------------------------------------------------------------------
Total Shareholders' Equity 522 460
- ---------------------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 10,717 $ 10,745
- ---------------------------------------------------------------------------------------------------------------------
See 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 June 30, Six Months Ended June 30,
--------------------------- -------------------------
(in millions) 2002 2001 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES
Operating Revenues $ 606 $ 677 $1,175 $ 1,392
Operating Revenues from Affiliates 953 906 1,845 1,819
- ---------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 1,559 1,583 3,020 3,211
- ---------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Purchased Power 634 690 1,186 1,272
Purchased Power from Affiliates 71 31 137 48
Fuel 224 230 433 449
Operating and Maintenance 405 400 833 798
Operating and Maintenance Expense from Affiliates 6 5 11 11
Depreciation and Amortization 65 75 128 167
Taxes Other Than Income 41 39 90 85
- ---------------------------------------------------------------------------------------------------------------------
Total Operating Expense 1,446 1,470 2,818 2,830
- ---------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 113 113 202 381
- ---------------------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (10) (17) (27) (35)
Interest Expense from Affiliates (1) (9) (1) (24)
Equity in Earnings of Unconsolidated Affiliates 9 13 32 39
Other, net 24 14 40 18
- ---------------------------------------------------------------------------------------------------------------------
Total Other Income and Deductions 22 1 44 (2)
- ---------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT
OF CHANGES IN ACCOUNTING PRINCIPLES 135 114 246 379
INCOME TAXES 51 43 96 150
- ---------------------------------------------------------------------------------------------------------------------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN
ACCOUNTING PRINCIPLES 84 71 150 229
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING
PRINCIPLES -- -- 13 12
- ---------------------------------------------------------------------------------------------------------------------
NET INCOME 84 71 163 241
- ---------------------------------------------------------------------------------------------------------------------
OTHER COMPREHENSIVE INCOME (LOSS) (net of income taxes)
Unrealized Gain (Loss) on Marketable Securities (74) 31 (83) (80)
SFAS 133 Transition Adjustment -- -- -- 4
Cash Flow Hedge Fair Value Adjustment 6 (35) (67) (36)
- ---------------------------------------------------------------------------------------------------------------------
Total Other Comprehensive Income (Loss) (68) (4) (150) (112)
- ---------------------------------------------------------------------------------------------------------------------
TOTAL COMPREHENSIVE INCOME $ 16 $ 67 $ 13 $ 129
- ---------------------------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements
17
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended June 30,
----------------------------
(in millions) 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 163 $ 241
Adjustments to Reconcile Net Income to Net Cash Flows
Provided by Operating Activities:
Depreciation and Amortization, including nuclear fuel 312 366
Cumulative Effect of a Change in Accounting Principle (net of income taxes) (13) (12)
Provision for Uncollectible Accounts 17 3
Deferred Income Taxes (4) (6)
Equity in (Earnings) Losses of Unconsolidated Affiliates (32) (39)
Net Realized Losses on Nuclear Decommissioning Trust Funds 21 24
Other Operating Activities 70 (116)
Changes in Working Capital:
Accounts Receivable (136) 115
Changes in Receivables and Payables to Affiliates, net (93) (161)
Inventories (54) (110)
Accounts Payable, Accrued Expenses and Other Current Liabilities 316 156
Other Current Assets (48) 24
- ---------------------------------------------------------------------------------------------------------------------
Net Cash Flows provided by Operating Activities 519 485
- ---------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures (475) (301)
Acquisition of Generating Plants (443) --
Proceeds from Nuclear Decommissioning Trust Funds 889 621
Investment in Nuclear Decommissioning Trust Funds (943) (655)
Note Receivable from Affiliate (75) 236
Other Investing Activities (1) --
- ---------------------------------------------------------------------------------------------------------------------
Net Cash Flows used in Investing Activities (1,048) (99)
- ---------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Change in Intercompany Payable, Affiliate 331 (696)
Issuance of Long-Term Debt -- 752
Retirement of Long-Term Debt (2) (2)
Distribution to Member -- (121)
- ---------------------------------------------------------------------------------------------------------------------
Net Cash Flows provided by (used in) Financing Activities 329 (67)
- ---------------------------------------------------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (200) 319
- ---------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 224 4
- ---------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 24 $ 323
- ---------------------------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements
18
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, December 31,
(in millions) 2002 2001
- ----------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 24 $ 224
Accounts Receivable, net
Customer 503 316
Other 38 150
Receivable from Affiliate 523 444
Inventories, at average cost
Fossil Fuel 135 105
Materials and Supplies 227 202
Accumulated Deferred Income Taxes 7 --
Other 103 65
- ----------------------------------------------------------------------------------------
Total Current Assets 1,560 1,506
- ----------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT, NET 2,650 2,003
DEFERRED DEBITS AND OTHER ASSETS
Nuclear Decommissioning Trust Funds 3,060 3,165
Investments 913 859
Notes Receivable from Affiliates 261 291
Deferred Income Taxes 437 297
Other 223 223
- ----------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 4,894 4,835
- ----------------------------------------------------------------------------------------
TOTAL ASSETS $ 9,104 $ 8,344
- ----------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements
19
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, December 31,
(in millions) 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
LIABILITIES AND MEMBER'S EQUITY
CURRENT LIABILITIES
Long-Term Debt Due within One Year $ 6 $ 4
Accounts Payable 788 585
Accounts Payable to Affiliate 16 105
Notes Payable to Affiliate 331 --
Accrued Expenses 416 303
Deferred Income Taxes -- 7
Other 215 171
- ---------------------------------------------------------------------------------------------------------------------
Total Current Liabilities 1,772 1,175
- ---------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT 1,065 1,021
DEFERRED CREDITS AND OTHER LIABILITIES
Unamortized Investment Tax Credits 230 234
Nuclear Decommissioning Liability for Retired Plants 1,379 1,353
Pension Obligation 102 118
Non-Pension Postretirement Benefits Obligation 396 384
Spent Nuclear Fuel Obligation 851 843
Other 361 280
- ---------------------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 3,319 3,212
- ---------------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES
MEMBER'S EQUITY
Membership Interest 2,316 2,316
Undistributed Earnings 686 523
Accumulated Other Comprehensive Income (Loss) (54) 97
- ---------------------------------------------------------------------------------------------------------------------
Total Member's Equity 2,948 2,936
- ---------------------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND MEMBER'S EQUITY $ 9,104 $ 8,344
- ---------------------------------------------------------------------------------------------------------------------
See 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
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 June 30, 2002
and for the three and six months then ended are unaudited, but include all
adjustments that Exelon Corporation (Exelon), Commonwealth Edison Company
(ComEd), PECO Energy Company (PECO) and Exelon Generation Company, LLC
(Generation) consider 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, 2001 consolidated balance sheet data
were derived from audited financial statements but do not include all
disclosures required by generally accepted accounting principles. 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 and PECO included in or incorporated by
reference in Item 8 of their Annual Report on Form 10-K for the year ended
December 31, 2001 and the Notes to Consolidated Financial Statements in
Generation's Form S-4 registration statement declared effective on April 24,
2002 by the Securities and Exchange Commission (SEC), (Generation's Form S-4).
See ITEM 6. Exhibits and Reports on Form 8-K.
2. ADOPTION OF NEW ACCOUNTING PRINCIPLES (Exelon, ComEd, PECO and Generation)
SFAS No. 141 and SFAS No. 142
In 2001, the Financial Accounting Standard Board (FASB) issued
Statement of Accounting Standard (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
is effective for business combinations initiated after June 30, 2001. In
addition, SFAS No. 141 requires that unamortized negative goodwill related to
pre-July 1, 2001 purchases be recognized as a change in accounting principle
concurrent with the adoption of SFAS No. 142, "Goodwill and Other Intangible
Assets" (SFAS No. 142). At December 31, 2001, AmerGen 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,
21
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 business (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 model. These cash flows were discounted to
2002 using a risk-adjusted discount rate. The impairment was recorded as a
cumulative effect of a change in accounting principle in the first quarter of
2002.
The changes in the carrying amount of goodwill by reportable segment
(see Note 6 for further discussion of reportable segments) for the six months
ended June 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 contingency (7) -- (7)
- ---------------------------------------------------------------------------------------------------------------------
Balance as of June 30, 2002 $ 4,895 $ 76 $ 4,971
- ---------------------------------------------------------------------------------------------------------------------
The June 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.
22
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) $ (254)
Minority interest (net of income taxes of $4 million) 11
Elimination of AmerGen negative goodwill (net of income taxes of $9 million) 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 six months ended June 30,
2002 and 2001, respectively, adjusted to exclude 2001 amortization expense
related to goodwill that is no longer being amortized.
Exelon
Three Months Ended June 30, Six Months Ended June 30,
--------------------------- -------------------------
2002 2001 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
Reported income before cumulative effect
of changes in accounting principles $ 485 $ 315 $ 722 $ 702
Cumulative effect of changes in
accounting principles -- -- (230) 12
- ---------------------------------------------------------------------------------------------------------------------
Reported net income 485 315 492 714
Goodwill amortization -- 38 -- 77
- ---------------------------------------------------------------------------------------------------------------------
Adjusted net income $ 485 $ 353 $ 492 $ 791
- ---------------------------------------------------------------------------------------------------------------------
Basic earnings per common share:
Reported income before cumulative effect
of changes in accounting principles $ 1.50 $ 0.98 $ 2.24 $ 2.19
Cumulative effect of changes in
accounting principles -- -- (0.71) 0.04
- ---------------------------------------------------------------------------------------------------------------------
Reported net income 1.50 0.98 1.53 2.23
Goodwill amortization -- 0.12 -- 0.24
- ---------------------------------------------------------------------------------------------------------------------
Adjusted net income $ 1.50 $ 1.10 $ 1.53 $ 2.47
- ---------------------------------------------------------------------------------------------------------------------
Diluted earnings per common share:
Reported income before cumulative effect
of changes in accounting principles $ 1.50 $ 0.97 $ 2.23 $ 2.17
Cumulative effect of changes in
accounting principles -- -- (0.71) 0.04
- ---------------------------------------------------------------------------------------------------------------------
Reported net income 1.50 0.97 1.52 2.21
Goodwill amortization -- 0.12 -- 0.24
- ---------------------------------------------------------------------------------------------------------------------
Adjusted net income $ 1.50 $ 1.09 $ 1.52 $ 2.45
- ---------------------------------------------------------------------------------------------------------------------
ComEd
Three Months Ended June 30, Six Months Ended June 30,
--------------------------- --------------------------
2002 2001 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
Reported net income $ 231 $ 182 $ 360 $ 329
Goodwill amortization -- 32 -- 64
- ---------------------------------------------------------------------------------------------------------------------
Adjusted net income $ 231 $ 214 $ 360 $ 393
- ---------------------------------------------------------------------------------------------------------------------
Generation
The cessation of the amortization of negative goodwill of AmerGen on
January 1, 2002 did not have a material impact on Generation's reported net
income for the three or six months ended June 30, 2002.
24
EITF Issue 02-3
Exelon and 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 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, revenues from trading activity were presented in Revenue
and the energy costs related to energy trading were presented as either
Purchased Power or Fuel expense on Exelon and Generation's Consolidated
Statements of Income. For comparative purposes, energy costs related to energy
trading have been reclassified in prior periods to revenue to conform with the
net basis of presentation required by EITF 02-3. For the three and six months
ended June 30, 2001, $30 million of purchased power expense and $5 million of
fuel expense 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 six months ended June 30, 2002.
SFAS No. 144
In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets" (SFAS No. 144). Exelon, ComEd, PECO
and Generation adopted SFAS No. 144 on January 1, 2002. SFAS No. 144 establishes
accounting and reporting standards for both the impairment and disposal of
long-lived assets. SFAS No. 144 is effective for fiscal years beginning after
December 15, 2001 and its provisions are generally applied prospectively. The
adoption of this statement had no effect on Exelon's reported financial
positions, results of operations or cash flows.
SFAS No. 133
SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities" (SFAS No. 133) applies to all derivative instruments and requires
that such instruments be recorded on the balance sheet either as an asset or a
liability measured at their fair value through earnings, with special accounting
permitted for certain qualifying hedges. On January 1, 2001, Exelon, ComEd,
PECO, and Generation adopted SFAS No. 133. Generation recognized a non-cash gain
of $12 million, net of income taxes, in earnings and deferred a non-cash gain of
$4 million, net of income taxes, in accumulated other comprehensive income and
PECO deferred a non-cash gain of $40 million, net of income taxes, in
accumulated other comprehensive income.
3. ACQUISITIONS AND DISPOSITIONS (Exelon and Generation)
Acquisition of Generating Plants from TXU
On April 25, 2002, Generation acquired two natural-gas and oil-fired plants from
TXU Corp. (TXU) for an aggregate purchase price of $443 million. The purchase
included the 893-megawatt Mountain Creek Steam Electric Station in Dallas and
the 1,441-megawatt Handley Steam Electric Station in Fort Worth. The transaction
included a power purchase agreement for TXU to purchase power during the months
of May through September from 2002 through 2006. During the periods covered by
the power purchase agreement, TXU will make fixed capacity payments and will
provide fuel to Exelon in return for exclusive rights to the energy and capacity
of the generation plants. Substantially all of the purchase price has been
allocated to property, plant, and equipment pending final valuation of plant
assets.
25
Sale of AT&T Wireless
On April 1, 2002, Enterprises sold its 49% interest in AT&T Wireless
PCS of Philadelphia, LLC to a subsidiary of AT&T Wireless Services for $285
million in cash. Enterprises recorded an after-tax gain of $116 million in
other, net on the $84 million investment, which was reflected in Deferred Debits
and Other Assets on Exelon's Consolidated Balance Sheets.
Sithe New England Holdings, LLC Acquisition
On June 26, 2002, Generation agreed to purchase Sithe New England
Holdings, LLC, (Sithe New England) a subsidiary of Sithe Energies Inc. (Sithe),
and related power marketing operations in exchange for a $543 million note plus
the assumption of non-recourse debt, estimated to be approximately $1.2 billion
at the transaction closing date. The parties are seeking Federal Energy
Regulatory Commission (FERC) and other required approvals of the purchase by
October 31, 2002. Exelon has negotiated closing conditions that allow Exelon to
terminate the purchase if the conditions are not satisfied. If approved, and if
the closing conditions are satisfied, the transaction could be completed in
November 2002.
The purchase involves approximately 4,471 MWs of generation capacity,
consisting of 2,050 MWs in operation and 2,421 MWs under construction, which
will increase Generation's net assets by approximately $1.7 billion when the
transaction closes. Sithe New England's generation facilities are located
primarily in Massachusetts, but are also located in Maine.
Generation is a 49.9% owner of Sithe and accounts for the investment as
an unconsolidated equity investment. The Sithe New England purchase will not
affect the accounting for Sithe as an equity investment. Additionally,
Generation is subject to a Put and Call Agreement (PCA) that gives Generation
the right to purchase (Call) the remaining 50.1% of Sithe, and gives the other
Sithe shareholders the right to sell (Put) their interest to Generation. If the
Put option is exercised, Generation has the obligation to complete the purchase.
The PCA provides that the Put and Call options become exercisable as of December
18, 2002. The Sithe New England purchase is a separate transaction from the PCA
that 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, ComEd and PECO)
On April 1, 2002, the Illinois Commerce Commission (ICC) issued an
interim order in ComEd's Delivery Services Rate Case. The interim order is
subject to an audit of test year expenditures that is anticipated to be
completed by the end of 2002 with a final order to be issued in 2003. The order
sets new delivery rates for residential customers choosing a new retail electric
supplier. The new rates became effective May 1, 2002 when residential customers
were eligible to choose their supplier of electricity. Traditional bundled rates
paid by customers that retain ComEd as their electricity supplier are not
affected by this order. Bundled rates will remain frozen through 2006, as a
result of the June 6, 2002 amendments to the Illinois
26
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.
As permitted by the Pennsylvania Electric Competition Act, the
Pennsylvania Department of Revenue has calculated a 2002 Revenue Neutral
Reconciliation (RNR) adjustment to the gross receipts tax rate in order to
neutralize the impact of electric restructuring on its tax revenues. In January
2002, the 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 change in the gross receipts tax rate. The
RNR adjustment is under appeal. The RNR adjustment increases the gross receipts
tax rate, which will increase PECO's annual revenues and tax obligations by
approximately $50 million in 2002.
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 June 30, Six Months Ended June 30,
--------------------------- -------------------------
2002 2001 2002 2001
- ----------------------------------------------------------------------------------------------------------------------
Average common shares outstanding 322 321 322 320
Assumed exercise of stock options 2 3 2 3
- ----------------------------------------------------------------------------------------------------------------------
Average diluted common shares outstanding 324 324 324 323
- ----------------------------------------------------------------------------------------------------------------------
Stock options not included in average common shares used in calculating
diluted earnings per share due to their antidilutive effect were three million
for the three and six months ended June 30, 2002 and one million for the three
and six months ended June 30, 2001.
27
6. SEGMENT INFORMATION (Exelon)
Exelon operates in three business segments: energy delivery, generation
and enterprises. Energy delivery consists of the operations of ComEd and PECO.
Beginning in 2002, Exelon evaluates the performance of its business segments on
the basis of net income. Exelon's segment information for the three months and
six months ended June 30, 2002 as compared to the same periods in 2001 and at
June 30, 2002 and December 31, 2001 are as follows:
Three Months Ended June 30, 2002 as compared to Three Months Ended June 30, 2001
Corporate and
Energy Intersegment
Delivery Generation Enterprises Eliminations Consolidated
-------------------------------------------------------------------------------------------------------------------
Revenues:
2002 $ 2,476 $ 1,559 $ 476 $ (992) $ 3,519
2001 2,436 1,583 546 (949) 3,616
Intersegment Revenues:
2002 $ 15 $ 953 $ 24 $ (992) $ --
2001 16 906 27 (949) --
Net Income:
2002 $ 322 $ 84 $ 83 $ (4) $ 485
2001 264 71 (5) (15) 315
-------------------------------------------------------------------------------------------------------------------
Six Months Ended June 30, 2002 as compared to Six Months Ended June 30, 2001
Corporate and
Energy Intersegment
Delivery Generation Enterprises Eliminations Consolidated
-------------------------------------------------------------------------------------------------------------------
Revenues:
2002 $ 4,811 $ 3,020 $ 966 $(1,921) $ 6,876
2001 4,933 3,211 1,213 (1,918) 7,439
Intersegment Revenues:
2002 $ 29 $ 1,845 $ 47 $(1,921) $ --
2001 59 1,819 40 (1,918) --
Net Income:
2002 $ 538 $ 163 $ (188) $ (21) $ 492
2001 530 241 (30) (27) 714
-------------------------------------------------------------------------------------------------------------------
Total Assets:
June 30, 2002 $26,915 $ 9,104 $ 1,290 $(1,688) $ 35,621
December 31, 2001 26,461 8,344 1,790 (1,735) 34,860
-------------------------------------------------------------------------------------------------------------------
28
7. FAIR VALUE OF FINANCIAL ASSETS AND LIABILITIES (Exelon, ComEd, PECO and
Generation)
During the three and six months ended June 30, 2002 and 2001, Exelon
recorded net gains/(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 June 30, 2002 $(13) $ (7) $ 15 $ (3) $ (8)
Three months ended June 30, 2001 -- 15 (61) (2) (48)
Six months ended June 30, 2002 (6) (1) (107) 14 (100)
Six months ended June 30, 2001 -- 8 (62) 2 (52)
- ---------------------------------------------------------------------------------------------------------------------
During the three months ended June 30, 2002 and 2001, and the six
months ended June 30, 2002 and 2001, Generation recognized net MTM gains on
non-trading energy derivative contracts not designated as cash flow hedges, in
operating revenues as follows:
2002 2001
- ---------------------------------------------------------------------------------------------------------------------
Three months ended June 30, $ 4 $ 5
Six months ended June 30, 10 22
- ---------------------------------------------------------------------------------------------------------------------
During the three months ended June 30, 2002 and 2001 and the six months
ended June 30, 2002 and 2001, no amounts were reclassified from accumulated
other comprehensive income into earnings as a result of forecasted energy
commodity transactions no longer being probable.
During the three months ended June 30, 2002 and 2001, and the six
months ended June 30, 2002 and 2001, Generation recognized net MTM losses on
energy trading contracts, in operating revenues as follows:
2002 2001
- ---------------------------------------------------------------------------------------------------------------------
Three months ended June 30, $ (9) $ (6)
Six months ended June 30, (13) (6)
- ---------------------------------------------------------------------------------------------------------------------
During the three months ended June 30, 2002 and 2001 and the six months
ended June 30, 2002 and 2001, PECO reclassified other income in the Consolidated
Statements of Income and Comprehensive Income, as a result of the discontinuance
of cash flow hedges related to certain forecasted financing transactions that
were no longer probable of occurring as follows:
2002 2001
- ---------------------------------------------------------------------------------------------------------------------
Three months ended June 30, $ -- $ --
Six months ended June 30, -- 6
- ---------------------------------------------------------------------------------------------------------------------
29
As of June 30, 2002, deferred net gains on derivative instruments
accumulated in other comprehensive income are expected to be reclassified to
earnings during the next twelve months are as follows:
ComEd PECO Generation Enterprises Exelon
- ---------------------------------------------------------------------------------------------------------------------
Gains Expected to be Reclassified $ 1 $ 15 $ -- $ 2 $ 18
- ---------------------------------------------------------------------------------------------------------------------
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.
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.
June 30, 2002
---------------------------------------------------------------
Gross Gross
Amortized Unrealized Unrealized Estimated
Cost Gains Losses Fair Value
- ---------------------------------------------------------------------------------------------------------------------
Equity securities $ 1,677 $ 115 $ (406) $ 1,386
Debt securities
Government obligations 994 39 (1) 1,032
Other debt securities 641 18 (17) 642
- ---------------------------------------------------------------------------------------------------------------------
Total debt securities 1,635 57 (18) 1,674
- ---------------------------------------------------------------------------------------------------------------------
Total available-for-sale securities $ 3,312 $ 172 $ (424) $ 3,060
- ---------------------------------------------------------------------------------------------------------------------
Unrealized gains and losses are recognized in Accumulated Depreciation
and Accumulated Other Comprehensive Income in Generation's Consolidated Balance
Sheet.
For the three months ended June 30, 2002, proceeds from the sale of
decommissioning trust investments and gross realized gains and losses on those
sales were $309 million, $13 million and $24 million, respectively. For the six
months ended June 30, 2002, proceeds from the sale of decommissioning trust
investments and gross realized gains and losses on those sales were $889
million, $31 million and $56 million, respectively.
Net realized losses of $4 million were recognized in Accumulated
Depreciation in Generation's Consolidated Balance Sheets at June 30, 2002 and
$21 million of net realized losses were recognized in Other Income and
Deductions in Generation's Consolidated Statements of Income and Comprehensive
Income for the six months ended June 30, 2002. The available-for-sale securities
held at June 30, 2002 have an average maturity of eight to ten years. The cost
of these securities was determined on the basis of specific identification.
30
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 Note in the
Consolidated Financial Statements of Exelon, ComEd and PECO for the year ended
December 31, 2001 and Generation's S-4 dated April 24, 2002.
Environmental Liabilities
Exelon has identified 72 sites where former manufactured gas plant
(MGP) activities have or may have resulted in actual site contamination. As of
June 30, 2002, Exelon had accrued $139 million for environmental investigation
and remediation costs that currently can be reasonably estimated, including $115
million for MGP investigation and remediation.
ComEd had accrued $96 million (discounted) as of June 30, 2002, for
environmental investigation and remediation costs that currently can be
reasonably estimated. This reserve included $90 million for MGP investigation
and remediation. ComEd is currently experiencing delays in the ongoing
remediation of an MGP site in Oak Park, Illinois, and is evaluating the impact
of those delays on the cost to complete the project. The impact of the delays is
currently uncertain, but could increase the environmental reserve in the future.
PECO had accrued $34 million (undiscounted) as of June 30, 2002, for
environmental investigation and remediation costs that currently can be
reasonably estimated, including $25 million for MGP investigation and
remediation.
Generation had accrued $9 million (undiscounted) as of June 30, 2002,
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.
31
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:
Power Only Purchases from
Net Capacity Power Only ------------------------- Transmission
Purchases (1) Sales AmerGen Non-Affiliates Rights Purchases
- ---------------------------------------------------------------------------------------------------------------------
2002 $ 634 $ 2,111 $ 127 $ 1,659 $ 72
2003 692 1,491 247 588 108
2004 859 822 301 200 89
2005 389 244 227 78 83
2006 352 120 227 66 2
Thereafter 4,120 23 2,045 272 --
- ---------------------------------------------------------------------------------------------------------------------
Total $ 7,046 $ 4,811 $ 3,174 $ 2,863 $ 354
- ---------------------------------------------------------------------------------------------------------------------
(1) Net Capacity Purchases includes Midwest Generation commitments as of July
1, 2002. On July 1, 2002, Generation notified Midwest Generation of the
exercise of its call options under the existing Coal Generation Purchase
Power Agreement. Generation exercised options on 1,265 MWs of capacity and
did not exercise options on 2,684 MWs of capacity. In 2003, Generation will
take 1,696 MWs of non-option capacity and 1,265 MWs of option capacity
under the existing contract. Net Capacity Purchases also includes capacity
sales to TXU under the purchase power agreement entered into in connection
with the purchase of two generating plants in April 2002, which states that
TXU will purchase the plant output from May through September from 2002
through 2006. The combined capacity of the two plants is 2,334 MWs.
In connection with the 2001 corporate restructuring, ComEd entered into
a purchase power agreement (PPA) with Generation. Under the terms of the PPA,
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.
The PPA also specifies that prior to 2005, ComEd and Generation will jointly
determine and agree on a market-based price for energy delivered under the PPA
for 2005 and 2006. In the event that the parties cannot agree to market-based
prices for 2005 and 2006 prior to July 1, 2004, ComEd has the option of
terminating the PPA effective December 31, 2004. ComEd will obtain any
additional supply required from market sources in 2005 and 2006, and subsequent
to 2006, will obtain all of its supply from market sources, which could include
Generation.
In connection with the 2001 corporate restructuring, PECO entered into
a PPA with Generation. Under the terms of the PPA, PECO obtains substantially
all of its electric supply from Generation through 2010. Also, under the
restructuring, PECO assigned its rights and 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.
32
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, a total of six
nearly identical class action lawsuits were filed in the Federal District Court
in Chicago asserting securities claims on behalf of Exelon investors during
April to September 2001. 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.
On May 30 and July 2, 2002, the Court granted Exelon's agreed-upon motions to
consolidate the pending cases into one lawsuit, and stayed discovery
indefinitely. A lead plaintiff has not been selected. 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 the January 1, 1992 franchise agreement. As part of
the settlement agreement, ComEd and Chicago agreed to a revised combination of
ongoing work under the franchise agreement and new initiatives that will result
in defined transmission and distribution expenditures by ComEd to improve
electric services in Chicago. The settlement agreement provides that ComEd would
be subject to liquidated damages if the projects are not completed by various
dates, unless it was prevented from doing so by events beyond its reasonable
control. In addition, ComEd and Chicago established an Energy Reliability and
Capacity Account, into which ComEd deposited $25 million during each of the
years 1999 through 2001 and has conditionally agreed to deposit $25 million at
the end of 2002, to help ensure an adequate and reliable electric supply for
Chicago.
FERC Municipal Request for Refund. Three of ComEd's wholesale municipal
customers filed a complaint and request for refund with the FERC alleging that
ComEd failed to properly adjust its rates, as provided for under the terms of
the electric service contracts with the municipal customers and to track certain
refunds made to ComEd's retail customers in the years 1992 through 1994. In the
third quarter of 1998, FERC granted the complaint and directed that refunds be
made, with interest. ComEd filed a request for rehearing. On April 30, 2001,
FERC issued an order granting rehearing in which it determined that its 1998
order had been erroneous and that no refunds were due from ComEd to the
municipal customers. On June 29, 2001, FERC denied the customers' requests for
rehearing of the order granting rehearing. In August 2001, each of the three
wholesale municipal customers appealed the April 30, 2001 FERC order to the
Federal circuit court, which consolidated the appeals for the purposes of
briefing and decision. In November 2001, the court suspended briefing pending
court-initiated settlement discussions.
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
33
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, the Illinois
Appellate Court held that the developers' claims against the state were
premature, and the Illinois Supreme Court denied leave to appeal that ruling.
Developers of both facilities have since filed amended complaints repeating
their allegations that ComEd breached the contracts in question and requesting
damages for such breach reflecting the state-subsidized rate to which the
developers claim they were entitled under their contracts. These matters are in
the discovery phase. Certain of the plaintiffs have produced an expert report
claiming approximately $175 million in damages, a quantification ComEd
vigorously disputes. Virtually all parties have filed motions for summary
judgment. ComEd is contesting each case and has filed its motion for summary
judgment arguing that, as a matter of law, it did not breach any of the
contracts.
Service Interruptions. In August 1999, three class action lawsuits were
filed against ComEd, and subsequently consolidated, in the Circuit Court of Cook
County, Illinois seeking damages for personal injuries, property damage and
economic losses related to a series of service interruptions that occurred in
the summer of 1999. The combined effect of these interruptions resulted in over
168,000 customers losing service for more than four hours. Conditional class
certification was approved by the court for the sole purpose of exploring
settlement talks. ComEd filed a motion to dismiss the complaints. On April 24,
2001, the court dismissed four of the five counts of the consolidated complaint
without prejudice and the sole remaining count was dismissed in part. On June 1,
2001, the plaintiffs filed a second amended consolidated complaint and ComEd has
filed an answer. A portion of any settlement or verdict may be covered by
insurance; discussions with the carrier are ongoing.
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.
ComEd and 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 attorneys fees. On
34
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.
Generation
Cotter Corporation Litigation. During 1989 and 1991, actions were
brought in Federal and state courts in Colorado against ComEd and its
subsidiary, Cotter Corporation (Cotter), seeking unspecified damages and
injunctive relief based on allegations that Cotter permitted radioactive and
other hazardous material to be released from its mill into areas owned or
occupied by the plaintiffs, resulting in property damage and potential adverse
health effects. In 1994, a Federal jury returned nominal dollar verdicts against
Cotter on eight plaintiffs' claims in the 1989 cases, which verdicts were upheld
on appeal. The remaining claims in the 1989 actions were settled or dismissed.
In 1998, a jury verdict was rendered against Cotter in favor of 14 of the
plaintiffs in the 1991 cases, totaling approximately $6 million in compensatory
and punitive damages, interest and medical monitoring. On appeal, the Tenth
Circuit Court of Appeals reversed the jury verdict, and remanded the case for
new trial. These plaintiffs' cases were consolidated with the remaining 26
plaintiffs' cases, which had not been tried. The consolidated trial was
completed on June 28, 2001. The jury returned a verdict against Cotter and
awarded $16.3 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 million. This matter is being appealed by Cotter in the Tenth
Circuit Court of Appeals. Cotter will vigorously contest the award.
In November 2000, another trial involving a separate sub-group of 13
plaintiffs, seeking $19 million in damages plus interest was completed in
federal district court in Denver. The jury awarded nominal damages of $42,500 to
11 of 13 plaintiffs, but awarded no damages for any personal injury or health
claims, other than requiring Cotter to perform periodic medical monitoring at
minimal cost. Cotter and the plaintiffs both appealed the verdict to the Tenth
Circuit Court of Appeals.
On February 18, 2000, ComEd sold Cotter to an unaffiliated third party.
As part of the sale, ComEd agreed to indemnify Cotter for any liability incurred
by Cotter as a result of these actions, as well as any liability arising in
connection with the West Lake Landfill discussed in the next paragraph. In
connection with Exelon's 2001 corporate restructuring, the responsibility to
indemnify Cotter for any liability related to these matters was transferred by
ComEd to Generation.
The United States Environmental Protection Agency (EPA) has advised
Cotter that it is potentially liable in connection with radiological
contamination at a site known as the West Lake Landfill in Missouri. Cotter is
alleged to have disposed of approximately 39,000 tons of soils mixed with 8,700
tons of leached barium sulfate at the site. Cotter, along with three other
companies identified by the EPA as potentially responsible parties (PRPs), is
reviewing a draft feasibility study that recommends capping the site. The PRPs
are also engaged in discussions with the State of Missouri and the EPA. The
estimated costs of remediation for the site are $10 to $15 million. Once a final
feasibility study is complete and a remedy selected, it is expected
35
that the PRPs will agree on an allocation of responsibility for the costs. Until
an agreement is reached, Exelon cannot predict its share of the costs.
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),
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.
General
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 its respective financial condition or results of operations.
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,
while the reserves associated with Unicom were recorded as part of the
application of purchase accounting and did not affect results of operations.
Merger-related costs charged to expense in 2000 were $276 million,
consisting of $124 million for PECO employee costs and $152 million of direct
incremental costs. Direct incremental costs represent expenses directly
associated with completing the Merger, including professional fees, regulatory
approval and settlement costs, and settlement of compensation arrangements.
Employee costs represent estimated severance costs and pension and
postretirement benefits provided under Exelon's merger separation plans for
eligible employees who are expected to be involuntarily terminated before
December 2002 due to integration activities of the merged companies.
The purchase price allocation as of December 31, 2000 included a
liability of $307 million for Unicom employee costs and liabilities of
approximately $39 million for estimated costs of exiting various business
activities of former Unicom activities that were not compatible with the
strategic business direction of Exelon.
36
During 2001, Exelon finalized its 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 and
recorded adjustments to the purchase price allocation as follows:
Original 2001 Adjusted
Estimate Adjustments Liabilities
- ------------------------------------------------------------------------------------------------------------------------
Employee severance payments $ 128 $ 33 $ 161 (a)
Relocation and other benefits 21 9 30 (a)
- ------------------------------------------------------------------------------------------------------------------------
Employee severance payments and relocation and other benefits 149 42 191
Actuarially determined pension and postretirement costs 158 (11) 147 (b)
- ------------------------------------------------------------------------------------------------------------------------
Total Unicom - Employee Cost $ 307 $ 31 $ 338
- ------------------------------------------------------------------------------------------------------------------------
(a) The increase is a result of the identification in 2001 of additional
positions to be eliminated.
(b) The reduction results from lower estimated pension and post retirement
welfare benefits reflecting revised actuarial estimates.
The following table provides a reconciliation of the reserve for
employee severance and relocation costs associated with the merger:
- ------------------------------------------------------------------------------------------------------------------------
Employee severance and relocation reserve as of October 20, 2000 $ 149
Additional reserve 42
- ------------------------------------------------------------------------------------------------------------------------
Adjusted employee severance and relocation reserve 191
Payments to employees (October 2000-March 2002) (92)
Payments to employees (April 2002-June 2002) (33)
- ------------------------------------------------------------------------------------------------------------------------
Employee severance and relocation reserve as of June 30, 2002 $ 66
- ------------------------------------------------------------------------------------------------------------------------
Additional employee severance costs of $48 million primarily related to
PECO employees were charged to expense in 2001. Exelon anticipates that a total
of $281 million of employee costs will be funded from pension and postretirement
benefit plans.
As part of the January 2001 corporate restructuring, portions of the
employee severance and restructuring reserve were transferred from ComEd to
Generation, Enterprises and Exelon Business Services Company (BSC).
Approximately $37 million and $15 million of the employee severance and
relocation reserve as of June 30, 2002 relates to ComEd and Generation,
respectively, and is reflected on the Consolidated Balance Sheets of those
entities.
Approximately 3,300 Unicom and PECO positions have been identified to
be eliminated as a result of the merger. Exelon has terminated 2,255 employees
as of June 30, 2002 of which 510 were terminated in the second quarter of 2002.
The remaining positions are expected to be eliminated by the end of 2002.
10. LONG-TERM DEBT (Exelon and ComEd)
On June 13, 2002, ComEd issued $200 million of 6.15% First Mortgage
Bonds, due March 15, 2012. The $200 million bond issuance was a refinancing of
the $200 million of 8.5% First Mortgage Bonds redeemed on July 15, 2002 at a
redemption price of 103.915% of the principal amount.
37
In connection with the issuance of the $200 million of First Mortgage
Bonds, ComEd settled a forward starting interest rate swap in the notional
amount of $75 million resulting in a $1 million loss recorded in other
comprehensive income, which is being amortized over the expected remaining life
of the related debt.
On April 15, 2002, ComEd issued $100 million of Illinois Development
Finance Authority floating-rate Pollution Control Revenue Refunding Bonds,
Series 2002. 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.
On March 13, 2002, ComEd issued $400 million of 6.15% First Mortgage
Bonds, due March 15, 2012. This $400 million bond issuance refinanced other
First Mortgage Bonds. In connection with the issuance of $400 million of First
Mortgage Bonds, ComEd settled forward starting interest rate swaps in the
aggregate notional amount of $375 million resulting in a $9 million loss
recorded in other comprehensive income, which is being amortized over the
expected remaining life of the related debt.
On March 21, 2002, ComEd redeemed $200 million of 8.625% First Mortgage
Bonds at the redemption price of 103.84% of the principal amount. These bonds
had a maturity date of February 1, 2022.
During the six months ended June 30, 2002, ComEd recorded prepayment
premiums of $9 million, partially offset by net unamortized premiums, discounts
and debt issuance expenses of $2 million, associated with the early retirement
of debt in 2002 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.
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 June 30, 2002, PECO had sold a $225 million interest
in accounts receivable, consisting of a $170 million interest in 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 $55 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 June 30, 2002,
PECO met this requirement.
12. RELATED-PARTY TRANSACTIONS (Exelon, ComEd, PECO and Generation)
Exelon and Generation
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%. As
38
of June 30, 2002, $75 million had been loaned to AmerGen. In July 2002, the loan
agreement and the loan were increased to $100 million and the maturity date was
extended to July 1, 2003.
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, 2002. Currently, the
residual output approximates 25% of the total output of Clinton. For the three
months ended June 30, 2002 and 2001, and for the six months ended June 30, 2002
and 2001, the amount of purchased power recorded in Purchased Power in Exelon's
and Generation's Consolidated Statements of Income and Comprehensive Income is
$60 million and $12 million and $116 million and $22 million, respectively. As
of June 30, 2002 and December 31, 2001, Generation had a payable of $27 million
and $3 million, respectively, resulting from these PPAs.
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, but not less than
the higher of fully allocated costs for performing the services or the market
price. For the three months ended June 30, 2002 and 2001, the amount charged to
AmerGen for these services was $16 million. For the six months ended June 30,
2002 and 2001, the amount charged to AmerGen for these services was $30 million
and $32 million, respectively. As of June 30, 2002 and December 31, 2001,
Generation had a receivable of $61 million and $47 million, respectively,
resulting from these services.
ComEd
ComEd had a note receivable from Unicom Investments Inc. of $1.3
billion at June 30, 2002 and December 31, 2001, relating to the December 1999
fossil plant sale, which is included in Deferred Debits and Other Assets in
ComEd's Consolidated Balance Sheets. Interest income earned on this note
receivable was $7 million and $14 million, respectively, for the three months
ended June 30, 2002 and 2001 and was $15 million and $37 million, respectively,
for the six months ended June 30, 2002 and 2001. Interest receivable due on this
note was $15 million and $24 million at June 30, 2002 and December 31, 2001,
respectively, and is included in Current Assets on ComEd's Consolidated Balance
Sheets.
At December 31, 2000, ComEd had a $400 million receivable from PECO,
which was repaid in the second quarter of 2001. Interest income earned on the
receivable from PECO for the three months and six months ended June 30, 2001 was
$2 million and $8 million, respectively.
At June 30, 2002 and December 31, 2001, ComEd had an $875 million and
$937 million non-interest bearing receivable, respectively, from Exelon relating
to the 2001 corporate restructuring. This receivable is reflected as a reduction
of Shareholders' Equity in ComEd's Consolidated Balance Sheets and is expected
to be settled over the years 2002 through 2008.
39
ComEd had a short-term payable of $59 million at June 30, 2002 and
December 31, 2001, and a long-term payable of $260 million and $291 million at
June 30, 2002 and December 31, 2001, respectively, to Generation primarily
representing ComEd's legal requirements to remit collections of nuclear
decommissioning costs from customers to Generation. These liabilities to
Generation were included in Current Liabilities and Deferred Credits and Other
Liabilities, respectively, on ComEd's Consolidated Balance Sheets.
ComEd paid common stock dividends to Exelon of $117 million and $85
million for the three months ended June 30, 2002 and 2001, respectively, and of
$235 million and $148 million for the six months ended June 30, 2002 and 2001,
respectively.
Effective January 1, 2001, ComEd entered into a PPA with Generation.
Intercompany power purchases pursuant to the PPA for the three months ended June
30, 2002 and June 30, 2001 were $547 million and $585 million, respectively, and
for the six months ended June 30, 2002 and 2001 were $1,079 million and $1,193
million, respectively. At June 30, 2002 and December 31, 2001, there was a $212
million and $183 million payable, respectively, to Generation for the PPA as
well as other services provided which is included in Current Liabilities on
ComEd's Consolidated Balance Sheets.
ComEd provides electric, transmission, and other ancillary services to
Generation and Enterprises. These services were recorded in revenues and were
$12 million and $13 million for the three months ended June 30, 2002 and 2001,
respectively, and $23 million and $55 million for the six months ended June 30,
2002 and 2001, respectively. At June 30, 2002 and December 31, 2001, there was a
$3 million and $26 million receivable, respectively, for services provided,
which is included in Current Liabilities and Current Assets on ComEd's
Consolidated Balance Sheets, respectively.
ComEd receives a variety of corporate support services from BSC,
including legal, human resources, financial and information technology services.
Such services, provided at cost including applicable overhead, were $28 million
and $33 million for the three months ended June 30, 2002 and 2001, respectively,
of which $26 million and $30 million, respectively, was included in Operating
and Maintenance from Affiliates on ComEd's Consolidated Statements of Income and
Comprehensive Income and $2 million and $3 million, respectively, was
capitalized. For the six months ended June 30, 2002 and 2001, charges for such
services were $68 million and $63 million, of which $65 million and $58 million,
respectively, was included in Operating and Maintenance from Affiliates on
ComEd's Consolidated Statements of Income and Comprehensive Income and $3
million and $5 million, respectively, was capitalized. At June 30, 2002 and
December 31, 2001, there was a $6 million and $14 million payable, respectively,
to BSC for services provided which is included in Current Liabilities on ComEd's
Consolidated Balance Sheets.
ComEd receives substation and transmission engineering and construction
services under contracts with InfraSource. Such services totaling $6 million and
$13 million for the three months ended June 30, 2002 and 2001, respectively, and
totaling $13 million and $22 million for the six months ended June 30, 2002 and
2001, respectively, were capitalized.
40
ComEd has contracted with Exelon Services to provide energy
conservation services to ComEd customers. The costs were $3 million and $8
million for the three months ended June 30, 2002 and 2001, respectively, and
were $6 million and $12 million for the six months ended June 30, 2002 and 2001,
respectively, and were included in Operating and Maintenance expense on ComEd's
Consolidated Statements of Income and Comprehensive Income.
In order to benefit from economies of scale, ComEd processes certain
invoice payments on behalf of Generation and BSC. Receivables at June 30, 2002
and December 31, 2001 from Generation for such service totaled $8 million and
$21 million, respectively, and were included in Current Liabilities and Current
Assets on ComEd's Consolidated Balance Sheets, respectively, and from BSC
totaled $8 million and $19 million, respectively, and were included in Current
Assets on ComEd's Consolidated Balance Sheets.
PECO
Effective January 1, 2001, Exelon contributed to PECO a $2.0 billion
non-interest bearing receivable from Exelon related to the 2001 corporate
restructuring. This receivable is reflected as a reduction of Shareholders'
Equity in PECO's Consolidated Balance Sheets and is expected to be settled over
the years 2002 through 2010. As of June 30, 2002 and December 31, 2001, the
balance of this receivable from Exelon was $1.8 billion and $1.9 billion,
respectively.
PECO paid common stock dividends to Exelon of $85 million and $56
million for the three months ended June 30, 2002 and 2001, respectively, and
$170 million and $101 million for the six months ended June 30, 2002 and 2001,
respectively.
Effective January 1, 2001, PECO entered into a PPA with Generation.
Intercompany power purchases pursuant to the PPA were $346 million and $264
million for the three months ended June 30, 2002 and 2001, respectively, and
$649 million and $508 million for the six months ended June 30, 2002 and 2001.
As of June 30, 2002 and December 31, 2001, PECO's payable related to the PPA was
$137 million and $90 million, respectively.
PECO receives a variety of corporate support services from BSC,
including legal, human resources, financial and information technology services.
Such services, provided at cost including applicable overhead, were $7 million
and $15 million for the three months ended June 30, 2002 and 2001, respectively,
and $13 million and $17 million for the six months ended June 30, 2002 and 2001,
respectively. At June 30, 2002 and December 31, 2001, PECO had a $33 million and
$41 million payable, respectively, to BSC.
PECO receives services from Enterprises for construction and the
deployment of automated meter reading technology. Construction services totaling
$10 million and $14 million were capitalized in the six months ended June 30,
2002 and 2001, respectively. Automated meter reading technology services
totaling $8 million and $4 million for the three months ended June 30, 2002 and
2001, respectively, and totaling $16 million and $7 million for the six months
ended June 30, 2002 and 2001, respectively, were included in Operating and
Maintenance from Affiliates in the Consolidated Statements of Income and
Comprehensive Income. At June 30, 2002 and December 31, 2001, PECO had $6
million and $8 million payable, respectively, to Enterprises.
41
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%. Interest expense related to
this payable for the three and six months ended June 30, 2001 was $2 million and
$8 million, respectively.
PECO provides energy to Generation for Generation's own use.
Intercompany sales for the three and six months ended June 30, 2002 and 2001
were $2 million and $3 million, respectively, in each period.
Generation
Generation had a short-term receivable of $59 million at June 30, 2002
and December 31, 2001, and a long-term receivable of $260 million and $291
million at June 30, 2002 and December 31, 2001, respectively, from ComEd
primarily representing ComEd's legal requirements to remit collections of
nuclear decommissioning costs from customers to Generation resulting from the
restructuring. These receivables from ComEd were included in Current Assets and
Deferred Debits and Other Assets, respectively, on Generation's Consolidated
Balance Sheets.
Effective January 1, 2001, Generation entered into PPAs with ComEd and
PECO. Intercompany power sales pursuant to the PPAs for the three months ended
June 30, 2002 and 2001 were $893 million, including decommissioning revenue of
$3 million, and $849 million, including decommissioning revenue of $3 million,
respectively. For the six months ended June 30, 2002 and June 30, 2001 these
intercompany power sales were $1,728 million, including decommissioning revenue
of $6 million, and $1,701 million, including decommissioning revenue of $6
million, respectively. At June 30, 2002 and December 31, 2001, there was a $351
million and $273 million receivable, respectively, for the PPAs as well as other
services provided which is included in Current Assets on Generation's
Consolidated Balance Sheets.
Generation sells power to Exelon Energy. Power sales for the three
months ended June 30, 2002 and 2001 were $60 million and $57 million,
respectively, and for the six months ended June 30, 2002 and 2001 were $117
million and $118 million, respectively. At June 30, 2002 and December 31, 2001,
there was a $21 million and $15 million receivable, respectively.
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. These
purchases, including AmerGen, for the three months ended June 30, 2002 and 2001
were $75 million and $42 million, respectively, and for the six months ended
June 30, 2002 and 2001 were $147 million and $60 million, respectively. At June
30, 2002 and December 31, 2001, there was a payable for these power purchases of
$35 million and $26 million, respectively.
Generation receives a variety of corporate support services from BSC,
including legal, human resources, financial and information technology services.
Such services, provided at cost including applicable overhead, for the three
months ended June 30, 2002 and June 30, 2001 were $16 million and $22 million,
respectively, and $30 million and $35 million for the six months
42
ended June 30, 2002 and June 30, 2001, respectively, and were included in
Operating and Maintenance (O&M) expense on Generation's Consolidated Statements
of Income and Comprehensive Income. At June 30, 2002 and December 31, 2001,
there was an $8 million and an $18 million payable, respectively, to BSC for
services provided which is included in Current Liabilities on Generation's
Consolidated Balance Sheets.
In order to facilitate payment processing, ComEd processes certain
invoice payments on behalf of Generation and BSC. Payables at June 30, 2002 and
December 31, 2001 to ComEd for such services totaled $8 million and $21 million,
respectively, and were included in Current Liabilities on Generation's
Consolidated Balance Sheets.
In relation to the acquisition of two generating plants from TXU in
April of 2002, Generation had a $331 million payable to Exelon at June 30, 2002.
Interest expense related to this payable was $1 million for the three months and
six months ended June 30, 2002.
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. Interest expense related to this payable for the
three and six months ended June 30, 2001 was $8 million and $23 million,
respectively.
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 April 2002, the FASB issued SFAS No. 145, "
Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No.
13, and Technical Corrections" (SFAS No. 145). 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 Exelon's nuclear generating plants as well as certain other
long-lived assets.
Currently, Generation records the obligation for decommissioning
ratably over the lives of the plants. The January 1, 2003 adoption of SFAS No.
143 will require a cumulative effect adjustment effective the date of adoption
to adjust plant assets and decommissioning liabilities to the values they would
have been had this standard been employed from the in-service dates of the
plants.
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
43
liability recorded upon adoption of SFAS No. 143 will be charged to earnings and
recognized as a cumulative effect, net of expected regulatory recovery. The
decommissioning liability to be recorded represents an obligation for the future
decommissioning of the plants, and as a result accretion expense will be accrued
on this liability until such time as the obligation is satisfied.
Exelon, ComEd, PECO and Generation are in the process of evaluating the
impact of SFAS No. 143 on their financial statements, and cannot determine the
ultimate impact of adoption at this time, however, the cumulative effect could
be material to earnings. Additionally, although over the life of the plant the
charges to earnings for the depreciation of the asset and the interest on the
liability will be equal to the amounts currently recognized as decommissioning
expense, the timing of those charges will change and in the near-term period
subsequent to adoption, the depreciation of the asset and the interest on the
liability could result in an increase in expense.
SFAS No. 145 eliminates SFAS No. 4 "Reporting Gains and Losses from
Extinguishment of Debt" (SFAS No. 4) and thus allows for only those gains or
losses on the extinguishment of debt that meet the criteria of extraordinary
items to be treated as such in the financial statements. SFAS No. 145 also
amends Statement of Financial Accounting Standards No. 13, "Accounting for
Leases" (SFAS No. 13) to require sale-leaseback accounting for certain lease
modifications that have economic effects that are similar to sale-leaseback
transactions. The provisions of this statement relating to the rescission of
SFAS No. 4 are effective for fiscal years beginning after May 15, 2002, the
provisions of this statement relating to the amendment of SFAS No. 13 are
effective for transactions occurring after May 15, 2002, and all other
provisions of this Statement are effective for financial statements issued on or
after May 15, 2002. Exelon, ComEd, PECO and Generation are in the process of
evaluating the impact of SFAS No. 145 on their financial statements, and do not
expect the impact to be material.
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.
14. CHANGE IN ACCOUNTING ESTIMATE (Exelon, ComEd and Generation)
Effective April 1, 2001, Generation changed its accounting estimates
related to the depreciation and decommissioning of certain generating stations.
The estimated service lives were extended by 20 years for three nuclear
stations, by periods of up to 20 years for certain fossil stations and by 50
years for a pumped storage station. Effective July 1, 2001, the estimated
service lives were extended by 20 years for the remainder of Exelon's operating
nuclear stations. These changes were based on engineering and economic
feasibility studies performed by Generation considering, among other things,
future capital and maintenance expenditures at these plants. As a result of the
change, net income for the three months and six months ended June 30, 2002
increased $25 million ($16 million, net of income taxes) and $60 million ($36
million, net of income taxes), respectively.
44
Effective 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.
15. SUBSEQUENT EVENTS
On July 1, 2002, Exelon Generation notified Midwest Generation of the
exercise of its call options under the existing Coal Generation Purchase Power
Agreement. Exelon Generation exercised options on 1,265 MWs of capacity and did
not exercise options on 2,684 MWs of capacity. In 2003, Exelon Generation will
take 1,696 MWs of non-option capacity and 1,265 MWs of option capacity under the
existing contract.
45
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), through its subsidiaries, operates in
three business segments:
o Energy Delivery, consisting of the retail electricity distribution and
transmission businesses of Commonwealth Edison Company (ComEd) in
northern Illinois and PECO Energy Company (PECO) in southeastern
Pennsylvania and the natural gas distribution business of PECO in the
Pennsylvania counties surrounding the City of Philadelphia.
o Generation, consisting of Exelon Generation Company, LLC's (Generation)
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 weighted
towards the communications, energy services and retail services
industries.
See Note 6 of the 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 with the net basis of
presentation required by EITF 02-3.
RESULTS OF OPERATIONS
Three Months Ended June 30, 2002 Compared To Three Months Ended June 30, 2001
Net Income and Earnings Per Share
Net income increased $170 million, or 54%, for the three months ended
June 30, 2002. Diluted earnings per common share increased $0.53 per share, or
55%. The increase in net income reflects the gain on Enterprises' sale of its
49% interest in AT&T Wireless PCS of Philadelphia, LLC (AT&T Wireless), higher
earnings in Energy Delivery, primarily related to an increase in retail sales
due to warmer summer weather, the discontinuation of goodwill amortization at
Energy Delivery and Enterprises required by the adoption of FASB Statement of
Financial Accounting Standards (SFAS) No. 142, "Goodwill and Other Intangible
Assets" (SFAS No. 142) and certain other factors affecting net income, which are
discussed in the remainder of the results of operations section.
46
Exelon evaluates its performance on a business segments basis. The
analysis below presents the operating results for each of its business segments
for the three months ended June 30, 2002 compared to the three months ended June
30, 2001.
Corporate provides its business segments a variety of support services
including legal, human resources, financial and information technology 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 by Business Segment
Three Months Ended June 30,
---------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
Energy Delivery $ 322 $ 264 $ 58 21.9%
Generation 84 71 13 18.3%
Enterprises 83 (5) 88 n.m.
Corporate (4) (15) 11 (73.3%)
- -----------------------------------------------------------------------------------------------------
Total $ 485 $ 315 $ 170 53.9%
- -----------------------------------------------------------------------------------------------------
n.m. - not meaningful
Results of Operations - Energy Delivery Business Segment
Three Months Ended June 30,
---------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 2,476 $ 2,436 $ 40 1.6%
OPERATING EXPENSES
Purchased Power 958 901 57 6.3%
Fuel 53 79 (26) (32.9%)
Operating and Maintenance 351 374 (23) (6.1%)
Depreciation and Amortization 242 267 (25) (9.4%)
Taxes Other Than Income 136 110 26 23.6%
- ------------------------------------------------------------------------------------------------------
Total Operating Expense 1,740 1,731 9 0.1%
- ------------------------------------------------------------------------------------------------------
OPERATING INCOME 736 705 31 4.4%
- ------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (218) (260) 42 (16.1%)
Distributions on Preferred Securities of Subsidiaries (11) (12) 1 (8.3%)
Other, net 15 24 (9) (37.5%)
- ------------------------------------------------------------------------------------------------------
Total Other Income and Deductions (214) (248) 34 (13.7%)
- ------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 522 457 65 14.2%
INCOME TAXES 200 193 7 3.6%
- ------------------------------------------------------------------------------------------------------
NET INCOME $ 322 $ 264 $ 58 22.0%
- ------------------------------------------------------------------------------------------------------
Energy Delivery's gross margin (revenue net of purchased power and
fuel) increased $9 million, $25 million of which was attributable to warmer
summer weather in the second quarter
47
of 2002 as compared to the second quarter of 2001 in the ComEd service
territory, which increased retail electric volume. The retail increase was
offset by lower wholesale sales volume.
Lower operating and maintenance expense reflects a reduction in bad
debt expense due to a change in estimate and lower system repair and storm
restoration costs, partially offset by costs associated with the deployment of
automated meter reading technology and increased corporate allocations.
Energy Delivery's depreciation and amortization expense decreased by
$25 million reflecting $33 million for the discontinuation of goodwill
amortization due to the adoption of SFAS No. 142 as of January 1, 2002,
partially offset by $9 million of higher regulatory asset amortization.
As required by the Illinois Restructuring Act, ComEd made a
notification filing with the Illinois Commerce Commission (ICC) to reflect lower
depreciation rates effective July 1, 2002. No ICC approval is required for the
new rates to take effect. The anticipated annual reduction in depreciation
expense is estimated to be approximately $100 million.
Lower interest expense reflects a reduction in debt outstanding and
lower interest rates due to debt refinancing. The reduction in other, net,
primarily reflects lower intercompany interest income reflecting lower interest
rates.
Energy Delivery's effective income tax rate was 38.3% for the three
months ended June 30, 2002, compared to 42.2% for the three months ended June
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.
48
Energy Delivery Operating Statistics and Revenue Detail
Energy Delivery's electric sales statistics and revenue detail are as
follows:
For the three months ended June 30,
-----------------------------------
Retail Deliveries - (in gigawatthours (GWh)) 2002 2001 % Change
- ---------------------------------------------------------------------------------------------------------------------
Bundled Deliveries (1)
Residential 7,977 6,905 15.5%
Small Commercial & Industrial 7,481 7,115 5.1%
Large Commercial & Industrial 6,049 5,920 2.2%
Public Authorities & Electric Railroads 1,885 2,072 (9.0%)
- -----------------------------------------------------------------------------------------------------
23,392 22,012 6.3%
- -----------------------------------------------------------------------------------------------------
Unbundled Deliveries (2)
Alternative Energy Suppliers
- ---------------------------
Residential 557 848 (34.3%)
Small Commercial & Industrial 1,179 1,169 0.9%
Large Commercial & Industrial 1,635 1,983 (17.5%)
Public Authorities & Electric Railroads 181 95 90.5%
- -----------------------------------------------------------------------------------------------------
3,552 4,095 (13.3%)
- -----------------------------------------------------------------------------------------------------
PPO (ComEd Only)
- ---------------------------
Small Commercial & Industrial 839 798 5.1%
Large Commercial & Industrial 1,392 1,518 (8.3%)
Public Authorities & Electric Railroads 274 326 (16.0%)
- -----------------------------------------------------------------------------------------------------
2,505 2,642 (5.2%)
- -----------------------------------------------------------------------------------------------------
Total Unbundled Deliveries 6,057 6,737 (10.1%)
- -----------------------------------------------------------------------------------------------------
Total Retail Deliveries 29,449 28,749 2.4%
- -----------------------------------------------------------------------------------------------------
(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).
49
For the three months ended June 30,
-----------------------------------
Electric Revenue 2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
Bundled Revenues (1)
Residential $ 801 $ 724 $ 77 10.6%
Small Commercial & Industrial 669 624 45 7.2%
Large Commercial & Industrial 404 367 37 10.1%
Public Authorities & Electric Railroads 121 126 (5) (4.0%)
- -------------------------------------------------------------------------------------------------------
1,995 1,841 154 8.4%
- -------------------------------------------------------------------------------------------------------
Unbundled Revenues (2)
Alternative Energy Suppliers
- ---------------------------
Residential 42 67 (25) (37.3%)
Small Commercial & Industrial 30 41 (11) (26.8%)
Large Commercial & Industrial 33 40 (7) (17.5%)
Public Authorities & Electric Railroads 5 1 4 n.m.
- -------------------------------------------------------------------------------------------------------
110 149 (39) (26.2%)
- -------------------------------------------------------------------------------------------------------
PPO (ComEd Only)
- ---------------------------
Small Commercial & Industrial 55 53 2 3.8%
Large Commercial & Industrial 76 86 (10) (11.6%)
Public Authorities & Electric Railroads 17 19 (2) (10.5%)
- -------------------------------------------------------------------------------------------------------
148 158 (10) (6.3%)
- -------------------------------------------------------------------------------------------------------
Total Unbundled Revenues 258 307 (49) (16.0%)
- -------------------------------------------------------------------------------------------------------
Total Electric Retail Revenues 2,253 2,148 105 4.9%
- -------------------------------------------------------------------------------------------------------
Wholesale and Miscellaneous Revenue (3) 139 176 (37) (21.0%)
- -------------------------------------------------------------------------------------------------------
Total Electric Revenue $ 2,392 $ 2,324 $ 68 2.9%
- -------------------------------------------------------------------------------------------------------
(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 CTC charge.
(2) Unbundled service reflects 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 three months ended June
30, 2002, as compared to the same period in 2001 are attributable to the
following:
Variance
- ---------------------------------------------------------------------------------------------------------------------
Rate Changes $ (14)
Customer Choice 46
Weather 41
Other Effects 32
- ---------------------------------------------------------------------------------------------------------------------
Electric Retail Revenue $ 105
- ---------------------------------------------------------------------------------------------------------------------
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 partially offset
by $13 million due to an increase in PECO's gross receipts tax rate. The
increase in PECO's gross receipts tax
50
rate will increase PECO's annual revenue and tax obligation by
approximately $50 million in 2002.
o Customer Choice. All ComEd and PECO customers have the choice to purchase
energy from other suppliers. This choice generally does not impact kWh
deliveries, but affects revenue collected from customers related to energy
supplied by Energy Delivery. On May 1, 2002, all ComEd residential
customers were eligible to choose their supplier of electricity, however;
as of June 30, 2002, 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 favorable customer choice effect is attributable to increased
revenues of $85 million from customers in Pennsylvania selecting or
returning to PECO as their electric generation supplier, partially offset
by a decrease in revenues of $39 million from customers in Illinois
electing to purchase energy from an Alternative Retail Electric Supplier
(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 Weather. The demand for electricity and gas services is impacted by weather
conditions. Very warm weather in summer months and very cold weather in
other months is referred to as "favorable weather conditions", because
these weather conditions result in increased sales of electricity and gas.
Conversely, mild weather reduces demand.
The weather impact was favorable compared to the prior year as a
result of warmer summer weather in the ComEd service territory during the
second quarter of 2002 as compared to the same period in 2001.
o Other Effects. Other items increasing revenues were primarily related to a
$39 million favorable volume variance other than weather, due to the impact
of a strong housing construction market in Chicago partially offset by the
impact of a slower economy on large commercial and industrial customers.
The reduction in wholesale revenue for the three months ended June 30,
2002 as compared to the three months ended June 30, 2001 reflects a $10 million
decrease 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 $15 million reversal of reserve for revenue refunds related to certain of
ComEd's municipal customers as a result of a favorable FERC ruling.
On July 19, 2002, ComEd filed a request with the ICC to revise the
Provider of Last Resort (POLR) obligation in Illinois. ComEd is seeking
permission from the ICC to limit the availability by June 2006 of Rate 6L for
370 of ComEd's largest energy customers with demands of at least three MWs,
totaling approximately 2,500 MWs. Rate 6L is a bundled fixed rate offered to
large customers including heavy industrial plants, large office buildings,
government facilities and a variety of other businesses. The ICC has 120 days to
act on the filing or it will be deemed approved.
51
Energy Delivery's gas sales statistics and revenue detail are as
follows:
For the three months ended June 30,
-------------------------------------
2002 2001 Variance
- --------------------------------------------------------------------------------------------------------------------
Deliveries in million cubic feet (mmcf) 14,286 13,781 505
Revenue $84 $ 112 $ (28)
- --------------------------------------------------------------------------------------------------------------------
The changes in gas revenue for the quarter ended June 30, 2002, as
compared to the same 2001 period, are as follows:
(in millions) Variance
- ---------------------------------------------------------------------------------------------------------------------
Rate Changes $ (28)
Weather --
Volume (1)
Other 1
- ---------------------------------------------------------------------------------------------------------------------
Gas Revenue $ (28)
- ---------------------------------------------------------------------------------------------------------------------
o Rate Changes. The unfavorable variance in rates is attributable to an
adjustment of the purchased gas cost recovery by the Pennsylvania Public
Utilities Commission (PUC) effective in December 2001. The average rate per
million cubic feet for all customers for the quarter ended June 30, 2002
was 28% lower than the same 2001 period. PECO's gas rates are subject to
periodic adjustments by the PUC designed to recover or refund the
difference between actual cost of purchased gas and the amount included in
base rates and to recover or refund increases or decreases in certain state
taxes not recovered in base rates.
o Weather. The weather impact was neutral during the quarter ended June 30,
2002 as compared to the same 2001 period. Heating degree-days were
consistent in the quarter ended June 30, 2002 compared to the same 2001
period.
o Volume. Exclusive of weather impacts, delivery volume was consistent for
the quarter ended June 30, 2002 compared to the same 2001 period.
52
Results of Operations - Generation Business Segment
Three Months Ended June 30,
---------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 1,559 $1,583 $ (24) (1.5%)
OPERATING EXPENSES
Purchased Power 705 721 (16) (2.2%)
Fuel 224 230 (6) (2.6%)
Operating and Maintenance 411 405 6 1.5%
Depreciation and Amortization 65 75 (10) (13.3%)
Taxes Other Than Income 41 39 2 5.1%
- -------------------------------------------------------------------------------------------------------
Total Operating Expense 1,446 1,470 (24) (1.6%)
- -------------------------------------------------------------------------------------------------------
OPERATING INCOME 113 113 -- --
- -------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (11) (26) 15 (57.6%)
Equity in Earnings (Losses) of Unconsolidated Affiliates, net 9 13 (4) (30.8%)
Other, net 24 14 10 71.4%
- -------------------------------------------------------------------------------------------------------
Total Other Income and Deductions 22 1 21 n.m.
- -------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 135 114 21 18.4%
INCOME TAXES 51 43 8 18.6%
- -------------------------------------------------------------------------------------------------------
NET INCOME $ 84 $ 71 13 18.3%
- -------------------------------------------------------------------------------------------------------
Net income for the three months ended June 30, 2002 was positively
impacted by increased revenue from retail affiliates, increased revenue from the
acquisition of two generating plants in April 2002 and reduced depreciation and
interest expense, partially offset by depressed wholesale market prices for
energy. Operating revenues, net of fuel and purchased power, decreased by $2
million. Lower wholesale market prices for energy reduced margins by $46
million, which were partially offset by increased revenue from affiliates of $43
million, revenue from the two generating plants acquired in April 2002, and
lower fuel costs. Operating and maintenance expense increased by $6 million due
to additional employee benefit costs of $9 million and operating costs for two
generating plants acquired in April 2002 of $3 million. These additional
expenses were partially offset by $7 million less in nuclear outage costs and
other operating cost reductions including savings from Exelon's Cost Management
Initiative. The decline in depreciation expense reflects extension of the
estimated service lives of certain generating stations in the third quarter of
2001, partially offset by additional depreciation expense on plant placed in
service after June 30, 2001, including the acquisition of two generating plants
in April 2002. Lower interest expense is due to capitalized interest and a lower
interest rate on the spent nuclear fuel obligation. Additionally, revenue for
the three months ended June 30, 2002 includes a net trading portfolio loss of
$16 million compared to a net $6 million loss for the three months ended June
30, 2001.
Generation Operating Statistics:
53
For the three months ended June 30, 2002 and 2001, Generation's sales
and the supply of these sales exclusive of the trading portfolio were as
follows:
Three Months Ended June 30,
----------------------------
Sales (in GWhs) 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
Energy Delivery 28,294 28,105
Exelon Energy 1,355 1,415
Market Sales 20,589 18,548
- ---------------------------------------------------------------------------------------------------------------------
Total Sales 50,238 48,068
- ---------------------------------------------------------------------------------------------------------------------
Three Months Ended June 30,
----------------------------
Supply of Sales (in GWhs) 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
Nuclear Generation 28,353 28,443
Purchases - non-trading portfolio 18,220 16,392
Fossil and Hydro Generation 3,665 3,233
- ---------------------------------------------------------------------------------------------------------------------
Total Supply 50,238 48,068
- ---------------------------------------------------------------------------------------------------------------------
Trading volume was 8,566 GWhs and 454 GWhs for the three months ended
June 30, 2002 and 2001, respectively.
Generation's average margin data for the three months ended June 30,
2002 and 2001 were as follows:
Three Months Ended June 30,
----------------------------
($/MWh) 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
Average Realized Revenue
Energy Delivery $ 31.45 $ 30.09
Exelon Energy 44.73 40.11
Market Sales 30.69 37.69
Total Sales - excluding the trading portfolio 31.50 33.32
Average Supply Cost - excluding the trading portfolio $ 18.79 $ 20.05
Average Margin - excluding the trading portfolio $ 12.71 $ 13.27
- ---------------------------------------------------------------------------------------------------------------------
Generation's nuclear fleet, including AmerGen, performed at a capacity
factor of 92.1% for the three months ended June 30, 2002 compared to 93.6% the
same period in 2001. The lower capacity factor is primarily due to 72 planned
outage days in the three months ended June 30, 2002 versus 31 days in the same
period in 2001, including AmerGen. Generation's nuclear units' production costs
including AmerGen for the three months ended June 30, 2002 were $12.54 per MWh
compared to $13.02 per MWh for the same period in 2001. The reduced unit
production costs reflect additional generation due to power uprates, which more
than offset the lower capacity factor, and lower production costs due to
headcount reductions and Exelon's Cost Management Initiative in the three months
ended June 30, 2002 as compared to the same period in 2001. Generation's average
purchased power costs for wholesale operations were $39.96 per MWh for the three
months ended June 30, 2002, compared to $45.27 per MWh for the same
54
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 June 30,
----------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 476 $ 546 $ (70) (12.8%)
OPERATING EXPENSES
Purchased Power 56 61 (5) (8.2%)
Fuel 82 100 (18) (18.0%)
Operating and Maintenance 334 382 (48) (12.5%)
Depreciation and Amortization 17 16 1 6.2%
Taxes Other Than Income 2 3 (1) (33.3%)
- -------------------------------------------------------------------------------------------------------
Total Operating Expense 491 562 (71) (12.6%)
- -------------------------------------------------------------------------------------------------------
OPERATING INCOME (15) (16) 1 (6.2%)
- -------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (3) (9) 6 (66.6%)
Equity in Earnings (Losses) of Unconsolidated Affiliates, net 2 (6) 8 (133.3%)
Other, net 158 21 137 n.m.
- -------------------------------------------------------------------------------------------------------
Total Other Income and Deductions 157 6 151 n.m.
- -------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 142 (10) 152 n.m.
INCOME TAXES 59 (5) 64 n.m.
- -------------------------------------------------------------------------------------------------------
NET INCOME $ 83 $ (5) $ 88 n.m.
- -------------------------------------------------------------------------------------------------------
Enterprises' net income increased $88 million for the three months
ended June 30, 2002 compared to the same period in 2001. The increase in net
income is primarily attributable to the sale of Enterprises' 49% interest in
AT&T Wireless PCS of Philadelphia, LLC (AT&T Wireless) to a subsidiary of AT&T
Wireless Services for $285 million in cash that resulted in an after-tax gain of
$116 million and higher equity in earnings of unconsolidated affiliates of $8
million primarily as a result of the discontinuance of losses on AT&T Wireless.
These increases were partially offset by $36 million of investment write-downs
and $4 million of net asset write-downs.
Operating revenues decreased $70 million, or 13%, for the three months
ended June 30, 2002, compared to the same period in 2001. The decrease in
operating revenues was attributable to lower gas sales of $12 million primarily
resulting from lower gas prices, reduced retail energy sales of $20 million from
Exelon Energy, Inc. (Exelon Energy) due to exiting the retail energy business in
the Pennsylvania, New Jersey and Maryland area (PJM market), lower revenues of
$43 million from Exelon Services, Inc. (Exelon Services) from reduced volume of
construction project revenues and lower revenues of $19 million from
InfraSource, Inc. (InfraSource) from the continued decline in the
telecommunications industry and reduced volume of construction services in that
industry. These decreases were partially offset by higher electric revenues of
$22 million primarily resulting from higher electric prices in Illinois for
Exelon Energy.
55
Enterprises' operating and other expenses, net decreased $222 million
for the three months ended June 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 $18 million primarily
resulting from lower gas prices, lower power costs of $20 million resulting from
reduced operations of retail energy sales from Exelon Energy exiting the PJM
market, reduced costs relating to lower construction project volume at Exelon
Services of $33 million, reduced costs relating to lower volume of construction
services in the telecommunications industry at InfraSource of $18 million,
higher equity in earnings of unconsolidated affiliates of $8 million primarily
as a result of the discontinuance of losses on AT&T Wireless as a result of the
AT&T Wireless sale and lower interest expense of $6 million. These decreases
were partially offset by higher electric purchased power costs in Illinois of
$21 million for Exelon Energy, write-downs of communications investments of $27
million, write-downs of energy related investments of $9 million, a net
write-down of other assets of $4 million in 2002 and an $18 million gain in 2001
from the sale of a communications investment.
The effective income tax rate was 41.5% for the three months ended June
30, 2002, compared to 50.0% for the three months ended June 30, 2001. The
decrease in the effective tax rate was primarily attributable to the
discontinuation of goodwill amortization as of January 1, 2002, that was not
deductible for income tax purposes and a true-up of income taxes relating to a
merger between two Enterprises businesses in April 2001, partially offset by the
effect of the AT&T Wireless sale.
Six Months Ended June 30, 2002 Compared To Six Months Ended June 30, 2001
Net Income and Earnings Per Share
Exelon's income before the cumulative effect of changes in accounting
principles increased $20 million, or 3%, for the six months ended June 30, 2002.
Diluted earnings per common share on the same basis increased $0.06 per share,
or 3%. The increase in income before the cumulative effect of changes in
accounting principles reflects higher earnings due to the sale of AT&T Wireless,
warmer summer weather, and the discontinuation of goodwill amortization required
by the adoption of SFAS No. 142, partially offset by a decrease in retail sales
due to mild winter weather, lower wholesale energy prices, increased nuclear
refueling outage costs, employee severance costs and certain other factors
affecting net income, which are discussed in the remainder of the results of
operations section. Net income included net pretax charges of $10 million for
severance costs, primarily related to executive severance.
Net income decreased $222 million, or 31%, for the six months ended
June 30, 2002. Diluted earnings per common share decreased $0.69 per share, or
31%. Net income for the six months ended June 30, 2002 includes 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 six
months ended June 30, 2001 includes $12 million of income for the cumulative
effect of adopting SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities" (SFAS No. 133). See Note 2 of the Combined Notes to
Consolidated Financial Statements for further information regarding the adoption
of SFAS No. 133.
56
The analysis below presents the operating results for each of Exelon's
business segments for the six months ended June 30, 2002 compared to the six
months ended June 30, 2001.
Income Before Cumulative Effect of Changes in Accounting Principles by Business
Segment
Six Months Ended June 30,
----------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
Energy Delivery $ 538 $ 530 $ 8 1.5%
Generation 150 229 (79) (34.4%)
Enterprises 55 (30) 85 n.m.
Corporate (21) (27) 6 (22.2%)
- ---------------------------------------------------------------------------------------------------
Total $ 722 $ 702 $ 20 2.8%
- ---------------------------------------------------------------------------------------------------
Results of Operations - Energy Delivery Business Segment
Six Months Ended June 30,
----------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 4,811 $4,933 $ (122) (2.4%)
OPERATING EXPENSES
Purchased Power 1,846 1,793 53 2.9%
Fuel 188 284 (96) (33.8%)
Operating and Maintenance 724 724 -- --
Depreciation and Amortization 489 535 (46) (8.5%)
Taxes Other Than Income 268 225 43 19.1%
- --------------------------------------------------------------------------------------------------------
Total Operating Expense 3,515 3,561 (46) (1.2%)
- --------------------------------------------------------------------------------------------------------
OPERATING INCOME 1,296 1,372 (76) (5.5%)
- --------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (439) (506) 67 (13.2%)
Distributions on Preferred Securities of Subsidiaries (23) (23) -- --
Other, net 30 71 (41) (57.7%)
- --------------------------------------------------------------------------------------------------------
Total Other Income and Deductions (432) (458) 26 (5.6%)
- --------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 864 914 (50) (5.5%)
INCOME TAXES 326 384 (58) (15.1%)
- --------------------------------------------------------------------------------------------------------
NET INCOME $ 538 $ 530 $ 8 1.5%
- --------------------------------------------------------------------------------------------------------
Energy Delivery's gross margin (revenue net of purchased power and
fuel) declined $79 million, $26 million of which was attributable primarily to
warmer winter weather, partially offset by warmer summer weather in the ComEd
service territory during the second quarter of 2002, which reduced retail
electric and gas volumes, and a reduction in wholesale sales volumes.
Flat operating and maintenance expense reflects increased pension and
postretirement benefit costs and increased corporate allocations, including a
portion of executive severance charges, and an increase in the provision for
injuries and damages offset by decreased system
57
repair and storm damage costs, a decrease in the provision for bad debt expense,
and a decrease in the provision for obsolete inventory.
Energy Delivery's depreciation and amortization expense decreased by
$46 million reflecting $64 million for the discontinuation of goodwill
amortization due to the adoption of SFAS No. 142 as of January 1, 2002,
partially offset by $17 million of higher regulatory asset amortization.
Lower interest expense reflects reductions in debt outstanding and
lower interest rates due to debt refinancing. The reduction in other - net,
primarily reflects lower intercompany interest income reflecting lower interest
rates.
Energy Delivery's effective income tax rate was 37.7% for the six
months ended June 30, 2002, compared to 42.0% for the six months ended June 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.
58
Energy Delivery Operating Statistics and Revenue Detail
Energy Delivery's electric sales statistics and revenue detail are as
follows:
For the six months ended June 30,
---------------------------------
Retail Deliveries - (in GWhs) 2002 2001 % Change
- -------------------------------------------------------------------------------------------------------------------
Bundled Deliveries (1)
Residential 16,441 15,670 4.9%
Small Commercial & Industrial 14,687 13,991 5.0%
Large Commercial & Industrial 11,357 11,341 0.1%
Public Authorities & Electric Railroads 3,879 4,275 (9.3%)
- ----------------------------------------------------------------------------------------------------
46,364 45,277 2.4%
- ----------------------------------------------------------------------------------------------------
Unbundled Deliveries (2)
Alternative Energy Suppliers
- ----------------------------
Residential 1,348 1,375 (2.0%)
Small Commercial & Industrial 2,280 2,523 (9.6%)
Large Commercial & Industrial 3,124 4,335 (27.9%)
Public Authorities & Electric Railroads 320 143 123.8%
- ----------------------------------------------------------------------------------------------------
7,072 8,376 (15.6%)
- ----------------------------------------------------------------------------------------------------
PPO (ComEd Only)
- ----------------
Small Commercial & Industrial 1,602 1,622 (1.2%)
Large Commercial & Industrial 2,703 2,876 (6.0%)
Public Authorities & Electric Railroads 516 584 (11.6%)
- ----------------------------------------------------------------------------------------------------
4,821 5,082 (5.1%)
- ----------------------------------------------------------------------------------------------------
Total Unbundled Deliveries 11,893 13,458 (11.6%)
- ----------------------------------------------------------------------------------------------------
Total Retail Deliveries 58,257 58,735 (0.8%)
- ----------------------------------------------------------------------------------------------------
(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.
59
For the six months ended June 30,
---------------------------------
Electric Revenue 2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
Bundled Revenues (1)
Residential $ 1,563 $ 1,538 $ 25 1.6%
Small Commercial & Industrial 1,249 1,144 105 9.2%
Large Commercial & Industrial 750 687 63 9.2%
Public Authorities & Electric Railroads 230 250 (20) (8.0%)
- -------------------------------------------------------------------------------------------------------
3,792 3,619 173 4.8%
- -------------------------------------------------------------------------------------------------------
Unbundled Revenues (2)
Alternative Energy Suppliers
- ----------------------------
Residential 96 103 (7) (6.8%)
Small Commercial & Industrial 48 94 (46) (48.9%)
Large Commercial & Industrial 45 102 (57) (55.9%)
Public Authorities & Electric Railroads 7 3 4 133.3%
- -------------------------------------------------------------------------------------------------------
196 302 (106) (35.1%)
- -------------------------------------------------------------------------------------------------------
PPO (ComEd Only)
- ----------------
Small Commercial & Industrial 98 90 8 8.9%
Large Commercial & Industrial 140 146 (6) (4.1%)
Public Authorities & Electric Railroads 29 31 (2) (6.5%)
- -------------------------------------------------------------------------------------------------------
267 267 -- --
- -------------------------------------------------------------------------------------------------------
Total Unbundled Revenues 463 569 (106) (18.6%)
- -------------------------------------------------------------------------------------------------------
Total Electric Retail Revenues 4,255 4,188 67 1.6%
- -------------------------------------------------------------------------------------------------------
Wholesale and Miscellaneous Revenue (3) 263 338 (75) (22.2%)
- -------------------------------------------------------------------------------------------------------
Total Electric Revenue $ 4,518 $ 4,526 $ (8) (0.2%)
- -------------------------------------------------------------------------------------------------------
(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. 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.
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 six months ended June
30, 2002, as compared to the same period in 2001 are attributable to the
following:
Variance
- ---------------------------------------------------------------------------------------------------------------------
Rate Changes $ (15)
Customer Choice 87
Weather (31)
Other Effects 26
- ---------------------------------------------------------------------------------------------------------------------
Electric Retail Revenue $ 67
- ---------------------------------------------------------------------------------------------------------------------
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 effective January 1, 2001
60
offset by $26 million due to an increase in PECO's gross receipts tax rate
and the expiration of a 6% reduction in PECO's rates during the first
quarter of 2001.
o Customer Choice. The favorable customer choice effect is attributable to
increased revenues of $165 million from customers in Pennsylvania selecting
or returning to PECO as their electric generation supplier, partially
offset by a decrease in revenues of $78 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 Weather. The weather impact was unfavorable compared to the prior year as a
result of warmer winter weather in ComEd and PECO service territories
partially offset by warmer summer weather in the ComEd service territory
during the second quarter of 2002 as compared to the same period in 2001.
o Other Effects. Other items decreasing revenues were primarily related to a
net $58 million favorable volume variance other than weather, primarily due
to the impact of a strong housing construction market in Chicago, partially
offset by the payment of $14 million to Generation related to nuclear
decommissioning cost recovery under an agreement effective September 2001
which reduced PECO's revenue compared to the prior year, an $11 million
settlement of CTCs by a large PECO customer in 2001 and the impact of a
slower economy on large commercial and industrial customers.
The reduction in wholesale revenue for the six months ended June 30,
2002 as compared to the six months ended June 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.
Energy Delivery's gas sales statistics and revenue detail are as
follows:
For the six months ended June 30,
---------------------------------
2002 2001 Variance
- --------------------------------------------------------------------------------------------------------------------
Deliveries in mmcf 45,643 48,011 (2,368)
Revenue $ 293 $ 407 $(114)
- --------------------------------------------------------------------------------------------------------------------
The changes in gas revenue for the six months ended June 30, 2002, as
compared to the same 2001 period, are as follows:
Variance
- ---------------------------------------------------------------------------------------------------------------------
Rate Changes $ (63)
Weather (30)
Volume (22)
Other 1
- ---------------------------------------------------------------------------------------------------------------------
Gas Revenue $ (114)
- ---------------------------------------------------------------------------------------------------------------------
61
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 all customers
for the quarter ended June 30, 2002 was 24% lower than the same 2001
period.
o Weather. The unfavorable weather impact is attributable to warmer winter
weather during the six months ended June 30, 2002 as compared to the same
2001 period. Heating degree-days decreased 15% in the six months ended June
30, 2002 compared to the same 2001 period.
o Volume. Exclusive of weather impacts, lower delivery volume affected
revenue by $22 million in the six months ended June 30, 2002 compared to
the same 2001 period. Total deliveries to retail customers decreased 5% in
the six months ended June 30, 2002 compared to the same 2001 period,
primarily as a result of slower economic conditions in 2002 offset by
increased customer growth.
Results of Operations - Generation Business Segment
Six Months Ended June 30,
-------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 3,020 $3,211 $ (191) (5.9%)
OPERATING EXPENSES
Purchased Power 1,323 1,320 3 --
Fuel 433 449 (16) (3.5%)
Operating and Maintenance 844 809 35 4.3%
Depreciation and Amortization 128 167 (39) (23.3%)
Taxes Other Than Income 90 85 5 5.8%
- --------------------------------------------------------------------------------------------------------
Total Operating Expense 2,818 2,830 (12) --
- --------------------------------------------------------------------------------------------------------
OPERATING INCOME 202 381 (179) (46.9%)
- --------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (28) (59) 31 (52.5%)
Equity in Earnings of Unconsolidated Affiliates, net 32 39 (7) (17.9%)
Other, net 40 18 22 122.2%
- --------------------------------------------------------------------------------------------------------
Total Other Income and Deductions 44 (2) 46 n.m.
- --------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES AND CUMULATIVE
EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES 246 379 (133) (35.0%)
INCOME TAXES 96 150 (54) (36.0%)
- --------------------------------------------------------------------------------------------------------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN
ACCOUNTING PRINCIPLES 150 229 (79) (34.4%)
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING
PRINCIPLES 13 12 1 8.3%
- --------------------------------------------------------------------------------------------------------
NET INCOME $ 163 $ 241 (78) (32.3%)
- --------------------------------------------------------------------------------------------------------
Net income for the six months ended June 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 and lower depreciation and interest expense. Operating
62
revenues, net of fuel and purchased power, decreased by $178 million. Lower
wholesale market prices for energy reduced margins by $184 million, which was
partially offset by increased revenues from affiliates of $26 million and lower
fuel costs. The amount of low-cost nuclear generation available for sale was
reduced due to an increased number of nuclear generating station refueling
outages in the six months ended June 30, 2002, as compared to the same period in
2001. Operating and maintenance expense increased by $35 million, primarily due
to $55 million of costs incurred for the additional refueling outages and the
acquisition of two generating plants in April 2002. These additional expenses
were partially offset by other operating cost reductions, including $10 million
related to headcount reductions, a $10 million reduction in Generation's
severance accrual and $4 million in savings related to Exelon's Cost Management
Initiative. The decline in depreciation expense reflects extension of the
estimated service lives of generating stations in the third quarter of 2001,
partially offset by additional depreciation expense on plant placed in service
after June 30, 2001, including the acquisition of two generating plants in April
2002. Lower interest expense is due to capitalized interest and a lower interest
rate on the spent nuclear fuel obligation. Additionally, trading activities were
initiated in April 2001. Revenue for the six months ended June 30, 2002 includes
a net trading portfolio loss of $16 million compared to a net $6 million loss in
the six months ended June 30, 2001.
Generation Operating Statistics:
For the six months ended June 30, 2002 and 2001, Generation's sales and
the supply of these sales, excluding the trading portfolio, were as follows:
Six Months Ended June 30,
-------------------------
Sales (in GWhs) 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
Energy Delivery 56,044 57,309
Exelon Energy 2,605 3,006
Market Sales (1) 39,913 36,007
- ---------------------------------------------------------------------------------------------------------------------
Total Sales 98,562 96,322
- ---------------------------------------------------------------------------------------------------------------------
63
Six Months Ended June 30,
-------------------------
Supply of Sales (in GWhs) 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
Nuclear Generation 55,886 58,410
Purchases - non-trading portfolio 36,314 31,954
Fossil and Hydro Generation 6,362 5,958
- ---------------------------------------------------------------------------------------------------------------------
Total Supply 98,562 96,322
- ---------------------------------------------------------------------------------------------------------------------
Trading volume was 22,805 GWhs and 454 GWhs for the six months ended
June 30, 2002 and 2001, respectively.
Generation's average margin data for the six months ended June 30, 2002
and 2001 were as follows:
Six Months Ended June 30,
-------------------------
($/MWh) 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
Average Realized Revenue
Energy Delivery $ 30.73 $ 29.58
Exelon Energy 45.08 39.30
Market Sales 29.44 38.66
Total Sales - excluding the trading portfolio 30.58 33.27
Average Supply Cost - excluding the trading portfolio $ 17.78 $ 18.75
Average Margin - excluding the trading portfolio $ 12.80 $ 14.52
- ---------------------------------------------------------------------------------------------------------------------
Generation's nuclear fleet, including AmerGen, performed at a capacity
factor of 91.2% for the six months ended June 30, 2002 compared to 96.2% the
same period in 2001. Generation's nuclear units' production costs, including
AmerGen, for the six months ended June 30, 2002 were $13.38 per MWh compared to
$12.34 per MWh for the same period in 2001. The lower capacity factor and
increased unit production costs are primarily due to 153 days of planned outage
time in the six months ended June 30, 2002 versus 31 days in the same period in
2001. Generation's average purchased power costs for wholesale operations were
$36.76 per MWh for the six months ended June 30, 2002, compared to $41.81 per
MWh for the same period in 2001. The decrease in purchased power costs was
primarily due to depressed wholesale power market prices.
64
Results of Operations - Enterprises Business Segment
Six Months Ended June 30,
-------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 966 $1,213 $ (247) (20.4%)
OPERATING EXPENSES
Purchased Power 108 157 (49) (31.2%)
Fuel 234 365 (131) (35.9%)
Operating and Maintenance 634 705 (71) (10.1%)
Depreciation and Amortization 35 31 4 12.9%
Taxes Other Than Income 5 7 (2) (28.6%)
- -------------------------------------------------------------------------------------------------------
Total Operating Expense 1,016 1,265 (249) (19.7%)
- -------------------------------------------------------------------------------------------------------
OPERATING INCOME (50) (52) 2 (3.9%)
- -------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (8) (22) 14 (63.6%)
Equity in Earnings (Losses) of Unconsolidated Affiliates, net (5) (14) 9 (64.3%)
Other, net 158 38 120 n.m.
- -------------------------------------------------------------------------------------------------------
Total Other Income and Deductions 145 2 143 n.m.
- -------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES AND CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 95 (50) 145 n.m
INCOME TAXES 40 (20) 60 n.m
- -------------------------------------------------------------------------------------------------------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE 55 (30) 85 n.m
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE (243) -- (243) n.m.
- -------------------------------------------------------------------------------------------------------
NET INCOME $ (188) $ (30) $ (158) n.m.
- -------------------------------------------------------------------------------------------------------
Enterprises' net income increased $85 million for the six months ended
June 30, 2002 compared to the same period in 2001, excluding the cumulative
effect of a change in accounting principle. The increase in net income is
primarily attributable to the AT&T Wireless sale that resulted in an after-tax
gain of $116 million and higher equity in earnings of unconsolidated affiliates
of $9 million primarily as a result of the discontinuation of losses on AT&T
Wireless as a result of the AT&T Wireless sale. These increases were partially
offset by $40 million of investment write-downs and $4 million of net asset
write-downs. Enterprises' net loss increased $158 million after reflecting the
cumulative effect of a change in accounting principle resulting from 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,
was $243 million net of income taxes and minority interest.
Operating revenues decreased $247 million for the six months ended June
30, 2002, compared to the same period in 2001. The decrease in operating
revenues is attributable to lower gas sales of $116 million primarily resulting
from lower gas prices, reduced retail energy sales of
65
$91 million from Exelon Energy exiting the PJM market, lower revenues of $56
million from Exelon Services from reduced volume of construction projects and
lower revenues of $29 million from InfraSource from the continued decline in the
telecommunications industry and reduced volume of construction services in that
industry. These decreases were partially offset by higher electric revenues of
$45 million primarily resulting from higher electric prices in Illinois for
Exelon Energy.
Enterprises' operating and other expenses, net decreased $392 million
for the six months ended June 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 $107 million primarily resulting from
lower gas prices, lower purchased power costs of $114 million resulting from
reduced operations of retail energy sales from Exelon Energy exiting the PJM
market, reduced costs relating to lower construction project volume at Exelon
Services of $45 million, reduced costs relating to lower volume of construction
services in the telecommunications industry at InfraSource of $23 million, lower
interest expense of $14 million, and higher equity in earnings of unconsolidated
affiliates of $9 million primarily as a result of the discontinuance of losses
on AT&T Wireless as a result of the AT&T Wireless sale. These decreases were
partially offset by higher electric purchased power costs in Illinois of $42
million for Exelon Energy, write-downs of communications investments of $29
million, write-downs of energy related investments of $11 million, a net
write-down of other assets of $4 million in 2002 and a $28 million gain in 2001
from the sales of communications investments.
The effective income tax rate was 42.1% for the six months ended June
30, 2002, compared to 40.0% for the six months ended June 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.
LIQUIDITY AND CAPITAL RESOURCES
Exelon's businesses are capital intensive and require considerable
capital resources. Exelon'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. Exelon's access
to external financing at reasonable terms is dependent on the credit ratings of
Exelon and its subsidiaries and the general business condition of Exelon and the
utility industry. Capital resources are used primarily to fund Exelon's capital
requirements, including construction, investments in new and existing ventures,
repayments of maturing debt and preferred securities of subsidiaries and payment
of common stock dividends. Any potential future acquisitions could require
external financing, including the issuance by Exelon of common stock.
Cash Flows from Operating Activities
Cash flows provided by operations for the six months ended June 30,
2002 were $1.6 billion compared to $2.0 billion in the six months ended June 30,
2001. Approximately 70% of 2002 cash flows provided by operations for the six
months ended June 30, 2002 were provided by Energy Delivery and approximately
30% was provided by Generation. Enterprises' cash
66
flows from operations were immaterial to Exelon for the six months ended June
30, 2002. Energy Delivery's cash flows from operating activities primarily
result from sales of electricity and gas to a stable and diverse base of retail
customers at fixed prices and are weighted toward the third quarter. Energy
Delivery's future cash flows will depend upon the ability to achieve cost
savings in operations, and the impact of the economy, weather and customer
choice on its revenues. Generation's cash flows from operating activities
primarily result from the sale of electric energy to wholesale customers,
including Energy Delivery and Enterprises. Generation's future cash flow from
operating activities will depend upon future demand and market prices for energy
and the ability to continue to produce and supply power at competitive costs.
Although the amounts may vary from period to period as a result of the
uncertainties inherent in business, Exelon expects that Energy Delivery and
Generation will continue to provide a reliable and steady source of internal
cash flow from operations for the foreseeable future.
Cash Flows from Investing Activities
Cash flows used in investing activities for the six months ended June
30, 2002 were $1.3 billion, compared to $998 million for the six months ended
June 30, 2001. The increase was primarily attributable to the $443 million
acquisition of two generating plants from TXU Corp. (TXU) and increased capital
expenditures partially offset by $285 million of proceeds from the AT&T Wireless
sale. Capital expenditures other than the TXU acquisition, by business segment
for the six months ended June 30, 2002 and 2001 are as follows:
Six Months Ended June 30,
--------------------------
2002 2001
- ---------------------------------------------------------------------------------------------------------------------
Energy Delivery $ 495 $ 581
Generation 475 301
Enterprises 28 37
Corporate and Other 30 18
- ---------------------------------------------------------------------------------------------------------------------
Total Capital Expenditures $ 1,028 $ 937
- ---------------------------------------------------------------------------------------------------------------------
Energy Delivery's capital expenditures for 2002 reflect the
continuation of efforts to further improve the reliability of its distribution
system in the Chicago region. Energy Delivery's investing activities were funded
primarily through operating activities.
Generation's capital expenditures for 2002 are for additions to and
upgrades of existing facilities (including nuclear refueling outages), nuclear
fuel, and increases in capacity at existing plants. 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 available cash and Exelon commercial paper. Exelon expects to repay
the commercial paper utilizing Generation's internal cash flows.
Capital expenditures have increased for the six months ended June 30,
2002 as compared to 2001 due to higher nuclear fuel expenditures, growth and an
increase in the number of planned
67
refueling outages, during which significant work is performed for additions to
or upgrades of existing facilities.
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%. As of June
30, 2002, AmerGen had borrowed $75 million under this agreement. In July 2002,
the loan agreement and the loan were increased to $100 million and the maturity
date was extended to July 1, 2003.
Enterprises' capital expenditures for 2002 are primarily for additions
to or upgrades of existing facilities. On April 1, 2002, Exelon Enterprises
closed on the sale of its 49% interest in AT&T Wireless for $285 million in
cash. Proceeds from the transaction will be used for Exelon's general corporate
purposes.
Cash Flows from Financing Activities
Cash flows used in financing activities were $142 million in the second
quarter 2002, primarily attributable to debt service and payments of dividends
on common stock of $280 million. Debt financing activities during the six months
ended June 30, 2002 were as follows:
o ComEd issued $600 million in First Mortgage Bonds, issued $100 million of
Illinois Development Finance Authority floating-rate Pollution Control
Revenue Refunding Bonds, redeemed $100 million of 7.25% Illinois
Development Finance Authority Pollution Control Revenue Refunding Bonds,
redeemed $200 million in First Mortgage Bonds with available cash and
retired $170 million of transitional trust notes,
o PECO borrowed an additional $74 million of commercial paper and made
principal payments of $207 million on long-term debt with available cash.
Credit Issues
Exelon meets its short-term liquidity requirements primarily through
the issuance of commercial paper by Exelon, ComEd and PECO. Exelon, along with
ComEd, PECO and Generation, entered into a $1.5 billion unsecured revolving
credit facility with a group of banks. This credit facility is used principally
to support the commercial paper programs of Exelon, ComEd and PECO.
At June 30, 2002, Exelon's capital structure consisted of 60% of
long-term debt, 35% common stock, 2% notes payable and 3% preferred securities
of subsidiaries. Total debt included $6.6 billion of securitization debt
constituting obligations of certain consolidated special purpose entities,
representing 28% of capitalization.
At June 30, 2002, Exelon had outstanding $470 million of notes payable
consisting principally of commercial paper. For the six months ended June 30,
2002, the average interest rate on notes payable was approximately 1.96%.
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 June 30,
2002, the debt to total capitalization ratios on that basis for Exelon, ComEd,
PECO and Generation were 48%, 46%, 38% and 32%, respectively.
68
Exelon and its subsidiaries' access to the capital markets, including
the commercial paper market, and their financing costs in those markets are
dependent on their respective securities ratings. None of Exelon's or its
subsidiaries' borrowings is subject to default or prepayment as a result of a
downgrading of securities ratings although such a downgrading could increase
interest charges under Exelon's bank credit facility. Exelon and its
subsidiaries from time to time enter into interest rate swap and other
derivatives that require the maintenance of investment grade ratings. Failure to
maintain investment grade ratings would allow the counterparty to terminate the
derivative and settle the transaction on a net present value basis.
Under the Public Utility Holding Company Act of 1935 (PUHCA) and the
Federal Power Act, Exelon, ComEd, PECO and Generation can pay dividends only
from retained, undistributed or current earnings. However, an SEC order granted
permission to Exelon and ComEd to pay up to $500 million in dividends out of
additional paid-in capital, provided that Exelon agreed not to pay dividends out
of paid-in capital after December 31, 2002 if its common equity is less than 30%
of its total capitalization. At June 30, 2002, Exelon had retained earnings of
$1.4 billion, which includes ComEd retained earnings of $382 million, PECO
retained earnings of $277 million and Generation retained earnings of $686
million.
Contractual Obligations and Commercial Commitments
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 June 30, 2002 were materially unchanged, other than in the
normal course of business, from the amounts set forth in the December 31, 2001
Form 10-K except for the following:
o ComEd issued $600 million of First Mortgage Bonds due March 15, 2012,
issued $100 million of Illinois Development Finance Authority floating-rate
Pollution Control Revenue Refunding Bonds, series 2002, redeemed $100
million of 7.25% Illinois Development Finance Authority Pollution Control
Revenue Refunding Bonds, series 1991, redeemed $200 million of First
Mortgage Bonds due February 1, 2022, and retired $170 million of
transitional trust notes.
o Guarantees increased $300 million primarily related to an increase in the
amount of surety bonds required by Enterprises' insurance policies.
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) for $543 million, plus the assumption of
non-recourse debt estimated to be approximately $1.2 billion at the date of
purchase. The purchase is estimated to close in November 2002, subject to
regulatory approval. See Note 3 of the Combined Notes to the Consolidated
Financial Statements for additional information about the Sithe New England
acquisition.
o Purchase obligations increased by $1.2 billion, primarily due to an
increase of $2.0 billion in power only purchases partially offset by a $0.8
billion decrease in net capacity purchase commitments. The increase in
power only purchases is primarily due to Generation's
69
agreement to purchase all the energy from Unit No. 1 at Three Mile Island
after December 31, 2001 through December 31, 2014. This decrease in net
capacity purchase commitments is due primarily to the decision not to
exercise the option to purchase 2,684 MWs of capacity from Midwest
Generation in 2002 and 2003 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, 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 June 30, 2002,
Sithe had total assets of $4.1 billion and total debt of $2.1 billion, including
$1.6 billion of non-recourse project debt of which $1.0 billion is associated
with Sithe New England, $0.4 billion of subordinated debt, $49 million of
short-term debt, $33 million of capital leases, and excluding $411 million of
non-recourse project debt associated with Sithe's equity investments. For the
six months ended June 30, 2002, Sithe had revenues of $0.6 billion. As of June
30, 2002, Generation had a $725 million equity investment in Sithe. On June 26,
2002, Generation agreed to purchase Sithe New England for $543 million plus the
assumption of approximately $1.2 billion of non-recourse project debt, which is
expected to be outstanding at the time of the closing of the purchase.
Generation expects to close the purchase of Sithe New England in November 2002,
subject to regulatory approval.
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 June 30, 2002, including the debt of Sithe
described in the preceding paragraph, is currently estimated to be $2.3 billion
($1.2 billion based on Exelon's ownership interest of the investments).
70
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 for operating expenses.
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 plan
assets, discount rate, and the rate of increase in health care costs. The market
value of plan assets has been affected by sharp declines in the equity market
since the third quarter of 2000. As a result, at December 31, 2002, Exelon could
be required to recognize an additional minimum liability as prescribed by FASB
SFAS No. 87 "Employers' Accounting for Pensions" and FASB SFAS No. 132
"Employers' Disclosures about Pensions and Postretirement Benefits." The
liability would be recorded as a reduction to common equity, and the equity
would be restored to the balance sheet in future periods when the fair value of
plan assets exceeds the accumulated benefit obligations. The amount of reduction
to common equity recorded, if any, will depend upon the asset returns
experienced in 2002, but could be material. The recording of this reduction
would not affect net income or cash flow in 2002; however, pension cost and cash
funding requirements could increase in future years without a substantial
recovery in the equity markets.
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 July 29, 2002,
Generation had a net receivable from Dynegy of less than $5 million, and
consistent with the terms of the existing credit arrangement, has requested
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 June 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 $15 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
Independence Station and AmerGen's purchased power arrangement with Illinois
Power, a subsidiary of Dynegy, could be impacted by events related to Dynergy's
financial condition.
71
COMMONWEALTH EDISON COMPANY
GENERAL
ComEd operates in a single business segment, Energy Delivery, and its
operations consist of its retail electricity distribution and transmission
business in northern Illinois.
RESULTS OF OPERATIONS
Three Months Ended June 30, 2002 Compared to Three Months Ended June 30, 2001
Significant Operating Trends - ComEd
Three Months Ended June 30,
---------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 1,481 $1,530 $ (49) (3.2%)
OPERATING EXPENSES
Purchased Power 553 586 (33) (5.6%)
Operating and Maintenance 220 248 (28) (11.3%)
Depreciation and Amortization 133 168 (35) (20.8%)
Taxes Other Than Income 73 69 4 5.8%
- -------------------------------------------------------------------------------------------------------
Total Operating Expense 979 1,071 (92) (8.6%)
- -------------------------------------------------------------------------------------------------------
OPERATING INCOME 502 459 43 9.4%
- -------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (127) (143) 16 (11.2%)
Distributions on Company-Obligated Mandatorily
Redeemable Preferred Securities of Subsidiary Trusts
Holding Solely the Company's Subordinated Debt Securities (7) (7) -- --
Other, net 14 22 (8) (36.4%)
- -------------------------------------------------------------------------------------------------------
Total Other Income and Deductions (120) (128) 8 (6.3%)
- -------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 382 331 51 15.4%
INCOME TAXES 151 149 2 1.3%
- -------------------------------------------------------------------------------------------------------
NET INCOME $ 231 $ 182 $ 49 26.9%
- -------------------------------------------------------------------------------------------------------
Net Income
Net income increased $49 million, or 27% for the three months ended
June 30, 2002. Net income was impacted by $43 million increase in operating
income and by a lower effective income tax rate.
72
Operating Revenues
ComEd's electric sales statistics are as follows:
For the three months ended June 30,
-----------------------------------
Retail Deliveries - (in GWh) 2002 2001 % Change
- ---------------------------------------------------------------------------------------------------------------------
Bundled Deliveries (1)
Residential 5,862 5,232 12.0%
Small Commercial & Industrial 5,600 5,803 (3.5%)
Large Commercial & Industrial 2,122 2,748 (22.8%)
Public Authorities & Electric Railroads 1,685 1,891 (10.9%)
- -------------------------------------------------------------------------------------------------------
15,269 15,674 (2.6%)
- -------------------------------------------------------------------------------------------------------
Unbundled Deliveries (2)
ARES
- ----
Small Commercial & Industrial 1,177 645 82.5%
Large Commercial & Industrial 1,622 1,251 29.7%
Public Authorities & Electric Railroads 181 93 94.6%
- -------------------------------------------------------------------------------------------------------
2,980 1,989 49.8%
- -------------------------------------------------------------------------------------------------------
PPO
- ---
Small Commercial & Industrial 839 798 5.1%
Large Commercial & Industrial 1,392 1,518 (8.3%)
Public Authorities & Electric Railroads 274 326 (16.0%)
- -------------------------------------------------------------------------------------------------------
2,505 2,642 (5.2%)
- -------------------------------------------------------------------------------------------------------
Total Unbundled Deliveries 5,485 4,631 18.4%
- -------------------------------------------------------------------------------------------------------
Total Retail Deliveries 20,754 20,305 2.2%
- -------------------------------------------------------------------------------------------------------
(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.
73
For the three months ended June 30,
-----------------------------------
Electric Revenue 2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
Bundled Revenues (1)
Residential $ 523 $ 502 $ 21 4.2%
Small Commercial & Industrial 445 467 (22) (4.7%)
Large Commercial & Industrial 116 144 (28) (19.4%)
Public Authorities & Electric Railroads 102 109 (7) (6.4%)
- -------------------------------------------------------------------------------------------------------
1,186 1,222 (36) (3.0%)
- -------------------------------------------------------------------------------------------------------
Unbundled Revenues (2)
ARES
- ----
Small Commercial & Industrial 30 13 17 130.8%
Large Commercial & Industrial 32 21 11 52.4%
Public Authorities & Electric Railroads 5 1 4 n.m.
- -------------------------------------------------------------------------------------------------------
67 35 32 91.4%
- -------------------------------------------------------------------------------------------------------
PPO
- ---
Small Commercial & Industrial 55 53 2 3.8%
Large Commercial & Industrial 76 86 (10) (11.6%)
Public Authorities & Electric Railroads 17 19 (2) (10.5%)
- -------------------------------------------------------------------------------------------------------
148 158 (10) (6.3%)
- -------------------------------------------------------------------------------------------------------
Total Unbundled Revenues 215 193 22 11.4%
- -------------------------------------------------------------------------------------------------------
Total Electric Retail Revenues 1,401 1,415 (14) (1.0%)
Wholesale and Miscellaneous Revenue (3) 80 115 (35) (30.4%)
- -------------------------------------------------------------------------------------------------------
Total Electric Revenue $ 1,481 $1,530 $ (49) (3.2%)
- -------------------------------------------------------------------------------------------------------
(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) 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.
n.m. - not meaningful
The changes in electric retail revenues for the three months ended June
30, 2002, as compared to the three months ended June 30, 2001, are attributable
to the following:
Variance
- ---------------------------------------------------------------------------------------------------------------------
Weather $ 40
Rate Changes (27)
Customer Choice (39)
Other Effects 12
- ---------------------------------------------------------------------------------------------------------------------
Electric Retail Revenue $ (14)
- ---------------------------------------------------------------------------------------------------------------------
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 June 30, 2002 was
favorable compared to the three months ended June 30, 2001 as a result of
warmer summer weather in
74
the second quarter of 2002 as compared to the second quarter of 2001.
Cooling degree-days increased 29% in the three months ended June 30, 2002
compared to the three months ended June 30, 2001.
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 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 were
eligible to choose their supplier of electricity, however, as of June 30,
2002, 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 June 30, 2002,
approximately 22,600 retail customers had elected to purchase energy from
an ARES or the ComEd PPO, an increase from 14,000 customers at June 30,
2001. The MWhs delivered to such customers increased from approximately 4.6
million for the three months ended June 30, 2001 to 5.5 million for the
three months ended June 30, 2002, or approximately a 20% increase from the
previous year.
o Other Effects. A strong housing construction market in Chicago contributed
to residential and small commercial and industrial customer volume growth,
partially offset by the unfavorable impact of a slower economy on large
commercial and industrial customers.
On July 19, 2002, ComEd filed a request with the ICC to revise the
Provider of Last Resort (POLR) obligation in Illinois. ComEd is seeking
permission from the ICC to limit the availability by June 2006 of Rate 6L for
370 of ComEd's largest energy customers with demands of at least three MWs,
totaling approximately 2,500 MWs. Rate 6L is a bundled fixed rate offered to
large customers including heavy industrial plants, large office buildings,
government facilities and a variety of other businesses. The ICC has 120 days to
act on the filing or it will be deemed approved.
The reduction in wholesale revenue for the three months ended June 30,
2002 as compared to the three months ended June 30, 2001 was due primarily to a
$10 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 and a $15 million reversal of reserve in 2001
for revenue refunds related to certain of ComEd's municipal customers as a
result of a favorable FERC ruling.
Purchased Power Expense
Purchased power expense decreased $33 million, or 6% for the three
months ended June 30, 2002. The decrease in purchased power expense was
primarily attributable to a $29 million decrease as a result of customers
choosing to purchase energy from an ARES, an $8 million decrease due to the
expiration of the wholesale contracts offered by ComEd to support the open
access program in Illinois, a $5 million decrease related to a reduction in the
average purchase price of energy and a $5 million decrease due to the effects of
the slower economy on the large commercial and industrial customers partially
offset by a $15 million increase due to favorable weather conditions.
75
Operating and Maintenance Expense
Operating and maintenance (O&M) expense decreased $28 million, or 11%,
for the three months ended June 30, 2002. The decrease in O&M expense was
primarily attributable to an $11 million decrease in bad debt expense due to a
revised estimate of the reserve for uncollectible accounts, a $4 million
decrease in corporate allocations, and a $9 million decrease in repairs of
distribution systems damaged by others and storm restoration.
Depreciation and Amortization Expense
Depreciation and amortization expense decreased $35 million, or 21%,
for the three months ended June 30, 2002. This decrease is primarily due to the
discontinuation of goodwill amortization effective January 1, 2002 upon the
adoption of SFAS No. 142 partially offset by increased depreciation based on
higher property, plant and equipment balances.
As required by the Illinois Restructuring Act, a notification filing
was made with the ICC to reflect lower depreciation rates effective July 1,
2002. No ICC approval is required for the new rates to take effect. The
anticipated annual reduction in depreciation expense is estimated to be
approximately $100 million.
Taxes Other Than Income
Taxes other than income remained consistent from period to period.
Interest Charges
Interest charges consist of interest expense and distributions on
Company-Obligated Mandatorily Redeemable Preferred Securities of Subsidiary
Trusts. Interest charges decreased $16 million, or 11%, for the three months
ended June 30, 2002. The decrease in interest charges was primarily attributable
to the impact of lower interest rates for the three months ended June 30, 2002
as compared to the three months ended June 30, 2001, the early retirement of the
$196 million of First Mortgage Bonds in November of 2001 and the retirement of
$340 million in transitional trust notes since June 2001.
Other Income and Deductions
Other income and deductions, excluding interest charges, decreased $8
million or 36%, for the three months ended June 30, 2002. The decrease was
primarily attributable to $2 million in intercompany interest income relating to
the $400 million receivable from PECO which was repaid during second quarter
2001 and a $7 million reduction in intercompany interest income from Unicom
Investment Inc., reflecting lower interest rates.
Income Taxes
The effective income tax rate was 39.5% for the three months ended June 30,
2002, compared to 45.0% for the three months ended June 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.
76
Six Months Ended June 30, 2002 Compared to Six Months Ended June 30, 2001
Significant Operating Trends - ComEd
Six Months Ended June 30,
-------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 2,796 $2,976 $ (180) (6.1%)
OPERATING EXPENSES
Purchased Power 1,091 1,195 (104) (8.7%)
Operating and Maintenance 457 466 (9) (1.9%)
Depreciation and Amortization 268 334 (66) (19.8%)
Taxes Other Than Income 146 141 5 3.6%
- --------------------------------------------------------------------------------------------------------
Total Operating Expense 1,962 2,136 (174) (8.2%)
- --------------------------------------------------------------------------------------------------------
OPERATING INCOME 834 840 (6) (0.7%)
- --------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (252) (284) 32 (11.3%)
Distributions on Company-Obligated Mandatorily
Redeemable Preferred Securities of Subsidiary Trusts
Holding Solely the Company's Subordinated Debt Securities (15) (15) -- --
Other, net 29 59 (30) (50.9%)
- --------------------------------------------------------------------------------------------------------
Total Other Income and Deductions (238) (240) 2 (0.8%)
- --------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 596 600 (4) (0.7%)
INCOME TAXES 236 271 (35) (12.9%)
- --------------------------------------------------------------------------------------------------------
NET INCOME $ 360 $ 329 $ 31 9.4%
- --------------------------------------------------------------------------------------------------------
Net Income
Net income increased $31 million, or 9% for the six months ended June
30, 2002. Net income was impacted by a $35 million decrease in income taxes due
to a lower effective income tax rate offset in part by a decrease in operating
income.
77
Operating Revenues
ComEd's electric sales statistics are as follows:
For the six months ended June 30,
---------------------------------
Retail Deliveries - (in GWh) 2002 2001 % Change
- ---------------------------------------------------------------------------------------------------------------------
Bundled Deliveries (1)
Residential 12,271 11,538 6.4%
Small Commercial & Industrial 11,049 11,678 (5.4%)
Large Commercial & Industrial 4,078 5,638 (27.7%)
Public Authorities & Electric Railroads 3,486 3,901 (10.6%)
- -----------------------------------------------------------------------------------------------------
30,884 32,755 (5.7%)
- -----------------------------------------------------------------------------------------------------
Unbundled Deliveries (2)
ARES
- ----
Small Commercial & Industrial 2,181 1,107 97.0%
Large Commercial & Industrial 3,008 2,414 24.6%
Public Authorities & Electric Railroads 319 136 134.6%
- -----------------------------------------------------------------------------------------------------
5,508 3,657 50.6%
- -----------------------------------------------------------------------------------------------------
PPO
- ---
Small Commercial & Industrial 1,602 1,622 (1.2%)
Large Commercial & Industrial 2,703 2,876 (6.0%)
Public Authorities & Electric Railroads 517 584 (11.5%)
- -----------------------------------------------------------------------------------------------------
4,822 5,082 (5.1%)
- -----------------------------------------------------------------------------------------------------
Total Unbundled Deliveries 10,330 8,739 18.2%
- -----------------------------------------------------------------------------------------------------
Total Retail Deliveries 41,214 41,494 (0.7%)
- -----------------------------------------------------------------------------------------------------
(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.
(2) Unbundled service reflects customers electing to receive electric
generation service from an ARES or the PPO.
78
For the six months ended June 30,
---------------------------------
Electric Revenue 2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
Bundled Revenues (1)
Residential $ 1,041 $ 1,035 $ 6 0.6%
Small Commercial & Industrial 836 880 (44) (5.0%)
Large Commercial & Industrial 218 280 (62) (22.1%)
Public Authorities & Electric Railroads 194 216 (22) (10.2%)
- --------------------------------------------------------------------------------------------------------
2,289 2,411 (122) (5.1%)
- --------------------------------------------------------------------------------------------------------
Unbundled Revenues (2)
ARES
- ----
Small Commercial & Industrial 43 26 17 65.4%
Large Commercial & Industrial 41 48 (7) (14.6%)
Public Authorities & Electric Railroads 7 2 5 n.m.
- --------------------------------------------------------------------------------------------------------
91 76 15 19.7%
- --------------------------------------------------------------------------------------------------------
PPO
- ---
Small Commercial & Industrial 98 90 8 8.9%
Large Commercial & Industrial 140 146 (6) (4.1%)
Public Authorities & Electric Railroads 29 31 (2) (6.5%)
- --------------------------------------------------------------------------------------------------------
267 267 -- --
- --------------------------------------------------------------------------------------------------------
Total Unbundled Revenues 358 343 15 4.4%
- --------------------------------------------------------------------------------------------------------
Total Electric Retail Revenues 2,647 2,754 (107) (3.9%)
Wholesale and Miscellaneous Revenue (3) 149 222 (73) (32.9%)
- --------------------------------------------------------------------------------------------------------
Total Electric Revenue $ 2,796 $ 2,976 $ (180) (6.1%)
- --------------------------------------------------------------------------------------------------------
(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) 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 six months ended June
30, 2002, as compared to the six months ended June 30, 2001, are attributable to
the following:
Variance
- ---------------------------------------------------------------------------------------------------------------------
Weather $ (13)
Rate Changes (54)
Customer Choice (78)
Other Effects 38
- ---------------------------------------------------------------------------------------------------------------------
Retail Revenue $ (107)
- ---------------------------------------------------------------------------------------------------------------------
o Weather. The weather impact for the six months ended June 30, 2002 was
unfavorable compared to the six months ended June 30, 2001 as a result of
warmer winter weather partially offset by warmer summer weather in 2002
compared to 2001. Heating degree-days decreased 6% and were partially
offset by a 29% increase in cooling degree-days in the six months ended
June 30, 2002 compared to the six months ended June 30, 2001
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.
79
o Customer Choice. The decrease in revenues reflects customers in Illinois
electing to purchase energy from an ARES or the PPO. As of June 30, 2002,
approximately 22,600 retail customers had elected to purchase energy from
an ARES or the ComEd PPO, an increase from 14,000 customers at June 30,
2001. The MWhs delivered to such customers increased from approximately 8.7
million for the six months ended June 30, 2001 to 10.3 million for the six
months ended June 30, 2002, approximately a 20% increase from the previous
year.
o Other Effects. A strong housing construction market in Chicago contributed
to residential and small commercial and industrial customer volume growth,
partially offset by the unfavorable impact of a slower economy on large
commercial and industrial customers.
The reduction in wholesale revenue for the six months ended June 30,
2002 as compared to the six months ended June 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 $20 million of other miscellaneous revenue.
Purchased Power Expense
Purchased power expense decreased $104 million, or 9% for the six
months ended June 30, 2002. The decrease in purchased power expense was
primarily attributable to a $5 million decrease due to unfavorable weather
conditions, a $62 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.
Operating and Maintenance Expense
O&M expense remained relatively consistent from period to period.
Depreciation and Amortization Expense
Depreciation and amortization expense decreased $66 million, or 20%,
for the six months ended June 30, 2002. This decrease is primarily due to the
discontinuation of goodwill amortization effective January 1, 2002 upon the
adoption of SFAS No. 142 partially offset by increased depreciation based on
higher property plant and equipment balances.
Taxes Other Than Income
Taxes other than income remained consistent from period to period.
Interest Charges
Interest charges decreased $32 million, or 11%, for the six months
ended June 30, 2002. The decrease in interest charges was primarily attributable
to the impact of lower interest rates for the six months ended June 30, 2002 as
compared to the six months ended June 30, 2001, the early retirement of the $196
million of First Mortgage Bonds in November of 2001 and the retirement of $340
million in transitional trust notes since June 2001.
80
Other Income and Deductions
Other income and deductions, excluding interest charges, decreased $30
million, or 51%, for the six months ended June 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, and a $22 million reduction in intercompany interest income from Unicom
Investment Inc., reflecting lower interest rates.
Income Taxes
The effective income tax rate was 39.6% for the six months ended June
30, 2002, compared to 45.2% for the six months ended June 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.
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. ComEd's access to external
financing at reasonable terms is dependent on its credit ratings and the general
business condition of ComEd and the utility industry. Capital resources are used
primarily to fund ComEd's capital requirements, including construction,
repayments of maturing debt, and the payment of common stock dividends.
Cash Flows from Operating Activities
Cash flows provided by operations were $740 million for the six months
ended June 30, 2002 compared to $705 million for the six months ended June 30,
2001. The increase in cash flows in 2002 was primarily attributable to a $107
million increase in other operating activities partially offset by a $67 million
decrease in working capital. ComEd's future cash flows will depend upon the
ability to achieve cost savings in operations, 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 $352 million for the six
months ended June 30, 2002 compared to $58 million for the six months ended June
30, 2001. The increase in cash flows used in investing activities in 2002 was
primarily attributable to the paydown of the $400 million outstanding receivable
with PECO in the second quarter of 2001 partially offset by an $87 million
decrease in capital expenditures. ComEd's investing activities for the six
months ended June 30, 2002 were funded primarily through operating activities.
ComEd estimated that it will spend approximately $781 million in total
capital expenditures for 2002. Approximately two thirds of the budgeted 2002
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 it will obtain financing, when necessary, through borrowings, the
81
issuance of preferred securities, or capital contributions from Exelon. ComEd's
proposed capital expenditures and other investments are subject to periodic
review and revision to reflect changes in economic conditions and other factors.
Cash Flows from Financing Activities
Cash flows used in financing activities were $57 million for the six
months ended June 30, 2002 as compared to $322 million for the six months ended
June 30, 2001. Cash flows used in financing activities were primarily
attributable to debt service and payments of dividends to Exelon. ComEd's debt
financing activities for the six months ended June 30, 2002 reflected the
issuance of $600 million in First Mortgage Bonds, the issuance of $100 million
of 7.25% Illinois Development Finance Authority floating-rate Pollution Control
Revenue Refunding Bonds, the retirement of $170 million of transitional trust
notes, the early retirement of $200 million in First Mortgage Bonds with
available cash, and the redemption of $100 million of Illinois Development
Finance Authority Pollution Control Revenue Refunding Bonds. For the six months
ended June 30, 2001, ComEd's debt financing activities reflected the retirement
of $170 million of transitional trust notes. ComEd paid a $235 million dividend
to Exelon during the six months ended June 30, 2002 compared to a $148 million
dividend for the six months ended June 30, 2001.
Credit Issues
ComEd meets its short-term liquidity requirements primarily through the
issuance of commercial paper, borrowings under bank credit facilities and
borrowings from the Exelon intercompany money pool. ComEd, along with Exelon,
PECO and Generation entered into a $1.5 billion unsecured 364-day revolving
credit facility on December 12, 2001 with a group of banks. ComEd has a $300
million sublimit under the credit facility and expects to use the credit
facility principally to support its $300 million commercial paper program. This
credit facility requires ComEd to maintain a debt to total capitalization ratio
of 65% or less (excluding transitional trust notes). At June 30, 2002, ComEd's
debt to total capitalization ratio on that basis was 46%. At June 30, 2002,
ComEd had no short-term borrowings.
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 are subject to default or prepayment as a
result of a downgrading of securities ratings although such a downgrading could
increase interest charges under certain bank credit facilities. ComEd from time
to time enters into interest rate swaps and other derivatives that require the
maintenance of investment grade ratings. Failure to maintain investment grade
ratings would allow the counterparty to terminate the derivative and settle the
transaction on a net present value basis.
At June 30, 2002, ComEd's capital structure, excluding the deduction
from shareholders' equity of the $875 million receivable from Exelon, consisted
of 52% long-term debt, 46% of common stock, and 2% of preferred securities of
subsidiaries. Long-term debt included $2.1 billion of transitional trust notes
constituting obligations of certain consolidated special purpose entities
representing 16% of capitalization.
82
Under PUHCA and the Federal Power Act, ComEd can only pay dividends
from retained or current earnings. However, the SEC has authorized ComEd to pay
up to $500 million in dividends out of additional paid-in capital, provided
ComEd may not pay dividends out of paid-in capital after December 31, 2002 if
its common equity is less than 30% of its total capitalization (including
transitional trust notes). At June 30, 2002, ComEd had retained earnings of $382
million.
Contractual Obligations and Commercial Commitments
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 June 30, 2002 were materially unchanged, other than in the
normal course of business, from the amounts as set forth in the December 31,
2001 Form 10-K except for the issuance of $600 million of First Mortgage Bonds
due March 15, 2012, the issuance of $100 million of Illinois Development Finance
Authority floating-rate Pollution Control Revenue Refunding Bonds, Series 2002,
the redemption of $100 million of 7.25% Illinois Development Finance Authority
Pollution Control Revenue Refunding Bonds, Series 1991, the redemption of $200
million of First Mortgage Bonds due February 1, 2022, and the retirement of $170
million in transitional trust notes.
83
PECO ENERGY COMPANY
GENERAL
PECO operates in a single business segment, Energy Delivery, and its
operations consist of its retail electricity distribution and transmission
business in southeastern Pennsylvania and its natural gas distribution business
in the Pennsylvania counties surrounding the City of Philadelphia.
RESULTS OF OPERATIONS
Three Months Ended June 30, 2002 Compared to Three Months Ended June 30, 2001
Three Months Ended June 30,
---------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 995 $ 906 $ 89 9.8%
OPERATING EXPENSES
Purchased Power 405 315 90 28.6%
Fuel 53 79 (26) (32.9%)
Operating and Maintenance 131 126 5 4.0%
Depreciation and Amortization 109 99 10 10.1%
Taxes Other Than Income 63 41 22 53.7%
- -------------------------------------------------------------------------------------------------------
Total Operating Expense 761 660 101 15.3%
- -------------------------------------------------------------------------------------------------------
OPERATING INCOME 234 246 (12) (4.9%)
- -------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (92) (119) 27 (21.4%)
Distributions on Company-Obligated Mandatorily
Redeemable Preferred Securities of a Partnership
which holds Solely Subordinated Debentures of
the Company (2) (2) -- --
Other, net 2 4 (2) (50.0%)
- -------------------------------------------------------------------------------------------------------
Total Other Income and Deductions (92) (117) 25 (21.4%)
- -------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 142 129 13 10.1%
INCOME TAXES 49 44 5 11.4%
- -------------------------------------------------------------------------------------------------------
NET INCOME 93 85 8 9.4%
Preferred Stock Dividends (2) (3) 1 (33.3%)
- -------------------------------------------------------------------------------------------------------
NET INCOME ON COMMON STOCK $ 91 $ 82 $ 9 11.0%
- -------------------------------------------------------------------------------------------------------
Net income on common stock increased $9 million, or 11% for the quarter
ended June 30, 2002 as compared to the same 2001 period. The increase was a
result of higher additional volume, favorable rate adjustments and lower
interest expense on debt partially offset by increased depreciation and
amortization expense.
84
PECO's electric sales statistics are as follows:
For the three months ended June 30,
-----------------------------------
Deliveries - (in GWh) 2002 2001 % Change
- ---------------------------------------------------------------------------------------------------------------------
Bundled Deliveries (1)
Residential 2,115 1,673 26.4%
Small Commercial & Industrial 1,881 1,312 43.4%
Large Commercial & Industrial 3,927 3,172 23.8%
Public Authorities & Electric Railroads 200 181 10.5%
- -------------------------------------------------------------------------------------------------------
8,123 6,338 28.2%
- -------------------------------------------------------------------------------------------------------
Unbundled Deliveries (2)
Residential 557 848 (34.3%)
Small Commercial & Industrial 2 524 (99.6%)
Large Commercial & Industrial 13 732 (98.2%)
Public Authorities & Electric Railroads -- 2 (100.0%)
- -------------------------------------------------------------------------------------------------------
572 2,106 (72.8%)
- -------------------------------------------------------------------------------------------------------
Total Retail Deliveries 8,695 8,444 3.0%
- -------------------------------------------------------------------------------------------------------
(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.
For the three months ended June 30,
-----------------------------------
Electric Revenue 2002 2001 Variance %Change
- -------------------------------------------------------------------------------------------------------------------
Bundled Revenue (1)
Residential $ 278 $ 222 $ 56 25.2%
Small Commercial & Industrial 224 157 67 42.7%
Large Commercial & Industrial 288 224 64 28.6%
Public Authorities & Electric Railroads 19 17 2 11.8%
- -------------------------------------------------------------------------------------------------------
809 620 189 30.5%
- -------------------------------------------------------------------------------------------------------
Unbundled Revenue (2)
Residential 42 67 (25) (37.3%)
Small Commercial & Industrial -- 28 (28) (100.0%)
Large Commercial & Industrial 1 19 (18) (94.7%)
Public Authorities & Electric Railroads -- -- -- --
- -------------------------------------------------------------------------------------------------------
43 114 (71) (62.3%)
- -------------------------------------------------------------------------------------------------------
Total Electric Retail Revenues 852 734 118 16.1%
Wholesale and Miscellaneous Revenue (3) 59 60 (1) (1.7%)
- -------------------------------------------------------------------------------------------------------
Total Electric Revenue $ 911 $ 794 $ 117 14.7%
- -------------------------------------------------------------------------------------------------------
(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) Revenue from customers receiving generation from an alternate supplier
includes a distribution charge and a CTC charge.
(3) Wholesale and miscellaneous revenues include sales, transmission revenue,
sales to municipalities and other wholesale energy sales.
85
The changes in electric retail revenues for the quarter ended June 30,
2002, as compared to the same 2001 period, are as follows:
Variance
- ---------------------------------------------------------------------------------------------------------------------
Customer Choice $ 85
Rate Changes 13
Weather 1
Other Effects 19
- ---------------------------------------------------------------------------------------------------------------------
Electric Retail Revenue $ 118
- ---------------------------------------------------------------------------------------------------------------------
o Customer Choice. All PECO customers have choice 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 June 30, 2002, the customer load served by alternate
suppliers was 991 MW or 12.8% as compared to 1,102 MW or 14.5% as of June
30, 2001. For the quarter ended June 30, 2002, the percent of PECO's total
retail deliveries for which PECO was the electric supplier was 93.4% in
2002, an 18.3% increase as compared to 75.1% in 2001. As of June 30, 2002,
the number of customers served by alternate suppliers was 308,866 or 20.2%
as compared to June 30, 2001 of 400,972 or 26.4%. The increases 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.
In February 2002, New Power Company (New Power) notified PECO of
its intent to withdraw from providing Competitive Default Service (CDS) to
approximately 180,000 residential customers. As a result of that
withdrawal, those CDS customers were returned to PECO in the second quarter
of 2002. Pursuant to a tariff filing approved by the Pennsylvania Public
Utility Commission (PUC), PECO will serve those returned customers at the
discount energy rates on generation provided for under the original New
Power CDS Agreement for the remaining term of that contract. Subsequently,
in the second quarter of 2002, New Power also advised PECO it planned to
withdraw from serving all of its customers in Pennsylvania, including
approximately 15,000 non-CDS PECO customers, and to return those customers
to PECO in September.
o Rate Changes. 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) adjustment to the gross receipts tax rate in order to
neutralize the impact of electric restructuring on its tax revenues. The
RNR adjustment increases the gross receipts tax rate, which will increase
PECO's annual revenues and tax obligations by approximately $50 million in
2002. In January 2002, the PUC approved the adjustment to the gross
receipts tax rate, which was implemented effective January 1, 2002. The RNR
adjustment is under appeal.
o Weather. The demand for electricity and gas services is impacted by weather
conditions. Very warm weather in summer months and very cold weather in
other months is referred to as "favorable weather conditions", because
these weather conditions result in increased sales of electricity and gas.
Conversely, mild weather reduces demand.
86
The weather impact was favorable compared to the prior year as a result
of warmer summer weather.
o Other Effects. Other items affecting revenue during the quarter ended June
30, 2002 include:
o Volume. Exclusive of weather impacts, higher delivery volume affected
PECO's revenue by $24 million compared to the same 2001 period.
o Other. The payment of $7 million to Generation related to nuclear
decommissioning cost recovery under an agreement effective September
2001, which reduced PECO's revenue compared to the prior year.
PECO's gas sales statistics for the quarter ended June 30, 2002 as
compared to the same 2001 period are as follows:
For the three months ended June 30,
-----------------------------------
2002 2001 Variance
- --------------------------------------------------------------------------------------------------------------------
Deliveries in mmcf 14,286 13,781 505
Revenue $84 $ 112 $ (28)
- --------------------------------------------------------------------------------------------------------------------
The changes in gas revenue for the quarter ended June 30, 2002, as
compared to the same 2001 period, are as follows:
(in millions) Variance
- ---------------------------------------------------------------------------------------------------------------------
Rate Changes $ (28)
Weather --
Volume (1)
Other 1
- ---------------------------------------------------------------------------------------------------------------------
Gas Revenue $ (28)
- ---------------------------------------------------------------------------------------------------------------------
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 all customers
for the quarter ended June 30, 2002 was 28% lower than the same 2001
period. PECO's gas rates are subject to periodic adjustments by the PUC
designed to recover or refund the difference between actual cost of
purchased gas and the amount included in base rates and to recover or
refund increases or decreases in certain state taxes not recovered in base
rates.
o Weather. The weather impact was neutral during the quarter ended June 30,
2002 compared to the same 2001 period.
o Volume. Exclusive of weather impact, delivery volume was consistent for the
quarter ended June 30, 2002 compared to the same 2001 period.
87
Purchased Power and Fuel Expense
Purchased power and fuel expense for the quarter ended June 30, 2002
increased $64 million as compared to the same 2001 period. The increase in fuel
and purchased power expense was primarily attributable to $73 million from
customers in Pennsylvania selecting or returning to PECO as their electric
generation supplier, $9 million primarily attributable to higher delivery volume
and higher PJM ancillary charges of $8 million. These increases were partially
offset by $28 million from lower gas prices.
Operating and Maintenance Expense
O&M expense for the quarter ended June 30, 2002 increased $5 million,
or 4%, as compared to the same 2001 period. The increase in O&M expense was
primarily attributable to $5 million related to the deployment of automated
meter reading technology and $3 million related to an increased allocation of
corporate expense.
Depreciation and Amortization Expense
Depreciation and amortization expense for the quarter ended June 30,
2002 increased $10 million, or 10%, as compared to the same 2001 period. The
increase was primarily attributable to $9 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.
Taxes Other Than Income
Taxes other than income for the quarter ended June 30, 2002 increased
$22 million, or 54%, as compared to the same 2001 period. The increase was
primarily attributable to additional gross receipts tax related to additional
revenues and an increase in the gross receipts tax rate on electric revenue
effective January 1, 2002.
Interest Charges
Interest charges consist of interest expense and distributions on
Company-Obligated Mandatorily Redeemable Preferred Securities of a Partnership
(COMRPS). Interest charges decreased $27 million, or 21% in the quarter ended
June 30, 2002 as compared to the same 2001 period. The decrease was primarily
attributable to lower interest expense on long-term debt of $22 million as a
result of principal payments and lower interest rates and interest expense
related to a loan from an affiliate in 2001 of $2 million.
Other Income and Deductions
Other income and deductions excluding interest charges remained
consistent in the quarter ended June 30, 2002 as compared to the same 2001
period.
Income Taxes
The effective tax rate was substantially unchanged at 34.5% for the
quarter ended June 30, 2002 as compared to 34.1% for the same 2001 period.
88
Preferred Stock Dividends
Preferred stock dividends for the quarter ended June 30, 2002 were
consistent as compared to the same 2001 period.
Six Months Ended June 30, 2002 Compared to Six Months Ended June 30, 2001
Six Months Ended June 30,
-------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 2,015 $1,957 $ 58 3.0%
OPERATING EXPENSES
Purchased Power 756 598 158 26.4%
Fuel 188 284 (96) (33.8%)
Operating and Maintenance 267 258 9 3.5%
Depreciation and Amortization 221 200 21 10.5%
Taxes Other Than Income 122 84 38 45.2%
- --------------------------------------------------------------------------------------------------------
Total Operating Expense 1,554 1,424 130 9.1%
- --------------------------------------------------------------------------------------------------------
OPERATING INCOME 461 533 (72) (13.5%)
- --------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (187) (227) 40 (17.6%)
Distributions on Company-Obligated Mandatorily
Redeemable Preferred Securities of a Partnership
which holds Solely Subordinated Debentures of
the Company (5) (5) -- --
Other, net 2 18 (16) (88.9%)
- --------------------------------------------------------------------------------------------------------
Total Other Income and Deductions (190) (214) 24 (11.2%)
- --------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 271 319 (48) (15.0%)
INCOME TAXES 90 112 (22) (19.6%)
- --------------------------------------------------------------------------------------------------------
NET INCOME 181 207 (26) (12.6%)
Preferred Stock Dividends (4) (5) 1 (20.0%)
- --------------------------------------------------------------------------------------------------------
NET INCOME ON COMMON STOCK $ 177 $ 202 $ (25) (12.4%)
- --------------------------------------------------------------------------------------------------------
Net income on common stock decreased $25 million, or 12% for the six
months ended June 30, 2002 as compared to the same 2001 period. The decrease was
a result of lower margins due to the unplanned return of certain residential,
commercial and industrial customers, milder weather, increased depreciation and
amortization expense, partially offset by favorable rate adjustments.
89
PECO's electric sales statistics are as follows:
For the six months ended June 30,
---------------------------------
Deliveries - (in GWh) 2002 2001 % Change
- -------------------------------------------------------------------------------------------------------------------
Bundled Deliveries (1)
Residential 4,171 4,132 0.9%
Small Commercial & Industrial 3,638 2,313 57.3%
Large Commercial & Industrial 7,278 5,703 27.6%
Public Authorities & Electric Railroads 393 374 5.1%
- --------------------------------------------------------------------------------------------------------
15,480 12,522 23.6%
- --------------------------------------------------------------------------------------------------------
Unbundled Deliveries (2)
Residential 1,348 1,375 (2.0%)
Small Commercial & Industrial 99 1,416 (93.0%)
Large Commercial & Industrial 116 1,921 (94.0%)
Public Authorities & Electric Railroads -- 7 (100.0%)
- --------------------------------------------------------------------------------------------------------
1,563 4,719 (66.9%)
- --------------------------------------------------------------------------------------------------------
Total Retail Deliveries 17,043 17,241 (1.1%)
- --------------------------------------------------------------------------------------------------------
(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.
For the six months ended June 30,
---------------------------------
Electric Revenue 2002 2001 Variance % Change
- -------------------------------------------------------------------------------------------------------------------
Bundled Revenue (1)
Residential $ 522 $ 503 $ 19 3.8%
Small Commercial & Industrial 413 264 149 56.4%
Large Commercial & Industrial 532 407 125 30.7%
Public Authorities & Electric Railroads 37 34 3 8.8%
- --------------------------------------------------------------------------------------------------------
1,504 1,208 296 24.5%
- --------------------------------------------------------------------------------------------------------
Unbundled Revenue (2)
Residential 96 103 (7) (6.8%)
Small Commercial & Industrial 5 68 (63) (92.6%)
Large Commercial & Industrial 3 54 (51) (94.4%)
Public Authorities & Electric Railroads -- 1 (1) (100.0%)
- --------------------------------------------------------------------------------------------------------
104 226 (122) (54.0%)
- --------------------------------------------------------------------------------------------------------
Total Electric Retail Revenues 1,608 1,434 174 12.1%
Wholesale and Miscellaneous Revenue (3) 114 116 (2) (1.7%)
- --------------------------------------------------------------------------------------------------------
Total Electric Revenue $ 1,722 $ 1,550 $ 172 11.1%
- --------------------------------------------------------------------------------------------------------
(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) Revenue from customers receiving generation from an alternate supplier
includes a distribution charge and a CTC charge.
(3) Wholesale and miscellaneous revenues include sales, transmission revenue,
sales to municipalities and other wholesale energy sales.
90
The changes in electric retail revenues for the six months ended June
30, 2002, as compared to the same 2001 period, are as follows:
Variance
- ---------------------------------------------------------------------------------------------------------------------
Customer Choice $ 165
Rate Changes 39
Weather (18)
Other Effects (12)
- ---------------------------------------------------------------------------------------------------------------------
Electric Retail Revenue $ 174
- ---------------------------------------------------------------------------------------------------------------------
o Customer Choice. As of June 30, 2002, the customer load served by alternate
suppliers was 991 MW or 12.8% as compared to 1,102 MW or 14.5% as of June
30, 2001. For the six months ended June 30, 2002, the percent of PECO's
total retail deliveries for which PECO was the electric supplier was 90.9%
in 2002, an 18.2% increase as compared to 72.7% in 2001. As of June 30,
2002, the number of customers served by alternate suppliers was 308,866 or
26.4% as compared to June 30, 2001 of 400,972 or 26.4%. 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 $26 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 unfavorable compared to the prior year
primarily as a result of warmer winter weather. Heating degree-days
decreased 15% for the six months ended June 30, 2002 compared to the same
2001 period.
o Other Effects. Other items affecting revenue during the six months ended
June 30, 2002 include:
o Volume. Exclusive of weather impacts, higher delivery volume increased
PECO's revenue by $7 million compared to the same 2001 period.
o Other. The payment of $14 million to Generation related to nuclear
decommissioning cost recovery under an agreement effective September
2001 which reduced PECO's revenue compared to the prior year and an
$11 million settlement of CTCs by a large customer in the first
quarter of 2001.
PECO's gas sales statistics for the six months ended June 30, 2002 as
compared to the same 2001 period are as follows:
2002 2001 Variance
- --------------------------------------------------------------------------------------------------------------------
Deliveries in mmcf 45,643 48,011 (2,368)
Revenue $293 $407 $ (114)
- --------------------------------------------------------------------------------------------------------------------
91
The changes in gas revenue for the six months ended June 30, 2002, as
compared to the same 2001 period, are as follows:
Variance
- ---------------------------------------------------------------------------------------------------------------------
Rate Changes $ (63)
Weather (30)
Volume (22)
Other 1
- ---------------------------------------------------------------------------------------------------------------------
Gas Revenue $ (114)
- ---------------------------------------------------------------------------------------------------------------------
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 all customers
for the six months ended June 30, 2002 was 24% lower than the same 2001
period.
o Weather. The unfavorable weather impact is attributable to warmer winter
weather during the six months ended June 30, 2002 as compared to the same
2001 period. Heating degree-days decreased 15% in the six months ended June
30, 2002 compared to the same 2001 period.
o Volume. Exclusive of weather impacts, lower delivery volume affected
revenue by $22 million in the six months ended June 30, 2002 compared to
the same 2001 period. Total deliveries to retail customers decreased 5% in
the six months ended June 30, 2002 compared to the same 2001 period,
primarily as a result of slower economic conditions in 2002 offset by
increased customer growth.
Purchased Power and Fuel Expense
Purchased power and fuel expense for the six months ended June 30, 2002
increased $62 million as compared to the same 2001 period. The increase in fuel
and purchased power expense was primarily attributable to $150 million from
customers in Pennsylvania selecting or returning to PECO as their electric
generation supplier and higher PJM ancillary charges of $17 million. These
increases were partially offset by $63 million from lower gas prices, $30
million as a result of unfavorable weather conditions and $22 million primarily
attributable to lower delivery volume primarily related to gas.
Operating and Maintenance Expense
O&M expense for the six months ended June 30, 2002 increased $9
million, or 4%, as compared to the same 2001 period. The increase in O&M expense
was primarily attributable to $12 million related to the deployment of automated
meter reading technology and $9 million related to an increased allocation of
corporate expense. These increases were partially offset by $6 million of
incremental storm costs in 2001 and $4 million associated with a write-off of
excess and obsolete inventory in 2001.
92
Depreciation and Amortization Expense
Depreciation and amortization expense for the six months ended June 30,
2002 increased $21 million, or 11%, as compared to the same 2001 period. The
increase was primarily attributable to $17 million of additional amortization of
PECO's CTC and an increase of $4 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 six months ended June 30, 2002
increased $38 million, or 45%, as compared to the same 2001 period. The increase
was primarily attributable to additional gross receipts tax related to
additional revenues and an increase in the gross receipts tax rate on electric
revenue effective January 1, 2002.
Interest Charges
Interest charges decreased $40 million, or 18% in the six months ended
June 30, 2002 as compared to the same 2001 period. The decrease was primarily
attributable to lower interest expense on long-term debt of $32 million as a
result of principal payments, lower interest rates and an $8 million reduction
in interest expense due to lower interest rates on a loan from ComEd in 2001.
Other Income and Deductions
Other income and deductions excluding interest charges decreased $16
million, or 89% in the six months ended June 30, 2002 as compared to the same
2001 period. The decrease in other income and deductions was primarily
attributable to lower interest income of $6 million in 2002. The decrease was
also attributable to a gain on the settlement of an interest rate swap of $6
million and the favorable settlement of a customer contract of $3 million, both
of which occurred in 2001.
Income Taxes
The effective tax rate was 33.2% for the six months ended June 30, 2002
as compared to 35.1% for the same 2001 period. The decrease in the effective tax
rate was primarily attributable to a reduction in state income taxes.
Preferred Stock Dividends
Preferred stock dividends for the quarter ended June 30, 2002 were
consistent as compared to the same 2001 period.
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. PECO's access to external
financing at reasonable terms is dependent on its credit ratings and the general
business condition of PECO and the utility industry. Capital resources are used
primarily to fund construction, repayments of maturing debt and preferred
securities and
93
payment of common stock dividends to Exelon.
Cash Flows from Operating Activities
Cash flows provided by operations for the six months ended June 30,
2002 were $468 million compared to $427 million for the six months ended June
30, 2001. The increase in cash flows was primarily attributable to lower
payments related to accounts payable of $46 million, higher collection of
deferred energy costs as a result of a change in gas rates of $42 million and
lower prepaid taxes of $29 million. These increases were partially offset by
changes in intercompany receivables and payables of $41 million and deferred
income taxes of $32 million. 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 cost savings in operations, and the impact of the
economy, weather and customer choice on its revenues. Although the amounts may
vary from period to period as a result of 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.
Cash Flows from Investing Activities
Cash flows used in investing activities for the six months ended June
30, 2002 were $122 million compared to $87 million for the six months ended June
30, 2001. The increase in cash flows used in investing activities was primarily
attributable to an increase in other investing activities. PECO's investing
activities during the six months ended June 30, 2002 were funded primarily by
operating activities.
PECO's projected capital expenditures for 2002 are $284 million.
Approximately one half of the budgeted 2002 expenditures are for capital
additions to support customer and load growth and the remainder for additions
and upgrades to existing facilities. PECO anticipates that it will obtain
financing, when necessary, through 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 six months ended June
30, 2002 were $306 million compared to $332 million for the six months ended
June 30, 2001. Cash flows used in financing activities are primarily
attributable to debt service and payment of dividends to Exelon. The change in
cash flows used in financing activities is primarily attributable to an increase
in commercial paper borrowings of $196 million partially offset by additional
dividends paid to Exelon of $69 million, the contribution from Exelon in 2001 of
$53 million, additional debt service of $34 million, and proceeds from the
settlement of interest rate swap agreements in 2001 of $31 million.
Credit Issues
At June 30, 2002, PECO had outstanding $175 million of notes payable
consisting principally of commercial paper. Certain of the credit agreements to
which PECO is a party require PECO to maintain a debt to total capitalization
ratio of 65% or less, excluding
94
securitization debt and excluding the receivable from parent recorded in PECO's
shareholders' equity. At June 30, 2002, the debt to total capitalization ratios
on that basis for PECO was 38%.
PECO'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 PECO's borrowings are subject to default or prepayment as a
result of a downgrading of securities ratings although such a downgrading could
increase interest charges under PECO's bank credit facility. PECO from time to
time enters into interest rate swaps 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.
At June 30, 2002, PECO's capital structure, excluding the deduction
from shareholders' equity of the $1.8 billion receivable from Exelon, consisted
of 26% common equity, 2% notes payable, 3% preferred stock and COMRPS (which
comprised 2% of PECO's total capitalization structure), and 69% long-term debt
including transition bonds issued by PECO Energy Transition Trust (PETT).
Long-term debt included $4.4 billion of transition bonds representing 52% of
capitalization.
Under PUHCA and the Federal Power Act, PECO can pay dividends only from
retained or current earnings. At June 30, 2002, PECO had retained earnings of
$277 million.
Contractual Obligations and Commercial Commitments
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 June 30, 2002 were materially unchanged, other than in the
normal course of business, from the amounts as set forth in the December 31,
2001 Form 10-K except for an $85 million increase in the amount of surety bonds
required by PECO's insurance policies. Approximately one-fourth of the surety
bonds expire in the remainder of 2002 and the other three-fourths expire in the
two-year period ending December 2004.
95
EXELON GENERATION COMPANY, LLC
GENERAL
The operations of Generation consist of electric generating facilities,
energy marketing operations and equity interests in Sithe and AmerGen.
Generation early adopted the provision of EITF 02-3 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 with the net basis of presentation required by EITF 02-3.
RESULTS OF OPERATIONS
Three Months Ended June 30, 2002 Compared to Three Months Ended June 30, 2001
Significant Operating Trends - Generation
Three Months Ended June 30,
---------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 1,559 $1,583 $ (24) (1.5%)
OPERATING EXPENSES
Purchased Power 705 721 (16) (2.2%)
Fuel 224 230 (6) (2.6%)
Operating and Maintenance 411 405 6 1.5%
Depreciation 65 75 (10) (13.3%)
Taxes Other Than Income 41 39 2 5.1%
- --------------------------------------------------------------------------------------------------------
Total Operating Expense 1,446 1,470 (24) (1.6%)
- --------------------------------------------------------------------------------------------------------
OPERATING INCOME 113 113 --
- --------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (11) (26) 15 (57.7%)
Equity in Earnings (Losses) of Unconsolidated Affiliates, net 9 13 (4) (30.8%)
Other, net 24 14 10 71.4%
- --------------------------------------------------------------------------------------------------------
Total Other Income and Deductions 22 1 21 n.m.
- --------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 135 114 21 18.4%
INCOME TAXES 51 43 8 18.6%
- --------------------------------------------------------------------------------------------------------
NET INCOME $ 84 $ 71 13 18.3%
- --------------------------------------------------------------------------------------------------------
n.m. - not meaningful
Net Income
Generation's net income increased by $13 million, or 18%, for the three
months ended June 30, 2002 compared to the same period in the prior year. Net
income was positively impacted by increased revenue from affiliates, increased
revenue from the acquisition of two generating plants in April 2002 and reduced
depreciation and interest expense, partially offset by depressed wholesale
market prices for energy.
Operating Revenues, Net of Purchased Power and Fuel
Operating revenues, net of purchased power and fuel were $630 million
for the three months ended June 30, 2002 compared to $632 million for the same
period in 2001. The $2 million, or 0.3%, decrease was due to lower market prices
for energy, which reduced margins by $46 million during the three months ended
June 30, 2002 compared to the same period in 2001.
96
This decrease was partially offset by a $43 million increase in revenue from
affiliates, revenue from two generating plants acquired in April 2002, and lower
fuel costs. The average wholesale market prices were $7.00, or 18.6%, lower in
2002 compared to 2001. Generation's average purchased power costs for wholesale
operations were $39.96 per MWh for the three months ended June 30, 2002,
compared to $45.27 per MWh for the same period in 2001. The decrease in purchase
power costs resulted from the decrease in wholesale power market prices.
Additionally, revenue for the three months ended June 30, 2002 includes a net
trading portfolio loss of $16 million compared to a net $6 million loss for the
three months ended June 30, 2001.
For the three months ended June 30, 2002 and 2001, Generation's sales
and the supply of these sales excluding the trading portfolio, were as follows:
Three Months Ended June 30,
---------------------------
Sales (in GWhs) 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
Energy Delivery 28,294 28,105
Exelon Energy 1,355 1,415
Market Sales 20,589 18,548
- ---------------------------------------------------------------------------------------------------------------------
Total Sales 50,238 48,068
- ---------------------------------------------------------------------------------------------------------------------
Three Months Ended June 30,
---------------------------
Supply of Sales (in GWhs) 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
Nuclear Generation 28,353 28,443
Purchases - non-trading portfolio 18,220 16,392
Fossil and Hydro Generation 3,665 3,233
- ---------------------------------------------------------------------------------------------------------------------
Total Supply 50,238 48,068
- ---------------------------------------------------------------------------------------------------------------------
Trading volume was 8,566 GWhs and 454 GWhs for the three months ended
June 30, 2002 and 2001, respectively.
Generation's average margins on energy sales for the three months ended
June 30, 2002 and 2001 are as follows:
Three Months Ended June 30,
---------------------------
($/MWh) 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
Average Realized Revenue
Energy Delivery $ 31.45 $ 30.09
Exelon Energy 44.73 40.11
Market Sales 30.69 37.69
Total Sales - excluding the trading portfolio 31.50 33.32
Average Supply Cost - excluding the trading portfolio $ 18.79 $ 20.05
Average Margin - excluding the trading portfolio $ 12.71 $ 13.27
- ---------------------------------------------------------------------------------------------------------------------
Generation's nuclear fleet, including AmerGen, performed at a capacity
factor of 92.1% for the three months ended June 30, 2002 compared to 93.6% for
the same period in 2001.
97
Generation's nuclear fleet's production costs, including AmerGen, for the three
months ended June 30, 2002 were $12.54 per MWh compared to $13.02 per MWh for
the same period in 2001. The lower capacity factor is primarily due to 72
planned outage days in the three months ended June 30, 2002, versus 31 days in
the same period in 2001, including AmerGen. Reduced unit production costs
reflect additional generation due to power uprates and lower production costs
due to headcount reductions and Exelon's Cost Management Initiative in the three
months ended June 30, 2002 as compared to the same period in 2001.
Operating and Maintenance
Operating and maintenance expenses increased $6 million, or 2%, for the
three months ended June 30, 2002 compared to the same period in 2001. The
increase was primarily due to additional employee benefit costs of $9 million,
additional operating costs related to fossil plant outage work and the costs
related to the two generating plants acquired in April 2002 of $3 million. These
increases were partially offset by $7 million less in nuclear outage costs and
other operating cost reductions including savings from Exelon's Cost Management
Initiative.
Depreciation
Depreciation expenses decreased $10 million, or 13%, for the three
months ended June 30, 2002 compared to the same period in the prior year due to
a $16 million reduction in depreciation expense arising from the extension of
the useful lives on certain generation facilities in the third quarter of 2001,
partially offset by additional depreciation expense on capital additions placed
in service after June 30, 2001 including the acquisition of two generating
plants in April 2002.
Taxes Other Than Income
Taxes other than income increased $2 million, or 5%, for the three
months ended June 30, 2002 compared to the same period in the prior year
primarily due to an increase in property taxes.
Interest Expense
Interest expense decreased $15 million, or 58%, for the three months
ended June 30, 2002, compared to the same period in the prior year. The decrease
is primarily due to capitalized interest and a lower interest rate on the spent
nuclear fuel obligation.
Equity in Earnings of Unconsolidated Affiliates
Equity in earnings of unconsolidated affiliates decreased $4 million,
or 31%, for the three months ended June 30, 2002 compared to the same period in
the prior year. This decrease was due to a $7 million reduction in Generation's
equity earnings in AmerGen, primarily due to a planned plant outage, which began
in the first quarter of 2002. This decrease is partially offset by a $3 million
increase in Generation's equity earnings in Sithe.
Other, net
Other, net increased $10 million for the three months ended June 30,
2002 compared to the same period in the prior year primarily due to a $10
million increase in investment income from the nuclear decommissioning trust
funds.
98
Income Taxes
The effective income tax rate was unchanged at 37.7% for the three
months ended June 30, 2002 and 2001.
Significant Operating Trends - Generation
Six Months Ended June 30,
-------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 3,020 $3,211 $ (191) (5.9%)
OPERATING EXPENSES
Purchased Power 1,323 1,320 3 0.2%
Fuel 433 449 (16) (3.6%)
Operating and Maintenance 844 809 35 4.3%
Depreciation 128 167 (39) (23.4%)
Taxes Other Than Income 90 85 5 5.9%
- --------------------------------------------------------------------------------------------------------
Total Operating Expense 2,818 2,830 (12) (0.4%)
- --------------------------------------------------------------------------------------------------------
OPERATING INCOME 202 381 (179) (47.0%)
- --------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (28) (59) 31 (52.5%)
Equity in Earnings (Losses) of Unconsolidated Affiliates, net 32 39 (7) (17.9%)
Other, net 40 18 22 122.2%
- --------------------------------------------------------------------------------------------------------
Total Other Income and Deductions 44 (2) 46 n.m.
- --------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES AND CUMULATIVE
EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES 246 379 (133) (35.1%)
INCOME TAXES 96 150 (54) (36.0%)
- --------------------------------------------------------------------------------------------------------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGES
IN ACCOUNTING PRINCIPLES 150 229 (79) (34.4%)
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING
PRINCIPLES, NET OF INCOME TAXES 13 12 1 8.3%
- --------------------------------------------------------------------------------------------------------
NET INCOME $ 163 $ 241 (78) (32.4%)
- --------------------------------------------------------------------------------------------------------
Net Income
Generation's net income decreased by $78 million, or 32%, for the six
months ended June 30, 2002 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 partially offset by an increase in
revenue from affiliates and lower depreciation and interest expense.
Operating Revenues, Net of Purchased Power and Fuel
Operating revenues, net of purchased power and fuel were $1,264 million
for the six months ended June 30, 2002 compared to $1,442 million for the same
period in the prior year. The $178 million, or 12%, decrease was due to lower
wholesale market prices for energy, which reduced margins by $184 million, which
was partially offset by increased revenues from affiliates of $26 million and
lower fuel costs. The amount of low-cost nuclear generation
99
available for sale was reduced due to an increased number of nuclear generating
station refueling outages in the six months ended June 30, 2002, compared to the
same period in 2001. Additionally, trading activities were initiated in April
2001. Revenue for the six months ended June 30, 2002 includes a net trading
portfolio loss of $16 million compared to a net $6 million loss in the six
months ended June 30, 2001.
For the six months ended June 30, 2002 and 2001, Generation's sales and
the supply of these sales excluding the trading portfolio were as follows:
Six Months Ended June 30,
---------------------------
Sales (in GWhs) 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
Energy Delivery 56,044 57,309
Exelon Energy 2,605 3,006
Market Sales 39,913 36,007
- ---------------------------------------------------------------------------------------------------------------------
Total Sales 98,562 96,322
- ---------------------------------------------------------------------------------------------------------------------
Six Months Ended June 30,
---------------------------
Supply of Sales (in GWhs) 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
Nuclear Generation 55,886 58,410
Purchases - non-trading portfolio 36,314 31,954
Fossil and Hydro Generation 6,362 5,958
- ---------------------------------------------------------------------------------------------------------------------
Total Supply 98,562 96,322
- ---------------------------------------------------------------------------------------------------------------------
Trading volume was 22,805 GWhs and 454 GWhs for the six months ended
June 30, 2002 and 2001, respectively.
Generation's average margins on energy sales for the six months ended
June 30, 2002 and 2001 are as follows:
Six Months Ended June 30,
---------------------------
($/MWh) 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
Average Realized Revenue
Energy Delivery $ 30.73 $ 29.58
Exelon Energy 45.08 39.30
Market Sales 29.44 38.66
Total Sales - excluding the trading portfolio 30.58 33.27
Average Supply Cost - excluding the trading portfolio 17.78 18.75
Average Margin - excluding the trading portfolio 12.80 14.52
- ---------------------------------------------------------------------------------------------------------------------
Generation's nuclear fleet, including AmerGen, performed at a capacity
factor 91.2% for the six months ended June 30, 2002 compared to 96.2% for the
same period in 2001. Generation's nuclear fleet's production costs, including
AmerGen, for the six months ended June 30, 2002 were $13.38 per MWh compared to
$12.34 per MWh for the same period in 2001. The lower capacity factor and
increased unit production costs are primarily due to 153 planned outage days in
the six months ended June 30, 2002, versus 31 days in the same period in 2001,
100
including AmerGen. Increased unit production costs are partially offset by lower
production costs due to headcount reductions and cost savings initiatives.
Generation's average purchased power costs for wholesale operations were $36.76
per MWh for the six months ended June 30, 2002, compared to $41.81 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
Operating and maintenance expense increased $35 million, or 4%, for the
six months ended June 30, 2002 compared to the same period in 2001. This was due
to the additional operating and maintenance expense of $55 million arising from
an increased number of nuclear plant refueling outages during the six months
ended June 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 $10 million
related to headcount reductions, a $10 million reduction in Generation's
severance accrual and $4 million in savings from Exelon's Cost Management
Initiative. The severance reduction represents a reversal of costs previously
charged to operating expense.
Depreciation
Depreciation expenses decreased $39 million, or 23%, for the six months
ended June 30, 2002 compared to the same period in 2001 due to a $48 million
reduction in depreciation expense arising from the extension of the useful lives
on certain generation facilities commencing in the second quarter of 2001,
partially offset by additional depreciation expense on capital additions placed
in service after June 30, 2001, including the acquisition of two generating
plants in April 2002.
Taxes Other Than Income
Taxes other than income increased $5 million, or 6%, for the six months
ended June 30, 2002 compared to the same period in 2001 due primarily to the
Texas franchisee taxes related to the acquisition of two generating plants from
TXU in April 2002 and an increase in property taxes.
Interest Expense
Interest expense decreased $31 million, or 53%, for the six months
ended June 30, 2002, compared to the same period in 2001. The decrease is due to
capitalized interest and a lower interest rate on the spent nuclear fuel
obligation.
Equity in Earnings of Unconsolidated Affiliates
Equity in earnings of unconsolidated affiliates decreased $7 million,
or 18%, for the six months ended June 30, 2002 compared to the same period in
2001. This decrease was due to a $12 million reduction in Generation's equity
earnings in AmerGen, primarily due to a planned plant outage in 2002. This
decrease is partially offset by an increase of $5 million in Generation's equity
earnings of Sithe.
101
Other, net
Other, net increased $22 million, or 122%, for the six months ended
June 30, 2002 compared to the same period in 2001, primarily due to a $22
million increase in investment income from the nuclear decommissioning trust
funds.
Income Taxes
The effective income tax rate was substantially unchanged at 39.0% for
the six months ended June 30, 2002 compared to 39.6% for the same period in
2001.
Cumulative Effect of Changes in Accounting Principles
On January 1, 2002, Generation adopted SFAS No. 141 resulting in a
benefit of $13 million (net 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).
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 and borrowings or capital contributions from Exelon.
Generation's access to external financing at reasonable terms is dependent on
Generation's credit ratings and general business condition, as well as the
general business conditions of the industry. Capital resources are used
primarily to fund capital requirements, including construction, investments in
new and existing ventures, and repayments of maturing debt. Any potential future
acquisitions could require external financing or borrowings or capital
contributions for Exelon.
Cash Flows from Operating Activities
Cash flows provided by operations were $519 million for the six months
ended June 30, 2002, compared to $485 million for the same period in 2001.
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 $1,048 million for the six
months ended June 30, 2002, compared to $99 million for the same period in 2001.
Capital expenditures were $258 million and the investment in nuclear fuel was
$217 million in the six months ended June 30, 2002 compared to capital
expenditures of $173 million and investment in nuclear fuel of $128 million in
the same period in 2001. In addition to the 2002 capital expenditures,
Generation closed the purchase of two natural-gas and oil-fired plants from TXU
on April 25, 2002. The $443 million purchase was funded with available cash and
borrowings from Exelon. An increased number of
102
nuclear generating station refueling outages occurred during the six months
ended June 30, 2002 compared to the same period in 2001. Generation's investing
activities were funded from operating activities, borrowings from Exelon and the
use of available cash.
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%. As of June
30, 2002, AmerGen had borrowed $75 million under this agreement. In July 2002,
the loan agreement and the loan were increased to $100 million and the maturity
date was extended to July 1, 2003.
Cash Flows from Financing Activities
Cash flows provided by financing activities were $329 million for the
six months ended June 30, 2002, compared to cash used of $67 million for the
same period in the prior year. In 2002 Generation obtained a $331 million loan
from Exelon for the acquisition of two generating plants. The prior year amount
represented net distributions of $121 million to Exelon and the issuance of
long-term debt of $752 million. Also, in 2001 Generation repaid $696 million it
had borrowed from Exelon related to the acquisition of a 49.9% interest in
Sithe.
Credit Issues
Generation meets its short-term liquidity requirements primarily
through borrowings under bank credit facilities and borrowings from the Exelon
intercompany utility money pool. Generation, along with Exelon, ComEd and PECO
entered into a $1.5 billion unsecured 364-day revolving credit facility on
December 12, 2001 with a group of banks. As of June 30, 2002, no borrowing
sublimit had been established for Generation under this credit facility. This
credit facility requires Generation to maintain a debt to total capitalization
ratio of 65% or less. At June 30, 2002, Generation's debt to total
capitalization ratio was 32%.
Generation's access to the capital markets and its financing costs in
those markets are dependent on its securities ratings. None of Generation's
borrowings are subject to default or prepayment as a result of a downgrading of
securities ratings although such a downgrading could increase interest charges
under certain bank credit facilities.
From time to time Generation enters into interest rate swap and other
derivatives that require the maintenance of investment grade ratings. Failure to
maintain investment grade ratings would allow the counterparty to terminate the
derivative and settle the transaction on a net present value basis.
Under PUHCA and the Federal Power Act, Generation can only pay
dividends from undistributed or current earnings. At June 30, 2002, Generation
had undistributed earnings of $686 million.
Contractual Obligations and Commercial Commitments
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 June 30, 2002 were materially unchanged, other than in the
normal course of business, from the amounts set forth in the December 31, 2001
Form10-K except for the following:
103
o On April 25, 2002 Generation closed the purchase of 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 for $543
million plus the assumption of non-recourse debt estimated to be
approximately $1.2 billion at the date of purchase. The purchase is
estimated to close in November 2002, subject to regulatory approval. See
Note 3 of the Combined Notes to the Consolidated Financial Statements for
additional information about the Sithe New England acquisition.
o Purchase obligations increased by $1.2 billion, primarily due to an
increase of $2.0 billion in power only purchases partially offset by a $0.8
billion decrease in net capacity purchase commitments. The increase in
power only purchases is primarily 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. This decrease in net capacity purchase
commitments is due primarily to the decision not to exercise the option to
purchase 2,684 MWs of capacity from Midwest Generation in 2002 and 2003 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, 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 June 30, 2002,
Sithe had total assets of $4.1 billion and total debt of $2.1 billion, including
$1.6 billion of non-recourse project debt of which $1.0 billion is associated
with Sithe New England, $0.4 billion of subordinated debt, $49 million of
short-term debt, $33 million of capital leases, and excluding $411 million of
non-recourse project debt associated with Sithe's equity investments. For the
six months ended June 30, 2002, Sithe had revenues of $0.6 billion. As of June
30, 2002, Generation had a $725 million equity investment in Sithe. On June 26,
2002, Generation agreed to purchase Sithe New England for $543 million plus the
assumption of approximately $1.2 billion of non-recourse project debt, which is
104
expected to be outstanding at the time of the closing of the purchase.
Generation expects to close the purchase of Sithe New England in November 2002,
subject to regulatory approval.
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 June 30, 2002 including the debt of Sithe
described in the preceding paragraph, is currently estimated to be $2.3 billion
($1.2 billion based on Exelon's ownership interest of the investments).
Generation and British Energy, Generation's joint venture partner in
AmerGen, have each agreed to provide up to $100 million to AmerGen at any time
for operating expenses.
Other Factors
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 July 29, 2002, Generation had a
net receivable from Dynegy of less than $5 million, and consistent with the
terms of the existing credit arrangement, has requested 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 June 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 $15 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 Independence Station and
AmerGen's purchased power arrangement with Illinois Power, a subsidiary of
Dynegy, could be impacted by events related to Dynergy's financial condition.
105
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
Commodity Price Risk
Generation
Generation's energy contracts are accounted for under SFAS No. 133.
Most non-trading contracts qualify for a normal purchases and normal sales
exception. Those that do not are recorded as assets or liabilities on the
balance sheet at fair value. Changes in the fair value of qualifying cash-flow
hedge contracts are recorded in accumulated other comprehensive income, and
gains and losses are recognized in earnings when the underlying transaction
matures. Mark-to-market gains and losses on other 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 recognized in
earnings related to energy contracts for the three months ended June 30, 2002
and 2001 include $17 million of realized gains from cash-flow hedge contract
settlements and $5 million in non-cash mark-to-market losses on other derivative
contracts, and for the six months ended June 30, 2002 include $54 million of
realized gains from cash-flow hedge contract settlements and $2 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 liabilities in Exelon and Generation's
Consolidated Balance Sheet for the three months and six months ended June 30,
2002:
Three Months Ended June 30, 2002
--------------------------------
(in millions) Non-trading Trading
- ---------------------------------------------------------------------------------------------------------------------
Fair value of contracts outstanding as of April 1, 2002 $ (38) $ 10
Change in fair value during the three months ended June 30, 2002:
Contracts settled during period (20) 7
Mark-to-market gain/(loss) on contracts settled during the period 10 (7)
Mark to market gain/(loss) on other contracts 29 (9)
Changes in fair value attributable to changes in valuation techniques and
assumptions -- --
- ---------------------------------------------------------------------------------------------------------------------
Total change in fair value 19 (9)
- ---------------------------------------------------------------------------------------------------------------------
Fair value of contracts outstanding at June 30, 2002 $ (19) $ 1
- ---------------------------------------------------------------------------------------------------------------------
The total change in fair value during the three months ended June 30,
2002 is reflected in the 2002 financial statements as follows:
Non-trading Trading
- ---------------------------------------------------------------------------------------------------------------------
Mark-to-market gain/(loss) on trading activities and non-qualifying
hedge contracts or hedge ineffectiveness reflected in earnings $ 4 $ (9)
Mark-to-market gain/(loss) on cash-flow hedge contracts reflected in
Other Comprehensive Income 15 --
- ---------------------------------------------------------------------------------------------------------------------
Total change in fair value $ 19 $ (9)
- ---------------------------------------------------------------------------------------------------------------------
106
Six Months Ended June 30, 2002
--------------------------------
(in millions) Non-trading Trading
- ------------------------------------------------------------------------------------------------------------------------
Fair value of contracts outstanding as of January 1, 2002 $ 78 $ 14
Change in fair value during the six months ended June 30, 2002:
Contracts settled during period (64) 3
Mark-to-market gain/(loss) on contracts settled during the period 21 (8)
Mark to market gain/(loss) on other contracts (54) (8)
Changes in fair value attributable to changes in valuation techniques and
assumptions -- --
- ------------------------------------------------------------------------------------------------------------------------
Total change in fair value (97) (13)
- ------------------------------------------------------------------------------------------------------------------------
Fair value of contracts outstanding at June 30, 2002 $ (19) $ 1
- ------------------------------------------------------------------------------------------------------------------------
The total change in fair value during the six months ended June 30,
2002 is reflected in the 2002 financial statements as follows:
Non-trading Trading
- ------------------------------------------------------------------------------------------------------------------------
Mark-to-market gain/(loss) on trading activities and non-qualifying
hedge contracts or hedge ineffectiveness reflected in earnings $ 10 $ (13)
Mark-to-market gain/(loss) on cash-flow hedge contracts reflected in
Other Comprehensive Income (107) --
- ------------------------------------------------------------------------------------------------------------------------
Total change in fair value $ (97) $ (13)
- ------------------------------------------------------------------------------------------------------------------------
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 represent contracts for which external valuations are not available,
primarily option contracts. These contracts are valued using the Black model, an
industry standard option valuation model, and other valuation techniques and are
discounted using a risk-free interest rate. The fair values in each category
reflect the level of forward prices and volatility factors as of June 30, 2002
and may change as a result of future changes in these factors.
107
Mark-to market gains 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 that do not meet hedge criteria under SFAS No. 133 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-trading and trading derivative contracts and sources of fair
value as of June 30, 2002 are as follows:
Maturities within
--------------------------------------- Total Fair
(in millions) 1 Year 2-3 Years 4-5 Years Value
- ---------------------------------------------------------------------------------------------------------------------
Non-trading, qualifying cash flow hedge contracts (1):
Prices provided by other external sources $ -- $ (24) $ (6) $ (30)
- ---------------------------------------------------------------------------------------------------------------------
Total $ -- $ (24) $ (6) $ (30)
- ---------------------------------------------------------------------------------------------------------------------
Non-trading, other derivative contracts (2):
Actively quoted prices $ 4 $ -- $ -- $ 4
Prices provided by other external sources 22 11 5 38
Prices based on model or other valuation methods (8) (6) (17) (31)
- ---------------------------------------------------------------------------------------------------------------------
Total $ 18 $ 5 $ (12) $ 11
- ---------------------------------------------------------------------------------------------------------------------
Trading, other derivative contracts (3):
Actively quoted prices $ 1 $ -- $ -- $ 1
Prices provided by other external sources (3) (3) -- (6)
Prices based on model or other valuation methods 4 2 -- 6
- ---------------------------------------------------------------------------------------------------------------------
Total $ 2 $ (1) $ -- $ 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.
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 by two credit
rating agencies to below investment grade. As of July 29, 2002, Generation had a
net receivable from Dynegy of less than $5 million, and consistent with the
terms of the existing credit arrangement, has requested 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 June 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 $15 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 Independence Station and
AmerGen's
108
purchased power arrangement with Illinois Power, a subsidiary of Dynegy, could
be impacted by events related to Dynergy's financial condition.
109
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
As previously reported in Exelon's March 2002 Form 10-Q, on May 8,
2002, a class action lawsuit was filed against Exelon on behalf of purchasers of
Exelon securities between April 24, 2001 and September 27, 2001 (Class Period).
The lawsuit was filed in the United States District Court for the Northern
District of Illinois, Eastern Division. The complaint alleges 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. Corbin A. McNeill, Jr., John Rowe and Ruth Ann Gillis were also
named as defendants. Between May 8 and June 14, 2002, an additional five nearly
identical class actions lawsuits were filed. On May 30 and July 2, 2002, the
Court consolidated the cases into one lawsuit. Exelon believes that the lawsuit
is without merit and will vigorously contest this matter.
As previously reported in the 2001 Form 10-K and the March 2002 Form
10-Q, several developers of non-utility generating facilities filed litigation
against various Illinois officials claiming that the enforcement of an Illinois
law amendment, which removed the entitlement of those facilities to receive
state-subsidized payments for electricity sold to ComEd after March 15, 1996,
violated their rights under the Federal and state constitutions. Subsequently,
the developers filed complaints alleging that ComEd breached the contracts in
question and requested damages reflecting the state-subsidized rate to which the
developers claim they were entitled under their contracts. In July 2002, certain
of the plaintiffs produced an expert report claiming approximately $175 million
in damages, a quantification ComEd vigorously disputes. Virtually all parties
have filed motions for summary judgment. ComEd is contesting each case and has
filed its motion for summary judgment arguing that, as a matter of law, it did
not breach any of the contracts.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Information regarding the submission of matters to a vote of security
holders is presented in the Form 10-Q for the Quarterly period ended March 31,
2002.
ITEM 5. OTHER INFORMATION
ComEd
On May 28, 2002, ComEd filed a declaration with the FERC to join PJM.
ComEd committed to place its transmission system under the control of an
independent transmission company that would operate within PJM West, which would
be managed by National Grid USA and would also include the transmission systems
of American Electric Power East and Illinois Power.
110
On July 19, 2002, ComEd filed a request with the ICC to revise the POLR
obligation in Illinois. ComEd is seeking permission from the ICC to limit the
availability by June 2006 of Rate 6L for 370 of ComEd's largest energy customers
with demands of at least three MWs, totaling approximately 2,500 MWs. Rate 6L is
a bundled fixed rate offered to large customers including heavy industrial
plants, large office buildings, government facilities and a variety of other
businesses. The ICC has 120 days to act on the filing or it will be deemed
approved.
On August 1, 2002, ComEd set a new record for highest peak load
experienced to date of 21,852 MWs.
PECO
As previously disclosed in the 2001 Form 10-K, in February 2002, New
Power notified PECO of its intent to withdraw from providing Competitive Default
Service ("CDS") to approximately 180,000 residential customers. As a result of
that withdrawal, those CDS customers were returned to PECO in the second quarter
of 2002. Pursuant to a tariff filing approved by the Pennsylvania Public Utility
Commission, PECO will serve those returned customers at the discount energy
rates on generation provided for under the original New Power CDS Agreement for
the remaining term of that contract. Subsequently, in the second quarter of
2002, New Power also advised PECO it planned to withdraw from serving all of its
customers in Pennsylvania, including approximately 15,000 non-CDS PECO
customers, and to return those customers to PECO in September 2002.
On July 29, 2002, PECO set a new record for highest peak load
experienced to date of 8,193 MWs.
Generation
On April 25, 2002, Generation completed the purchase of two TXU Energy
power plants located in Dallas and Fort Worth areas for 443 million. The
agreement was first announced in December 2001. The purchase includes the 893 MW
Mountain Creek Steam Electric Station in Dallas and the 1,441 MW Handley Steam
Electric Station in Fort Worth. The purchase was funded with available cash and
commercial paper.
On June 21, 2002, Generation signed an agreement with Peoples Calumet,
LLC to form Southeast Chicago Energy Project, LLC. Southeast Chicago Energy
Project LLC will operate a 350MW simple cycle peaking power generating facility
consisting of 8 turbines located in Chicago. As of June 30, 2002 Generation's
investment in the Southeast Chicago Project, LLC was $166 million.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
99.1 - Certification 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
June 30, 2002, by John W. Rowe and Ruth Ann M. Gillis for
Exelon Corporation.
99.2 - Certification 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
June 30, 2002, by Frank M. Clark for Commonwealth Edison
Company.
99.3 - Certification 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
June 30, 2002, by Robert E. Berdelle for Commonwealth Edison
Company.
99.4 - Certification 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
June 30, 2002, by Kenneth G. Lawrence for PECO Energy Company.
99.5 - Certification 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
June 30, 2002, by Frank F. Frankowski for PECO Energy Company.
99.6 - Certification 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
June 30, 2002, by Oliver D. Kingsley for Exelon Generation
Company, LLC.
99.7 - Certification 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
June 30, 2002, by Ruth Ann M. Gillis for Exelon Generation
Company, LLC.
99.8 - 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).
111
(b) Reports on Form 8-K:
Exelon filed Current Reports on Form 8-K during the three
months ended June 30, 2002 regarding the following items:
Date of Earliest
Event Reported Description of Item Reported
- --------------------------------------------------------------------------------
April 2, 2002 "ITEM 5. OTHER EVENTS" regarding an interim
order in Commonwealth Edison's Delivery
Services Rate Case.
April 4, 2002 "ITEM 5. OTHER EVENTS" regarding the
announcement that an indirect subsidiary of
Exelon filed for protection under Chapter 11
of the Bankruptcy Code.
April 10, 2002 "ITEM 9. REGULATION FD DISCLOSURE" regarding
a presentation by representatives of Power
Team, Generation's Power Marketing
Organization, to Capital Group Companies.
The exhibit includes the slides used during
the presentation.
April 19, 2002 "ITEM 5. OTHER EVENTS and REGULATION FD
DISCLOSURE" regarding the announcement that
Ruth Ann M. Gillis, Senior Vice President
and Chief Financial Officer, will become
Senior Vice President and President, Exelon
Business Services Company.
April 22, 2002 "ITEM 5. OTHER EVENTS" reporting Exelon's
first quarter 2002 earnings results. Exelon
also announced that Nicholas DeBenedictis
was elected to the board of directors of
Exelon Corporation. "ITEM 9. REGULATION FD
DISCLOSURE" regarding highlights of the
Exelon First Quarter Earnings Conference
Call.
May 2, 2002 "ITEM 5. OTHER EVENTS" regarding the
announcement of the completion of the
purchase of two TXU Corp. power plants.
May 14, 2002 "ITEM 9. REGULATION FD DISCLOSURE" regarding
a presentation by Ruth Ann M. Gillis, Senior
Vice President and CFO of Exelon
Corporation, to investors at the Salomon
Smith Barney Power & Merchant Energy 2002
Conference. The exhibits include the slides
used and copies of the materials made
available to investors attending the
conference.
112
May 17, 2002 "ITEM 5. OTHER EVENTS" regarding
Commonwealth Edison's resolution of a FERC
reporting issue with Illinois Regulators.
May 22, 2002 "ITEM 5. OTHER EVENTS" regarding Exelon's
affirmation of Power Team's delivery-based
trading strategy.
May 22, 2002 "ITEM 9. REGULATION FD DISCLOSURE"
representatives of Exelon Corporation
attended the Edison Electric Institute's
International Finance Conference held in New
York. The exhibits include the materials
made available at the conference.
May 23, 2002 "ITEM 5. OTHER EVENTS" regarding Exelon's
response to FERC that Power Team did not
engage in any of the strategies put forth in
the Enron Corp. (Enron) memos referred to in
FERC's data request. A copy of Exelon's
response to the FERC data request was
included as an exhibit.
June 10, 2002 "ITEM 5. OTHER EVENTS" regarding Exelon's
reaffirmation of the company's earnings
outlook for 2002 and the announcement that
it will host an investor conference.
June 12, 2002 "ITEM 9. REGULATION FD DISCLOSURE" John W.
Rowe, President and CEO of Exelon, made a
presentation to investors at the Deutsche
Bank Electric and Power Conference. The
exhibits include the presentation slides and
other materials made available at the
conference.
June 20, 2002 "ITEM 9. REGULATION FD DISCLOSURE" senior
officers of Exelon made presentations at the
Exelon Investor Conference in New York City.
The exhibits include the presentation slides
and other materials made available at the
conference.
June 20, 2002 "ITEM 9. REGULATION FD DISCLOSURE" regarding
additional information management provided
during Exelon's Investor Conference in New
York on June 20, 2002.
June 27, 2002 "ITEM 5. OTHER EVENTS" a note to Exelon's
financial community regarding Exelon
Generation's agreement to purchase Sithe New
England Holdings, LLC.
- --------------------------------------------------------------------------------
ComEd filed Current Reports on Form 8-K during the three
months ended June 30, 2002 regarding the following items:
Date of Earliest
Event Reported Description of Item Reported
- --------------------------------------------------------------------------------
113
April 2, 2002 "ITEM 5. OTHER EVENTS" regarding an interim
order in Commonwealth Edison's Delivery
Services Rate Case.
April 22, 2002 "ITEM 5. OTHER EVENTS" reporting Exelon's
first quarter 2002 earnings results. Exelon
also announced that Nicholas DeBenedictis
was elected to the board of directors of
Exelon Corporation. "ITEM 9. REGULATION FD
DISCLOSURE" regarding highlights of the
Exelon First Quarter Earnings Conference
Call.
May 14, 2002 "ITEM 9. REGULATION FD DISCLOSURE" regarding
a presentation by Ruth Ann M. Gillis, Senior
Vice President and CFO of Exelon
Corporation, to investors at the Salomon
Smith Barney Power & Merchant Energy 2002
Conference. The exhibits include the slides
used and copies of the materials made
available to investors attending the
conference.
May 17, 2002 "ITEM 5. OTHER EVENTS" regarding
Commonwealth Edison's resolution of a FERC
reporting issue with Illinois Regulators.
May 22, 2002 "ITEM 9. REGULATION FD DISCLOSURE"
representatives of Exelon Corporation
attended the Edison Electric Institute's
International Finance Conference held in New
York. The exhibits include the materials
made available at the conference.
June 12, 2002 "ITEM 9. REGULATION FD DISCLOSURE" John W.
Rowe, President and CEO of Exelon, made a
presentation to investors at the Deutsche
Bank Electric and Power Conference. The
exhibits include the presentation slides and
other materials made available at the
conference.
June 20, 2002 "ITEM 9. REGULATION FD DISCLOSURE" senior
officers of Exelon made presentations at the
Exelon Investor Conference in New York City.
The exhibits include the presentation slides
and other materials made available at the
conference.
June 20, 2002 "ITEM 9. REGULATION FD DISCLOSURE" regarding
additional information management provided
during Exelon's Investor Conference in New
York on June 20, 2002.
- --------------------------------------------------------------------------------
PECO filed Current Reports on Form 8-K during the three months
ended June 30, 2002 regarding the following items:
Date of Earliest
Event Reported Description of Item Reported
- --------------------------------------------------------------------------------
114
April 22, 2002 "ITEM 5. OTHER EVENTS" reporting Exelon's
first quarter 2002 earnings results. Exelon
also announced that Nicholas DeBenedictis
was elected to the board of directors of
Exelon Corporation. "ITEM 9. REGULATION FD
DISCLOSURE" regarding highlights of the
Exelon First Quarter Earnings Conference
Call.
May 14, 2002 "ITEM 9. REGULATION FD DISCLOSURE" regarding
a presentation by Ruth Ann M. Gillis, Senior
Vice President and CFO of Exelon
Corporation, to investors at the Salomon
Smith Barney Power & Merchant Energy 2002
Conference. The exhibits include the slides
used and copies of the materials made
available to investors attending the
conference.
May 22, 2002 "ITEM 9. REGULATION FD DISCLOSURE"
representatives of Exelon Corporation
attended the Edison Electric Institute's
International Finance Conference held in New
York. The exhibits include the materials
made available at the conference.
June 12, 2002 "ITEM 9. REGULATION FD DISCLOSURE" John W.
Rowe, President and CEO of Exelon, made a
presentation to investors at the Deutsche
Bank Electric and Power Conference. The
exhibits include the presentation slides and
other materials made available at the
conference.
June 20, 2002 "ITEM 9. REGULATION FD DISCLOSURE" senior
officers of Exelon made presentations at the
Exelon Investor Conference in New York City.
The exhibits include the presentation slides
and other materials made available at the
conference.
June 20, 2002 "ITEM 9. REGULATION FD DISCLOSURE" regarding
additional information management provided
during Exelon's Investor Conference in New
York on June 20, 2002.
- --------------------------------------------------------------------------------
Generation filed Current Reports on Form 8-K during the three
months ended June 30, 2002 regarding the following items:
Date of Earliest
Event Reported Description of Item Reported
- --------------------------------------------------------------------------------
May 2, 2002 "ITEM 5. OTHER EVENTS" regarding the
announcement of the completion of the
purchase of two TXU Corp. power plants.
May 14, 2002 "ITEM 9. REGULATION FD DISCLOSURE" regarding
a presentation by Ruth Ann M. Gillis, Senior
Vice President and CFO of Exelon
Corporation, to investors at the Salomon
Smith Barney Power & Merchant Energy 2002
115
Conference. The exhibits include the slides
used and copies of the materials made
available to investors attending the
conference.
May 22, 2002 "ITEM 5. OTHER EVENTS" regarding Exelon's
affirmation of Power Team's delivery-based
trading strategy.
May 22, 2002 "ITEM 9. REGULATION FD DISCLOSURE"
representatives of Exelon Corporation
attended the Edison Electric Institute's
International Finance Conference held in New
York. The exhibits include the materials
made available at the conference.
May 23, 2002 "ITEM 5. OTHER EVENTS" regarding Exelon's
response to FERC that Power Team did not
engage in any of the strategies put forth in
the Enron memos referred to in FERC's data
request. A copy of Exelon's response to the
FERC data request was included as an
exhibit.
June 12, 2002 "ITEM 9. REGULATION FD DISCLOSURE" John W.
Rowe, President and CEO of Exelon, made a
presentation to investors at the Deutsche
Bank Electric and Power Conference. The
exhibits include the presentation slides and
other materials made available at the
conference.
June 20, 2002 "ITEM 9. REGULATION FD DISCLOSURE" senior
officers of Exelon made presentations at the
Exelon Investor Conference in New York City.
The exhibits include the presentation slides
and other materials made available at the
conference.
June 20, 2002 "ITEM 9. REGULATION FD DISCLOSURE" regarding
additional information management provided
during Exelon's Investor Conference in New
York on June 20, 2002.
June 27, 2002 "ITEM 5. OTHER EVENTS" a note to Exelon's
financial community regarding Exelon
Generation's agreement to purchase Sithe New
England Holdings, LLC.
- --------------------------------------------------------------------------------
116
SIGNATURES
Pursuant to requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
EXELON CORPORATION
/s/ John W. Rowe
--------------------------------
JOHN W. ROWE
President and CEO
/s/ Ruth Ann M. Gillis
--------------------------------
RUTH ANN M. GILLIS
Senior Vice President and Chief Financial Officer
/s/ Matthew F. Hilzinger
--------------------------------
MATTHEW F. HILZINGER
Vice President and Corporate Controller
(Principal Accounting Officer)
August 6, 2002
117
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.
COMMONWEALTH EDISON COMPANY
/s/ Pamela B. Strobel
--------------------------------
PAMELA B. STROBEL
Chairman and CEO
Exelon Energy Delivery
/s/ Frank M. Clark
--------------------------------
FRANK M. CLARK
President
/s/ Robert E. Berdelle
--------------------------------
ROBERT E. BERDELLE
Vice President and Chief Financial Officer
(Principal Accounting Officer)
August 6, 2002
118
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.
PECO ENERGY COMPANY
/s/ Pamela B. Strobel
--------------------------------
PAMELA B. STROBEL
Chairman and CEO
Exelon Energy Delivery
/s/ Ken G. Lawrence
--------------------------------
KEN G. LAWRENCE
President
/s/ Frank F. Frankowski
---------------------------------
FRANK F. FRANKOWSKI
Vice President and Chief Financial Officer
(Principal Accounting Officer)
August 6, 2002
119
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 GENERATION COMPANY, LLC
/s/ Oliver D. Kingsley Jr.
--------------------------------
OLIVER D. KINGSLEY JR.
CEO and President
/s/ Ruth Ann M. Gillis
--------------------------------
RUTH ANN M. GILLIS
Senior Vice President and Chief Financial Officer
Exelon Corporation
(Principal Financial Officer)
August 6, 2002
120