UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended September 30, 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 October 15, 2002 was as follows:
Exelon Corporation Common Stock, without par value 322,984,742
Commonwealth Edison Company Common Stock, $12.50 par value 127,016,409
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 51
Exelon Corporation 51
Commonwealth Edison Company 80
PECO Energy Company 94
Exelon Generation Company, LLC 108
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK 121
ITEM 4. CONTROLS AND PROCEDURES 124
PART II. OTHER INFORMATION 126
ITEM 1. LEGAL PROCEEDINGS 126
ITEM 5. OTHER INFORMATION 126
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K 128
SIGNATURES 131
CERTIFICATIONS 133
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 from the forward-looking statements made by a registrant
include those discussed herein as well as those listed in Note 8 of Notes to
Consolidated Financial Statements, those discussed in "Management's Discussion
and Analysis of Financial Condition and Results of Operations--Outlook" in
Exelon Corporation's 2001 Annual Report, those discussed in "Risk Factors" in
PECO Energy Company's Registration Statement on Form S-3, Reg. No. 333-99361,
those discussed in "Risk Factors" 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, those discussed in
"Risk Factors" in Commonwealth Edison Company's Registration Statement of Form
S-3, Reg. No. 333-99363 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. None of the Registrants undertake any obligation to
publicly release any revision to its 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 Nine Months Ended
September 30, September 30,
(in millions, except per share data) 2002 2001 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $4,370 $4,185 $ 11,245 $ 11,625
OPERATING EXPENSES
Purchased Power 1,233 1,249 2,543 2,634
Purchased Power from Unconsolidated Affiliate 104 26 220 48
Fuel 373 356 1,233 1,455
Operating and Maintenance 1,114 1,101 3,252 3,293
Depreciation and Amortization 345 369 1,012 1,109
Taxes Other Than Income 201 172 568 493
- ---------------------------------------------------------------------------------------------------------------------
Total Operating Expense 3,370 3,273 8,828 9,032
- ---------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 1,000 912 2,417 2,593
- ---------------------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (249) (283) (739) (864)
Distributions on Preferred Securities of Subsidiaries (11) (11) (34) (34)
Equity in Earnings of Unconsolidated Affiliates, net 92 52 114 77
Other, net 16 (51) 239 48
- ---------------------------------------------------------------------------------------------------------------------
Total Other Income and Deductions (152) (293) (420) (773)
- ---------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES AND CUMULATIVE
EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES 848 619 1,997 1,820
INCOME TAXES 297 243 724 742
- ---------------------------------------------------------------------------------------------------------------------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN
ACCOUNTING PRINCIPLES 551 376 1,273 1,078
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING
PRINCIPLES (net of income taxes of ($90) and $8 for the nine
months ended September 30, 2002 and 2001, respectively) -- -- (230) 12
- ---------------------------------------------------------------------------------------------------------------------
NET INCOME 551 376 1,043 1,090
- ---------------------------------------------------------------------------------------------------------------------
OTHER COMPREHENSIVE INCOME (LOSS) (net of income taxes)
SFAS 133 Transition Adjustment -- -- -- 44
Cash Flow Hedge Fair Value Adjustment (28) 13 (109) (17)
Unrealized Gain (Loss) on Marketable Securities, net (73) (30) (158) (154)
Interest in Other Comprehensive Income of
Unconsolidated Affiliates (20) (3) (21) (1)
- ---------------------------------------------------------------------------------------------------------------------
Total Other Comprehensive Income (Loss) (121) (20) (288) (128)
- ---------------------------------------------------------------------------------------------------------------------
TOTAL COMPREHENSIVE INCOME $ 430 $ 356 $ 755 $ 962
=====================================================================================================================
AVERAGE SHARES OF COMMON STOCK OUTSTANDING - Basic 323 321 322 320
=====================================================================================================================
AVERAGE SHARES OF COMMON STOCK OUTSTANDING - Diluted 324 323 324 323
=====================================================================================================================
EARNINGS PER AVERAGE COMMON SHARE:
BASIC:
Income Before Cumulative Effect of Changes in Accounting
Principles $ 1.71 $ 1.17 $ 3.95 $ 3.36
Cumulative Effect of Changes in Accounting Principles -- -- (0.71) 0.04
- ---------------------------------------------------------------------------------------------------------------------
Net Income $ 1.71 $ 1.17 $ 3.24 $ 3.40
=====================================================================================================================
DILUTED:
Income Before Cumulative Effect of Changes in Accounting
Principles $ 1.70 $ 1.16 $ 3.93 $ 3.33
Cumulative Effect of Changes in Accounting Principles -- -- (0.71) 0.04
- ---------------------------------------------------------------------------------------------------------------------
Net Income $ 1.70 $ 1.16 $ 3.22 $ 3.37
=====================================================================================================================
DIVIDENDS PER COMMON SHARE $ 0.44 $ 0.42 $ 1.32 $ 1.40
=====================================================================================================================
See Notes to Consolidated Financial Statements
5
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended September 30,
(in millions) 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 1,043 $ 1,090
Adjustments to Reconcile Net Income to Net Cash Flows
Provided by Operating Activities:
Depreciation and Amortization, including nuclear fuel 1,284 1,481
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 107 95
Deferred Income Taxes 293 (101)
Deferred Energy Costs 50 21
Equity in Earnings of Unconsolidated Affiliates, net (114) (77)
Net Realized Losses on Nuclear Decommissioning Trust Funds 32 90
Other Operating Activities 162 (76)
Changes in Working Capital:
Accounts Receivable (320) (163)
Inventories (31) 41
Accounts Payable, Accrued Expenses and Other Current Liabilities (6) 572
Changes in Receivables and Payables to Unconsolidated Affiliates, net 46 --
Other Current Assets 24 (4)
- ---------------------------------------------------------------------------------------------------------------------
Net Cash Flows provided by Operating Activities 2,601 2,957
- ---------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures (1,534) (1,352)
Acquisition of Generating Plants (443) --
Enterprises Acquisitions, net of cash acquired -- (39)
Proceeds from the Sale of Investments 287 --
Proceeds from Nuclear Decommissioning Trust Funds 1,184 1,077
Investment in Nuclear Decommissioning Trust Funds (1,330) (1,128)
Note Receivable from Unconsolidated Affiliate (42) --
Other Investing Activities 81 (143)
- ---------------------------------------------------------------------------------------------------------------------
Net Cash Flows used in Investing Activities (1,797) (1,585)
- ---------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Long-Term Debt 956 2,126
Retirement of Long-Term Debt (1,946) (1,433)
Change in Short-Term Debt 428 (957)
Dividends on Common Stock (420) (448)
Change in Restricted Cash 81 125
Proceeds from Employee Stock Plans 64 52
Contribution from Minority Interest of Consolidated Subsidiary 43 --
Redemption of Preferred Securities of Subsidiaries (18) (18)
Other Financing Activities (16) 32
- ---------------------------------------------------------------------------------------------------------------------
Net Cash Flows used in Financing Activities (828) (521)
- ---------------------------------------------------------------------------------------------------------------------
INCREASE IN CASH AND CASH EQUIVALENTS (24) 851
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 461 526
- ---------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 490 $ 1,377
=====================================================================================================================
SUPPLEMENTAL CASH FLOW INFORMATION
Non-cash Investing and Financing Activities:
Contribution of Land from Minority Interest of Consolidated Subsidiary $ 12 --
Regulatory Asset Fair Value Adjustment -- $ 347
Purchase Accounting Estimate Adjustments -- $ 63
See Notes to Consolidated Financial Statements
6
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
(in millions) 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 461 $ 485
Restricted Cash 291 372
Accounts Receivable, net
Customer 2,007 1,687
Other 210 428
Receivable from Unconsolidated Affiliate 40 44
Inventories, at average cost
Fossil Fuel 189 222
Materials and Supplies 312 249
Deferred Income Taxes 101 23
Other 300 272
- ---------------------------------------------------------------------------------------------------------------------
Total Current Assets 3,911 3,782
- ---------------------------------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT, NET 14,926 13,781
DEFERRED DEBITS AND OTHER ASSETS
Regulatory Assets 6,111 6,423
Nuclear Decommissioning Trust Funds 2,997 3,165
Investments 1,665 1,623
Goodwill, net 4,964 5,335
Other 662 708
- ---------------------------------------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 16,399 17,254
- ---------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS $ 35,236 $ 34,817
=====================================================================================================================
See Notes to Consolidated Financial Statements
7
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
(in millions) 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Notes Payable $ 788 $ 360
Long-Term Debt Due within One Year 1,501 1,406
Accounts Payable 1,304 964
Accrued Expenses 942 1,182
Other 495 505
- ---------------------------------------------------------------------------------------------------------------------
Total Current Liabilities 5,030 4,417
- ---------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT 11,904 12,879
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred Income Taxes 4,506 4,388
Unamortized Investment Tax Credits 305 316
Nuclear Decommissioning Liability for Retired Plants 1,389 1,353
Pension Obligation 315 334
Non-Pension Postretirement Benefits Obligation 893 847
Spent Nuclear Fuel Obligation 854 843
Other 859 694
- ---------------------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 9,121 8,775
- ---------------------------------------------------------------------------------------------------------------------
PREFERRED SECURITIES OF SUBSIDIARIES 595 613
MINORITY INTEREST OF CONSOLIDATED SUBSIDIARIES 75 31
COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS' EQUITY
Common Stock 6,995 6,930
Deferred Compensation (1) (2)
Retained Earnings 1,830 1,200
Accumulated Other Comprehensive Income (Loss) (313) (26)
- ---------------------------------------------------------------------------------------------------------------------
Total Shareholders' Equity 8,511 8,102
- ---------------------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 35,236 $ 34,817
=====================================================================================================================
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 Nine Months Ended
September 30, September 30,
(in millions) 2002 2001 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES
Operating Revenues $1,912 $1,905 $ 4,685 $ 4,826
Operating Revenues from Affiliates 26 14 49 69
- ---------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 1,938 1,919 4,734 4,895
- ---------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Purchased Power 8 6 20 8
Purchased Power from Affiliate 967 948 2,046 2,141
Operating and Maintenance 234 229 620 625
Operating and Maintenance from Affiliates 33 36 104 106
Depreciation and Amortization 129 178 397 512
Taxes Other Than Income 77 82 223 223
- ---------------------------------------------------------------------------------------------------------------------
Total Operating Expense 1,448 1,479 3,410 3,615
- ---------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 490 440 1,324 1,280
- ---------------------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (122) (137) (374) (423)
Interest Expense from Affiliate -- (10) -- (10)
Distributions on Company-Obligated
Mandatorily Redeemable Preferred Securities of
Subsidiary Trusts Holding Solely the Company's
Subordinated Debt Securities (7) (7) (22) (22)
Interest Income from Affiliates 8 24 23 70
Other, net (8) 9 6 24
- ---------------------------------------------------------------------------------------------------------------------
Total Other Income and Deductions (129) (121) (367) (361)
- ---------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 361 319 957 919
INCOME TAXES 146 141 381 412
- ---------------------------------------------------------------------------------------------------------------------
NET INCOME 215 178 576 507
- ---------------------------------------------------------------------------------------------------------------------
OTHER COMPREHENSIVE INCOME (LOSS) (net of income taxes):
Cash Flow Hedge Fair Value Adjustment (15) -- (31) --
Unrealized Gain (Loss) on Marketable Securities (1) (1) (3) (5)
- ---------------------------------------------------------------------------------------------------------------------
Total Other Comprehensive Income (Loss) (16) (1) (34) (5)
- ---------------------------------------------------------------------------------------------------------------------
TOTAL COMPREHENSIVE INCOME $ 199 $ 177 $ 542 $ 502
=====================================================================================================================
See Notes to Consolidated Financial Statements
9
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended September 30,
(in millions) 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 576 $ 507
Adjustments to Reconcile Net Income to Net Cash Flows
Provided by Operating Activities:
Depreciation and Amortization 397 512
Provision for Uncollectible Accounts 29 31
Deferred Income Taxes 92 26
Other Operating Activities 86 (27)
Changes in Working Capital:
Accounts Receivable (198) (80)
Inventories (4) 25
Accounts Payable, Accrued Expenses and Other Current Liabilities 64 324
Changes in Receivables and Payables to Affiliates, net 449 (279)
Other Current Assets (2) 4
- ---------------------------------------------------------------------------------------------------------------------
Net Cash Flows provided by Operating Activities 1,489 1,043
- ---------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures (549) (631)
Notes Receivable from Affiliate 14 400
Other Investing Activities 9 --
- ---------------------------------------------------------------------------------------------------------------------
Net Cash Flows used in Investing Activities (526) (231)
- ---------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Short-Term Borrowings 94 --
Issuance of Long-Term Debt 701 --
Retirement of Long-Term Debt (1,365) (260)
Dividends on Common Stock (353) (253)
Change in Restricted Cash (37) (5)
Other Financing Activities (10) --
- ---------------------------------------------------------------------------------------------------------------------
Net Cash Flows used in Financing Activities (970) (518)
- ---------------------------------------------------------------------------------------------------------------------
(DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS (7) 294
- ---------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 23 141
- ---------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 16 $ 435
=====================================================================================================================
SUPPLEMENTAL CASH FLOW INFORMATION
Non-cash Investing and Financing Activities:
Net Assets Transferred as a result of Restructuring, net of Note Payable -- $ 1,307
Receivable from Parent -- $ 1,062
Purchase Accounting Estimate Adjustment -- $ 63
Regulatory Asset Fair Value Adjustment -- $ 347
Retirement of Treasury Shares $ 1,344 $ 2,023
See Notes to Consolidated Financial Statements
10
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
(in millions) 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 16 $ 23
Restricted Cash 78 41
Accounts Receivable, net
Customer 914 745
Other 89 87
Receivables from Affiliates 8 6
Inventories, at average cost 60 56
Deferred Income Taxes 40 52
Other 17 15
- ---------------------------------------------------------------------------------------------------------------------
Total Current Assets 1,222 1,025
- ---------------------------------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT, NET 7,610 7,351
DEFERRED DEBITS AND OTHER ASSETS
Regulatory Assets 583 667
Investments 54 64
Goodwill, net 4,888 4,902
Notes Receivable from Affiliates 1,300 1,314
Other 311 304
- ---------------------------------------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 7,136 7,251
- ---------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS $ 15,968 $ 15,627
=====================================================================================================================
See Notes to Consolidated Financial Statements
11
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
(in millions) 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Short-Term Borrowings $ 94 $ --
Long-Term Debt Due within One Year 798 849
Accounts Payable 200 144
Accrued Expenses 396 374
Payables to Affiliates 615 218
Other 183 212
- ---------------------------------------------------------------------------------------------------------------------
Total Current Liabilities 2,286 1,797
- ---------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT 5,295 5,850
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred Income Taxes 1,749 1,671
Unamortized Investment Tax Credits 52 55
Pension Obligation 167 151
Non-Pension Postretirement Benefits Obligation 145 146
Payables to Affiliates 251 297
Other 322 248
- ---------------------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 2,686 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 (845) (937)
Retained Earnings 480 257
Treasury Stock, at cost -- (1,344)
Accumulated Other Comprehensive Income (Loss) (39) (5)
- ---------------------------------------------------------------------------------------------------------------------
Total Shareholders' Equity 5,372 5,083
- ---------------------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 15,968 $ 15,627
=====================================================================================================================
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 Nine Months Ended
September 30, September 30,
(in millions) 2002 2001 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES
Operating Revenues $1,221 1,048 $ 3,230 $ 2,999
Operating Revenues from Affiliates 3 3 9 9
- ---------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 1,224 1,051 3,239 3,008
- ---------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Purchased Power 68 57 175 147
Purchased Power from Affiliate 441 363 1,090 872
Fuel 40 51 228 335
Operating and Maintenance 125 134 350 352
Operating and Maintenance from Affiliates 15 22 57 61
Depreciation and Amortization 127 115 348 315
Taxes Other Than Income 85 51 207 135
- ---------------------------------------------------------------------------------------------------------------------
Total Operating Expense 901 793 2,455 2,217
- ---------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 323 258 784 791
- ---------------------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (93) (105) (280) (324)
Interest Expense from Affiliate -- -- -- (8)
Company-Obligated Mandatorily Redeemable Preferred
Securities of a Partnership, which holds Solely
Subordinated Debentures of the Company (2) (2) (7) (7)
Interest Income from Affiliates -- 9 -- 10
Other, net 5 3 7 20
- ---------------------------------------------------------------------------------------------------------------------
Total Other Income and Deductions (90) (95) (280) (309)
- ---------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 233 163 504 482
INCOME TAXES 76 59 166 171
- ---------------------------------------------------------------------------------------------------------------------
NET INCOME 157 104 338 311
Preferred Stock Dividends (2) (2) (6) (7)
- ---------------------------------------------------------------------------------------------------------------------
NET INCOME ON COMMON STOCK $ 155 $ 102 $ 332 $ 304
=====================================================================================================================
OTHER COMPREHENSIVE INCOME
Net Income $ 157 $ 104 $ 338 $ 311
Other Comprehensive Income (Loss) (net of income taxes):
SFAS 133 Transition Adjustment -- -- -- 40
Cash Flow Hedge Fair Value Adjustment (5) (10) (10) (20)
Unrealized Gain (Loss) on Marketable Securities (1) -- -- --
- ---------------------------------------------------------------------------------------------------------------------
TOTAL COMPREHENSIVE INCOME $ 151 $ 94 $ 328 $ 331
=====================================================================================================================
See Notes to Consolidated Financial Statements
13
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended September 30,
(in millions) 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 338 $ 311
Adjustments to Reconcile Net Income to Net Cash Flows
Provided by Operating Activities:
Depreciation and Amortization 348 315
Provision for Uncollectible Accounts 48 50
Deferred Income Taxes (64) (49)
Deferred Energy Costs 50 14
Other Operating Activities 15 (23)
Changes in Working Capital:
Accounts Receivable (69) (64)
Changes in Receivables and Payables to Affiliates, net (27) 154
Inventories (8) (21)
Accounts Payable, Accrued Expenses and Other Current Liabilities (107) 92
Other Current Assets (51) (35)
- ---------------------------------------------------------------------------------------------------------------------
Net Cash Flows provided by Operating Activities 473 744
- ---------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures (180) (153)
Other Investing Activities 3 (1)
- ---------------------------------------------------------------------------------------------------------------------
Net Cash Flows used in Investing Activities (177) (154)
- ---------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Retirement of Long-Term Debt (571) (1,167)
Issuance of Long-Term Debt 225 805
Contribution from Parent 30 121
Change in Short-Term Debt 274 (161)
Dividends on Preferred and Common Stock (261) (176)
Change in Restricted Cash 113 98
Change in Receivable and Payable to Affiliate, net -- (41)
Retirement of Mandatorily Redeemable Preferred Stock (19) (18)
Settlement of Interest Rate Swap Agreements (5) 31
- ---------------------------------------------------------------------------------------------------------------------
Net Cash Flows used in Financing Activities (214) (508)
- ---------------------------------------------------------------------------------------------------------------------
INCREASE IN CASH AND CASH EQUIVALENTS 82 82
Cash Transferred in Restructuring -- (31)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 32 49
- ---------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 114 $ 100
=====================================================================================================================
SUPPLEMENTAL CASH FLOW INFORMATION Non-cash Investing and Financing Activities:
Net Assets Transferred as a result of Restructuring,
net of Receivable from Affiliates -- $ 1,577
Contribution of Receivable from Parent -- $ 1,983
See Notes to Consolidated Financial Statements
14
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
(in millions) 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 114 $ 32
Restricted Cash 210 323
Accounts Receivable, net
Customer 310 286
Other 30 33
Receivables from Affiliates 17 1
Inventories, at average cost
Fossil Fuel 79 72
Materials and Supplies 7 7
Prepaid Taxes 50 1
Other 10 58
- ---------------------------------------------------------------------------------------------------------------------
Total Current Assets 827 813
- ---------------------------------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT, NET 4,121 4,047
DEFERRED DEBITS AND OTHER ASSETS
Regulatory Assets 5,527 5,756
Investments 21 24
Pension Asset 37 13
Other 83 85
- ---------------------------------------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 5,668 5,878
- ---------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS $ 10,616 $ 10,738
=====================================================================================================================
See Notes to Consolidated Financial Statements
15
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
(in millions) 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Notes Payable $ 375 $ 101
Payables to Affiliates 130 187
Long-Term Debt Due within One Year 689 548
Accounts Payable 61 54
Accrued Expenses 277 397
Deferred Income Taxes 27 27
Other 37 21
- ---------------------------------------------------------------------------------------------------------------------
Total Current Liabilities 1,596 1,335
- ---------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT 4,950 5,438
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred Income Taxes 2,881 2,938
Unamortized Investment Tax Credits 25 27
Non-Pension Postretirement Benefits Obligation 271 239
Payable to Affiliate -- 44
Other 118 110
- ---------------------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 3,295 3,358
- ---------------------------------------------------------------------------------------------------------------------
COMPANY-OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES OF A PARTNERSHIP,
WHICH HOLDS SOLELY SUBORDINATED
DEBENTURES OF THE COMPANY 128 128
MANDATORILY REDEEMABLE PREFERRED STOCK -- 19
COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS' EQUITY
Common Stock 1,942 1,912
Receivable from Parent (1,788) (1,878)
Preferred Stock 137 137
Retained Earnings 347 270
Accumulated Other Comprehensive Income 9 19
- ---------------------------------------------------------------------------------------------------------------------
Total Shareholders' Equity 647 460
- ---------------------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 10,616 $ 10,738
=====================================================================================================================
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 Nine Months Ended
September 30, September 30,
(in millions) 2002 2001 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES
Operating Revenues $ 750 $ 787 $1,924 $ 2,180
Operating Revenues from Affiliates 1,463 1,404 3,309 3,223
- ---------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 2,213 2,191 5,233 5,403
- ---------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Purchased Power 1,251 1,209 2,555 2,504
Purchased Power from Affiliates 6 59 26 85
Fuel 273 242 706 691
Operating and Maintenance 351 322 1,098 1,046
Operating and Maintenance Expense from Affiliates 40 42 136 127
Depreciation and Amortization 68 57 197 224
Taxes Other Than Income 37 36 126 121
- ---------------------------------------------------------------------------------------------------------------------
Total Operating Expense 2,026 1,967 4,844 4,798
- ---------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 187 224 389 605
- ---------------------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (22) (27) (48) (62)
Interest Expense from Affiliates (1) (14) (3) (38)
Equity in Earnings of Unconsolidated Affiliates 87 60 119 99
Interest Income from Affiliates -- 10 -- 10
Other, net 14 (35) 54 (17)
- ---------------------------------------------------------------------------------------------------------------------
Total Other Income and Deductions 78 (6) 122 (8)
- ---------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT
OF CHANGES IN ACCOUNTING PRINCIPLES 265 218 511 597
INCOME TAXES 102 78 198 228
- ---------------------------------------------------------------------------------------------------------------------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN
ACCOUNTING PRINCIPLES 163 140 313 369
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING
PRINCIPLES -- -- 13 12
- ---------------------------------------------------------------------------------------------------------------------
NET INCOME 163 140 326 381
- ---------------------------------------------------------------------------------------------------------------------
OTHER COMPREHENSIVE INCOME (LOSS) (net of income taxes)
Unrealized Gain (Loss) on Marketable Securities (69) (54) (151) (134)
SFAS 133 Transition Adjustment -- -- -- 4
Cash Flow Hedge Fair Value Adjustment (11) 50 (79) 14
Interest in Other Comprehensive Income of Unconsolidated
Affiliates (20) (3) (21) (1)
- ---------------------------------------------------------------------------------------------------------------------
Total Other Comprehensive Income (Loss) (100) (7) (251) (117)
- ---------------------------------------------------------------------------------------------------------------------
TOTAL COMPREHENSIVE INCOME $ 63 $ 133 $ 75 $ 264
=====================================================================================================================
See Notes to Consolidated Financial Statements
17
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended September 30,
(in millions) 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 326 $ 381
Adjustments to Reconcile Net Income to Net Cash Flows
Provided by Operating Activities:
Depreciation and Amortization, including nuclear fuel 475 531
Cumulative Effect of a Change in Accounting Principle (net of income taxes) (13) (12)
Provision for Uncollectible Accounts 20 3
Deferred Income Taxes 246 (84)
Equity in (Earnings) Losses of Unconsolidated Affiliates (119) (99)
Net Realized Losses on Nuclear Decommissioning Trust Funds 32 90
Other Operating Activities 109 (162)
Changes in Working Capital:
Accounts Receivable (90) (4)
Changes in Receivables and Payables to Affiliates, net (325) 13
Inventories (22) (37)
Accounts Payable, Accrued Expenses and Other Current Liabilities 174 145
Other Current Assets (42) 17
- ---------------------------------------------------------------------------------------------------------------------
Net Cash Flows provided by Operating Activities 771 782
- ---------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures (715) (497)
Acquisition of Generating Plants (443) --
Proceeds from Nuclear Decommissioning Trust Funds 1,184 1,077
Investment in Nuclear Decommissioning Trust Funds (1,330) (1,128)
Note Receivable from Affiliate (42) --
Other Investing Activities 3 6
- ---------------------------------------------------------------------------------------------------------------------
Net Cash Flows used in Investing Activities (1,343) (542)
CASH FLOWS FROM FINANCING ACTIVITIES
Change in Note Payable, Affiliate 348 (696)
Contribution from Minority Interest in Consolidated Subsidiary 43 --
Issuance of Long-Term Debt 30 821
Retirement of Long-Term Debt (4) (3)
Distribution to Member (30) (156)
- ---------------------------------------------------------------------------------------------------------------------
Net Cash Flows provided by (used in) Financing Activities 387 (34)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (185) 206
- ---------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 224 4
- ---------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 39 $ 210
=====================================================================================================================
SUPPLEMENTAL CASH FLOW INFORMATION
Non-cash Investing and Financing Activities:
Contribution of Land from Minority Interest of Consolidated Subsidiary $ 12 --
See Notes to Consolidated Financial Statements
18
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
(in millions) 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 39 $ 224
Accounts Receivable, net
Customer 443 316
Other 63 150
Receivables from Affiliates 783 373
Inventories, at average cost
Fossil Fuel 101 105
Materials and Supplies 228 202
Deferred Income Taxes 7 --
Other 113 65
- ---------------------------------------------------------------------------------------------------------------------
Total Current Assets 1,777 1,435
- ---------------------------------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT, NET 2,796 2,003
DEFERRED DEBITS AND OTHER ASSETS
Nuclear Decommissioning Trust Funds 2,997 3,165
Investments 922 816
Note Receivable from Affiliate 246 291
Deferred Income Taxes 340 212
Other 202 223
- ---------------------------------------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 4,707 4,707
- ---------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS $ 9,280 $ 8,145
=====================================================================================================================
See Notes to Consolidated Financial Statements
19
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 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 892 585
Payables to Affiliates 33 34
Note Payable to Affiliate 348 --
Accrued Expenses 257 303
Deferred Income Taxes -- 7
Other 194 171
- ---------------------------------------------------------------------------------------------------------------------
Total Current Liabilities 1,730 1,104
- ---------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT 1,096 1,021
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred Income Taxes 247 --
Unamortized Investment Tax Credits 228 234
Nuclear Decommissioning Liability for Retired Plants 1,389 1,353
Pension Obligation 100 118
Non-Pension Postretirement Benefits Obligation 404 384
Spent Nuclear Fuel Obligation 854 843
Other 324 280
- ---------------------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 3,546 3,212
- ---------------------------------------------------------------------------------------------------------------------
MINORITY INTEREST OF CONSOLIDATED SUBSIDIARY 55 --
COMMITMENTS AND CONTINGENCIES
MEMBER'S EQUITY
Membership Interest 2,286 2,316
Undistributed Earnings 850 523
Accumulated Other Comprehensive Income (Loss) (283) (31)
- ---------------------------------------------------------------------------------------------------------------------
Total Member's Equity 2,853 2,808
- ---------------------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND MEMBER'S EQUITY $ 9,280 $ 8,145
=====================================================================================================================
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 September 30,
2002 and for the three and nine 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 sheets were
derived from audited financial statements but do not include all disclosures
required by generally accepted accounting principles (GAAP). Certain prior-year
amounts have been reclassified for comparative purposes. These reclassifications
had no effect on net income or shareholders' or member's equity. These notes
should be read in conjunction with the Notes to Consolidated Financial
Statements of Exelon, ComEd 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 No. 333-85496 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.
The consolidated financial statements contained herein include the
accounts of majority-owned subsidiaries after the elimination of intercompany
transactions. Investments and joint ventures in which a 20% to 50% interest is
owned and a significant influence is exerted are accounted for under the equity
method of accounting. The proportionate interests in jointly owned electric
utility plants are consolidated. Investments in which less than a 20% interest
is owned are accounted for under the cost method of accounting. Exelon owns 100%
of all significant consolidated subsidiaries, either directly or indirectly,
except for ComEd of which Exelon owns 99%, InfraSource of which Exelon owns 95%
and Southeast Chicago Energy Project, LLC of which Exelon owns 70% through
Generation. Exelon and Generation have reflected the third-party interests in
the above majority owned investments as minority interests in their Consolidated
Statements of Cash Flows, Consolidated Balance Sheets and in Other, Net on the
Consolidated Statements of Income and Comprehensive Income.
2. ADOPTION OF NEW ACCOUNTING PRINCIPLES (Exelon, ComEd, PECO and Generation)
SFAS No. 141 and SFAS No. 142
In 2001, the Financial Accounting Standards 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
21
pre-July 1, 2001 purchases be recognized as a change in accounting principle
concurrent with the adoption of SFAS No. 142, "Goodwill and Other Intangible
Assets" (SFAS No. 142). At December 31, 2001, AmerGen Energy Company, LLC
(AmerGen), an equity-method investee of Generation, had $43 million of negative
goodwill, net of accumulated amortization, recorded on its balance sheet. Upon
AmerGen's adoption of SFAS No. 141 in January 2002, Generation recognized its
proportionate share of income of $22 million ($13 million, net of income taxes)
as a cumulative effect of a change in accounting principle.
Exelon, ComEd, PECO and Generation adopted SFAS No. 142 as of January
1, 2002. SFAS No. 142 establishes new accounting and reporting standards for
goodwill and intangible assets. Other than goodwill, Exelon does not have
significant other intangible assets recorded on its consolidated balance sheets.
Under SFAS No. 142, goodwill is no longer subject to amortization, however,
goodwill is subject to an assessment for impairment using a two-step fair value
based test, the first step of which must be performed at least annually, or more
frequently if events or circumstances indicate that goodwill might be impaired.
The first step compares the fair value of a reporting unit to its carrying
amount, including goodwill. If the carrying amount of the reporting unit exceeds
its fair value, the second step is performed. The second step compares the
carrying amount of the goodwill to the fair value of the goodwill. If the fair
value of goodwill is less than the carrying amount, an impairment loss is
reported as a reduction to goodwill and a charge to operating expense, except at
the transition date, when the loss is reflected as a cumulative effect of a
change in accounting principle.
As of December 31, 2001, Exelon's Consolidated Balance Sheets reflected
approximately $5.3 billion in goodwill net of accumulated amortization,
including $4.9 billion of net goodwill related to the October 20, 2000 merger of
Unicom Corporation (Unicom), the former parent company of ComEd, and PECO
(Merger) recorded on ComEd's Consolidated Balance Sheets, with the remainder
related to acquisitions by Exelon Enterprises Company, LLC (Enterprises). The
first step of the transitional impairment analysis indicated that ComEd's
goodwill was not impaired but that an impairment did exist with respect to
goodwill recorded in Enterprises' reporting units. Exelon's infrastructure
services 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 investment. These cash flows were
discounted to 2002 using a risk-adjusted discount rate. The impairment was
recorded as a cumulative effect of a change in accounting principle in the first
quarter of 2002.
22
The changes in the carrying amount of goodwill by reportable segment
(see Note 6 for further discussion of reportable segments) for the nine months
ended September 30, 2002 are as follows:
Energy
Delivery Enterprises Total
- ---------------------------------------------------------------------------------------------------------------------
Balance as of January 1, 2002 $ 4,902 $ 433 $ 5,335
Impairment losses -- (357) (357)
Settlement of pre-Merger income tax contingencies (7) -- (7)
Merger severance adjustment (7) -- (7)
- ---------------------------------------------------------------------------------------------------------------------
Balance as of September 30, 2002 $ 4,888 $ 76 $ 4,964
=====================================================================================================================
The September 30, 2002, Energy Delivery goodwill relates to ComEd and
the remaining Enterprises goodwill relates to the InfraSource and Exelon
Services reporting units. Consistent with SFAS No. 142, the remaining goodwill
will be reviewed for impairment on an annual basis, or more frequently if
significant events occur that could indicate an impairment exists. ComEd and
Enterprises plan to perform an impairment review in the fourth quarter of 2002.
Such future review would be consistent with the review conducted related to the
implementation of SFAS No. 142 (implementation review), which required estimates
of numerous items with varying degrees of uncertainty, such as discount rates,
terminal value earnings multiples, future revenue levels and estimated future
expenditure levels for ComEd and Enterprises; load growth and the resolution of
future rate proceedings for ComEd; and customer base and construction back logs
for Enterprises. Significant changes from the assumptions used in the
implementation review could possibly result in a future impairment loss. The
Illinois legislation provides that reductions to ComEd's common equity resulting
from goodwill impairments will not impact ComEd's earnings through 2006 under
the earnings provisions of the legislation.
The components of the net transitional impairment loss recognized in
the first quarter of 2002 as a cumulative effect of a change in accounting
principle are as follows:
Exelon
- ---------------------------------------------------------------------------------------------------------------------
Enterprises goodwill impairment (net of income taxes of $103 million) $ (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 nine months ended
September 30, 2002 and 2001, respectively, adjusted to exclude 2001 amortization
expense related to goodwill that is no longer being amortized.
Exelon
Three Months Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
Reported income before cumulative effect
of changes in accounting principles $ 551 $ 376 $ 1,273 $ 1,078
Cumulative effect of changes in
accounting principles -- -- (230) 12
- ---------------------------------------------------------------------------------------------------------------------
Reported net income 551 376 1,043 1,090
Goodwill amortization -- 37 -- 114
- ---------------------------------------------------------------------------------------------------------------------
Adjusted net income $ 551 $ 413 $ 1,043 $ 1,204
- ---------------------------------------------------------------------------------------------------------------------
Basic earnings per common share:
Reported income before cumulative effect
of changes in accounting principles $ 1.71 $ 1.17 $ 3.95 $ 3.36
Cumulative effect of changes in
accounting principles -- -- (0.71) 0.04
- ---------------------------------------------------------------------------------------------------------------------
Reported net income 1.71 1.17 3.24 3.40
Goodwill amortization -- 0.12 -- 0.36
- ---------------------------------------------------------------------------------------------------------------------
Adjusted net income $ 1.71 $ 1.29 $ 3.24 $ 3.76
- ---------------------------------------------------------------------------------------------------------------------
Diluted earnings per common share:
Reported income before cumulative effect
of changes in accounting principles $ 1.70 $ 1.16 $ 3.93 $ 3.33
Cumulative effect of changes in
accounting principles -- -- (0.71) 0.04
- ---------------------------------------------------------------------------------------------------------------------
Reported net income 1.70 1.16 3.22 3.37
Goodwill amortization -- 0.11 -- 0.35
- ---------------------------------------------------------------------------------------------------------------------
Adjusted net income $ 1.70 $ 1.27 $ 3.22 $ 3.72
- ---------------------------------------------------------------------------------------------------------------------
ComEd
Three Months Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
Reported net income $ 215 $ 178 $ 576 $ 507
Goodwill amortization -- 32 -- 97
- ---------------------------------------------------------------------------------------------------------------------
Adjusted net income $ 215 $ 210 $ 576 $ 604
- ---------------------------------------------------------------------------------------------------------------------
Generation
The cessation of the amortization of negative goodwill of AmerGen on
January 1, 2002 did not have a material impact on Generation's reported net
income for the three or nine months ended September 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 to the net
basis of presentation required by EITF 02-3. For the three and nine months ended
September 30, 2001, $93 million and $123 million of purchased power expense,
respectively, and $7 million and $12 million of fuel expense, respectively, was
reclassified and reflected as a reduction to revenue. The three months ended
March 31, 2002 included $504 million of purchased power expense and $9 million
of fuel expense that has been reclassified and reflected as a reduction to
revenue in the nine months ended September 30, 2002.
SFAS No. 144
In September 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, ComEd, PECO or Generation's
reported financial positions, results of operations or cash flows.
SFAS No. 145
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB
Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical
Corrections" (SFAS No. 145). SFAS No. 145 eliminates SFAS No. 4 "Reporting Gains
and Losses from Extinguishment of Debt" (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 adoption of SFAS No. 145 had no effect on Exelon, ComEd, PECO
or Generation'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
25
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 purchased power agreement for TXU to purchase power
during the months of May through September from 2002 through 2006. During the
periods covered by the purchased power agreement, TXU will make fixed capacity
payments, variable expense payments, and will provide fuel to Exelon in return
for exclusive rights to the energy and capacity of the generation plants.
Substantially all of the purchase price has been allocated to property, plant
and equipment.
Sale of AT&T Wireless
On April 1, 2002, Enterprises sold its 49% interest in AT&T Wireless
PCS of Philadelphia, LLC to a subsidiary of AT&T Wireless Services for $285
million in cash. Enterprises recorded an after-tax gain of $116 million in
other, net on the $84 million investment, which had been reflected in Deferred
Debits and Other Assets on Exelon's Consolidated Balance Sheets.
Sithe New England Holdings Acquisition
On June 26, 2002, Generation agreed to purchase Sithe New England
Holdings, LLC (Sithe New England), a subsidiary of Sithe Energies Inc. (Sithe),
and related power marketing operations in exchange for a $543 million note. In
addition, Generation will assume various Sithe guarantees related to an equity
contribution agreement between Sithe New England and Sithe Boston Generation
(Boston Generation), a project subsidiary of Sithe New England. The equity
contribution agreement requires, among other things, that Sithe New England,
upon the occurrence of certain events, contribute up to $38 million of equity
for the purpose of completing the construction of two generating facilities.
Boston Generation established a $1.2 billion credit facility in order to finance
the construction of these two generating facilities. The approximately $1.1
billion expected to be outstanding under the facility at the transaction closing
date, will be reflected on Exelon's Consolidated Balance Sheet. Sithe New
England has provided security interests in and has pledged the stock of its
other project subsidiaries to Boston Generation. If the closing conditions are
satisfied, the transaction could be completed in November 2002.
The purchase involves approximately 4,471 megawatts (MWs) of generation
capacity, consisting of 1,670 MWs in operation and 2,421 MWs under construction,
which would increase Generation's net assets by approximately $1.6 billion.
Sithe New England's generation facilities are located primarily in
Massachusetts.
Generation is a 49.9% owner of Sithe and accounts for the investment as
an unconsolidated equity investment. The Sithe New England purchase would not
affect the accounting for Sithe as an equity investment. Separate from the Sithe
New England transaction, Generation is subject to a Put and Call Agreement (PCA)
that gives Generation the right to purchase (Call) the remaining 50.1% of Sithe,
and gives the other Sithe shareholders the right to sell (Put) their interest to
26
Generation. If the Put option is exercised, Generation has the obligation to
complete the purchase. The PCA provides that the Put and Call options become
exercisable as of December 18, 2002 and expire in December 2005. The Sithe New
England purchase is a separate transaction from the PCA in that it is intended
to enable Generation to acquire only the Sithe assets that fit Generation's
strategy, accelerate the realization of synergies, and reduce the amount of debt
needed to finance the transaction.
See ITEM 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations - Exelon Corporation - for further discussion of the
PCA.
4. REGULATORY ISSUES (Exelon, ComEd and PECO)
On June 1, 2001, ComEd filed with the Illinois Commerce Commission (ICC)
to establish delivery service charges for residential customers in preparation
for residential customer choice, which began in May 2002. The filing also
updated delivery service charges for non-residential customers.
On April 1, 2002, the ICC issued an interim order in ComEd's Delivery
Services Rate Case. The interim order is subject to an audit of test year (2000)
expenditures, including capital plant expenditures, with a final order to be
issued in 2003. The order sets delivery rates for residential customers choosing
a new retail electric supplier. The new rates became effective May 1, 2002 when
residential customers became eligible to choose their supplier of electricity.
Traditional bundled rates paid by customers that retain ComEd as their
electricity supplier are not affected by this order. Bundled rates will remain
frozen through 2006, as a result of the June 6, 2002 amendments to the Illinois
Restructuring Act that extended the freeze on bundled rates for an additional
two years. Delivery service rates for non-residential customers are not affected
by the order. The potential revenue impact of the interim order is not expected
to be material in 2002.
On October 10, 2002, ComEd received the audit report on the audit of
test year expenditures by the Liberty Consulting Group (Liberty), a consulting
firm engaged by the ICC in conjunction with the audit of test year expenditures.
Using the interim order as a starting point, Liberty recommends certain
additional disallowances to test year expenditures and rate base levels, which,
if ultimately approved by the ICC would result in lower residential delivery
service charges and higher non-residential delivery service charges. The ICC
will hold hearings on the Liberty audit report and responses from ComEd and
other parties. A final decision is expected in the middle of 2003.
ComEd intends to contest the Liberty audit findings in the reopened
hearings and cannot currently determine what portion, if any, of the Liberty
audit recommendations the ICC will accept. If the ICC ultimately determines that
all or some portion of ComEd's distribution plant is not recoverable through
rates, ComEd may be required to write-off some or all of the amount of its
investment that the ICC determines is not recoverable. The estimated potential
write-off, before income taxes, could be up to approximately $100 million if the
Liberty audit recommendations were to be accepted by the ICC in their entirety.
ComEd recorded a charge to earnings, before income taxes, of $12 million in the
third quarter of 2002, representing the estimated minimum probable write-off
exposure resulting from the audit findings.
27
As permitted by the Pennsylvania Electric Competition Act, the
Pennsylvania Department of Revenue calculated a 2002 Revenue Neutral
Reconciliation (RNR) adjustment to the gross receipts tax rate in order to
neutralize the impact of electric restructuring on its tax revenues. In January
2002, the 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 increases the gross receipts tax rate, which will increase PECO's
annual revenues and tax obligations by approximately $50 million in 2002. The
RNR adjustment was under appeal. The case was remanded to the PUC and in August
2002, the PUC ruled that PECO is properly authorized to recover these costs.
5. EARNINGS PER SHARE (Exelon)
Diluted earnings per share are calculated by dividing net income by the
weighted average number of shares of common stock outstanding, including shares
issuable upon exercise of stock options outstanding under Exelon's stock option
plans considered to be common stock equivalents. The following table shows the
effect of these stock options on the weighted average number of shares
outstanding used in calculating diluted earnings per share (in millions):
Three Months Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
Average common shares outstanding 323 321 322 320
Assumed exercise of stock options 1 2 2 3
- ---------------------------------------------------------------------------------------------------------------------
Average diluted common shares outstanding 324 323 324 323
=====================================================================================================================
Stock options not included in average common shares used in calculating
diluted earnings per share due to their antidilutive effect were five million
for the three and nine months ended September 30, 2002 and four million and one
million for the three and nine months ended September 30, 2001, respectively.
28
6. SEGMENT INFORMATION (Exelon, ComEd and PECO)
Exelon operates in three business segments: energy delivery, generation
and enterprises. Beginning in 2002, Exelon evaluates the performance of its
business segments on the basis of net income. ComEd and PECO operate in one
business segment, Energy Delivery. Exelon's segment information for the three
months and nine months ended September 30, 2002 as compared to the same periods
in 2001 and at September 30, 2002 and December 31, 2001 are as follows:
Three Months Ended September 30, 2002 as compared to Three Months Ended
September 30, 2001
Corporate and
Energy Intersegment
Delivery Generation Enterprises Eliminations Consolidated
- -------------------------------------------------------------------------------------------------------------------
Revenues(1):
2002 $ 3,162 $ 2,213 $ 509 $ (1,514) $ 4,370
2001 2,970 2,191 529 (1,505) 4,185
Intersegment Revenues:
2002 $ 29 $ 1,463 $ 22 $ (1,514) $ --
2001 17 1,404 84 (1,505) --
Operating Expenses(1):
2002 $ 2,350 $ 2,026 $ 494 $ (1,500) $ 3,370
2001 2,272 1,967 529 (1,495) 3,273
Net Income/(Loss)
2002 $ 370 $ 163 $ 15 $ 3 $ 551
2001 280 140 (33) (11) 376
- -------------------------------------------------------------------------------------------------------------------
29
Nine Months Ended September 30, 2002 as compared to Nine Months Ended September 30, 2001
Corporate and
Energy Intersegment
Delivery Generation Enterprises Eliminations Consolidated
- --------------------------------------------------------------------------------------------------------------------
Revenues(2):
2002 $ 7,973 $ 5,233 $ 1,475 $(3,436) $ 11,245
2001 7,903 5,403 1,742 (3,423) 11,625
Intersegment Revenues:
2002 $ 59 $ 3,309 $ 72 $(3,440) $ --
2001 78 3,223 124 (3,425) --
Operating Expenses(2):
2002 $ 5,865 $ 4,844 $ 1,510 $ (3,391) $ 8,828
2001 5,833 4,798 1,794 (3,393) 9,032
Net Income/(Loss):
2002 $ 908 $ 326 $(174) $ (17) $1,043
2001 810 381 (63) (38) 1,090
- --------------------------------------------------------------------------------------------------------------------
Total Assets:
September 30, 2002 $ 26,584 $9,280 $1,310 $(1,938) $ 35,236
December 31, 2001 26,365 8,145 1,790 (1,483) 34,817
- --------------------------------------------------------------------------------------------------------------------
<FN>
(1) $59 million and $58 million in utility taxes are included in the Revenues
and Expenses for the three months ended September 30, 2002 and 2001,
respectively, for ComEd. $64 million and $50 million in utility taxes are
included in the Revenues and Expenses for the three months ended September
30, 2002 and 2001, respectively, for PECO.
(2) $157 million and $156 million in utility taxes are included in the Revenues
and Expenses for the nine months ended September 30, 2002 and 2001,
respectively, for ComEd. $157 million and $103 million in utility taxes are
included in the Revenues and Expenses for the nine months ended September
30, 2002 and 2001, respectively, for PECO.
</FN>
7. FAIR VALUE OF FINANCIAL ASSETS AND LIABILITIES (Exelon, ComEd, PECO and
Generation)
During the three and nine months ended September 30, 2002 and 2001,
Exelon recorded pre-tax gains and losses in other comprehensive income relating
to mark-to-market (MTM) adjustments of contracts designated as cash flow hedges
as follows:
ComEd PECO Generation Enterprises Exelon
- ---------------------------------------------------------------------------------------------------------------------
Three months ended September 30, 2002 $ (36) $ -- $ (24) $ 4 $ (56)
Three months ended September 30, 2001 -- (12) 84 9 81
Nine months ended September 30, 2002 (42) (1) (132) 19 (156)
Nine months ended September 30, 2001 -- (4) (23) 11 (16)
- ---------------------------------------------------------------------------------------------------------------------
During the three months ended September 30, 2002 and 2001, and the nine
months ended September 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 September 30, $ 1 $ 7
Nine months ended September 30, 11 29
- ---------------------------------------------------------------------------------------------------------------------
30
During the three months ended September 30, 2002 and 2001, and the nine
months ended September 30, 2002 and 2001, Generation recognized net MTM gains
and losses on energy trading contracts, in earnings as follows:
2002 2001
- ---------------------------------------------------------------------------------------------------------------------
Three months ended September 30, $ -- $ 4
Nine months ended September 30, (13) (2)
- ---------------------------------------------------------------------------------------------------------------------
During the three months ended September 30, 2002 and 2001 and the nine
months ended September 30, 2002 and 2001, 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 September 30, $ -- $ --
Nine months ended September 30, -- 6
- ---------------------------------------------------------------------------------------------------------------------
As of September 30, 2002, deferred net gains/(losses) 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
- ---------------------------------------------------------------------------------------------------------------------
Net Gains (Losses) Expected to be Reclassified $ (1) $ 15 $ (48) $ 5 $ (29)
- ---------------------------------------------------------------------------------------------------------------------
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.
During the three months ended September 30, 2002 and 2001 and the nine
months ended September 30, 2002 and 2001, Generation did not reclassify any
amounts from accumulated other comprehensive income into earnings as a result of
forecasted energy commodity transactions no longer being probable.
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.
31
September 30, 2002
-------------------------------------------------------------------------
Gross Gross
Amortized Unrealized Unrealized Estimated
Cost Gains Losses Fair Value
- ---------------------------------------------------------------------------------------------------------------------
Equity securities $ 1,754 $ 59 $ (557) $ 1,256
Debt securities
Government obligations 989 73 -- 1,062
Other debt securities 674 33 (28) 679
- ---------------------------------------------------------------------------------------------------------------------
Total debt securities 1,663 106 (28) 1,741
- ---------------------------------------------------------------------------------------------------------------------
Total available-for-sale securities $ 3,417 $ 165 $ (585) $ 2,997
=====================================================================================================================
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 September 30, 2002, proceeds from the sale
of decommissioning trust investments and gross realized gains and losses on
those sales were $295 million, $12 million and $21 million, respectively. For
the nine months ended September 30, 2002, proceeds from the sale of
decommissioning trust investments and gross realized gains and losses on those
sales were $1,184 million, $43 million and $77 million, respectively.
For the nine months ended September 30, 2002, net realized losses of $2
million were recognized in Accumulated Depreciation in Generation's Consolidated
Balance Sheets and $32 million of net realized losses were recognized in Other
Income and Deductions in Generation's Consolidated Statements of Income and
Comprehensive Income. The available-for-sale securities held at September 30,
2002 have an average maturity of eight to ten years. The cost of these
securities was determined on the basis of specific identification.
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.
Environmental Liabilities
Exelon has identified 71 sites where former manufactured gas plant
(MGP) activities have or may have resulted in actual site contamination. As of
September 30, 2002, Exelon had accrued $150 million for environmental
investigation and remediation costs that currently can be reasonably estimated,
including $127 million for MGP investigation and remediation.
As of September 30, 2002, ComEd had accrued $107 million (discounted)
for environmental investigation and remediation costs that currently can be
reasonably estimated. This reserve included $103 million for MGP investigation
and remediation. The MGP reserve was increased by $17 million in the third
quarter of 2002 as the result of a delay in implementing the ongoing remediation
for a MGP site in Oak Park, Illinois.
As of September 30, 2002, PECO had accrued $34 million (undiscounted)
for environmental investigation and remediation costs that currently can be
reasonably estimated, including $24 million for MGP investigation and
remediation.
32
As of September 30, 2002, Generation had accrued $9 million
(undiscounted) for environmental investigation and remediation cost, none of
which relates to MGP investigation and remediation.
Exelon, ComEd, PECO and Generation cannot predict the extent to which
they will incur other significant liabilities for additional investigation and
remediation costs at these or additional sites identified by environmental
agencies or others, or whether such costs may be recoverable from third parties.
Energy Commitments
Exelon and Generation had long-term commitments relating to the net
purchase and sale of energy, capacity and transmission rights from unaffiliated
utilities, including Midwest Generation LLC (Midwest Generation), and others,
including AmerGen, as expressed in the following table:
Net Capacity Power Only Power Only Purchases from Transmission Rights
Purchases (1) Sales AmerGen Non-Affiliates Purchases (2)
- ---------------------------------------------------------------------------------------------------------------------
2002 $ 191 $ 850 $ 47 $ 796 $ 32
2003 597 1,954 261 1,467 75
2004 642 944 315 744 93
2005 357 231 489 212 84
2006 329 92 494 177 3
Thereafter 4,150 22 2,003 901 --
- ---------------------------------------------------------------------------------------------------------------------
Total $ 6,266 $ 4,093 $ 3,609 $ 4,297 $ 287
- ---------------------------------------------------------------------------------------------------------------------
<FN>
(1) Net Capacity Purchases includes Midwest Generation commitments as of
October 2, 2002. On October 2, 2002, Generation notified Midwest Generation
of its exercise of termination options under the existing Collins
Generating Station (Collins) and Peaking Unit (Peaking) Purchase Power
Agreements. Generation exercised its termination options on 1,727 MWs in
2003 and 2004. In 2003, Generation will take 1,778 MWs of option capacity
under the Collins and Peaking Unit Agreements as well as 1,265 MWs of
option capacity under the Coal Generation Purchase Power Agreement. Net
capacity purchases in 2004 include 3,474 MWs of optional capacity from
Midwest Generation. Net Capacity Purchases also include capacity sales to
TXU under the purchase power 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.
(2) Transmission Rights Purchases include estimated commitments in 2004 and
2005 for additional transmission rights that will be required to fulfill
firm sales contracts.
</FN>
Additionally, Generation has the following commitments.
In connection with the 2001 corporate restructuring, ComEd entered into
a purchase power agreement (PPA) with Generation under which Generation has
agreed to supply all of ComEd's load requirements through 2004. Prices for this
energy vary depending upon the time of day and month of delivery. During 2005
and 2006, ComEd's PPA is a partial requirements agreement under which ComEd will
purchase all of its required energy and capacity from Generation, up to the
available capacity of the nuclear generating plants formerly owned by ComEd and
transferred to Generation. Under the terms of the PPA, Generation is responsible
for obtaining any required transmission service. The PPA also specifies that
prior to 2005, ComEd and Generation will jointly determine and agree on a
market-based price for energy delivered under the PPA for 2005 and 2006. In the
event that the parties cannot agree to market-based prices for 2005 and 2006
prior to July 1, 2004, ComEd has the option of terminating the PPA effective
December 31, 2004. ComEd will obtain any additional supply required from market
33
sources in 2005 and 2006, and subsequent to 2006, will obtain all of its supply
from market sources, which could include Generation.
In connection with the 2001 corporate restructuring, PECO entered into
a PPA with Generation under which 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.
Under terms of the 2001 corporate restructuring, ComEd remits to
Generation any amounts collected from customers for nuclear decommissioning.
Under an agreement effective September 2001, PECO remits to Generation any
amounts collected from customers for nuclear decommissioning.
Litigation
Exelon
Securities Litigation. Between May 8 and June 14, 2002, several class
action lawsuits were filed in the Federal District Court in Chicago asserting
nearly identical securities law claims on behalf of purchasers of Exelon
securities between April 24, 2001 and September 27, 2001 (Class Period). The
complaints allege that Exelon violated Federal securities laws by issuing a
series of materially false and misleading statements relating to its 2001
earnings expectations during the Class Period. The court consolidated the
pending cases into one lawsuit and has appointed two lead plaintiffs as well as
lead counsel.
On October 1, 2002, the plaintiffs filed a consolidated amended
complaint. In addition to the original claims, this complaint contains
allegations of new facts and contains several new theories of liability. Exelon
believes the lawsuit is without merit and is vigorously contesting this matter.
ComEd
Chicago Franchise. In March 1999, ComEd reached a settlement agreement
with the City of Chicago (Chicago) to end the arbitration proceeding between
ComEd and Chicago regarding their January 1, 1992 franchise agreement. As part
of the settlement agreement, ComEd and Chicago agreed to a revised combination
of ongoing work under the franchise agreement and new initiatives that will
result in defined transmission and distribution expenditures by ComEd to improve
electric services in Chicago. The settlement agreement provides that ComEd would
be subject to liquidated damages if the projects are not completed by various
dates, unless it was prevented from doing so by events beyond its reasonable
control. In addition, ComEd and Chicago established an Energy Reliability and
Capacity Account, into which ComEd paid $25 million during each of the years
1999 through 2001 and has conditionally agreed to pay $25 million at the end of
2002, to help ensure an adequate and reliable electric supply for Chicago.
FERC Municipal Request for Refund. Three of ComEd's wholesale municipal
customers filed a complaint and request for refund with FERC, alleging that
ComEd failed to properly adjust its rates, as provided for under the terms of
the electric service contracts with the municipal customers and to track certain
refunds made to ComEd's retail customers in the years 1992 through 1994. In the
34
third quarter of 1998, FERC granted the complaint and directed that refunds be
made, with interest. ComEd filed a request for rehearing. On April 30, 2001,
FERC issued an order granting rehearing in which it determined that its 1998
order had been erroneous and that no refunds were due from ComEd to the
municipal customers. On June 29, 2001, FERC denied the customers' requests for
rehearing of the order granting rehearing. In August 2001, each of the three
wholesale municipal customers appealed the April 30, 2001 FERC order to the
Federal circuit court, which consolidated the appeals for the purposes of
briefing and decision.
Retail Rate Law. In 1996, several developers of non-utility generating
facilities filed litigation against various Illinois officials claiming that the
enforcement against those facilities of an amendment to Illinois law removing
the entitlement of those facilities to state-subsidized payments for electricity
sold to ComEd after March 15, 1996 violated their rights under the Federal and
state constitutions. The developers also filed suit against ComEd for a
declaratory judgment that their rights under their contracts with ComEd were not
affected by the amendment. On August 4, 1999, 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. ComEd
is contesting each case.
Service Interruptions. In August 1999, three class action lawsuits were
filed against ComEd, and subsequently consolidated, in the Circuit Court of Cook
County, Illinois seeking damages for personal injuries, property damage and
economic losses related to a series of service interruptions that occurred in
the summer of 1999. The combined effect of these interruptions resulted in over
168,000 customers losing service for more than four hours. Conditional class
certification was approved by the court for the sole purpose of exploring
settlement. ComEd filed a motion to dismiss the complaints. On April 24, 2001,
the court dismissed four of the five counts of the consolidated complaint
without prejudice and the sole remaining count was dismissed in part. On June 1,
2001, the plaintiffs filed a second amended consolidated complaint and ComEd has
filed an answer. A portion of any settlement or verdict may be covered by
insurance.
Enron. As a result of Enron Corp.'s bankruptcy proceeding, ComEd has
potential monetary exposure for 366 of its customer accounts that were served by
Enron Energy Services (EES) as a billing agent. EES has rejected its contracts
with these accounts, with the exception of approximately 100 accounts for which
EES retains its billing agency. ComEd is working to ensure that customers know
what amounts are owed to ComEd on accounts for which EES has been removed as
billing agent, and has obtained updated billing addresses for these accounts.
With regard to the accounts for which EES retains its billing agency, ComEd's
total amount outstanding is not material. Because that amount is owed to ComEd
by individual customers, it is not part of the bankrupt Enron's estate. The ICC
has rescinded EES's authority to act as an alternative retail energy supplier in
Illinois. However, EES never served as a supplier, as opposed to a billing
agent, to any of ComEd's retail accounts.
35
Generation
Godley Park District Litigation. On April 18, 2001, the Godley Park
District filed suit in Will County Circuit Court against ComEd and Generation
alleging that oil spills at Braidwood Station have contaminated the Park
District's water supply. The complaint sought actual damages, punitive damages
of $100 million and statutory penalties. The court dismissed all counts seeking
punitive damages and statutory penalties, and the plaintiff has filed an amended
complaint before the court. The amended complaint added counts under the
Illinois Public Utility Act (PUA), which provides for statutory penalties and
allows recovery of attorney's fees. On April 20, 2002, the Court denied ComEd
and Generation's motion to dismiss the additional counts under the PUA. ComEd
and Generation are contesting the liability and damages sought by the plaintiff.
As a result of the 2001 corporate restructuring, Generation has responsibility
for this matter.
Cotter Corporation Litigation. During 1989 and 1991, actions were
brought in Federal and state courts in Colorado against ComEd and its
subsidiary, Cotter Corporation (Cotter), seeking unspecified damages and
injunctive relief based on allegations that Cotter permitted radioactive and
other hazardous material to be released from its mill into areas owned or
occupied by the plaintiffs, resulting in property damage and potential adverse
health effects. In 1994, a Federal jury returned nominal dollar verdicts against
Cotter on eight plaintiffs' claims in the 1989 cases, which verdicts were upheld
on appeal. The remaining claims in the 1989 actions were settled or dismissed.
In 1998, a jury verdict was rendered against Cotter in favor of 14 of the
plaintiffs in the 1991 cases, totaling approximately $6 million in compensatory
and punitive damages, interest and medical monitoring. On appeal, the Tenth
Circuit Court of Appeals reversed the jury verdict, and remanded the case for
new trial. These plaintiffs' cases were consolidated with the remaining 26
plaintiffs' cases, which had not been tried. The consolidated trial was
completed on June 28, 2001. The jury returned a verdict against Cotter and
awarded $16.3 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 is vigorously contesting the award.
In November 2000, another trial involving a separate sub-group of 13
plaintiffs, seeking $19 million in damages plus interest was completed in
Federal District Court in Denver. The jury awarded nominal damages of $42,500 to
11 of 13 plaintiffs, but awarded no damages for any personal injury or health
claims, other than requiring Cotter to perform periodic medical monitoring at
minimal cost. Cotter and the plaintiffs both appealed the 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.
36
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 million to $15 million. Once
a final feasibility study is complete and a remedy selected, it is expected that
the PRPs will agree on an allocation of responsibility for the costs. Until an
agreement is reached, Generation 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 their respective financial condition or results of operations.
Credit Contingencies
Generation
Generation is a counterparty to Dynegy Inc. (Dynegy) in various energy
transactions. In early July 2002, the credit ratings of Dynegy were downgraded
by two credit rating agencies to below investment grade. As of September 30,
2002, Generation had a net receivable from Dynegy of approximately $7 million,
and consistent with the terms of the existing credit arrangement, has received
collateral in support of this receivable. Generation also has credit risk
associated with Dynegy through Generation's equity investment in Sithe. Sithe is
a 60% owner of the Independence generating station, a 1,040 MW gas-fired
qualified facility that has an energy only long-term tolling arrangement with
Dynegy, with a related financial swap arrangement. As of September 30, 2002,
Sithe had recognized an asset on its balance sheet related to the fair value of
the financial swap agreement with Dynegy that is marked-to-market under the
terms of SFAS No. 133. If Dynegy is unable to fulfill the terms of this
agreement, Sithe would be required to write-off the fair value asset, which
Generation estimates would result in an approximate $22 million reduction in its
equity earnings from Sithe, based on Generation's current 49.9% investment
ownership in Sithe. Additionally, the future economic value of Sithe's
investment in the Independence Station and AmerGen's purchased power arrangement
with Illinois Power, a subsidiary of Dynegy, could be impacted by events related
to Dynegy's financial condition.
37
9. MERGER-RELATED COSTS (Exelon, ComEd, PECO and Generation)
In association with the Merger, Exelon recorded certain reserves for
restructuring costs. The reserves associated with PECO were charged to expense
pursuant to EITF Issue 94-3 "Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity (including Certain
Costs Incurred in a Restructuring)"; while the reserves associated with Unicom
were recorded as part of the application of purchase accounting and did not
affect results of operations, consistent with EITF Issue 95-3, "Recognition of
Liabilities in Connection with a Purchase Business Combination."
Exelon, PECO and Generation
Merger costs charged to expense. PECO's merger-related costs charged to
expense in 2000 were $248 million, consisting of $116 million for PECO employee
costs and $132 million of direct incremental costs incurred by PECO in
conjunction with the merger transaction. Direct incremental costs represent
expenses directly associated with completing the Merger, including professional
fees, regulatory approval and settlement costs, and settlement of compensation
arrangements. Employee costs represent estimated severance costs and pension and
postretirement benefits provided under Exelon's merger separation plans for
eligible employees who are expected to be involuntarily terminated before
December 2002 due to integration activities of the merged companies. Additional
employee severance costs of $48 million, primarily related to PECO employees,
were charged to operating and maintenance expense in 2001, and a $10 million
reduction in the estimated liability related to Generation employees was
recorded in operating and maintenance expense in the first quarter of 2002.
Employee costs are being paid from the Exelon's pension and post-retirement
benefit plans, except for certain benefits such as outplacement services,
continuation of health care coverage and educational benefits. As of September
30, 2002 a liability of $7 million is reflected on Exelon's balance sheet for
payment of these benefits, of which $2 million is reflected on PECO's balance
sheet and $3 million is reflected on Generation's balance sheet.
A total of 960 PECO positions are expected to be eliminated as a result
of the merger, 274 of which related to generation, 230 of which related to PECO
energy delivery and the remainder from the enterprises and corporate support
areas of the company. As of September 30, 2002, 788 of the positions had been
eliminated, of which 162 related to PECO energy delivery, and 181 related to
generation and the remainder to enterprises and corporate support. The remaining
positions are expected to be eliminated in the fourth quarter of 2002.
Additionally, in the third quarter of 2000, approximately $20 million
of closing costs and $8 million of stock compensation costs associated with
Unicom were charged to expense.
Exelon, ComEd and Generation
Merger Costs Included in Purchase Price Allocation. The purchase price
allocation as of December 31, 2000 included a liability of $307 million for
Unicom employee costs and liabilities of approximately $39 million for estimated
costs of exiting various business activities of former Unicom activities that
were not compatible with the strategic business direction of Exelon.
38
During 2001, Exelon, ComEd and Generation finalized plans for
consolidation of functions, including negotiation of an agreement with the
International Brotherhood of Electrical Workers Local 15 regarding severance
benefits to union employees. Also, in January of 2001, ComEd transferred a
portion of its employee related liabilities to Generation, Enterprises and
Business Services Company (BSC) as part of the corporate restructuring. In the
third quarter of 2002, Exelon reduced its reserve by $12 million due to the
elimination of identified positions through normal attrition, which did not
require payments under Exelon's merger separation plans, and a determination
that certain positions would not be eliminated by the end of 2002 as originally
planned due to a change in certain business plans. The reduction in the reserve
was recorded as a purchase price adjustment to goodwill. In 2001 and through
September 30, 2002, Exelon, ComEd and Generation recorded adjustments to the
purchase price allocation as follows:
Exelon
Original Adjustments Adjusted
Estimate 2001 2002 Liabilities
- -----------------------------------------------------------------------------------------------------------------------
Employee severance payments $ 128 $ 33 $ (10) $ 151 (a)
Other benefits 21 9 (2) 28 (a)
- -----------------------------------------------------------------------------------------------------------------------
Employee severance payments and other benefits 149 42 (12) 179
Actuarially determined pension and postretirement costs 158 (11) -- 147 (b)
- -----------------------------------------------------------------------------------------------------------------------
Total Unicom employee cost $ 307 $ 31 $ (12) $ 326
=======================================================================================================================
<FN>
(a) The increase is a result of the identification in 2001 of additional
positions to be eliminated, partially offset by the 2002 elimination of
identified positions through normal attrition and changes in certain
business plans.
(b) The reduction results from lower estimated pension and post retirement
welfare benefits reflecting revised actuarial estimates.
</FN>
The following table provides a reconciliation of the reserve for
employee severance and other benefits associated with the Merger:
- ---------------------------------------------------------------------------------------------------------------------
Adjusted employee severance and other benefits reserve $ 179
Payments to employees (October 2000-June 2002) (125)
Payments to employees (July 2002-September 2002) (10)
- ---------------------------------------------------------------------------------------------------------------------
Employee severance and other benefits reserve as of September 30, 2002 $ 44
=====================================================================================================================
ComEd
Original Adjustments Adjusted
Estimate Transfer 2001 2002 Liabilities
- ------------------------------------------------------------------------------------------------------------------------
Employee severance payments $ 128 $ (68) $ 17 $ (7) $ 70 (a)
Other benefits 21 (14) 8 (2) 13 (a)
- ------------------------------------------------------------------------------------------------------------------------
Employee severance payments
and other benefits 149 (82) 25 (9) 83
Actuarially determined pension
and postretirement costs 158 (82) 10 -- 86 (b)
- ------------------------------------------------------------------------------------------------------------------------
Unicom employee cost - ComEd $ 307 $ (164) $ 35 $ (9) $ 169
========================================================================================================================
<FN>
(a) The increase is a result of the identification in 2001 of additional
positions to be eliminated, partially offset by the 2002 elimination of
identified positions through normal attrition and changes in certain
business plans.
(b) The reduction results from lower estimated pension and post retirement
welfare benefits reflecting revised actuarial estimates.
</FN>
39
The following table provides a reconciliation of ComEd's reserve for
employee severance and other benefits associated with the Merger:
- ---------------------------------------------------------------------------------------------------------------------
Adjusted employee severance and other benefits reserve $ 83
Payments to employees (October 2000-June 2002) (54)
Payments to employees (July 2002-September 2002) (5)
- ---------------------------------------------------------------------------------------------------------------------
Employee severance and other benefits reserve as of September 30, 2002 $ 24
=====================================================================================================================
Generation
Original Adjustments Adjusted
Estimate 2001 2002 Liabilities
- ------------------------------------------------------------------------------------------------------------------------
Employee severance payments $ 45 $ (12) $ (2) $ 31 (a)
Other benefits 5 2 -- 7 (a)
- ------------------------------------------------------------------------------------------------------------------------
Employee severance payments and other benefits 50 (10) (2) 38
Actuarially determined pension and postretirement costs 71 (25) -- 46 (b)
- ------------------------------------------------------------------------------------------------------------------------
Unicom employee cost - Generation $ 121 $ (35) $ (2) $ 84
========================================================================================================================
<FN>
(a) The increase is a result of the identification in 2001 of additional
positions to be eliminated, partially offset by the 2002 elimination of
identified positions through normal attrition and changes in certain
business plans.
(b) The reduction results from lower estimated pension and post retirement
welfare benefits reflecting revised actuarial estimates.
</FN>
The following table provides a reconciliation of the reserve for
employee severance and other benefits associated with the Merger:
- ---------------------------------------------------------------------------------------------------------------------
Adjusted employee severance and other benefits reserve $ 38
Payments to employees (October 2000-June 2002) (26)
Payments to employees (July 2002-September 2002) (3)
- ---------------------------------------------------------------------------------------------------------------------
Employee severance and other benefits reserve as of September 30, 2002 $ 9
=====================================================================================================================
Exelon, ComEd and Generation
The following table provides the status of the former Unicom positions
identified to be eliminated as a result of the Merger:
Corporate
& Other ComEd Generation Total
- ---------------------------------------------------------------------------------------------------------------------
Estimate at October 20, 2000 180 1,022 1,073 2,275
2001 adjustments (a) 109 206 (197) 118
Total estimated positions to be eliminated 289 1,228 876 2,393
Terminated employees (October 2000-June 2002) (241) (648) (699) (1,588)
Terminated employees (July 2002-September 2002) (9) (49) (13) (71)
Normal attrition (9) (148) (75) (232)
Business plan changes (b) (2) (99) (49) (150)
- ---------------------------------------------------------------------------------------------------------------------
Remaining positions to be eliminated by the end of 2002 28 284 40 352
=====================================================================================================================
<FN>
(a) The increase is a result of the identification of additional positions to
be eliminated in 2001.
(b) The reduction is due to a determination in the third quarter of 2002, that
certain positions would not be eliminated by the end of 2002 as originally
planned due to a change in certain business plans.
</FN>
40
10. LONG-TERM DEBT (Exelon, ComEd and PECO) ComEd
On September 30, 2002, ComEd paid on maturity $200 million of variable
rate senior notes due September 30, 2002.
On September 16, 2002, ComEd paid on maturity $200 million of 7.375%
First Mortgage Bonds, Series 85, due September 15, 2002. On September 16, 2002,
ComEd also redeemed $200 million of 8.375% First Mortgage Bonds, Series 86, at a
redemption price of 103.425% of the principal amount. These bonds had a maturity
date of September 15, 2022.
On June 13, 2002, ComEd issued $200 million of 6.15% First Mortgage
Bonds, Series 98, due March 15, 2012. The $200 million bond issuance was a
refinancing of the $200 million of 8.5% First Mortgage Bonds, Series 84 redeemed
on July 15, 2002 at a redemption price of 103.915% of the principal amount.
These redeemed bonds had a maturity date of July 15, 2022.
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 pre-tax loss recorded in other
comprehensive income, which is being amortized over the expected remaining life
of the related debt.
On June 4, 2002, ComEd issued $100 million of Illinois Development
Finance Authority floating-rate Pollution Control Revenue Refunding Bonds,
Series 2002 due April 15, 2013. The $100 million bond issuance was used to
redeem $100 million of 7.25% Illinois Development Finance Authority Pollution
Control Revenue Refunding Bonds, Series 1991. These redeemed bonds had a
maturity date of June 1, 2011.
On March 21, 2002, ComEd redeemed $200 million of 8.625% First Mortgage
Bonds, Series 81, at a redemption price of 103.84% of the principal amount.
These bonds had a maturity date of February 1, 2022.
On March 13, 2002, ComEd issued $400 million of 6.15% First Mortgage
Bonds, Series 98, due March 15, 2012. This $400 million bond issuance refinanced
other First Mortgage Bonds. In connection with the bond issuance, ComEd settled
forward starting interest rate swaps in the aggregate notional amount of $375
million, resulting in a $9 million pre-tax loss recorded in other comprehensive
income, which is being amortized over the expected remaining life of the related
debt.
During the nine months ended September 30, 2002, ComEd recorded
prepayment premiums of $24 million and net unamortized premiums, discounts and
debt issuance expenses of $3 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.
PECO
On September 23, 2002, PECO issued $225 million of 4.75% First and
Refunding Mortgage Bonds, due October 1, 2012. This bond issuance repaid
commercial paper that was used to pay at maturity $222 million of First and
Refunding Mortgage Bonds with a weighted average interest rate of 7.30%. In
41
connection with the issuance of the First and Refunding Mortgage Bonds, PECO
settled forward starting interest rate swaps in the aggregate notional amount of
$200 million resulting in a $5 million pre-tax loss recorded in other
comprehensive income, which is being amortized over the expected remaining life
of the related debt.
11. SALE OF ACCOUNTS RECEIVABLE (Exelon and PECO)
PECO is party to an agreement, which expires in November 2005, with a
financial institution under which it can sell or finance with limited recourse
an undivided interest, adjusted daily, in up to $225 million of designated
accounts receivable. As of September 30, 2002, PECO had sold a $225 million
interest in accounts receivable, consisting of a $164 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 $61 million
interest in special-agreement accounts receivable which were accounted for as a
long-term note payable. PECO retains the servicing responsibility for these
receivables. The agreement requires PECO to maintain the $225 million interest,
which, if not met, requires cash, which would otherwise be received by PECO
under this program, to be held in escrow until the requirement is met. At
September 30, 2002, PECO met this requirement.
12. RELATED-PARTY TRANSACTIONS (Exelon, ComEd, PECO and Generation) Exelon and
Generation
Exelon and Generation's financial statements reflect related-party
transactions with unconsolidated affiliates as reflected in the tables below.
Three Months Nine Months
Ended September 30, Ended September 30,
2002 2001 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
Purchased Power from AmerGen (1) $ 104 $ 26 $ 220 $ 48
Interest Income from AmerGen (2) 1 -- 2 --
Services Provided to AmerGen (3) 16 18 46 50
Services Provided to Sithe (4) -- -- 1 --
Services Provided by Sithe (5) 3 -- 5 --
- ---------------------------------------------------------------------------------------------------------------------
42
September 30, 2002 December 31, 2001
- ---------------------------------------------------------------------------------------------------------------------
Net Receivable from AmerGen (1,2,3) $ 42 $ 44
Net Payable to Sithe (4,5) 3 --
- ---------------------------------------------------------------------------------------------------------------------
<FN>
(1) Generation has entered into PPAs dated December 18, 2001 and November 22,
1999 with AmerGen. Under the 2001 PPA, Generation has agreed to purchase
from AmerGen all the energy from Unit No. 1 at Three Mile Island Nuclear
Station from January 1, 2002 through December 31, 2014. Under the 1999
PPA, Generation has agreed to purchase from AmerGen all of the residual
energy from Clinton Nuclear Power Station (Clinton), through December 31,
2002. Currently, the residual output approximates 29% of the total output
of Clinton. In accordance with the terms of the AmerGen partnership
agreement, the 1999 PPA will be extended through the end of the AmerGen
partnership agreement.
(2) In February 2002, Generation entered into an agreement to loan AmerGen up
to $75 million at an interest rate equal to the 1-month London Interbank
Offering Rate plus 2.25%. In July 2002, the limit of the loan agreement
was increased to $100 million and the maturity date was extended to July
1, 2003. As of September 30 2002, the outstanding principal balance of
the loan was $42 million.
(3) Under a service agreement dated March 1, 1999, Generation provides
AmerGen with certain operation and support services to the nuclear
facilities owned by AmerGen. This service agreement has an indefinite
term and may be terminated by Generation or AmerGen on 90 days notice.
Generation is compensated for these services in an amount agreed to in
the work order, which is not less than the higher of its fully allocated
cost for performing each service or the market price for such service.
(4) Under a service agreement dated December 18, 2000, Generation provides
certain engineering and environmental services for fossil fuels
facilities owned by Sithe and for certain developmental projects.
Generation is compensated for these services in the amount agreed to in
the work order, but not less than the higher of fully allocated costs for
performing such services or the market price.
(5) Under a service agreement dated December 18, 2000, Sithe provides
Generation certain fuel and project development services. Sithe is
compensated for these services in the amount agreed to in the work order,
but not less than the higher of fully allocated costs for performing such
services or the market price.
</FN>
Generation's additional related-party transactions are discussed in the
"Generation" section of this note.
43
ComEd
ComEd's financial statements reflect related-party transactions as
reflected in the tables below.
Three Months Nine Months
Ended September 30, Ended September 30,
2002 2001 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
Operating Revenues from Affiliates
Generation (1) $ 22 $ 9 $ 41 $ 30
Enterprises (1) 4 5 8 39
Purchased Power from Affiliate
PPA with Generation (2) 967 948 2,046 2,141
O&M from Affiliates
BSC (3) 29 32 94 90
Exelon Services (4) 3 4 9 16
InfraSource (7) 1 -- 1 --
Interest Income from Affiliates
UII (5) 8 14 23 51
PECO (6) -- -- -- 8
Generation (8) -- 9 -- 9
Other -- 1 -- 2
Interest Expense from Affiliate
Generation (12) -- 10 -- 10
Capitalized costs
BSC (3) 3 1 6 6
InfraSource (7) 3 3 16 21
Cash Dividends Paid to Parent 118 105 353 253
- ---------------------------------------------------------------------------------------------------------------------
44
September 30,2002 December 31, 2001
- ---------------------------------------------------------------------------------------------------------------------
Receivables from Affiliates
UII (5) $ 8 $ --
BSC (3,8) -- 6
Notes Receivable from Affiliates
UII (5) 1,284 1,297
Other 16 17
Payables to Affiliates
Generation Decommissioning (9) 59 59
Generation (1,2,8) 544 136
BSC (3,8) 12 --
Exelon Corporate (11) -- 13
Other -- 10
Deferred Credits and Other Liabilities
Generation Decommissioning obligation (9) 244 291
Other 7 6
Shareholders' Equity - Receivable from Parent (10) 845 937
- ---------------------------------------------------------------------------------------------------------------------
<FN>
(1) ComEd provides electric, transmission, and other ancillary services to
Generation and Enterprises.
(2) Effective January 1, 2001, ComEd entered into a PPA with Generation. See
Note 8 of Combined Notes to Consolidated Financial Statements for further
information regarding the PPA. The Generation payable primarily consists
of services related to the PPA.
(3) ComEd receives a variety of corporate support services from Exelon
Business Services Company (BSC), including legal, human resources,
financial and information technology services. A portion of such
services, provided at cost including applicable overhead, is capitalized.
(4) ComEd has contracted with Exelon Services to provide energy conservation
services to ComEd customers.
(5) ComEd has a note and interest receivable from Unicom Investments Inc.
(UII) relating to the December 1999 fossil plant sale. (6) At December
31, 2000, ComEd had a $400 million receivable from PECO, which was repaid
in the second quarter of 2001. (7) ComEd receives substation and
transmission engineering and construction services under contracts with
InfraSource. A portion
of such services is capitalized.
(8) In order to benefit from economies of scale, ComEd processes certain
invoice payments on behalf of Generation and BSC. During 2001, ComEd
earned interest from Generation relating to these invoice payments.
(9) ComEd had a short-term and long-term payable to Generation, primarily
representing ComEd's legal requirements to remit collections of nuclear
decommissioning costs from customers to Generation.
(10) ComEd has a non-interest bearing receivable from Exelon related to the
2001 corporate restructuring. The receivable is expected to be settled
over the years 2002 through 2008.
(11) ComEd pays Exelon for a variety of corporate expenses including
allocations under a tax sharing agreement and stock options.
(12) In consideration for the net assets transferred as part of the corporate
restructuring effective January 1, 2001, ComEd had a note payable to
affiliates of $463 million. This note payable was repaid during 2001.
</FN>
45
PECO
PECO's financial statements reflect a number of related-party
transactions as reflected in the table below.
Three Months Nine Months
Ended September 30, Ended September 30,
2002 2001 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
Operating Revenues from Affiliate
Generation (1) $ 3 $ 3 $ 9 $ 9
Purchased Power from Affiliate
Generation (2) 441 363 1,090 872
O&M from Affiliates
BSC (3) 10 15 36 47
Enterprises (4) 5 7 21 14
Interest Expense from Affiliates
ComEd (5) -- -- -- 8
Interest Income from Affiliates
Generation (7) -- 5 -- 6
Other -- 4 -- 4
Cash Dividends Paid to Parent 85 69 255 169
- ---------------------------------------------------------------------------------------------------------------------
September 30, 2002 December 31, 2001
- ---------------------------------------------------------------------------------------------------------------------
Receivables from Affiliates
BSC (3) $ 17 $ --
Other -- 1
Payables to Affiliates
Generation (2) 122 117
BSC (3) -- 61
Enterprises (4) 8 9
Deferred Credits and Other Liabilities
BSC -- 44
Capitalized Costs
Enterprises (4) 16 29
Shareholders' Equity - Receivable from Parent (6) 1,788 1,878
- ---------------------------------------------------------------------------------------------------------------------
<FN>
(1) PECO provides energy to Generation for Generation's own use.
(2) Effective January 1, 2001, PECO entered into a PPA with Generation. See
Note 8 of Combined Notes to Consolidated Financial Statements for further
information regarding the PPA.
(3) PECO provides services to BSC related to invoice processing. PECO
receives a variety of corporate support services from BSC, including
legal, human resources, financial and information technology services.
Such services are provided at cost, including applicable overhead.
(4) PECO receives services from Enterprises for construction, which are
capitalized, and the deployment of automated meter reading technology,
which is expensed.
(5) At December 31, 2000, PECO had a $400 million payable to ComEd, which was
repaid in the second quarter of 2001. The average annual interest rate on
this payable for the period outstanding was 6.5%.
(6) PECO has a non-interest bearing receivable from Exelon related to the
2001 corporate restructuring. The receivable is expected to be settled
over the years 2001 through 2010.
(7) PECO received interest income from Generation in 2001 related to a loan.
</FN>
46
Generation
In addition to the transactions described in the "Exelon and
Generation" section of this footnote, Generation's financial statements reflect
a number of related-party transactions as reflected in the tables below.
Three Months Nine Months
Ended September 30, Ended September 30,
2002 2001 2002 2001
- ---------------------------------------------------------------------------------------------------------------------
Operating Revenues from Affiliates
PPA with ComEd (1) $ 946 $ 945 $ 2,021 $ 2,133
PPA with PECO (1) 441 363 1,090 872
PPA with Exelon Energy (2) 73 93 190 210
Decommissioning with ComEd 3 3 8 8
Purchased Power from Affiliates
ComEd (3) -- 7 13 20
PECO(3) -- 2 1 4
Exelon Energy (3) 6 50 12 61
O&M from Affiliates
ComEd (3) 4 2 11 10
PECO (3) 3 1 8 5
BSC (3) 33 39 117 112
Interest Expense from Affiliates
Exelon (5,6) 1 -- 3 23
ComEd (8) -- 9 -- 9
PECO (9) -- 5 -- 6
Interest Income from Affiliate
ComEd (10) -- 10 -- 10
- ---------------------------------------------------------------------------------------------------------------------
September 30, 2002 December 31, 2001
- ---------------------------------------------------------------------------------------------------------------------
Receivables from Affiliates
ComEd (1,3,8) $ 544 $ 136
PECO (1) 122 117
Exelon Energy (2) 19 17
Note Receivable from Affiliate
ComEd (7) 59 59
Long-term Notes Receivable from Affiliates
ComEd (7) 244 291
Other 2 --
Accounts Payable
Exelon (6) 14 23
BSC (4) 19 11
Note Payable-Exelon (5) 348 --
- ---------------------------------------------------------------------------------------------------------------------
<FN>
(1) Effective January 1, 2001, Generation entered into PPAs with ComEd and
PECO. See Note 8 of Combined Notes to Consolidated Financial Statements
for further information on the PPAs.
(2) Generation sells power to Exelon Energy.
(3) Generation purchases power from AmerGen under PPAs as discussed in the
Exelon and Generation section of this note. Additionally, Generation
purchases power from PECO for Generation's own use, buys back excess
power from Exelon Energy and purchases transmission and ancillary
services from ComEd.
(4) Generation receives a variety of corporate support services from BSC,
including legal, human resources, financial and information technology
services. Such services are provided at cost, including applicable
overhead.
(5) Generation had a $348 million payable to Exelon at September 30, 2002,
which includes $331 million related to the acquisition of two generating
plants in April of 2002.
(6) In relation to the December 18, 2001 acquisition of 49.9% of Sithe
common stock, Generation had a $700 million payable to Exelon, which was
repaid in the second quarter of 2001.
(7) Generation had a short-term and a long-term receivable from ComEd,
primarily representing ComEd's legal requirements to remit collections
of nuclear decommissioning costs from customers to Generation resulting
from the 2001 corporate restructuring.
(8) In order to facilitate payment processing, ComEd processes certain
invoice payments on behalf of Generation.
(9) Generation paid interest to PECO in 2001 related to a loan.
(10) In consideration for the net assets transferred as a part of the
corporate restructuring effective January 1, 2001, Generation had a note
receivable from ComEd. This note was repaid in 2001.
</FN>
13. NEW ACCOUNTING PRONOUNCEMENTS (Exelon, ComEd, PECO and Generation)
In June 2001, the FASB issued SFAS No. 143, "Asset Retirement
Obligations" (SFAS No. 143). In July 2002, the FASB issued SFAS No. 146,
"Accounting for Costs Associated with Exit or Disposal Activities" (SFAS No.
146).
SFAS No. 143 provides accounting requirements for retirement
obligations associated with tangible long-lived assets. Exelon expects to adopt
SFAS No. 143 on January 1, 2003. Retirement obligations associated with
long-lived assets included within the scope of SFAS No. 143 are those for which
there is a legal obligation to settle under existing or enacted law, statute,
written or oral contract or by legal construction under the doctrine of
promissory estoppel. Adoption of SFAS No. 143 will change the accounting for the
decommissioning of Generation's nuclear generating plants as well as certain
other long-lived assets.
48
As it relates to nuclear decommissioning, the effect of this cumulative
adjustment will be to change the decommissioning liability to reflect the fair
value of the decommissioning obligation at the balance sheet date. Additionally,
the standard will require the accrual of an asset related to the decommissioning
obligation, which will be amortized over the remaining lives of the plants. The
net difference between the asset recognized and the liability recorded upon
adoption of SFAS No. 143 will be charged to earnings and recognized as a
cumulative effect of a change in accounting principle, net of expected
regulatory recovery. The decommissioning liability to be recorded represents an
obligation for the future decommissioning of the plants and, as a result,
accretion expense will be accrued on this liability until such time as the
obligation is satisfied.
Currently, Generation records the obligation for decommissioning
ratably over the lives of the plants. Exelon, ComEd, PECO and Generation are in
the process of evaluating the impact of adopting SFAS 143 on their financial
condition. Based on the current information and assumptions, Exelon estimates
that the non-cash impact on 2003 earnings per share (EPS) to be up to a negative
ten cents. However, if economic conditions change the assumptions, the EPS
impact could be more or less than ten cents per share. Additionally, the
adoption of the standard is expected to result in a large non-cash one-time
cumulative effect of a change in accounting principle gain of at least $1.5
billion, after tax. Like the EPS impact, the one-time impact could change with a
change in the assumptions or economic conditions. The final determination is in
part a function of the Treasury bond rate at the time of the adoption of the
standard. Additionally, although over the life of the plant the charges to
earnings for the depreciation of the asset and the interest on the liability
will be equal to the amounts that would have been recognized as decommissioning
expense under the current accounting, the timing of those charges will change
and in the near-term period subsequent to adoption, the depreciation of the
asset and the interest on the liability is expected to result in an increase in
expense.
SFAS No. 146 requires 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) 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. The service life
extension is subject to Nuclear Regulatory Commission (NRC) approval of an
extension of existing NRC operating licenses, which are generally 40 years. The
estimated annualized reduction in expense from the change is $132 million ($79
million, net of income taxes). As a result of the change, net income for the
three months and nine months ended September 30, 2002 increased approximately
49
$37 million ($22 million, net of income taxes) and approximately $96 million
($58 million, net of income taxes), respectively.
ComEd
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.
Effective July 1, 2002, ComEd has lowered its depreciation rates based
on a new depreciation study reflecting its significant construction program in
recent years, changes in and development of new technologies, and changes in
estimated plant service lives since the last depreciation study. The annualized
reduction in depreciation expense, based on December 31, 2001 plant balances, is
estimated to be approximately $100 million ($60 million, net of income taxes).
As a result of the change, net income for the three months and nine months ended
September 30, 2002 increased approximately $24 million ($14 million, net of
income taxes).
15. SUBSEQUENT EVENTS
ComEd
On October 15, 2002, ComEd paid at maturity $100 million of 9.17%
medium-term notes due October 15, 2002.
PECO
On October 9, 2002, PECO exchanged $250 million of 5.95% First and
Refunding Mortgage Bonds, due November 1, 2011, for $250 million of 5.95% First
and Refunding Mortgage Bonds, due November 1, 2011, which are registered under
the Securities Act. The exchange bonds are identical to the outstanding bonds
except for the elimination of certain transfer restrictions and registration
rights pertaining to the outstanding bonds. PECO did not receive any cash
proceeds from issuance of the exchange bonds.
50
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 to the net basis of
presentation required by EITF 02-3.
RESULTS OF OPERATIONS
Three Months Ended September 30, 2002 Compared To Three Months Ended September
30, 2001
Net Income and Earnings Per Share
Net income increased $175 million, or 47%, for the three months ended
September 30, 2002. Diluted earnings per common share increased $0.54 per share,
or 47%. The increase in net income reflects higher earnings in Energy Delivery,
51
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.
Exelon evaluates its performance on a business segment basis. The
analysis below presents the operating results for each of its business segments
for the three months ended September 30, 2002 compared to the three months ended
September 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 September 30,
--------------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
Energy Delivery $ 370 $ 280 $ 90 32.1%
Generation 163 140 23 16.4%
Enterprises 15 (33) 48 (145.5%)
Corporate 3 (11) 14 (127.3%)
- --------------------------------------------------------------------------------------------------
Total $ 551 $ 376 $ 175 46.5%
==================================================================================================
52
Results of Operations - Energy Delivery Business Segment
Three Months Ended September 30,
--------------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 3,162 $2,970 $ 192 6.5%
OPERATING EXPENSES
Purchased Power 1,485 1,374 111 8.1%
Fuel 40 51 (11) (21.6%)
Operating and Maintenance 407 421 (14) (3.3%)
Depreciation and Amortization 256 293 (37) (12.6%)
Taxes Other Than Income 162 133 29 21.8%
- -------------------------------------------------------------------------------------------------------
Total Operating Expense 2,350 2,272 78 3.4%
- -------------------------------------------------------------------------------------------------------
OPERATING INCOME 812 698 114 16.3%
- -------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (215) (253) 38 (15.0%)
Distributions on Preferred Securities of Subsidiaries (11) (11) -- --
Other, net 5 46 (41) (89.1%)
- -------------------------------------------------------------------------------------------------------
Total Other Income and Deductions (221) (218) (3) 1.4%
- -------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 591 480 111 23.1%
INCOME TAXES 221 200 21 10.5%
- -------------------------------------------------------------------------------------------------------
NET INCOME $ 370 $ 280 $ 90 32.1%
=======================================================================================================
Energy Delivery's gross margin (revenue net of purchased power and
fuel) increased $92 million, $81 million of which was attributable to warmer
summer weather in the third quarter of 2002 as compared to the third quarter of
2001, which increased retail electric volume.
Lower operating and maintenance expense reflects operating productivity
improvements and lower storm restoration costs, partially offset by costs
associated with the deployment of automated meter reading technology and
increased corporate allocations, a $17 million increase in the reserve for
manufactured gas plant (MGP) investigation and remediation.
Energy Delivery's depreciation and amortization expense decreased by
$37 million reflecting $32 million for the discontinuation of goodwill
amortization due to the adoption of SFAS No. 142 as of January 1, 2002 and a $24
million decrease due to lower depreciation rates at ComEd effective July 1,
2002, partially offset by $6 million of higher regulatory asset amortization and
higher depreciation expense related to higher plant in service balances.
ComEd completed a depreciation study and implemented lower depreciation
rates effective July 1, 2002. The new depreciation rates reflect ComEd's
significant construction program in recent years, changes in and development of
new technologies, and changes in estimated plant service lives since the last
depreciation study. The annual reduction in depreciation expense is estimated to
be approximately $100 million based on December 31, 2001 plant balances.
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
53
rates from Generation and from Unicom Investment, Inc. and a $12 million reserve
for a potential plant disallowance from an audit performed in conjunction with
ComEd's delivery services rate case.
Energy Delivery's effective income tax rate was 37.4% for the three
months ended September 30, 2002, compared to 41.7% for the three months ended
September 30, 2001. The decrease in the effective tax rate was primarily
attributable to the discontinuation of goodwill amortization as of January 1,
2002, which was not deductible for income tax purposes, and a reduction in state
income taxes.
Energy Delivery Operating Statistics and Revenue Detail
Energy Delivery's electric sales statistics and revenue detail are as
follows:
Three Months Ended September 30,
--------------------------------
Retail Deliveries - (in gigawatthours (GWh)) 2002 2001 Variance % Change
- -------------------------------------------------------------------------------------------------------------------
Bundled Deliveries (1)
Residential 12,543 10,573 1,970 18.6%
Small Commercial & Industrial 8,095 8,298 (203) (2.4%)
Large Commercial & Industrial 6,079 6,341 (262) (4.1%)
Public Authorities & Electric Railroads 1,836 2,299 (463) (20.1%)
- -------------------------------------------------------------------------------------------------------
28,553 27,511 1,042 3.8%
- -------------------------------------------------------------------------------------------------------
Unbundled Deliveries (2)
Alternative Energy Suppliers
Residential 371 990 (619) (62.5%)
Small Commercial & Industrial 1,794 998 796 79.8%
Large Commercial & Industrial 2,428 1,796 632 35.2%
Public Authorities & Electric Railroads 299 92 207 n.m.
- -------------------------------------------------------------------------------------------------------
4,892 3,876 1,016 26.2%
- -------------------------------------------------------------------------------------------------------
PPO (ComEd Only)
Small Commercial & Industrial 782 827 (45) (5.4%)
Large Commercial & Industrial 1,249 1,447 (198) (13.7%)
Public Authorities & Electric Railroads 345 150 195 130.0%
- -------------------------------------------------------------------------------------------------------
2,376 2,424 (48) (2.0%)
- -------------------------------------------------------------------------------------------------------
Total Unbundled Deliveries 7,268 6,300 968 15.4%
- -------------------------------------------------------------------------------------------------------
Total Retail Deliveries 35,821 33,811 2,010 5.9%
=======================================================================================================
<FN>
(1) Bundled service reflects deliveries to customers taking electric service
under tariffed rates, which include the cost of energy and the delivery
cost of the transmission and the distribution of the energy. PECO's
tariffed rates also include a Competitive Transition Charge (CTC).
(2) Unbundled service reflects customers electing to receive electric
generation service from an alternative energy supplier or ComEd's Power
Purchase Option (PPO).
n.m. - not meaningful
</FN>
54
Three Months Ended September 30,
--------------------------------
Electric Revenue 2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
Bundled Revenues (1)
Residential $ 1,318 $ 1,120 $ 198 17.7%
Small Commercial & Industrial 757 767 (10) (1.3%)
Large Commercial & Industrial 402 408 (6) (1.5%)
Public Authorities & Electric Railroads 125 138 (13) (9.4%)
- -------------------------------------------------------------------------------------------------------
2,602 2,433 169 7.0%
- -------------------------------------------------------------------------------------------------------
Unbundled Revenues (2)
Alternative Energy Suppliers
Residential 32 81 (49) (60.5%)
Small Commercial & Industrial 60 16 44 n.m.
Large Commercial & Industrial 67 19 48 n.m.
Public Authorities & Electric Railroads 10 1 9 n.m.
- -------------------------------------------------------------------------------------------------------
169 117 52 44.4%
- -------------------------------------------------------------------------------------------------------
PPO (ComEd Only)
Small Commercial & Industrial 57 77 (20) (25.9%)
Large Commercial & Industrial 74 120 (46) (38.3%)
Public Authorities & Electric Railroads 19 13 6 46.2%
- -------------------------------------------------------------------------------------------------------
150 210 (60) (28.6%)
- -------------------------------------------------------------------------------------------------------
Total Unbundled Revenues 319 327 (8) (2.4%)
- -------------------------------------------------------------------------------------------------------
Total Electric Retail Revenues 2,921 2,760 161 5.8%
- -------------------------------------------------------------------------------------------------------
Wholesale and Miscellaneous Revenue (3) 174 134 40 29.9%
- -------------------------------------------------------------------------------------------------------
Total Electric Revenue $ 3,095 $ 2,894 $ 201 6.9%
=======================================================================================================
<FN>
(1) Bundled revenue reflects deliveries to customers taking electric service
under tariffed rates, which include the cost of energy and the delivery
cost of the transmission and the distribution of the energy. PECO's
tariffed rates also include a CTC charge.
(2) Unbundled revenue reflects revenue from customers electing to receive
electric generation service from an alternative energy supplier or ComEd's
PPO. Revenues from customers choosing an alternative energy supplier
include a distribution charge and a CTC. Revenues from customers choosing
ComEd's PPO includes an energy charge at market rates, transmission, and
distribution charges and a CTC. Transmission charges received from
alternative energy suppliers are included in wholesale and miscellaneous
revenue.
(3) Wholesale and miscellaneous revenues include sales to alternative energy
suppliers, transmission revenue, sales to municipalities and other
wholesale energy sales.
</FN>
The changes in electric retail revenues for the three months ended
September 30, 2002, as compared to the same period in 2001 are attributable to
the following:
Variance
- -------------------------------------------------------------------------------------------------
Weather $ 146
Rate Changes (29)
Customer Choice (3)
Other Effects 47
- -------------------------------------------------------------------------------------------------
Electric Retail Revenue $ 161
=================================================================================================
o Weather. The demand for electricity services is impacted by weather
conditions. Very warm weather in summer months and very cold weather in
other months is referred to as "favorable weather conditions," because
these weather conditions result in increased sales of electricity.
Conversely, mild weather reduces demand.
55
The weather impact was favorable compared to the prior year as a
result of warmer summer weather during the third quarter of 2002. Cooling
degree days in the ComEd and PECO service territories were 26% and 20%
higher, respectively, in the third quarter of 2002 as compared to the third
quarter of 2001.
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 resulting from an increase in PECO's gross receipts tax
rate. The increase in PECO's gross receipts tax rate is expected to
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 became eligible to choose their supplier of electricity; however,
as of September 30, 2002, no alternative electric supplier has sought
approval from the Illinois Commerce Commission (ICC) and no electric
utilities have chosen to enter the ComEd residential market for the supply
of electricity.
The customer choice effect is attributable to a decrease in
revenues of $43 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)
offset by increased revenues of $40 million from customers in Pennsylvania
selecting or returning to PECO as their electric generation supplier.
o Other Effects. Exclusive of weather effects, higher delivery volume
affected Energy Delivery's revenue compared to the same 2001 period.
The increase in wholesale revenue for the three months ended September
30, 2002 as compared to the three months ended September 30, 2001 was due
primarily to reimbursement to ComEd from Generation of $12 million for
third-party energy reconciliations.
Energy Delivery's gas sales statistics and revenue detail are as
follows:
Three Months Ended September 30,
--------------------------------
2002 2001 Variance
- --------------------------------------------------------------------------------------------------------------------
Deliveries in million cubic feet (mmcf) 11,347 10,525 822
Revenue $67 $ 75 $ (8)
- --------------------------------------------------------------------------------------------------------------------
56
The changes in gas revenue for the quarter ended September 30, 2002, as
compared to the same 2001 period, are as follows:
(in millions) Variance
- -------------------------------------------------------------------------------------------------
Rate Changes $ (4)
Weather (3)
Volume (1)
- -------------------------------------------------------------------------------------------------
Gas Revenue $ (8)
=================================================================================================
o Rate Changes. The unfavorable variance in rates is attributable to an
adjustment of the purchased gas cost recovery by the PUC effective in
December 2001. The average rate per million cubic feet for the quarter
ended September 30, 2002 was 17% 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 demand for gas service is impacted by weather conditions. Very
cold weather in winter months is referred to as a "favorable weather
condition," because this weather condition results in increased sales of
gas. Conversely, mild weather reduces demand. Heating degree-days decreased
92% in the quarter ended September 30, 2002 compared to the same 2001
period.
o Volume. Exclusive of weather impact, delivery volume was consistent for the
quarter ended September 30, 2002 compared to the same 2001 period.
57
Results of Operations - Generation Business Segment
Three Months Ended September 30,
--------------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 2,213 $2,191 $ 22 1.0%
OPERATING EXPENSES
Purchased Power 1,257 1,268 (11) (0.9%)
Fuel 273 242 31 12.8%
Operating and Maintenance 391 364 27 7.4%
Depreciation and Amortization 68 57 11 19.3%
Taxes Other Than Income 37 36 1 2.8%
- -------------------------------------------------------------------------------------------------------
Total Operating Expense 2,026 1,967 59 3.0%
- -------------------------------------------------------------------------------------------------------
OPERATING INCOME 187 224 (37) (16.5%)
- -------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (23) (41) 18 (43.9%)
Equity in Earnings (Losses) of Unconsolidated Affiliates, net 87 60 27 45.0%
Other, net 14 (25) 39 156.0%
- -------------------------------------------------------------------------------------------------------
Total Other Income and Deductions 78 (6) 84 n.m.
- -------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 265 218 47 21.6%
INCOME TAXES 102 78 24 30.8%
- -------------------------------------------------------------------------------------------------------
NET INCOME $ 163 $ 140 $ 23 16.4%
=======================================================================================================
Net income for the three months ended September 30, 2002 was positively
impacted by increased revenue from affiliates, increased revenue from the
acquisition of two generating plants in April 2002, reduced interest expense,
increased equity in earnings of unconsolidated subsidiaries and lower losses on
nuclear decommissioning trust funds, partially offset by depressed wholesale
market prices for energy, increased depreciation expense, and increased
operating and maintenance expenses. Operating revenues, net of fuel and
purchased power, increased by $2 million reflecting a $59 million increase in
revenue from Generation's retail affiliates driven by a weather-driven increase
in sales volume to these affiliates partially offset by the impact of depressed
wholesale market prices for energy. Generation's revenues include $8 million due
to the net effect of the energy reconciliation of certain third-party sales in
ComEd's service territory and the impact of that energy reconciliation on
Generation's PPA with ComEd. Operating and maintenance expense increased by $27
million due to $10 million arising from an increased number of nuclear plant
refueling outage days, $3 million related to increased fossil plant outage work
and $7 million related to the two generating plants acquired in April 2002.
These increases were partially offset by other operating cost reductions
including cost reductions related to Exelon's Cost Management Initiative. The
increase in depreciation expense reflects additional depreciation expense on
routine capital additions, the acquisition of two generating plants acquired in
April 2002 and Southeast Chicago Energy Project, LLC's (Southeast Chicago)
peaking facility (Southeast Chicago Energy Project). The decrease in interest
expense is due to a lower interest rate on the spent nuclear fuel obligation and
lower affiliate interest expense. Equity in earnings of unconsolidated
affiliates increased primarily due to a Sithe mark-to-market adjustment,
partially offset by an impairment adjustment recorded at Sithe. Other, net
increased $39 million for the three months ended September 30, 2002 compared to
58
the same period in the prior year primarily due to lower losses on
decommissioning trust investments during 2002 as compared to the same period in
2001. Additionally, revenue for the three months ended September 30, 2002
includes a net trading portfolio loss of $12 million compared to a net $5
million gain for the three months ended September 30, 2001.
Generation Operating Statistics:
For the three months ended September 30, 2002 and 2001, Generation's
sales and the supply of these sales exclusive of the trading portfolio were as
follows:
Three Months Ended September 30,
--------------------------------
Sales (in GWhs) 2002 2001 % Change
- ---------------------------------------------------------------------------------------------------------------------
Energy Delivery 34,535 32,692 5.6%
Exelon Energy 1,461 2,038 (28.3%)
Market Sales 21,177 17,781 19.1%
- -------------------------------------------------------------------------------------------------------
Total Sales 57,173 52,511 8.9%
=======================================================================================================
Three Months Ended September 30,
--------------------------------
Supply of Sales (in GWhs) 2002 2001 % Change
- ---------------------------------------------------------------------------------------------------------------------
Nuclear Generation 29,817 28,456 4.8%
Purchases - non-trading portfolio 23,425 20,505 14.2%
Fossil and Hydro Generation 3,931 3,550 10.7%
- -------------------------------------------------------------------------------------------------------
Total Supply 57,173 52,511 8.9%
=======================================================================================================
Trading volume of 28,455 GWhs and 1,832 GWhs for the three months ended
September 30, 2002 and 2001, respectively, is not included in the table above.
Generation's average margin data for the three months ended September
30, 2002 and 2001 were as follows:
Three Months Ended September 30,
--------------------------------
($/MWh) 2002 2001 % Change
- ---------------------------------------------------------------------------------------------------------------------
Average Realized Revenue
Energy Delivery $ 40.18 $ 40.01 0.4%
Exelon Energy 49.72 46.67 6.5%
Market Sales 35.50 42.55 (16.6%)
Total Sales - excluding the trading portfolio 38.69 41.13 (5.9%)
Average Supply Cost (1) - excluding trading portfolio $ 26.66 $ 28.70 (7.1%)
Average Margin - excluding the trading portfolio $ 12.04 $ 12.43 (3.1%)
- ---------------------------------------------------------------------------------------------------------------------
<FN>
(1) Average Supply costs represent purchased power and fuel costs.
</FN>
Generation's nuclear fleet, including AmerGen, performed at a capacity
factor of 93.9% for the three months ended September 30, 2002 compared to 93.0%
for the same period in 2001. Generation's nuclear units' production costs,
including AmerGen, for the three months ended September 30, 2002 were $12.40 per
MWh compared to $12.52 per MWh for the same period in 2001. Reduced unit
production costs reflect additional generation due to power uprates, headcount
reductions and Exelon's Cost Management Initiative. Generation's average
purchased power costs for wholesale operations were $53.75 per MWh for the three
59
months ended September 30, 2002, compared to $62.18 per MWh for the same period
in 2001. The decrease in purchased power costs was primarily due to depressed
wholesale power market prices.
Results of Operations - Enterprises Business Segment
Three Months Ended September 30,
--------------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 509 $ 529 $ (20) (3.8%)
OPERATING EXPENSES
Purchased Power 73 88 (15) (17.0%)
Fuel 60 63 (3) (4.8%)
Operating and Maintenance 349 361 (12) (3.3%)
Depreciation and Amortization 11 16 (5) (31.3%)
Taxes Other Than Income 1 1 -- --
- -------------------------------------------------------------------------------------------------------
Total Operating Expense 494 529 (35) (6.6%)
- -------------------------------------------------------------------------------------------------------
OPERATING INCOME 15 -- 15 n.m.
- -------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (3) (9) 6 (66.7%)
Equity in Earnings (Losses) of Unconsolidated Affiliates, net 8 (8) 16 (200.0%)
Other, net -- (34) 34 (100.0%)
- -------------------------------------------------------------------------------------------------------
Total Other Income and Deductions 5 (51) 56 (109.8%)
- -------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 20 (51) 71 (139.2%)
INCOME TAXES 5 (18) 23 (127.8%)
- -------------------------------------------------------------------------------------------------------
NET INCOME $ 15 $ (33) $ 48 (145.4%)
=======================================================================================================
Enterprises' net income increased $48 million for the three months
ended September 30, 2002 compared to the same period in 2001. The increase in
net income is primarily attributable to increased operating income of $15
million, higher equity in earnings of unconsolidated affiliates of $11 million
due to the discontinuance of losses on AT&T Wireless PCS of Philadelphia, LLC
(AT&T Wireless) as a result of the sale of Enterprises' 49% interest in AT&T
Wireless to a subsidiary of AT&T Wireless Services, $10 million of equity in
earnings from a communications joint venture relating to its recovery of trade
receivables previously considered uncollectible and a $36 million loss in 2001
from a write-down of a communications investment.
Operating revenues decreased $20 million, or 3.8%, for the three months
ended September 30, 2002, compared to the same period in 2001. The decrease in
operating revenues was primarily attributable to reduced retail energy sales of
$50 million from Exelon Energy, Inc. (Exelon Energy) due to exiting the retail
energy business in the Pennsylvania, New Jersey and Maryland area (PJM market).
This decrease was partially offset by higher electric revenues of $22 million
primarily resulting from higher electric prices in Illinois for Exelon Energy,
higher revenues of $4 million from Exelon Services, Inc. (Exelon Services) from
increased construction project revenues and higher revenues of $4 million from
InfraSource, Inc. (InfraSource) primarily from increased infrastructure and
construction services in the electric line of business.
60
Enterprises' operating and other expenses, net decreased $91 million
for the three months ended September 30, 2002 compared to the same period in
2001. The decrease was primarily attributable to lower power costs of $34
million resulting from reduced operations of retail energy sales from Exelon
Energy exiting the PJM market, reduced costs at InfraSource of $10 million
relating to construction services in the electric line of business in addition
to overall reductions in administrative expenses, higher equity in earnings of
unconsolidated affiliates of $11 million as a result of the discontinuance of
losses on AT&T Wireless as a result of the AT&T Wireless sale, $10 million of
equity in earnings from a communications joint venture relating to its recovery
of trade receivables previously considered uncollectible, lower depreciation and
amortization of $5 million from the discontinuance of goodwill amortization,
lower interest expense of $6 million and a $36 million loss in 2001 from a
write-down of a communications investment. These decreases were partially offset
by higher electric purchased power costs in Illinois of $19 million and
increased costs relating to construction projects at Exelon Services of $5
million.
The effective income tax rate was 25.0% for the three months ended
September 30, 2002, compared to 35.3% for the three months ended September 30,
2001. The decrease in the effective tax rate was primarily attributable to a $5
million reduction in estimated state income taxes recorded during the quarter
and the discontinuation of goodwill amortization as of January 1, 2002, that was
not deductible for income tax purposes.
Nine Months Ended September 30, 2002 Compared To Nine Months Ended September 30,
2001
Net Income and Earnings Per Share
Exelon's income before the cumulative effect of changes in accounting
principles increased $195 million, or 18%, for the nine months ended September
30, 2002. Diluted earnings per common share on the same basis increased $0.60
per share, or 18%. The increase in income before the cumulative effect of
changes in accounting principles reflects higher earnings due to the sale of
AT&T Wireless, a 1.6% increase in retail sales reflecting warmer summer weather
partially offset by mild winter weather, the extension of the estimated service
lives of generating stations in 2001 and the discontinuation of goodwill
amortization required by the adoption of SFAS No. 142, partially offset by lower
wholesale energy prices, increased nuclear refueling outage costs, employee
severance costs and certain other factors affecting net income, which are
discussed in the remainder of the results of operations section. Net income
included net pre-tax charges of $10 million for severance costs, primarily
related to executive severance.
Net income decreased $47 million, or 4%, for the nine months ended
September 30, 2002. Diluted earnings per common share decreased $0.15 per share,
or 4%. Net income for the nine months ended September 30, 2002 included a $230
million charge for the cumulative effect of changes in accounting principles,
reflecting goodwill impairment upon the adoption of SFAS No. 142. Net income for
the nine months ended September 30, 2001 included $12 million of income for the
cumulative effect of 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.
61
The analysis below presents the operating results for each of Exelon's
business segments for the nine months ended September 30, 2002 compared to the
nine months ended September 30, 2001.
Income Before Cumulative Effect of Changes in Accounting Principles by Business Segment
Nine Months Ended September 30,
-------------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
Energy Delivery $ 908 $ 810 $ 98 12.1%
Generation 313 369 (56) (15.2%)
Enterprises 69 (63) 132 (209.5%)
Corporate (17) (38) 21 55.3%
- -------------------------------------------------------------------------------------------------------
Total $ 1,273 $ 1,078 $ 195 18.1%
=======================================================================================================
Results of Operations - Energy Delivery Business Segment
Nine Months Ended September 30,
-------------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 7,973 $7,903 $ 70 0.9%
OPERATING EXPENSES
Purchased Power 3,331 3,167 164 5.2%
Fuel 228 335 (107) (31.9%)
Operating and Maintenance 1,131 1,145 (14) (1.2%)
Depreciation and Amortization 745 828 (83) (10.0%)
Taxes Other Than Income 430 358 72 20.1%
- -------------------------------------------------------------------------------------------------------
Total Operating Expense 5,865 5,833 32 0.5%
- -------------------------------------------------------------------------------------------------------
OPERATING INCOME 2,108 2,070 38 1.8%
- -------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (654) (759) 105 (13.8%)
Distributions on Preferred Securities of Subsidiaries (34) (34) -- --
Other, net 35 117 (82) (70.1%)
- -------------------------------------------------------------------------------------------------------
Total Other Income and Deductions (653) (676) 23 (3.4%)
- -------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 1,455 1,394 61 4.4%
INCOME TAXES 547 584 (37) (6.3%)
- -------------------------------------------------------------------------------------------------------
NET INCOME $ 908 $ 810 $ 98 12.1%
=======================================================================================================
Energy Delivery's gross margin (revenue net of purchased power and
fuel) increased $13 million, $55 million of which was attributable primarily to
warmer summer weather, which increased retail electric and gas volumes,
partially offset by a warmer winter.
Lower operating and maintenance expense reflects operating productivity
improvements and lower storm restoration costs, a decrease in the provisions for
bad debt expense and a decrease in the provision for obsolete inventory,
partially offset by increased pension and postretirement benefit costs and
increased corporate allocations, including a portion of executive severance
62
charges, an increase in the provision for injuries and damages and an increase
in reserves for MGP investigation and remediation.
Energy Delivery's depreciation and amortization expense decreased by
$83 million reflecting $97 million from the discontinuation of goodwill
amortization due to the adoption of SFAS No. 142 as of January 1, 2002 and a $24
million decrease due to lower depreciation rates at ComEd effective July 1,
2002, partially offset by $14 million of higher regulatory asset amortization
and higher depreciation expense related to higher plant in service balances.
Lower interest expense reflects reductions in the amount of debt
outstanding as well as lower interest rates due to debt refinancing. The
reduction in other, net primarily reflects lower intercompany interest income
reflecting lower interest rates and a $12 million reserve for a potential plant
disallowance resulting from an audit performed in conjunction with ComEd's
delivery service rate case.
Energy Delivery's effective income tax rate was 37.6% for the nine
months ended September 30, 2002, compared to 41.9% for the nine months ended
September 30, 2001. The decrease in the effective tax rate was primarily
attributable to the discontinuation of goodwill amortization as of January 1,
2002, which was not deductible for income tax purposes, and a reduction in state
income taxes.
63
Energy Delivery Operating Statistics and Revenue Detail
Energy Delivery's electric sales statistics and revenue detail are as
follows:
Nine Months Ended September 30,
-------------------------------
Retail Deliveries - (in GWhs) 2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
Bundled Deliveries (1)
Residential 28,984 26,243 2,741 10.4%
Small Commercial & Industrial 22,782 22,289 493 2.2%
Large Commercial & Industrial 17,436 17,682 (246) (1.4%)
Public Authorities & Electric Railroads 5,715 6,574 (859) (13.1%)
- -------------------------------------------------------------------------------------------------------
74,917 72,788 2,129 2.9%
- -------------------------------------------------------------------------------------------------------
Unbundled Deliveries (2)
Alternative Energy Suppliers
Residential 1,720 2,365 (645) (27.3%)
Small Commercial & Industrial 4,075 3,521 554 15.7%
Large Commercial & Industrial 5,551 6,131 (580) (9.5%)
Public Authorities & Electric Railroads 618 235 383 163.0%
- -------------------------------------------------------------------------------------------------------
11,964 12,252 (288) (2.4%)
- -------------------------------------------------------------------------------------------------------
PPO (ComEd Only)
Small Commercial & Industrial 2,384 2,448 (64) (2.6%)
Large Commercial & Industrial 3,952 4,324 (372) (8.6%)
Public Authorities & Electric Railroads 861 734 127 17.3%
- -------------------------------------------------------------------------------------------------------
7,197 7,506 (309) (4.1%)
- -------------------------------------------------------------------------------------------------------
Total Unbundled Deliveries 19,161 19,758 (597) (3.0%)
- -------------------------------------------------------------------------------------------------------
Total Retail Deliveries 94,078 92,546 1,532 1.7%
=======================================================================================================
<FN>
(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.
</FN>
64
Nine Months Ended September 30,
-------------------------------
Electric Revenue 2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
Bundled Revenues (1)
Residential $ 2,880 $ 2,659 $ 221 8.3%
Small Commercial & Industrial 2,007 1,910 97 5.1%
Large Commercial & Industrial 1,152 1,095 57 5.2%
Public Authorities & Electric Railroads 356 388 (32) (8.3%)
- -------------------------------------------------------------------------------------------------------
6,395 6,052 343 5.7%
- -------------------------------------------------------------------------------------------------------
Unbundled Revenues (2)
Alternative Energy Suppliers
Residential 129 184 (55) (30.0%)
Small Commercial & Industrial 107 110 (3) (2.8%)
Large Commercial & Industrial 111 121 (10) (8.3%)
Public Authorities & Electric Railroads 18 4 14 n.m.
- -------------------------------------------------------------------------------------------------------
365 419 (54) (12.9%)
- -------------------------------------------------------------------------------------------------------
PPO (ComEd Only)
Small Commercial & Industrial 155 167 (12) (7.2%)
Large Commercial & Industrial 214 267 (53) (19.9%)
Public Authorities & Electric Railroads 48 44 4 9.1%
- -------------------------------------------------------------------------------------------------------
417 478 (61) (12.8%)
- -------------------------------------------------------------------------------------------------------
Total Unbundled Revenues 782 897 (115) (12.8%)
- -------------------------------------------------------------------------------------------------------
Total Electric Retail Revenues 7,177 6,949 228 3.3%
- -------------------------------------------------------------------------------------------------------
Wholesale and Miscellaneous Revenue (3) 438 472 (34) (7.2%)
- -------------------------------------------------------------------------------------------------------
Total Electric Revenue $ 7,615 $ 7,421 $ 194 2.6%
=======================================================================================================
<FN>
(1) Bundled revenue reflects deliveries to customers taking electric service
under tariffed rates, which include the cost of energy and the delivery
cost of the transmission and the distribution of the energy. PECO's
tariffed rates also include a CTC charge.
(2) Unbundled revenue reflects revenue from customers electing to receive
electric generation service from an alternative energy supplier or ComEd's
PPO. Revenue from customers choosing an alternative energy supplier
includes a distribution charge and a CTC. Revenues from customers choosing
ComEd's PPO includes an energy charge at market rates, transmission, and
distribution charges and a CTC. Transmission charges received from
alternative energy suppliers are included in wholesale and miscellaneous
revenue.
(3) Wholesale and miscellaneous revenues include sales to alternative energy
suppliers, transmission revenue, sales to municipalities and other
wholesale energy sales.
</FN>
The changes in electric retail revenues for the nine months ended
September 30, 2002, as compared to the same period in 2001 are attributable to
the following:
Variance
- -------------------------------------------------------------------------------------------------
Weather $ 115
Customer Choice 84
Rate Changes (54)
Other Effects 83
- -------------------------------------------------------------------------------------------------
Electric Retail Revenue $ 228
=================================================================================================
o Weather. The weather impact was favorable compared to the prior year as a
result of warmer summer weather in ComEd and PECO service territories
partially offset by warmer winter weather in the ComEd and PECO service
territories. Cooling degree days in the ComEd and PECO service territories
were 27% and 14% higher, respectively, in the nine months ended September
30, 2002 as compared to the same period in 2001. Heating degree days in the
65
ComEd and PECO service territories were 7% and 16% lower, respectively, in
the nine months ended September 30, 2002 as compared to the same period in
2001.
o Customer Choice. The increase in electric retail revenues due to customer
choice results from increased revenues of $205 million from customers in
Pennsylvania selecting or returning to PECO as their electric generation
supplier, partially offset by a decrease in revenues of $121 million from
customers in Illinois electing to purchase energy from an ARES or the PPO,
under which customers can purchase power from ComEd at a market-based rate.
ComEd and PECO continue to collect delivery charges from these customers.
o Rate Changes. The decrease in revenues attributable to rate changes
reflects the 5% ComEd residential rate reduction, effective October 1,
2001, required by the Illinois restructuring legislation and the timing of
a $60 million PECO rate reduction in effect for 2001 and 2002, offset by
$39 million due to an increase in PECO's gross receipts tax rate effective
January 1, 2002 and the expiration of a 6% reduction in PECO's rates during
the first quarter of 2001.
o Other Effects. For ComEd, other items impacting revenues were primarily a
strong housing construction market in Chicago which contributed to
residential and small commercial and industrial customer volume growth in
the early portion of the year, partially offset by the unfavorable impact
of a slower economy on large commercial and industrial customers. For PECO,
other items impacting revenues were $53 million from higher delivery
volume, exclusive of weather impacts, partially offset by an $11 million
settlement of CTCs by a large customer in the first quarter of 2001.
The reduction in wholesale revenue for the nine months ended September
30, 2002 as compared to the nine months ended September 30, 2001 was due
primarily to a decrease in off-system sales due to the expiration of wholesale
contracts that were offered by ComEd from June 2000 to May 2001 to support the
open access program in Illinois, and a 2001 reversal of reserve for revenue
refunds related to certain of ComEd's municipal customers as a result of a
favorable FERC ruling, partially offset by an increase of $12 million due
primarily to reimbursement from Generation for third-party energy
reconciliations.
Energy Delivery's gas sales statistics and revenue detail are as
follows:
Nine Months Ended September 30,
-------------------------------
2002 2001 Variance
- ---------------------------------------------------------------------------------------------------------------------
Deliveries in mmcf 56,990 58,536 (1,546)
Revenue $358 $482 $ (124)
- ---------------------------------------------------------------------------------------------------------------------
66
The changes in gas revenue for the nine months ended September 30,
2002, as compared to the same 2001 period, are as follows:
Variance
- -------------------------------------------------------------------------------------------------
Rate Changes $ (67)
Weather (33)
Volume (23)
Other (1)
- -------------------------------------------------------------------------------------------------
Gas Revenue $ (124)
=================================================================================================
o Rate Changes. The unfavorable variance in rates is attributable to an
adjustment of the purchased gas cost recovery by the PUC effective in
December 2001. The average rate per million cubic feet for the nine months
ended September 30, 2002 was 23% lower than the same 2001 period.
o Weather. The unfavorable weather impact is attributable to warmer winter
weather during the nine months ended September 30, 2002 as compared to the
same 2001 period. Heating degree-days decreased 16% in the nine months
ended September 30, 2002 compared to the same 2001 period.
o Volume. Exclusive of weather impacts, lower delivery volume reduced revenue
by $23 million in the nine months ended September 30, 2002 compared to the
same 2001 period. Total deliveries to customers decreased 3% in the nine
months ended September 30, 2002 compared to the same 2001 period, primarily
as a result of slower economic conditions in 2002 offset by increased
customer growth.
67
Results of Operations - Generation Business Segment
Nine Months Ended September 30,
-------------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 5,233 $5,403 $ (170) (3.1%)
OPERATING EXPENSES
Purchased Power 2,581 2,589 (8) (0.3)%
Fuel 706 691 15 2.2%
Operating and Maintenance 1,234 1,173 61 5.2%
Depreciation and Amortization 197 224 (27) (12.1%)
Taxes Other Than Income 126 121 5 4.1%
- -------------------------------------------------------------------------------------------------------
Total Operating Expense 4,844 4,798 46 1.0%
- -------------------------------------------------------------------------------------------------------
OPERATING INCOME 389 605 (216) (35.7%)
- -------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (51) (100) 49 (49.0%)
Equity in Earnings of Unconsolidated Affiliates, net 119 99 20 20.2%
Other, net 54 (7) 61 n.m.
- -------------------------------------------------------------------------------------------------------
Total Other Income and Deductions 122 (8) 130 n.m.
- -------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES AND CUMULATIVE
EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES 511 597 (86) (14.4%)
INCOME TAXES 198 228 (30) (13.2%)
- -------------------------------------------------------------------------------------------------------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN
ACCOUNTING PRINCIPLES 313 369 (56) (15.2%)
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING
PRINCIPLES 13 12 1 8.3%
- -------------------------------------------------------------------------------------------------------
NET INCOME $ 326 $ 381 $ (55) (14.4%)
=======================================================================================================
Net income for the nine months ended September 30, 2002 was adversely
impacted by a lower margin on wholesale energy sales due to depressed market
prices for energy, a reduced supply of low-cost nuclear generation, and
increased operating and maintenance expense, partially offset by an increase in
revenue from affiliates, increased revenue from the acquisition of two
generating plants in April 2002, increased interest income decreased
depreciation and interest expense and lower nuclear decommissioning trust fund
losses. Operating revenues, net of fuel and purchased power, decreased by $177
million reflecting a decrease in margin on market sales attributable to lower
margin from market sales, offset by weather related increases in sales to
affiliates and a decrease trading margins. Market sales margins were negatively
impacted by lower average market sales prices. The effect of the lower sales
prices were partially offset by lower average supply costs and increased market
sales volumes. The decrease in trading margins was principally attributed to
lower purchase power costs associated with lower wholesale market prices
realized and reduced transmission costs. Operating and maintenance expense
increased, primarily due to $65 million of costs incurred for the additional
refueling outages during the nine months ended September 30, 2002 as compared to
the same period in 2001, as well as additional allocated corporate costs
including executive severance. These additional expenses were partially offset
by other operating cost reductions, including $11 million related to headcount
reductions, a $10 million reduction in Generation's severance accrual and cost
68
reductions related to Exelon's Cost Management Initiative. The decline in
depreciation expense reflects extension of the estimated service lives of
generating stations, partially offset by additional depreciation expense on
plant placed in service, including two generating plants in April 2002 and the
Southeast Chicago Energy Project. Lower interest expense is due to capitalized
interest and a lower interest rate on the spent nuclear fuel obligation,
partially offset by an increase in interest expense on long-term debt. Other,
net increased $61 million for the nine months ended September 30, 2002 compared
to the same period in the prior year primarily due to substantial market losses
on decommissioning trust investments during 2001 as compared to the same period
in 2002. Additionally, trading activities were initiated in April 2001. Revenue
for the nine months ended September 30, 2002 includes a net trading portfolio
loss of $27 million compared to a net $1 million loss in the nine months ended
September 30, 2001.
Generation Operating Statistics:
For the nine months ended September 30, 2002 and 2001, Generation's
sales and the supply of these sales, excluding the trading portfolio, were as
follows:
Nine Months Ended September 30,
-------------------------------
Sales (in GWhs) 2002 2001 % Change
- ---------------------------------------------------------------------------------------------------------------------
Energy Delivery 90,579 90,001 0.6%
Exelon Energy 4,067 5,044 (19.4%)
Market Sales 61,089 53,787 13.6%
- -------------------------------------------------------------------------------------------------------
Total Sales 155,735 148,832 4.6%
=======================================================================================================
Nine Months Ended September 30,
Supply of Sales (in GWhs) 2002 2001 % Change
- ---------------------------------------------------------------------------------------------------------------------
Nuclear Generation 86,127 87,397 (1.5%)
Purchases - non-trading portfolio 59,496 52,459 13.4%
Fossil and Hydro Generation 10,112 8,976 12.7%
- -------------------------------------------------------------------------------------------------------
Total Supply 155,735 148,832 4.6%
=======================================================================================================
Trading volume of 51,260 GWhs and 2,286 GWhs for the nine months ended
September 30, 2002 and 2001, respectively, is not included in the table above.
69
Generation's average margin data for the nine months ended September
30, 2002 and 2001 were as follows:
Nine Months Ended September 30,
-------------------------------
($/MWh) 2002 2001 % Change
- ---------------------------------------------------------------------------------------------------------------------
Average Realized Revenue
Energy Delivery $ 34.33 $ 33.37 2.9%
Exelon Energy 46.75 42.28 10.6%
Market Sales 31.55 39.95 (21.0%)
Total Sales - excluding the trading portfolio 33.56 36.05 (6.9%)
Average Supply Cost (1) - excluding trading portfolio $ 21.04 $ 21.72 (3.1%)
Average Margin - excluding the trading portfolio $ 12.52 $ 14.18 (11.7%)
- ---------------------------------------------------------------------------------------------------------------------
<FN>
(1) Average supply cost includes purchase power and fuel cost.
</FN>
Generation's nuclear fleet, including AmerGen, performed at a capacity
factor of 92.1% for the nine months ended September 30, 2002 compared to 95.1%
the same period in 2001. Generation's nuclear fleet's production costs,
including AmerGen, for the nine months ended September 30, 2002 were $13.05 per
MWh compared to $12.40 per MWh for the same period in 2001. The lower capacity
factor and increased unit production costs are primarily due to 186 days of
planned outage time in the nine months ended September 30, 2002 versus 55, days
in the same period in 2001. Increased unit production costs are partially offset
by headcount reductions and Exelon's Cost Management Initiatives. Generation's
average purchased power costs for wholesale operations were $43.60 per MWh for
the nine months ended September 30, 2002, compared to $49.77 per MWh for the
same period in 2001. The decrease in purchased power costs was primarily due to
depressed wholesale power market prices.
70
Results of Operations - Enterprises Business Segment
Nine Months Ended September 30,
-------------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $1,475 $1,742 $ (267) (15.3%)
OPERATING EXPENSES
Purchased Power 181 244 (63) (25.8%)
Fuel 294 429 (135) (31.5%)
Operating and Maintenance 983 1,066 (83) (7.8%)
Depreciation and Amortization 46 47 (1) (2.1%)
Taxes Other Than Income 6 8 (2) (25.0%)
- -------------------------------------------------------------------------------------------------------
Total Operating Expense 1,510 1,794 (284) (15.8%)
- -------------------------------------------------------------------------------------------------------
OPERATING INCOME (35) (52) 17 (32.7%)
- --------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (11) (31) 20 (64.5%)
Equity in Earnings (Losses) of Unconsolidated Affiliates, net 3 (22) 25 (113.6%)
Other, net 158 4 154 n.m.
- -------------------------------------------------------------------------------------------------------
Total Other Income and Deductions 150 (49) 199 n.m.
- -------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES AND CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 115 (101) 216 (213.9%)
INCOME TAXES 46 (38) 84 (221.1%)
- -------------------------------------------------------------------------------------------------------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE 69 (63) 132 (209.5%)
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE (243) -- (243) n.m.
- -------------------------------------------------------------------------------------------------------
NET INCOME $ (174) $ (63) $ (111) 176.2%
=======================================================================================================
Enterprises' net income increased $132 million for the nine months
ended September 30, 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, increased operating income of $17 million,
higher equity in earnings of unconsolidated affiliates of $18 million due to the
discontinuation of losses on AT&T Wireless as a result of the AT&T Wireless
sale, $10 million of equity in earnings from a communications joint venture
relating to its recovery of trade receivables previously considered
uncollectible and a $26 million net loss in 2001 from the write-down of a
communications investment. These increases were partially offset by $40 million
of investment write-downs and $4 million of net asset write-downs in 2002 and an
$18 million gain in 2001 from the sale of a communications investment.
Enterprises' net loss increased $111 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 $267 million for the nine months ended
September 30, 2002, compared to the same period in 2001. The decrease in
operating revenues was attributable to lower gas sales of $110 million primarily
71
resulting from lower gas prices, reduced retail energy sales of $141 million
from Exelon Energy exiting the PJM market, lower revenues of $52 million from
Exelon Services from reduced construction projects and lower revenues of $24
million from InfraSource from the continued decline in the telecommunications
industry and reduced construction services in that industry. These decreases
were partially offset by higher electric revenues of $60 million primarily
resulting from higher electric prices in Illinois for Exelon Energy.
Enterprises' operating and other expenses, net decreased $483 million
for the nine months ended September 30, 2002 compared to the same period in
2001. The decrease is primarily attributable to a pre-tax gain of $198 million
recorded on the AT&T Wireless sale, lower gas costs of $109 million primarily
resulting from lower gas prices, lower power costs of $154 million resulting
from reduced operations of retail energy sales from Exelon Energy exiting the
PJM market, reduced costs relating to construction projects at Exelon Services
of $41 million, reduced costs relating to construction services in the
telecommunications industry and overall reductions in administrative expenses at
InfraSource of $35 million, lower interest expense of $20 million, higher equity
in earnings of unconsolidated affiliates of $18 million as a result of the
discontinuance of losses on AT&T Wireless as a result of the AT&T Wireless sale,
$10 million of equity in earnings from a communications joint venture relating
to its recovery of trade receivables previously considered uncollectible and a
$26 million net loss in 2001 from the write-down of a communications investment.
These decreases were partially offset by higher electric purchased power costs
in Illinois of $68 million for Exelon Energy, write-down of communications
investments of $29 million, write-down of energy related investments of $11
million, a net write-down of other assets of $4 million in 2002 and a $18
million gain in 2001 from the sale of a communications investment.
The effective income tax rate was 40.0% for the nine months ended
September 30, 2002, compared to 37.6% for the nine months ended September 30,
2001. The increase in the effective tax rate was primarily attributable to the
AT&T Wireless sale offset by the discontinuation of goodwill amortization as of
January 1, 2002, that was not deductible for income tax purposes.
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.
72
Cash Flows from Operating Activities
Cash flows provided by operations for the nine months ended September
30, 2002 were $2.6 billion compared to $3.0 billion in the nine months ended
September 30, 2001. Approximately 70% of 2002 cash flows provided by operations
for the nine months ended September 30, 2002 were provided by Energy Delivery
and approximately 30% were provided by Generation. Enterprises' cash flows from
operations were immaterial to Exelon for the nine months ended September 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 and are weighted toward the third quarter. Energy Delivery's future
cash flows will depend upon the ability to achieve operating cost reductions,
and the impact of the economy, weather and customer choice on its revenues.
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 nine months ended
September 30, 2002 were $1.8 billion, compared to $1.6 billion for the nine
months ended September 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 nine months ended September 30, 2002 and 2001 are as
follows:
Nine Months Ended September 30,
-------------------------------
2002 2001
- ---------------------------------------------------------------------------------------------------------------------
Energy Delivery $ 729 $ 784
Generation 715 497
Enterprises 34 53
Corporate and Other 56 18
- ---------------------------------------------------------------------------------------------------------------------
Total Capital Expenditures $ 1,534 $ 1,352
=====================================================================================================================
Energy Delivery's capital expenditures for 2002 reflect the
continuation of efforts to further improve the reliability of its distribution
system. 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 Exelon commercial paper. Exelon expects to repay the commercial
paper utilizing Generation's internal cash flows.
73
Capital expenditures have increased for the nine months ended September
30, 2002 as compared to 2001 due to higher nuclear fuel expenditures, growth and
an increase in the number of planned refueling outages, during which significant
work is performed on additions to or upgrades of existing facilities.
In February 2002, Generation entered into an agreement to loan AmerGen
up to $75 million at an interest rate of one-month LIBOR plus 2.25%. In July
2002, the loan agreement and the loan were increased to $100 million and the
maturity date was extended to July 1, 2003. As of September 30, 2002, the
balance of the loan to AmerGen was $42 million.
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.
Cash Flows from Financing Activities
Cash flows used in financing activities were $828 million in the nine
months ended September 30, 2002 compared to $521 million for the same period in
2001 due to higher levels of net reductions in short-term and long-term debt and
payments of dividends on common stock of $420 million. Debt financing activities
during the nine months ended September 30, 2002 are discussed in the Contractual
Obligations and Commercial Commitments section of Management's Discussion and
Analysis of Financial Condition and Results of Operations.
Credit Issues
Exelon meets its short-term liquidity requirements primarily through
the issuance of commercial paper by Exelon, at the holding company level, and by
ComEd, PECO and Generation. Exelon, along with ComEd, PECO and Generation,
participates in a $1.5 billion unsecured 364-day revolving credit facility with
a group of banks effective December 12, 2001. Under the terms of this credit
facility, Exelon has the flexibility to increase or decrease the sublimits of
each of the participants upon written notification to these banks. As of
September 30, 2002, Exelon's sublimit is $700 million at the holding company
level. This credit facility is used principally to support the $700 million
commercial paper program at the Exelon holding company level. At September 30,
2002, Exelon had $319 million of commercial paper outstanding at the holding
company level. At September 30, 2002, the Exelon Consolidated Balance Sheet
reflects the $788 million total amount of commercial paper outstanding for all
participants in the credit facility.
To provide an additional short-term borrowing option that will
generally be more favorable to the borrowing participants than the cost of
external financing, Exelon operates an intercompany money pool. Participation in
the money pool is subject to authorization by the Exelon Corporate Treasurer.
Exelon, ComEd and its subsidiary Commonwealth Edison of Indiana, Inc., PECO,
Generation and Business Services Company currently may participate in the money
pool. Funding of, and borrowings from, the money pool are predicated on whether
such funding results in mutual economic benefits to each of the participants,
although Exelon is not permitted to be a net borrower from the fund. Interest on
borrowings is based on short-term market rates of interest, or specific
borrowing rates if the funds are provided by external financing. There have been
no material money pool transactions in 2002.
74
At September 30, 2002, Exelon had outstanding $788 million of notes
payable consisting principally of commercial paper. For the nine months ended
September 30, 2002, the average interest rate on notes payable was approximately
1.91%. Certain of the credit agreements to which Exelon, ComEd, PECO and
Generation are a party require each of them to maintain a debt to total
capitalization ratio of 65% or less (excluding securitization debt and for PECO,
excluding the receivable from parent recorded in PECO's shareholders' equity).
At September 30, 2002, the debt to total capitalization ratios on that basis for
Exelon, ComEd, PECO and Generation were 46%, 42%, 41% and 34%, respectively.
At September 30, 2002, Exelon's capital structure consisted of 58% of
long-term debt, 37% common stock, 3% notes payable and 2% preferred securities
of subsidiaries. Total debt included $6.3 billion of securitization debt
constituting obligations of certain consolidated special purpose entities,
representing 27% of capitalization.
Exelon and its subsidiaries' access to the capital markets, including
the commercial paper market, and their financing costs in those markets are
dependent on their respective credit ratings. None of Exelon's or its
subsidiaries' borrowings are subject to default or prepayment as a result of a
downgrading of credit ratings although such a downgrading could increase
interest charges under Exelon's bank credit facility. Exelon and its
subsidiaries from time to time enter into energy commodity and other derivative
transactions that require the maintenance of investment grade ratings. Failure
to maintain investment grade ratings would allow the counterparty to terminate
the derivative and settle the transaction on a net present value basis.
Under 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 September 30, 2002, Exelon had retained earnings
of $1.8 billion, which includes ComEd retained earnings of $480 million, PECO
retained earnings of $347 million and Generation retained earnings of $850
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 September 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 6.15% First Mortgage Bonds, Series 98 due
March 15, 2012, issued $100 million of Illinois Development Finance
Authority floating-rate Pollution Control Revenue Refunding Bonds, Series
2002 due April 15, 2013, redeemed $100 million of 7.25% Illinois
Development Finance Authority Pollution Control Revenue Refunding Bonds,
Series 1991, due June 1, 2011, redeemed $200 million of 8.625% First
Mortgage Bonds, Series 81 due February 1, 2022, redeemed $200 million of
8.5% First Mortgage Bonds, Series 84 due July 15, 2022, paid at maturity
$200 million of 7.375% First Mortgage Bonds, Series 85 due September 15,
2002, redeemed $200 million of 8.375% First Mortgage Bonds, Series 86 due
75
September 15, 2022, paid at maturity $200 million of variable rate senior
notes due September 30, 2002, paid at maturity $100 million of 9.17%
medium-term notes due October 15, 2002, and retired $254 million of
transitional trust notes. At September 30, 2002, ComEd had $94 million in
short-term borrowings.
o PECO issued $225 million of 4.75% First and Refunding Mortgage Bonds due
October 1, 2012. This bond issuance repaid commercial paper that was used
to pay at maturity $222 million of First and Refunding Mortgage Bonds. PECO
made principal payments of $326 million on transition bonds and made
additional borrowings of commercial paper of $274 million.
o Guarantees increased approximately $280 million, primarily related to a
$410 million increase in the amount of performance bonds, bid bonds and
surety bonds required by Enterprises, partially offset by $120 million in
letters of credit on pollution control bonds at Generation being renewed
and no longer required to be guaranteed.
o Insured long-term debt increased $100 million related to ComEd's issuance
of $100 million in variable rate debt that has been credit enhanced through
the purchase of insurance coverage.
o On April 25, 2002 Generation closed the purchase of two generating plants
from TXU. The $443 million purchase was funded primarily with commercial
paper issued by Exelon.
o On June 26, 2002, Generation agreed to purchase Sithe New England Holdings,
LLC (Sithe New England), a subsidiary of Sithe, and related power marketing
operations for a $543 million note. In addition, Generation will assume
various Sithe guarantees related to an equity contribution agreement
between Sithe New England and Sithe Boston Generation (Boston Generation),
a project subsidiary of Sithe New England. The equity contribution
agreement requires, among other things, that Sithe New England, upon the
occurrence of certain events, contribute up to $38 million of equity for
the purpose of completing the construction of two generating facilities.
Boston Generation established a $1.2 billion credit facility in order to
finance the construction of these two generating facilities. The
approximately $1.1 billion expected to be outstanding under the facility at
the transaction closing date, will be reflected on Exelon's Consolidated
Balance Sheet. Sithe New England has provided security interests in and has
pledged the stock of its other project subsidiaries to Boston Generation.
If the closing conditions are satisfied, the purchase could be completed in
November 2002.
o At September 30, 2002, Southeast Chicago, a company 70% owned by
Generation, was obligated to make equity distributions of $55 million over
the next 20 years to the unaffiliated third party owning the remaining 30%
of Southeast Chicago. This amount reflects a return of such third party's
investment in Southeast Chicago's peaking facility in Chicago, IL.
Generation has the right to purchase, generally at a premium, and this
third party has the right to require Generation to purchase, generally at a
discount, its remaining investment in Southeast Chicago. Additionally,
Generation may be required to purchase the third party's remaining
investment in Southeast Chicago upon the occurrence of certain events,
including upon a failure by Generation to maintain an investment grade
rating.
o Purchase obligations increased by $2.3 billion, primarily due to an
increase of $3.8 billion in power only purchases and a $0.1 billion
increase in transmission rights purchases partially offset by a $1.6
billion decrease in net capacity purchase commitments. Approximately $2
billion of the increase in power only purchases is due to Generation's
agreement to purchase all the energy from Unit No. 1 at Three Mile Island
after December 31, 2001 through December 31, 2014 and the remaining $1.8
billion increase is primarily due to purchase contracts entered into in
lieu of a portion of the Midwest Generation options contracts. The increase
in transmission rights purchases is primarily due to estimated commitments
in 2004 and 2005 for additional transmission rights that will be required
to fulfill firm sales contracts. The decrease in net capacity purchase
76
commitments is due primarily to the decision not to exercise options to
purchase 4,411 MWs of capacity from Midwest Generation in 2002 through 2004
as well as the increase in capacity sales under the TXU tolling agreement.
Off Balance Sheet Obligations
Generation owns 49.9% of the outstanding common stock of Sithe and has
an option, beginning on December 18, 2002 and expiring in December 2005 to
purchase the remaining common stock outstanding (Remaining Interest) in Sithe.
The purchase option expires on December 18, 2005. In addition, the Sithe
stockholders who own in the aggregate the Remaining Interest have the right to
require Generation to purchase the Remaining Interest (Put Rights) during the
same period in which Generation can exercise its purchase option. At the end of
this exercise period, if Generation has not exercised its purchase option and
the other Sithe stockholders have not exercised their Put Rights, Generation
will have an additional one-time option to purchase shares from the other
stockholders in Sithe to bring Generation's ownership in Sithe from the current
49.9% to 50.1% of Sithe's total outstanding common stock.
If Generation exercises its option to acquire the Remaining Interest,
or if all the other Sithe stockholders exercise their Put Rights, the purchase
price for 70% of the Remaining Interest will be set at fair market value subject
to a floor of $430 million and a ceiling of $650 million. The balance of the
Remaining Interest will be valued at fair market value subject to a floor of
$141 million and a ceiling of $330 million. In either instance, the floor and
ceiling will accrue interest from the beginning of the exercise period.
If Generation increases its ownership in Sithe to 50.1% or more, Sithe
will become a consolidated subsidiary and Exelon's financial results will
include Sithe's financial results from the date of purchase. At September 30,
2002, Sithe had total assets of $4.2 billion and total debt of $2.1 billion,
including $1.6 billion of subsidiary debt incurred to finance the construction
of two new generating facilities of which $1.1 billion is associated with Sithe
New England, $0.4 billion of subordinated debt, $47 million of short-term debt,
$33 million of capital leases, and excluding $430 million of non-recourse
project debt associated with Sithe's equity investments. For the nine months
ended September 30, 2002, Sithe had revenues of $0.9 billion. As of September
30, 2002, Generation had a $722 million equity investment in Sithe.
On June 26, 2002, Generation agreed to purchase Sithe New England, a
subsidiary of Sithe, and related power marketing operations in exchange for a
$543 million note. In addition, Generation will assume various Sithe guarantees
related to an equity contribution agreement between Sithe New England and Boston
Generation, a project subsidiary of Sithe New England. The equity contribution
agreement requires, among other things, that Sithe New England, upon the
occurrence of certain events, contribute up to $38 million of equity for the
purpose of completing the construction of two generating facilities. Boston
Generation established a $1.2 billion credit facility in order to finance the
construction of these two generating facilities. The approximately $1.1 billion
expected to be outstanding under the facility at the transaction closing date,
will be reflected on Exelon's Consolidated Balance Sheet. Sithe New England has
provided security interests in and has pledged the stock of its other project
subsidiaries to Boston Generation. If the closing conditions are satisfied, the
transaction could be completed in November 2002.
Additionally, the debt on the books of Exelon's unconsolidated equity
investments and joint ventures is not reflected on Exelon's Consolidated Balance
77
Sheets. Total investee debt, at September 30, 2002, including the debt of Sithe
described in the preceding paragraph, is currently estimated to be $2.2 billion
($1.1 billion based on Exelon's ownership interest of the investments).
Generation and British Energy plc (British Energy), Generation's joint
venture partner in AmerGen, have each agreed to provide up to $100 million to
AmerGen at any time that the Management Committee of AmerGen determines that in
order to protect the public health and safety and/or to comply with Nuclear
Regulatory Commission (NRC) requirements, such funds are necessary to meet
ongoing operating expenses or to safely maintain any AmerGen plant.
Other Factors
Exelon's costs of providing pension and postretirement benefit plans
are dependent upon a number of factors, such as the rates of return on pension
plan assets, discount rate, and the rate of increase in health care costs. The
market value of plan assets has been affected by sharp declines in the equity
market since the third quarter of 2000. As a result, at December 31, 2002,
Exelon could be required to recognize an additional minimum liability as
prescribed by SFAS No. 87 "Employers' Accounting for Pensions" and 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. Based upon the market
value of plan assets at September 30, 2002 and estimated market performance for
the remainder of 2002, the amount of the reduction to common equity (net of
income taxes) is estimated to be in the range of $500 million to $1.0 billion.
This estimate could increase or decrease as a result of actual market
performance in the fourth quarter of 2002. The recording of this reduction would
not affect net income or cash flow in 2002 or compliance with debt covenants;
however, pension cost and cash funding requirements could increase in future
years without a substantial recovery in the equity markets.
Approximately $33 million was included in operating and maintenance
expense in 2001 for the cost of Exelon's pension and post-retirement benefit
plans, exclusive of the 2001 charges for employee severance programs. These
costs are expected to increase in 2002 by approximately $55 million as the
result of the effects of the decline in market value of plan assets and discount
rates, and increases in health care costs. Further increases in pension and
postretirement expense are expected for the year 2003 as a result of the same
factors. Although the 2003 increase will depend on market conditions, Exelon
preliminarily estimates that pension and postretirement benefit costs will
increase by approximately $70 million in 2003 from 2002 cost levels.
Exelon's defined benefit pension plans currently meet the minimum
funding requirements of the Employment Retirement Income Security Act of 1974;
however, Exelon currently expects to make a discretionary plan contribution in
the fourth quarter of 2002 of $100 million to $200 million and a discretionary
plan contribution in 2003 of $300 million to $350 million. These contributions
are expected to be funded primarily by internally generated cash flows from
operations or through external sources.
78
Generation is a counterparty to Dynegy Inc. (Dynegy) in various energy
transactions. In early July 2002, the credit ratings of Dynegy were downgraded
by two credit rating agencies to below investment grade. As of September 30,
2002, Generation had a net receivable from Dynegy of approximately $7 million,
and consistent with the terms of the existing credit arrangement, has received
collateral in support of this receivable. Generation also has credit risk
associated with Dynegy through Generation's equity investment in Sithe. Sithe is
a 60% owner of the Independence generating station, a 1,040 MW gas-fired
qualified facility that has an energy only long-term tolling arrangement with
Dynegy, with a related financial swap arrangement. As of September 30, 2002,
Sithe had recognized an asset on its balance sheet related to the fair value of
the financial swap agreement with Dynegy that is marked-to-market under the
terms of SFAS No. 133. If Dynegy is unable to fulfill the terms of this
agreement, Sithe would be required to write-off the fair value asset, which
Generation estimates would result in an approximate $22 million reduction in its
equity earnings from Sithe, based on Generation's current 49.9% investment
ownership in Sithe. The fair value of this asset may change over time.
Additionally, the future economic value of Sithe's investment in the
Independence Station and AmerGen's purchased power arrangement with Illinois
Power, a subsidiary of Dynegy, could be impacted by events related to Dynegy's
financial condition.
79
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 September 30, 2002 Compared to Three Months Ended September 30, 2001
Significant Operating Trends - ComEd
Three Months Ended September 30,
--------------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 1,938 $1,919 $ 19 1.0%
OPERATING EXPENSES
Purchased Power 975 954 21 2.2%
Operating and Maintenance 267 265 2 0.8%
Depreciation and Amortization 129 178 (49) (27.5%)
Taxes Other Than Income 77 82 (5) (6.1%)
- -------------------------------------------------------------------------------------------------------
Total Operating Expense 1,448 1,479 (31) (2.1%)
- -------------------------------------------------------------------------------------------------------
OPERATING INCOME 490 440 50 11.4%
- -------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (122) (147) 25 (17.0%)
Distributions on Company-Obligated Mandatorily
Redeemable Preferred Securities of Subsidiary Trusts
Holding Solely the Company's Subordinated Debt Securities (7) (7) -- --
Other, net -- 33 (33) (100.0%)
- -------------------------------------------------------------------------------------------------------
Total Other Income and Deductions (129) (121) (8) (6.6%)
- -------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 361 319 42 13.2%
INCOME TAXES 146 141 5 3.5%
- -------------------------------------------------------------------------------------------------------
NET INCOME $ 215 $ 178 $ 37 20.8%
=======================================================================================================
Net Income
Net income increased $37 million, or 21% for the three months ended
September 30, 2002. Net income was impacted by the favorable effect of warmer
than normal summer weather, lower depreciation rates, the discontinuation of
goodwill amortization and a lower effective income tax rate, partially offset by
the effects of a 5% residential rate reduction and customers electing to
purchase energy from an ARES or the PPO.
80
Operating Revenues
ComEd's electric sales statistics are as follows:
Three Months Ended September 30,
--------------------------------
Retail Deliveries - (in GWh) 2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
Bundled Deliveries (1)
Residential 9,121 8,398 723 8.6%
Small Commercial & Industrial 6,029 6,308 (279) (4.4%)
Large Commercial & Industrial 2,073 2,506 (433) (17.3%)
Public Authorities & Electric Railroads 1,612 2,105 (493) (23.4%)
- -------------------------------------------------------------------------------------------------------
18,835 19,317 (482) (2.5%)
- -------------------------------------------------------------------------------------------------------
Unbundled Deliveries (2)
ARES
Small Commercial & Industrial 1,640 898 742 82.6%
Large Commercial & Industrial 2,192 1,548 644 41.6%
Public Authorities & Electric Railroads 299 91 208 n.m.
- -------------------------------------------------------------------------------------------------------
4,131 2,537 1,594 62.8%
- -------------------------------------------------------------------------------------------------------
PPO
Small Commercial & Industrial 782 827 (45) (5.4%)
Large Commercial & Industrial 1,249 1,448 (199) (13.7%)
Public Authorities & Electric Railroads 345 150 195 (130.0%)
- -------------------------------------------------------------------------------------------------------
2,376 2,425 (49) (2.0%)
- -------------------------------------------------------------------------------------------------------
Total Unbundled Deliveries 6,507 4,962 1,545 31.1%
- -------------------------------------------------------------------------------------------------------
Total Retail Deliveries 25,342 24,279 1,063 4.4%
=======================================================================================================
<FN>
(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.
n.m. - not meaningful
</FN>
81
Three Months Ended September 30,
--------------------------------
Electric Revenue 2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
Bundled Revenues (1)
Residential $ 840 $ 816 $ 24 2.9%
Small Commercial & Industrial 506 531 (25) (4.7%)
Large Commercial & Industrial 106 126 (20) (15.9%)
Public Authorities & Electric Railroads 104 119 (15) (12.6%)
- -------------------------------------------------------------------------------------------------------
1,556 1,592 $ (36) (2.3%)
- -------------------------------------------------------------------------------------------------------
Unbundled Revenues (2)
ARES
Small Commercial & Industrial 51 10 41 n.m.
Large Commercial & Industrial 60 12 48 n.m.
Public Authorities & Electric Railroads 10 1 9 n.m.
- -------------------------------------------------------------------------------------------------------
121 23 98 n.m.
- -------------------------------------------------------------------------------------------------------
PPO
Small Commercial & Industrial 57 77 (20) (25.9%)
Large Commercial & Industrial 74 120 (46) (38.3%)
Public Authorities & Electric Railroads 19 13 6 46.2%
- -------------------------------------------------------------------------------------------------------
150 210 (60) (28.6%)
- -------------------------------------------------------------------------------------------------------
Total Unbundled Revenues 271 233 38 16.3%
- -------------------------------------------------------------------------------------------------------
Total Electric Retail Revenues 1,827 1,825 2 0.1%
Wholesale and Miscellaneous Revenue (3) 111 94 17 18.1%
- -------------------------------------------------------------------------------------------------------
Total Electric Revenue $ 1,938 $ 1,919 $ 19 1.0%
=======================================================================================================
<FN>
(1) Bundled revenue reflects deliveries to customers taking electric service
under tariffed rates, which include the cost of energy and the delivery
cost of the transmission and the distribution of the energy.
(2) Revenue from customers choosing an ARES includes a distribution charge and
a CTC charge. Transmission charges received from ARES are included in
wholesale and miscellaneous revenue. Revenues from customers choosing the
PPO includes an energy charge at market rates, transmission, and
distribution charges and a CTC charge.
(3) Wholesale and miscellaneous revenues include sales to ARES, transmission
revenue, sales to municipalities and other wholesale energy sales.
</FN>
The changes in electric retail revenues for the three months ended
September 30, 2002, as compared to the three months ended September 30, 2001,
are attributable to the following:
Variance
- -------------------------------------------------------------------------------------------------
Weather $ 86
Rate Changes (45)
Customer Choice (43)
Other Effects 4
- -------------------------------------------------------------------------------------------------
Electric Retail Revenue $ 2
=================================================================================================
o Weather. The demand for electricity is impacted by weather conditions. Very
warm weather in summer months and very cold weather in other months is
referred to as "favorable weather conditions," because these weather
conditions result in increased sales of electricity. Conversely, mild
weather reduces demand.
The weather impact for the three months ended September 30, 2002
was favorable compared to the three months ended September 30, 2001 as a
result of warmer summer weather in the third quarter of 2002 as compared to
the third quarter of 2001. Cooling degree-days increased 26% in the three
82
months ended September 30, 2002 compared to the three months ended
September 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 became
eligible to choose their supplier of electricity. However, as of September
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 September 30, 2002,
approximately 22,700 retail customers had elected to purchase energy from
an ARES or the ComEd PPO, an increase from 15,400 customers at September
30, 2001. The MWhs delivered to such customers increased from approximately
5.0 million for the three months ended September 30, 2001 to 6.5 million
for the three months ended September 30, 2002, or a 31% increase from the
previous year.
o Other Effects. The slowing economy both nationally and regionally has
yielded minimal quarterly gains as business uncertainty and unemployment
concerns limit customer activity and electricity sales.
The increase in wholesale and miscellaneous revenue for the three
months ended September 30, 2002 as compared to the three months ended September
30, 2001 was due primarily to reimbursement from Generation of $12 million for
the third-party energy reconciliations.
Purchased Power Expense
Purchased power expense increased $21 million, or 2% for the three
months ended September 30, 2002. The increase in purchased power expense was
primarily attributable to a $38 million increase associated with additional
increased weather related on-peak sales volume, a $22 million increase due to an
increase in the weighted average on-peak/off-peak cost per MWh and $20 million
in additional expense resulting from additional energy billed under the PPA with
Generation as a result of the third-party energy reconciliations discussed in
the operating revenue section above, partially offset by a $62 million decrease
as a result of customers choosing to purchase energy from an ARES.
Operating and Maintenance Expense
Operating and maintenance (O&M) expense increased $2 million, or 1%,
for the three months ended September 30, 2002. The increase in O&M expense
reflects a $17 million increase in the reserve for MGP investigation and
remediation as a result of increased costs due to delays in the implementation
of ongoing remediation of a MGP site in Oak Park, Illinois partially offset by
operating productivity improvements and a $7 million decrease in other O&M
items.
83
Depreciation and Amortization Expense
Depreciation and amortization expense decreased $49 million, or 28%,
for the three months ended September 30, 2002 as follows:
Three Months Ended September 30,
--------------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
Depreciation Expense $ 75 $ 87 $ (12) (13.8%)
Recoverable Transition Costs Amortization 33 35 (2) (5.7%)
Other Amortization Expense 21 56 (35) (62.5%)
- -------------------------------------------------------------------------------------------------------
Total Depreciation and Amortization $ 129 $ 178 $ (49) (27.5%)
=======================================================================================================
The decrease in depreciation expense is primarily due to lower
depreciation rates effective July 1, 2002, partially offset by higher property,
plant and equipment balances. ComEd completed a depreciation study and
implemented lower depreciation rates effective July 1, 2002. The new
depreciation rates reflect ComEd's significant construction program in recent
years, changing in and development of new technologies, and changes in estimated
plant service lives since the last depreciation study. The annual reduction in
depreciation expense is estimated to be approximately $100 million ($60 million,
net of income taxes) based on December 31, 2001 plant balances. As a result of
the change, depreciation expense decreased $24 million ($14 million, net of
income taxes) for the three month period ended September 30, 2002.
The decrease in other amortization expense is primarily due to a
decrease of $32 million due to the discontinuation of goodwill amortization
effective January 1, 2002 upon the adoption of SFAS No. 142.
Recoverable transition costs amortization was consistent in the three
months ended September 30, 2002 compared to the same period in 2001. ComEd
expects to fully recover its recoverable transition costs regulatory asset
balance of $202 million by 2004. Consistent with the provision of the Illinois
legislation, regulatory assets may be recovered at amounts that provide ComEd an
earned return on common equity within the Illinois legislation earnings
threshold.
Taxes Other Than Income
Taxes other than income decreased $5 million, or 6%, for the three
months ended September 30, 2002. Taxes other than income were positively
affected in 2002 as a result of a real estate tax refund in the amount of $5
million.
Interest Charges
Interest charges consist of interest expense and distributions on
Company-Obligated Mandatorily Redeemable Preferred Securities of Subsidiary
Trusts. Interest charges decreased $25 million, or 17%, for the three months
ended September 30, 2002. The decrease in interest charges was primarily
attributable to the impact of lower interest rates for the three months ended
September 30, 2002 as compared to the three months ended September 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 September
2001 and $10 million of intercompany interest expense in 2001 relating to a
payable to Generation, which was repaid during 2001.
84
Other Income and Deductions
Other income and deductions, excluding interest charges, decreased $33
million, or 100%, for the three months ended September 30, 2002. The decrease
was primarily attributable to $9 million in intercompany interest income from
Generation in 2001 on the processing of certain invoice payments on behalf of
Generation, a $6 million reduction in intercompany interest income from Unicom
Investment Inc., reflecting lower interest rates, a $12 million accrual in 2002
for estimated minimum probable write-off exposure resulting from the Liberty
audit findings related to ComEd's delivery services rate case and a $6 million
decrease in various other income and deductions items.
Income Taxes
The effective income tax rate was 40.4% for the three months ended
September 30, 2002, compared to 44.2% for the three months ended September 30,
2001. The decrease in the effective tax rate was primarily attributable to the
discontinuation of goodwill amortization as of January 1, 2002, which was not
deductible for income tax purposes.
Nine Months Ended September 30, 2002 Compared to Nine Months Ended September 30,
2001
Significant Operating Trends - ComEd
Nine Months Ended September 30,
-------------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 4,734 $ 4,895 $ (161) (3.3%)
OPERATING EXPENSES
Purchased Power 2,066 2,149 (83) (3.9%)
Operating and Maintenance 724 731 (7) (1.0%)
Depreciation and Amortization 397 512 (115) (22.5%)
Taxes Other Than Income 223 223 -- --
- -------------------------------------------------------------------------------------------------------
Total Operating Expense 3,410 3,615 (205) (5.7%)
- -------------------------------------------------------------------------------------------------------
OPERATING INCOME 1,324 1,280 44 3.4%
- -------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (374) (433) 59 (13.6%)
Distributions on Company-Obligated Mandatorily
Redeemable Preferred Securities of Subsidiary Trusts
Holding Solely the Company's Subordinated Debt Securities (22) (22) -- --
Other, net 29 94 (65) (69.1%)
- -------------------------------------------------------------------------------------------------------
Total Other Income and Deductions (367) (361) (6) 1.7%
- -------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 957 919 38 4.1%
INCOME TAXES 381 412 (31) (7.5%)
- -------------------------------------------------------------------------------------------------------
NET INCOME $ 576 $ 507 $ 69 13.6%
=======================================================================================================
Net Income
Net income increased $69 million, or 14% for the nine months ended
September 30, 2002. Net income was primarily impacted by the discontinuation of
goodwill amortization and a lower effective income tax rate partially offset by
85
the effects of a 5% residential rate reduction and customers electing to
purchase energy from an ARES or the PPO.
Operating Revenues
ComEd's electric sales statistics are as follows:
Nine Months Ended September 30,
-------------------------------
Retail Deliveries - (in GWh) 2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
Bundled Deliveries (1)
Residential 21,392 19,936 1,456 7.3%
Small Commercial & Industrial 17,078 17,986 (908) (5. 1%)
Large Commercial & Industrial 6,151 8,144 (1,993) (24.5%)
Public Authorities & Electric Railroads 5,097 6,007 (910) (15.1%)
- -------------------------------------------------------------------------------------------------------
49,718 52,073 (2,355) (4.5%)
- -------------------------------------------------------------------------------------------------------
Unbundled Deliveries (2)
ARES
Small Commercial & Industrial 3,822 2,005 1,817 90.6%
Large Commercial & Industrial 5,200 3,962 1,238 31.2%
Public Authorities & Electric Railroads 618 227 391 172.2%
- -------------------------------------------------------------------------------------------------------
9,640 6,194 3,446 55.6%
- -------------------------------------------------------------------------------------------------------
PPO
Small Commercial & Industrial 2,384 2,448 (64) (2.6%)
Large Commercial & Industrial 3,952 4,324 (372) (8.6%)
Public Authorities & Electric Railroads 861 734 127 17.3%
- -------------------------------------------------------------------------------------------------------
7,197 7,506 (309) (4.1%)
- -------------------------------------------------------------------------------------------------------
Total Unbundled Deliveries 16,837 13,700 3,137 22.9%
- -------------------------------------------------------------------------------------------------------
Total Retail Deliveries 66,555 65,773 782 1.2%
=======================================================================================================
<FN>
(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.
</FN>
86
Nine Months Ended September 30,
-------------------------------
Electric Revenue 2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
Bundled Revenues (1)
Residential $ 1,881 $ 1,852 $ 29 1.6%
Small Commercial & Industrial 1,343 1,410 (67) (4.8%)
Large Commercial & Industrial 324 406 (82) (20.2%)
Public Authorities & Electric Railroads 297 335 (38) (11.3%)
- -------------------------------------------------------------------------------------------------------
3,845 4,003 (158) (3.9%)
- -------------------------------------------------------------------------------------------------------
Unbundled Revenues (2)
ARES
Small Commercial & Industrial 94 36 58 161.1%
Large Commercial & Industrial 101 60 41 68.3%
Public Authorities & Electric Railroads 18 3 15 n.m.
- -------------------------------------------------------------------------------------------------------
213 99 114 115.2%
- -------------------------------------------------------------------------------------------------------
PPO
Small Commercial & Industrial 155 167 (12) (7.2%)
Large Commercial & Industrial 214 267 (53) (19.9%)
Public Authorities & Electric Railroads 48 44 4 9.1%
- -------------------------------------------------------------------------------------------------------
417 478 (61) (12.8%)
- -------------------------------------------------------------------------------------------------------
Total Unbundled Revenues 630 577 53 9.2%
- -------------------------------------------------------------------------------------------------------
Total Electric Retail Revenues 4,475 4,580 (105) (2.3%)
Wholesale and Miscellaneous Revenue (3) 259 315 (56) (17.8%)
- -------------------------------------------------------------------------------------------------------
Total Electric Revenue $ 4,734 $ 4,895 $ (161) (3.3%)
=======================================================================================================
<FN>
(1) Bundled revenue reflects deliveries to customers taking electric service
under tariffed rates, which include the cost of energy and the delivery
cost of the transmission and the distribution of the energy.
(2) Revenue from customers choosing an ARES includes a distribution charge and
a CTC charge. Transmission charges received from ARES are included in
wholesale and miscellaneous revenue. Revenues from customers choosing the
PPO includes an energy charge at market rates, transmission, and
distribution charges and a CTC charge.
(3) Wholesale and miscellaneous revenues include sales to ARES, transmission
revenue, sales to municipalities and other wholesale energy sales.
</FN>
The changes in electric retail revenues for the nine months ended
September 30, 2002, as compared to the nine months ended September 30, 2001, are
attributable to the following:
Variance
- -------------------------------------------------------------------------------------------------
Customer Choice $ (121)
Rate Changes (99)
Weather 73
Other Effects 42
- -------------------------------------------------------------------------------------------------
Retail Revenue $ (105)
- -------------------------------------------------------------------------------------------------
o Customer Choice. The decrease in revenues reflects customers in Illinois
electing to purchase energy from an ARES or the PPO. As of September 30,
2002, approximately 22,700 retail customers had elected to purchase energy
from an ARES or the ComEd PPO, an increase from 15,400 customers at
September 30, 2001. The MWhs delivered to such customers increased from
approximately 13.7 million for the nine months ended September 30, 2001 to
16.8 million for the nine months ended September 30, 2002, a 23% increase
from the previous year.
87
o Rate Changes. The decrease attributable to rate changes reflects a 5%
residential rate reduction, effective October 1, 2001, required by the
Illinois restructuring legislation.
o Weather. The weather impact for the nine months ended September 30, 2002
was favorable compared to the nine months ended September 30, 2001 as a
result of warmer summer weather partially offset by warmer winter weather
in 2002 compared to 2001. Cooling degree-days increased 27% and were
partially offset by a 7% decrease in heating degree-days in the nine months
ended September 30, 2002 compared to the nine months ended September 30,
2001.
o Other Effects. A strong housing construction market in Chicago contributed
to residential and small commercial and industrial customer volume growth
in the early portion of the year, partially offset by the unfavorable
impact of a slower economy on large commercial and industrial customers.
The reduction in wholesale and miscellaneous revenue for the nine
months ended September 30, 2002 as compared to the nine months ended September
30, 2001 was due primarily to a $38 million decrease in off-system sales due to
the expiration of wholesale contracts that were offered by ComEd from June 2000
to May 2001 to support the open access program in Illinois, a $15 million
reversal of reserve for revenue refunds in 2001 related to certain of ComEd's
municipal customers as a result of a favorable FERC ruling, and $15 million of
other miscellaneous revenue partially offset by a reimbursement from Generation
of $12 million for third-party energy reconciliations.
Purchased Power Expense
Purchased power expense decreased $83 million, or 4% for the nine
months ended September 30, 2002. The decrease in purchased power expense was
primarily attributable to a $124 million decrease as a result of customers
choosing to purchase energy from an ARES and a $34 million decrease due to the
expiration of the wholesale contracts offered by ComEd to support the open
access program in Illinois partially offset by a $33 million associated with
increased retail demand due to favorable weather conditions, a $5 million
increase due to the effects of a strong housing construction market in Chicago
for residential and small commercial and industrial customers, a $17 million
increase due to an increase in the weighted average on-peak/off-peak cost per
MWh, and $20 million in additional expense as a result of third-party energy
reconciliations.
Operating and Maintenance Expense
The $7 million decrease in O&M expense was primarily due to operating
productivity improvements and the $11 million reduction in the allowance for
uncollectible accounts recorded in the second quarter, partially offset by a $17
million increase in the provision for injury and damages claims and a $16
million increase in environmental investigation and remediation expense.
88
Depreciation and Amortization Expense
Depreciation and amortization expense decreased $115 million, or 23%,
for the nine months ended September 30, 2002 as follows:
Nine Months Ended September 30,
-------------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
Depreciation Expense $ 258 $ 263 $ (5) (1.9)%
Recoverable Transition Costs Amortization 75 89 (14) (15.7%)
Other Amortization Expense 64 160 (96) (60.0)%
- -------------------------------------------------------------------------------------------------------
Total Depreciation and Amortization $ 397 $ 512 $ (115) (22.5)%
=======================================================================================================
The decrease in depreciation expense is due to $24 million related to
lower depreciation rates partially offset by the effect of higher property,
plant and equipment balances.
Recoverable transition costs amortization expense is determined using
the expected period of the rate freeze and the expected returns in the periods
under the rate freeze. The reduction in amortization expense in 2002 is due to
the second quarter of 2002 extension of the rate freeze partially offset by an
increase due to a third quarter of 2002 change in the expected returns during
the rate freeze period.
The decrease in other amortization expense is primarily due to a
decrease of $97 million due to discontinuation of goodwill amortization
effective January 1, 2002 upon the adoption of SFAS No. 142.
Taxes Other Than Income
Taxes other than income remained consistent from period to period.
Interest Charges
Interest charges decreased $59 million, or 14%, for the nine months
ended September 30, 2002. The decrease in interest charges was primarily
attributable to the impact of lower interest rates for the nine months ended
September 30, 2002 as compared to the nine months ended September 30, 2001, the
early retirement of the $196 million of First Mortgage Bonds in November of
2001, the retirement of $340 million in transitional trust notes since September
2001, and $10 million of intercompany interest expense in 2001 relating to a
payable in Generation, which was repaid during 2001.
Other Income and Deductions
Other income and deductions, excluding interest charges, decreased $65
million, or 69%, for the nine months ended September 30, 2002. The decrease was
primarily attributable to $8 million in intercompany interest income relating to
the $400 million receivable from PECO which was repaid during the second quarter
of 2001, a $28 million reduction in intercompany interest income from Unicom
Investment Inc., reflecting lower interest rates, $9 million in intercompany
interest income from Generation in 2001 on the processing of certain invoice
payments on behalf of Generation, a $12 million reserve for a potential plant
disallowance resulting from an audit performed in conjunction with ComEd's
delivery services rate case, and an $8 million decrease in various other income
and deductions items.
89
Income Taxes
The effective income tax rate was 39.8% for the nine months ended
September 30, 2002, compared to 44.8% for the nine months ended September 30,
2001. The decrease in the effective tax rate was primarily attributable to the
discontinuation of goodwill amortization as of January 1, 2002, which was not
deductible for income tax purposes.
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 dividends.
Cash Flows from Operating Activities
Cash flows provided by operations for the nine months ended September
30, 2002 were $1.5 billion as compared to $1.0 billion for the nine months ended
September 30, 2001. The increase in cash flows in 2002 was primarily
attributable to a $69 million increase in net income, a $113 million increase in
other operating activities, and a $315 million increase in working capital
partially offset by a decrease of $115 million in depreciation and amortization.
ComEd's future cash flows will depend upon the ability to achieve reductions in
operating costs, the impact of the economy, weather, and customer choice on its
revenues. Although the amounts may vary from period to period as a result of
uncertainties inherent in the business, ComEd expects to continue to provide a
reliable and steady source of internal cash flow from operations for the
foreseeable future.
Cash Flows from Investing Activities
Cash flows used in investing activities were $526 million for the nine
months ended September 30, 2002 compared to $231 million for the nine months
ended September 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 $82 million decrease in capital expenditures. ComEd's investing activities
for the nine months ended September 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 issuance
of preferred securities, or capital contributions from Exelon. ComEd's proposed
capital expenditures and other investments are subject to periodic review and
revision to reflect changes in economic conditions and other factors.
90
Cash Flows from Financing Activities
Cash flows used in financing activities for the nine months ended
September 30, 2002 were $970 million as compared to $518 million for the nine
months ended September 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 nine months ended September 30, 2002
reflected the issuance of $600 million of First Mortgage Bonds, the issuance of
$100 million of Illinois Development Finance Authority floating-rate Pollution
Control Revenue Refunding Bonds, the retirement of $254 million of transitional
trust notes, the early retirement of $600 million in First Mortgage Bonds with
available cash, the payment at maturity of $200 million in First Mortgage Bonds,
the payment at maturity of $200 million in variable rate senior notes, and the
redemption of $100 million of 7.25% Illinois Development Finance Authority
Pollution Control Revenue Refunding Bonds. As of September 30, 2002, ComEd had
$94 million in short-term borrowings. For the nine months ended September 30,
2001, ComEd's debt financing activities reflected the retirement of $254 million
of transitional trust notes. ComEd paid a $353 million dividend to Exelon during
the nine months ended September 30, 2002 compared to a $253 million dividend for
the nine months ended September 30, 2001.
Credit Issues
ComEd meets its short-term liquidity requirements primarily through the
issuance of commercial paper, borrowings under a bank credit facility and
borrowings from Exelon's intercompany money pool. ComEd, along with Exelon,
PECO, and Generation, participates in a $1.5 billion unsecured 364-day revolving
credit facility with a group of banks effective December 12, 2001. Under the
terms of this credit facility, Exelon has the flexibility to increase or
decrease the sublimits of each of the participants upon written notification to
these banks. As of September 30, 2002, ComEd's sublimit under this credit
facility is $200 million. ComEd expects to use the credit facility principally
to support its commercial paper program. This credit facility requires ComEd to
maintain a debt to total capitalization ratio of 65% or less, excluding
securitization debt. At September 30, 2002, ComEd's debt to total capitalization
ratio on that basis was 42%. At September 30, 2002, ComEd has $94 million in
commercial paper outstanding.
To provide an additional short-term borrowing option that will
generally be more favorable to the borrowing participants than the cost of
external financing, Exelon operates an intercompany money pool. Participation in
the money pool is subject to authorization by the Exelon Corporate Treasurer.
Exelon, ComEd and its subsidiary Commonwealth Edison of Indiana, Inc., PECO,
Generation and Business Services Company currently may participate in the money
pool. Funding of, and borrowings from, the money pool are predicated on whether
such funding results in mutual economic benefits to each of the participants,
although Exelon is not permitted to be a net borrower from the fund. Interest on
borrowings is based on short-term market rates of interest, or specific
borrowing rates if the funds are provided by external financing. There have been
no material money pool transactions in 2002.
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 credit ratings although such a downgrading could
increase interest charges under certain bank credit facilities.
91
At September 30, 2002, ComEd's capital structure, excluding the
deduction from shareholders' equity of the $845 million receivable from Exelon,
consisted of 48% long-term debt, 49% of common stock, 3% of preferred securities
of subsidiaries, and 1% of notes payable. Long-term debt included $2.1 billion
of transitional trust notes constituting obligations of certain consolidated
special purpose entities representing 16% of capitalization.
Under PUHCA and the Federal Power Act, ComEd can only pay dividends
from retained or current earnings: however, 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 September 30, 2002, ComEd had retained earnings of
$480 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 September 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 6.15% First Mortgage
Bonds, Series 98, due March 15, 2012, the issuance of $100 million of Illinois
Development Finance Authority floating-rate Pollution Control Revenue Refunding
Bonds, Series 2002 due April 15, 2013, the redemption of $100 million of 7.25%
Illinois Development Finance Authority Pollution Control Revenue Refunding
Bonds, Series 1991 due June 1, 2011, the redemption of $200 million of 8.625%
First Mortgage Bonds, Series 81, due February 1, 2022, the redemption of $200
million of 8.5% First Mortgage Bonds, Series 84 due July 15, 2022, the payment
at maturity of $200 million of 7.375% First Mortgage Bonds, Series 85, due
September 15, 2002, the redemption of $200 million of 8.375% First Mortgage
Bonds, Series 86, due September 15, 2022, the payment at maturity of $200
million of variable rate senior notes due September 30, 2002, the payment at
maturity of $100 million of 9.17% medium-term notes due October 15, 2002, and
the retirement of $254 million in transitional trust notes. At September 30,
2002, ComEd had $94 million in short-term borrowings. Insured long-term debt
increased $100 million related to the issuance of $100 million in variable rate
debt that has been credit enhanced through the purchase of insurance coverage.
Other Factors
ComEd is a participant in Exelon's pension and postretirement benefit
plans. ComEd's costs of providing pension and postretirement benefits to its
retirees are dependent a number of factors, such as the discount rate, rates of
return on plan assets, and the assumed rate of increase in health care costs.
Approximately $17 million was included in operating and maintenance expense in
2001 for the cost of pension and post-retirement benefit plans, exclusive of the
2001 charges for employee severance programs. These costs are expected to remain
consistent in 2002 but are preliminarily expected to increase by approximately
$25 million in 2003 as a result of the effects of the decline in market value of
plan assets and discount rates, and increases in health care costs. The actual
amount of the 2003 increase will depend on market conditions.
92
Exelon's defined benefit pension plans, of which ComEd is a
participant, currently meet the minimum funding requirements of the Employment
Retirement Income Security Act of 1974; however, Exelon currently expects to
make a discretionary plan contribution in the fourth quarter of 2002 of $100
million to $200 million and a discretionary plan contribution in 2003 of $300
million to $350 million. These contributions are expected to be funded primarily
by Exelon's internally generated cash flows from operations or through external
sources.
93
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 September 30, 2002 Compared to Three Months Ended September 30, 2001
Significant Operating Trends - PECO Three Months Ended September 30,
--------------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 1,224 $1,051 $ 173 16.5%
OPERATING EXPENSES
Purchased Power 509 420 89 21.2%
Fuel 40 51 (11) (21.6%)
Operating and Maintenance 140 156 (16) (10.3%)
Depreciation and Amortization 127 115 12 10.4%
Taxes Other Than Income 85 51 34 66.7%
- -------------------------------------------------------------------------------------------------------
Total Operating Expense 901 793 108 13.6%
- -------------------------------------------------------------------------------------------------------
OPERATING INCOME 323 258 65 25.2%
- -------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (93) (105) 12 (11.4%)
Distributions on Company-Obligated Mandatorily
Redeemable Preferred Securities of a Partnership
which holds Solely Subordinated Debentures of
the Company (2) (2) -- --
Other, net 5 12 (7) (58.3%)
- -------------------------------------------------------------------------------------------------------
Total Other Income and Deductions (90) (95) 5 (5.3%)
- -------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 233 163 70 42.9%
INCOME TAXES 76 59 17 28.8%
- -------------------------------------------------------------------------------------------------------
NET INCOME 157 104 53 51.0%
Preferred Stock Dividends (2) (2) -- --
- -------------------------------------------------------------------------------------------------------
NET INCOME ON COMMON STOCK $ 155 $ 102 $ 53 52.0%
=======================================================================================================
Net Income
Net income on common stock increased $53 million, or 52% for the
quarter ended September 30, 2002 as compared to the same 2001 period. The
increase was a result of higher sales volume, favorable rate adjustments, lower
operating and maintenance expense related to employee severance costs in 2001
associated with the Merger, and lower interest expense on debt partially offset
by increased depreciation and amortization expense.
94
Operating Revenues
PECO's electric sales statistics are as follows:
Three Months Ended September 30,
--------------------------------
Deliveries - (in GWh) 2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
Bundled Deliveries (1)
Residential 3,422 2,175 1,247 57.3%
Small Commercial & Industrial 2,066 1,990 76 3.8%
Large Commercial & Industrial 4,006 3,835 171 4.5%
Public Authorities & Electric Railroads 224 193 31 16.1%
- -------------------------------------------------------------------------------------------------------
9,718 8,193 1,525 18.6%
- -------------------------------------------------------------------------------------------------------
Unbundled Deliveries (2)
Residential 371 990 (619) (62.5%)
Small Commercial & Industrial 154 100 54 54.0%
Large Commercial & Industrial 236 249 (13) (5.2%)
Public Authorities & Electric Railroads -- -- -- --
- -------------------------------------------------------------------------------------------------------
761 1,339 (578) (43.2%)
Total Retail Deliveries 10,479 9,532 947 9.9%
=======================================================================================================
<FN>
(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.
</FN>
Three Months Ended September 30,
--------------------------------
Electric Revenue 2002 2001 Variance %Change
- ---------------------------------------------------------------------------------------------------------------------
Bundled Revenue (1)
Residential $ 478 $ 304 $ 174 57.2%
Small Commercial & Industrial 251 236 15 6.4%
Large Commercial & Industrial 296 282 14 5.0%
Public Authorities & Electric Railroads 21 19 2 10.5%
- -------------------------------------------------------------------------------------------------------
1,046 841 205 24.4%
- -------------------------------------------------------------------------------------------------------
Unbundled Revenue (2)
Residential 32 81 (49) (60.5%)
Small Commercial & Industrial 9 5 4 80.0%
Large Commercial & Industrial 7 7 -- --
Public Authorities & Electric Railroads -- -- -- --
- -------------------------------------------------------------------------------------------------------
48 93 (45) (48.4%)
- -------------------------------------------------------------------------------------------------------
Total Electric Retail Revenues 1,094 934 160 17.1%
Wholesale and Miscellaneous Revenue (3) 63 42 21 50.0%
- -------------------------------------------------------------------------------------------------------
Total Electric Revenue $ 1,157 $ 976 $ 181 18.5%
=======================================================================================================
<FN>
(1) Bundled revenue reflects revenue from customers taking electric service
under tariffed rates, which includes the cost of energy, the delivery cost
of the transmission and distribution of the energy and a CTC charge.
(2) Unbundled revenue reflects revenue from customers electing to receive
generation from an alternate supplier, which include a distribution charge
and a CTC charge.
(3) Wholesale and miscellaneous revenues include transmission revenue, sales to
municipalities and other wholesale energy sales.
</FN>
95
The changes in electric retail revenues for the quarter ended September
30, 2002, as compared to the same 2001 period, are as follows:
Variance
- ------------------------------------------------------------------------------------------------------------
Weather $ 60
Customer Choice 40
Rate Changes 16
Other Effects 44
- ------------------------------------------------------------------------------------------------------------
Electric Retail Revenue $ 160
- ------------------------------------------------------------------------------------------------------------
o Weather. The demand for electricity services is impacted by weather
conditions. Very warm weather in summer months and very cold weather in
other months is referred to as "favorable weather conditions", relative to
revenue because these weather conditions result in increased sales of
electricity. Conversely, mild weather reduces demand.
The weather impact was favorable compared to the prior year as a
result of warmer summer weather. Cooling degree-days increased 20% for the
quarter ended September 30, 2002 compared to the same 2001 period.
o Customer Choice. All PECO customers have the 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 September 30, 2002, the customer load served by alternate
suppliers was 973 MW or 12.5% as compared to 1,042 MW or 13.6% as of
September 30, 2001. For the quarter ended September 30, 2002, the percent
of PECO's total retail deliveries for which PECO was the electric supplier
was 92.8% in 2002, a 6.8% increase as compared to 86.0% in 2001. As of
September 30, 2002, the number of customers served by alternate suppliers
was 285,549 or 18.7% as compared to September 30, 2001 of 397,396 or 26.1%.
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 is serving those returned customers at the
discount energy rates on generation provided for under the original New
Power CDS Agreement for the remaining term of that contract. Subsequently,
in the second quarter of 2002, New Power also advised PECO it planned to
withdraw from serving all of its customers in Pennsylvania, including
approximately 15,000 non-CDS PECO customers. These customers were returned
to PECO during the third quarter of 2002.
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. In
January 2002, the Pennsylvania Public Utility Commission (PUC) approved the
96
RNR adjustment to the gross receipts tax rate collected from customers.
Effective January 1, 2002, PECO implemented the change in the gross
receipts tax rate. The RNR adjustment increases the gross receipts tax
rate, which is estimated to increase both PECO's annual revenues and tax
obligations by approximately $50 million in 2002. The RNR adjustment was
under appeal. The case was remanded to the PUC and in August 2002, the PUC
ruled that PECO is properly authorized to recover these costs.
o Other Effects. Other items affecting revenue during the quarter ended
September 30, 2002 include:
o Volume. Exclusive of weather impacts, higher delivery volume increased
PECO's revenue by $44 million compared to the same 2001 period.
o Other. A payment of $7 million during the quarter ended September 30,
2002 as compared to a payment of $21 million during the quarter ended
September 30, 2001 to Generation related to nuclear decommissioning
cost recovery under an agreement effective September 2001.
PECO's gas sales statistics for the quarter ended September 30, 2002 as
compared to the same 2001 period are as follows:
Three Months Ended September 30,
--------------------------------
2002 2001 Variance
- --------------------------------------------------------------------------------------------------------------------
Deliveries in mmcf 11,347 10,525 822
Revenue $67 $ 75 $ (8)
- --------------------------------------------------------------------------------------------------------------------
The changes in gas revenue for the quarter ended September 30, 2002, as
compared to the same 2001 period, are as follows:
(in millions) Variance
- -------------------------------------------------------------------------------------------------------------
Rate Changes $ (4)
Weather (3)
Volume (1)
- -------------------------------------------------------------------------------------------------------------
Gas Revenue $ (8)
- -------------------------------------------------------------------------------------------------------------
o Rate Changes. The unfavorable variance in rates is attributable to an
adjustment of the purchased gas cost recovery by the PUC effective in
December 2001. The average rate per million cubic feet for the quarter
ended September 30, 2002 was 17% 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 demand for gas service is impacted by weather conditions. Very
cold weather in winter months is referred to as a "favorable weather
condition," because this weather condition results in increased sales of
gas. Conversely, mild weather reduces demand. Heating degree-days decreased
92% in the quarter ended September 30, 2002 compared to the same 2001
period.
o Volume. Exclusive of weather impact, delivery volume was consistent for the
quarter ended September 30, 2002 compared to the same 2001 period.
97
Purchased Power and Fuel Expense
Purchased power and fuel expense for the quarter ended September 30,
2002 increased $78 million as compared to the same 2001 period. The increase in
fuel and purchased power expense was primarily attributable to $38 million from
customers in Pennsylvania selecting or returning to PECO as their electric
generation supplier, $24 million as a result of favorable weather conditions,
$13 million primarily attributable to higher delivery volume and higher PJM
ancillary charges of $11 million. These increases were partially offset by $4
million from lower gas prices.
Operating and Maintenance Expense
O&M expense for the quarter ended September 30, 2002 decreased $16
million, or 10%, as compared to the same 2001 period. The decrease in O&M
expense was primarily attributable to $18 million of employee severance costs
associated with the Merger and $6 million of incremental costs related to a
storm, both of which occurred in the third quarter of 2001. The decreases are
partially offset by $7 million related to an increased allocation of corporate
expense and $3 million related to the deployment of automated meter reading
technology.
Depreciation and Amortization Expense
Depreciation and amortization expense for the quarter ended September
30, 2002 increased $12 million, or 10%, as compared to the same 2001 period as
follows:
Three Months Ended September 30,
--------------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
Depreciation Expense $ 31 $ 30 $ 1 3.3%
Competitive Transition Charge Amortization 90 78 12 15.4%
Other Amortization Expense 6 7 (1) (14.3%)
- -------------------------------------------------------------------------------------------------------
Total Depreciation and Amortization $ 127 $ 115 $ 12 10.4%
=======================================================================================================
The increase was primarily attributable to $12 million of additional
amortization of PECO's CTC and an increase of $1 million related to depreciation
expense associated with additional plant in service. The additional amortization
of the CTC is in accordance with PECO's original settlement under the
Pennsylvania Competition Act.
Taxes Other Than Income
Taxes other than income for the quarter ended September 30, 2002
increased $34 million, or 67%, as compared to the same 2001 period. The increase
was primarily attributable to $14 million of additional gross receipts tax
related to additional revenues and an increase in the gross receipts tax rate on
electric revenue effective January 1, 2002. The increase was also attributable
to a reduction of $9 million in the state use tax accruals in 2001 and $7
million related to an additional assessment of real estate taxes in the third
quarter of 2002.
98
Interest Charges
Interest charges consist of interest expense and distributions on
Company-Obligated Mandatorily Redeemable Preferred Securities of a Partnership
(COMRPS). Interest charges decreased $12 million, or 11%, in the quarter ended
September 30, 2002 as compared to the same 2001 period. The decrease was
primarily attributable to lower interest expense on long-term debt of $15
million as a result of principal payments and lower interest rates.
Other Income and Deductions
Other income and deductions excluding interest charges for the quarter
ended September 30, 2002 decreased $7 million, or 58%, as compared to the same
2001 period. The decrease in other income and deductions was primarily
attributable to intercompany interest income of $9 million in the third quarter
of 2001.
Income Taxes
The effective tax rate was at 32.6% for the quarter ended September 30,
2002 as compared to 36.2% for the same 2001 period. The decrease in the
effective tax rate was primarily attributable to a favorable adjustment to prior
period income taxes in connection with the completion of the 2001 tax return.
Preferred Stock Dividends
Preferred stock dividends for the quarter ended September 30, 2002 were
consistent as compared to the same 2001 period.
99
Nine Months Ended September 30, 2002 Compared to Nine Months Ended September 30,
2001
Significant Operating Trends - PECO
Nine Months Ended September 30,
--------------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 3,239 $3,008 $ 231 7.7%
OPERATING EXPENSES
Purchased Power 1,265 1,019 246 24.1%
Fuel 228 335 (107) (31.9%)
Operating and Maintenance 407 413 (6) (1.5%)
Depreciation and Amortization 348 315 33 10.5%
Taxes Other Than Income 207 135 72 53.3%
- -------------------------------------------------------------------------------------------------------
Total Operating Expense 2,455 2,217 238 10.7%
- -------------------------------------------------------------------------------------------------------
OPERATING INCOME 784 791 (7) (0.9%)
- -------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (280) (332) 52 (15.7%)
Distributions on Company-Obligated Mandatorily
Redeemable Preferred Securities of a Partnership
which holds Solely Subordinated Debentures of
the Company (7) (7) -- --
Other, net 7 30 (23) (76.7%)
- -------------------------------------------------------------------------------------------------------
Total Other Income and Deductions (280) (309) 29 (9.4%)
- -------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 504 482 22 4.6%
INCOME TAXES 166 171 (5) (2.9%)
- -------------------------------------------------------------------------------------------------------
NET INCOME 338 311 27 8.7%
Preferred Stock Dividends (6) (7) 1 (14.3%)
- -------------------------------------------------------------------------------------------------------
NET INCOME ON COMMON STOCK $ 332 $ 304 $ 28 9.2%
=======================================================================================================
Net Income
Net income on common stock increased $28 million, or 9%, for the nine
months ended September 30, 2002 as compared to the same 2001 period. The
increase was a result of higher sales volume, favorable rate adjustments, lower
operating and maintenance expense related to employee severance costs in 2001
associated with the Merger, and lower interest expense on debt partially offset
by increased depreciation and amortization expense.
100
Operating Revenue
PECO's electric sales statistics are as follows:
Nine Months Ended September 30,
--------------------------------
Deliveries - (in GWh) 2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
Bundled Deliveries (1)
Residential 7,592 6,307 1,285 20.4%
Small Commercial & Industrial 5,704 4,303 1,401 32.6%
Large Commercial & Industrial 11,285 9,538 1,747 18.3%
Public Authorities & Electric Railroads 617 567 50 8.8%
- -------------------------------------------------------------------------------------------------------
25,198 20,715 4,483 21.6%
- -------------------------------------------------------------------------------------------------------
Unbundled Deliveries (2)
Residential 1,720 2,365 (645) (27.3%)
Small Commercial & Industrial 253 1,516 (1,263) (83.3%)
Large Commercial & Industrial 351 2,170 (1,819) (83.8%)
Public Authorities & Electric Railroads -- 7 (7) (100.0%)
- -------------------------------------------------------------------------------------------------------
2,324 6,058 (3,734) (61.6%)
- -------------------------------------------------------------------------------------------------------
Total Retail Deliveries 27,522 26,773 749 2.8%
- -------------------------------------------------------------------------------------------------------
<FN>
(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.
</FN>
Nine Months Ended September 30,
--------------------------------
Electric Revenue 2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
Bundled Revenue (1)
Residential $ 999 $ 807 $ 192 23.8%
Small Commercial & Industrial 664 500 164 32.8%
Large Commercial & Industrial 829 689 140 20.3%
Public Authorities & Electric Railroads 58 53 5 9.4%
- -------------------------------------------------------------------------------------------------------
2,550 2,049 501 24.5%
- -------------------------------------------------------------------------------------------------------
Unbundled Revenue (2)
Residential 129 184 (55) (29.9%)
Small Commercial & Industrial 13 73 (60) (82.2%)
Large Commercial & Industrial 10 61 (51) (83.6%)
Public Authorities & Electric Railroads -- 1 (1) (100.0%)
- -------------------------------------------------------------------------------------------------------
152 319 (167) (52.4%)
- -------------------------------------------------------------------------------------------------------
Total Electric Retail Revenues 2,702 2,368 334 14.1%
Wholesale and Miscellaneous Revenue (3) 179 158 21 13.3%
- -------------------------------------------------------------------------------------------------------
Total Electric Revenue $ 2,881 $ 2,526 $ 355 14.1%
=======================================================================================================
<FN>
(1) Bundled revenue reflects revenue from customers taking electric service
under tariffed rates, which includes the cost of energy, the delivery cost
of the transmission and distribution of the energy and a CTC charge.
(2) Unbundled revenue reflects revenue from customers electing to receive
generation from an alternate supplier, which include a distribution charge
and a CTC charge.
(3) Wholesale and miscellaneous revenues include transmission revenue, sales to
municipalities and other wholesale energy sales.
</FN>
101
The changes in electric retail revenues for the nine months ended
September 30, 2002, as compared to the same 2001 period, are as follows:
Variance
- -----------------------------------------------------------------------------------------------------
Customer Choice $ 205
Rate Changes 45
Weather 42
Other Effects 42
- -----------------------------------------------------------------------------------------------------
Electric Retail Revenue $ 334
=====================================================================================================
o Customer Choice. As of September 30, 2002, the customer load served by
alternate suppliers was 973 MW or 12.5% as compared to 1,042 MW or 13.6% as
of September 30, 2001. For the nine months ended September 30, 2002, the
percent of PECO's total retail deliveries for which PECO was the electric
supplier was 91.6% in 2002, a 14.1% increase as compared to 77.4% in 2001.
As of September 30, 2002, the number of customers served by alternate
suppliers was 285,549 or 18.7% as compared to September 30, 2001 of 397,396
or 26.1%. This increase in the customer load and the percentage of MWh
served by PECO, and the decrease in the number of customers served by
alternative suppliers primarily resulted from customers selecting or
returning to PECO as their electric generation supplier.
o Rate Changes. The increase in revenues attributable to rate changes
primarily reflects the expiration of a 6% reduction in PECO's electric
rates during the first quarter of 2001 and a $39 million increase as a
result of the increase in the gross receipts tax rate effective January 1,
2002. These increases are partially offset by the timing of a $60 million
rate reduction in effect for 2001 and 2002.
o Weather. The weather impact was favorable compared to the prior year as a
result of warmer summer weather partially offset by warmer winter weather.
Cooling degree-days increased 14% for the nine months ended September 30,
2002 compared to the same 2001 period. Heating degree-days decreased 16%
for the nine months ended September 30, 2002 compared to the same 2001
period.
o Other Effects. Other items affecting revenue during the nine months ended
September 30, 2002 include:
o Volume. Exclusive of weather impacts, higher delivery volume increased
PECO's revenue by $53 million compared to the same 2001 period.
o Other. An $11 million settlement of CTCs by a large customer in the
first quarter of 2001.
PECO's gas sales statistics for the nine months ended September 30,
2002 as compared to the same 2001 period are as
follows:
Nine Months Ended September 30,
--------------------------------
2002 2001 Variance
- ---------------------------------------------------------------------------------------------------------------------
Deliveries in mmcf 56,990 58,536 (1,546)
Revenue $358 $482 $ (124)
- ---------------------------------------------------------------------------------------------------------------------
102
The changes in gas revenue for the nine months ended September 30,
2002, as compared to the same 2001 period, are as follows:
Variance
- -----------------------------------------------------------------------------------------------------
Rate Changes $ (67)
Weather (33)
Volume (23)
Other (1)
- -----------------------------------------------------------------------------------------------------
Gas Revenue $ (124)
=====================================================================================================
o Rate Changes. The unfavorable variance in rates is attributable to an
adjustment of the purchased gas cost recovery by the PUC effective in
December 2001. The average rate per million cubic feet for the nine months
ended September 30, 2002 was 23% lower than the same 2001 period.
o Weather. The unfavorable weather impact is attributable to warmer winter
weather during the nine months ended September 30, 2002 as compared to the
same 2001 period. Heating degree-days decreased 16% in the nine months
ended September 30, 2002 compared to the same 2001 period.
o Volume. Exclusive of weather impacts, lower delivery volume reduced revenue
by $23 million in the nine months ended September 30, 2002 compared to the
same 2001 period. Total deliveries to customers decreased 3% in the nine
months ended September 30, 2002 compared to the same 2001 period, primarily
as a result of slower economic conditions in 2002 partially offset by
increased customer growth.
Purchased Power and Fuel Expense
Purchased power and fuel expense for the nine months ended September
30, 2002 increased $139 million as compared to the same 2001 period. The
increase in fuel and purchased power expense was primarily attributable to $187
million from customers in Pennsylvania selecting or returning to PECO as their
electric generation supplier and higher PJM ancillary charges of $28 million.
These increases were partially offset by $67 million from lower gas prices, $8
million from lower delivery volume primarily related to gas and $6 million as a
result of unfavorable weather conditions.
Operating and Maintenance Expense
O&M expense for the nine months ended September 30, 2002 decreased $6
million, or 2%, as compared to the same 2001 period. The decrease in O&M expense
was primarily attributable to $18 million of employee severance costs associated
with the Merger, $12 million of incremental costs related to two storms and $5
million associated with a write-off of excess and obsolete inventory, all of
which occurred in 2001. These decreases are partially offset by $16 million
related to an increased allocation of corporate expense and $15 million related
to the deployment of automated meter reading technology.
103
Depreciation and Amortization Expense
Depreciation and amortization expense for the nine months ended
September 30, 2002 increased $33 million, or 11%, as compared to the same 2001
period as follows:
Nine Months Ended September 30,
--------------------------------
2002 2001 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
Depreciation Expense $ 94 $ 89 $ 5 5.6%
Competitive Transition Charge Amortization 236 207 29 14.0%
Other Amortization Expense 18 19 (1) (5.3%)
- -------------------------------------------------------------------------------------------------------
Total Depreciation and Amortization $ 348 $ 315 $ 33 10.5%
=======================================================================================================
The increase was primarily attributable to $29 million of additional
amortization of PECO's CTC and an increase of $5 million related to depreciation
expense associated with additional plant in service. The additional amortization
of the CTC is in accordance with PECO's original settlement under the
Pennsylvania Competition Act.
Taxes Other Than Income
Taxes other than income for the nine months ended September 30, 2002
increased $72 million, or 53%, as compared to the same 2001 period. The increase
was primarily attributable to $54 million of additional gross receipts tax
related to additional revenues and an increase in the gross receipts tax rate on
electric revenue effective January 1, 2002. The increase was also attributable
to a reduction of $9 million in the state use tax accruals in 2001 and $7
million related to an additional assessment of real estate taxes in the third
quarter of 2002.
Interest Charges
Interest charges decreased $52 million, or 16%, for the nine months
ended September 30, 2002 as compared to the same 2001 period. The decrease was
primarily attributable to lower interest expense on long-term debt of $40
million as a result of principal payments and lower interest rates, and $8
million in interest expense on a loan from ComEd in 2001.
Other Income and Deductions
Other income and deductions excluding interest charges decreased $23
million, or 77%, for the nine months ended September 30, 2002 as compared to the
same 2001 period. The decrease in other income and deductions was primarily
attributable to lower interest income of $7 million in 2002. The decrease was
also attributable to intercompany interest income of $10 million, a gain on the
settlement of an interest rate swap of $6 million and the favorable settlement
of a customer contract of $3 million, all of which occurred in 2001.
Income Taxes
The effective tax rate was 32.9% for the nine months ended September
30, 2002 as compared to 35.5% for the same 2001 period. The decrease in the
effective tax rate was primarily attributable to a favorable adjustment to prior
period income taxes in connection with the completion of the 2001 tax return.
Preferred Stock Dividends
Preferred stock dividends for the quarter ended September 30, 2002 were
consistent as compared to the same 2001 period.
104
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 PECO's capital requirements, including construction,
repayments of maturing debt and payment of dividends.
Cash Flows from Operating Activities
Cash flows provided by operations for the nine months ended September
30, 2002 were $473 million compared to $744 million for the nine months ended
September 30, 2001. The decrease in cash flows from operating activities was
primarily attributable to higher payments related to accrued expenses of $255
million and changes in intercompany receivables and payables of $181 million.
These decreases were partially offset by lower payments related to accounts
payable of $54 million, higher collection of deferred energy costs as a result
of a change in gas rates of $36 million, higher CTC amortization of $29 million,
higher net income of $27 million and changes in material and supply inventories
of $13 million. PECO's cash flow from operating activities primarily results
from sales of electricity and gas to a stable and diverse base of retail
customers at fixed prices. PECO's future cash flows will depend upon the ability
to achieve operating cost reductions, and the impact of the economy, weather and
customer choice on its revenues. Although the amounts may vary from period to
period as a result of the uncertainties inherent in its business, PECO expects
that it will continue to provide a reliable and steady source of internal cash
flow from operations for the foreseeable future.
Cash Flows from Investing Activities
Cash flows used in investing activities for the nine months ended
September 30, 2002 were $177 million compared to $154 million for the nine
months ended September 30, 2001. The increase in cash flows used in investing
activities was primarily attributable to an increase in capital expenditures.
PECO's investing activities during the nine months ended September 30, 2002 were
funded primarily by operating activities.
PECO's projected capital expenditures for 2002 are $279 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 nine months ended
September 30, 2002 were $214 million compared to $508 million for the nine
months ended September 30, 2001. Cash flows used in financing activities are
primarily attributable to debt service and payment of dividends to Exelon. The
decrease in cash flows used in financing activities is primarily attributable to
a change in commercial paper borrowings of $435 million, a change in
105
intercompany payable of $41 million, lower debt service of $16 million partially
offset by lower contributions from Exelon of $91 million, additional dividends
paid to Exelon in 2002 of $86 million, and the change in settlement of interest
rate swap agreements of $36 million. PECO paid a $255 million dividend to Exelon
during the nine months ended September 30, 2002 compared to a $169 million
dividend for the nine months ended September 30, 2001.
Credit Issues
PECO meets its short-term liquidity requirements primarily through the
issuance of commercial paper, borrowings under a bank credit facility and
borrowings from Exelon's intercompany money pool. PECO, along with Exelon, ComEd
and Generation, participates in a $1.5 billion unsecured 364-day revolving
credit facility with a group of banks effective December 12, 2001. Under the
terms of this credit facility, Exelon has the flexibility to increase or
decrease the sublimits of each of the participants upon written notification to
these banks. As of September 30, 2002, PECO's sublimit under the credit facility
is $600 million. PECO expects to use the credit facility principally to support
its commercial paper program. This credit facility requires PECO to maintain a
debt to total capitalization ratio of 65% or less, excluding securitization debt
and excluding the receivable from parent recorded in PECO's shareholders'
equity. At September 30, 2002, PECO's debt to total capitalization ratio on that
basis was 41%. At September 30, 2002, PECO has $375 million in commercial paper
outstanding.
To provide an additional short-term borrowing option that will
generally be more favorable to the borrowing participants than the cost of
external financing, Exelon operates an intercompany money pool. Participation in
the money pool is subject to authorization by the Exelon Corporate Treasurer.
Exelon, ComEd and its subsidiary Commonwealth Edison of Indiana, Inc., PECO,
Generation and Business Services Company currently may participate in the money
pool. Funding of, and borrowings from, the money pool are predicated on whether
such funding results in mutual economic benefits to each of the participants,
although Exelon is not permitted to be a net borrower from the fund. Interest on
borrowings is based on short-term market rates of interest, or specific
borrowing rates if the funds are provided by external financing. There have been
no material money pool transactions in 2002.
PECO's access to the capital markets, including the commercial paper
market, and its financing costs in those markets are dependent on its credit
ratings. None of PECO's borrowings are subject to default or prepayment as a
result of a downgrading of credit ratings although such a downgrading could
increase interest charges under certain bank credit facilities.
At September 30, 2002, PECO's capital structure, excluding the
deduction from shareholders' equity of the $1.8 billion receivable from Exelon,
consisted of 27% common stock, 4% notes payable, 3% preferred securities and
COMRPS (which comprised 2% of PECO's total capitalization structure), and 66%
long-term debt including transition bonds issued by PECO Energy Transition
Trust. Long-term debt included $4.3 billion of transition bonds representing 50%
of capitalization.
Under PUHCA and the Federal Power Act, PECO can pay dividends only from
retained or current earnings. At September 30, 2002, PECO had retained earnings
of $347 million.
106
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 September 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 principal payments of $326 million on transition
bonds, additional borrowings of commercial paper of $274 million, the issuance
of $225 million of 4.75% First and Refunding Mortgage Bonds, due October 1, 2012
and the payment at maturity of $222 million of First and Refunding Mortgage
Bonds.
Other Factors
PECO is a participant in Exelon's pension and postretirement benefit
plans. PECO's costs of providing pension and postretirement benefits to its
retirees is dependent on a number of factors, such as the discount rate, rates
of return on plan assets, and the assumed rate of increase in health care costs.
A credit of approximately $2 million was included as a reduction to operating
and maintenance expense in 2001 for the cost of PECO's pension and
post-retirement benefit plans, exclusive of the 2001 charges for employees
severance programs. These costs are expected to increase in 2002 by
approximately $23 million as the result of the effects of the decline in market
value of plan assets and discount rates, and increases in health care costs.
Further increases in pension and postretirement expense are expected for the
year 2003. Although the 2003 increase will depend on market conditions PECO
preliminarily estimates that pension and postretirement benefit costs will
increase by approximately $15 million in 2003 from 2002 cost levels.
Exelon's defined benefit pension plans, of which PECO is a participant,
currently meet the minimum funding requirements of the Employment Retirement
Income Security Act of 1974, however Exelon currently expects to make a
discretionary plan contribution in the fourth quarter of 2002 of $100 million to
$200 million and a discretionary plan contribution in 2003 of $300 million to
$350 million. These contributions are expected to be funded primarily by
Exelon's internally generated cash flows from operations or through external
sources.
107
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 to the net basis of presentation required by EITF 02-3.
RESULTS OF OPERATIONS
Three Months Ended September 30, 2002 Compared to Three Months Ended September 30, 2001
Significant Operating Trends - Generation
Three Months Ended September 30,
--------------------------------
2002 2001 Variance % Change
- -----------------------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 2,213 $ 2,191 $ 22 1.0%
OPERATING EXPENSES
Purchased Power 1,257 1,268 (11) (0.9%)
Fuel 273 242 31 12.8%
Operating and Maintenance 391 364 27 7.4%
Depreciation 68 57 11 19.3%
Taxes Other Than Income 37 36 1 2.8%
- -------------------------------------------------------------------------------------------------------------------
Total Operating Expense 2,026 1,967 59 3.0%
- -------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 187 224 (37) (16.5%)
- -------------------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (23) (41) 18 43.9%
Equity in Earnings (Losses) of Unconsolidated Affiliates, net 87 60 27 45.0%
Other, net 14 (25) 39 156.0%
- -------------------------------------------------------------------------------------------------------------------
Total Other Income and Deductions 78 (6) 84 n.m.
- -------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 265 218 47 21.6%
INCOME TAXES 102 78 24 30.8%
- -------------------------------------------------------------------------------------------------------------------
NET INCOME $ 163 $ 140 $ 23 16.4%
===================================================================================================================
<FN>
n.m. - not meaningful
</FN>
Net Income
Generation's net income increased by $23 million, or 16%, for the three
months ended September 30, 2002 compared to the same period in the prior year.
Net income was positively impacted by increased revenue from affiliates,
increased revenue from two generating plants acquired in April 2002, reduced
interest expense and increased equity in earnings of unconsolidated
subsidiaries, partially offset by depressed wholesale market prices for energy,
increased depreciation and increased operating and maintenance expenses.
108
Operating Revenues, Net of Purchased Power and Fuel Expenses
Operating revenues, net of purchased power and fuel were $683 million
for the three months ended September 30, 2002 compared to $681 million for the
same period in 2001. Excluding the impact of a $16 million decrease in
decommissioning revenues in 2002 due to the timing of those revenues in 2001,
marketing and trading margin increased by $18 million. The increase in marketing
and trading margins was due to increased margin from sales to affiliates offset
by lower margin on market sales and trading losses. Margin from sales to
affiliates increased by $94 million. This increase was attributable to weather
related increased deliveries to PECO and ComEd, lower average supply costs, and
$8 million for the effects of certain third-party energy reconciliations. The
margin gains from sales to affiliates were offset by $59 million lower margin
from market sales and a $17 million decrease in trading margin. Market sales
margins were negatively impacted by lower average market sales prices of
$7.05/MWh. Excluding the benefit of $58 million of margin associated with the
Texas plant acquisition, average market prices realized for the three months
ended September 30, 2002 were $9.79/MWh lower than the same 2001 period. The
effect of the lower sales prices were partially offset by lower average supply
costs and increased market sales volumes. The $17 million decrease in trading
margin reflects a $12 million net loss for the period ended September 30, 2002
as compared to a $5 million net gain in the same 2001 period. Average supply
costs decreased by $2.04/MWh for the period ending September 30, 2002 as
compared to the same 2001 period. This decrease was principally attributed to
lower purchase power costs associated with lower wholesale market prices
realized and reduced transmission costs.
For the three months ended September 30, 2002 and 2001, Generation's
sales and the supply of these sales excluding the trading portfolio, were as
follows:
Three Months Ended September 30,
--------------------------------
Sales (in GWhs) 2002 2001 % Change
- ----------------------------------------------------------------------------------------------------------------------
Energy Delivery 34,535 32,692 5.6%
Exelon Energy 1,461 2,038 (28.3%)
Market Sales 21,177 17,781 19.1%
- -------------------------------------------------------------------------------------------------------
Total Sales 57,173 52,511 8.9%
=======================================================================================================
Three Months Ended September 30,
--------------------------------
Supply of Sales (in GWhs) 2002 2001 % Change
- ----------------------------------------------------------------------------------------------------------------------
Nuclear Generation 29,817 28,456 4.8%
Purchases - non-trading portfolio 23,425 20,505 14.2%
Fossil and Hydro Generation 3,931 3,550 10.7%
- -------------------------------------------------------------------------------------------------------
Total Supply 57,173 52,511 8.9%
=======================================================================================================
109
Trading volume of 28,455 GWhs and 1,832 GWhs for the three months ended
September 30, 2002 and 2001, respectively, is not included in the table above.
Generation's average margins on energy sales for the three months ended
September 30, 2002 and 2001 are as follows:
Three Months Ended September 30,
--------------------------------
($/MWh) 2002 2001 % Change
- ---------------------------------------------------------------------------------------------------------------------
Average Realized Revenue
Energy Delivery $ 40.18 $ 40.01 0.4%
Exelon Energy 49.72 46.67 6.5%
Market Sales 35.50 42.55 (16.6%)
Total Sales - excluding the trading portfolio 38.69 41.13 (5.9%)
Average Supply Cost (1) - excluding trading portfolio $ 26.66 $ 28.70 (7.1%)
Average Margin - excluding the trading portfolio $ 12.04 $ 12.43 (3.1%)
- ---------------------------------------------------------------------------------------------------------------------
<FN>
(1) Average supply cost includes purchase power and fuel cost.
</FN>
Generation's nuclear fleet, including AmerGen, performed at a capacity
factor of 93.9% for the three months ended September 30, 2002 compared to 93.0%
for the same period in 2001. Generation's nuclear fleet's production costs,
including AmerGen, for the three months ended September 30, 2002 were $12.40 per
MWh compared to $12.52 per MWh for the same period in 2001. Reduced unit
production costs reflect additional generation due to power uprates and
headcount reductions and Exelon's Cost Management Initiative. Generation's
average purchased power costs for wholesale operations were $53.75 per MWh for
the three months ended September 30, 2002, compared to $62.18 per MWh for the
same period in 2001. The decrease in purchase power costs was primarily due to
depressed wholesale power market prices.
Operating and Maintenance Expense
Operating and maintenance expenses increased $27 million, or 7%, for
the three months ended September 30, 2002 compared to the same period in 2001.
The increase was primarily due to additional operating and maintenance expenses
of $10 million arising from an increased number of nuclear plant refueling
outage days during the three months ended September 30, 2002 compared to the
same period in 2001, additional operating costs of $3 million related to fossil
plant outage work and $7 million related to the two generating plants acquired
in April 2002. These increases were partially offset by other operating cost
reductions, including reductions from Exelon's Cost Management Initiative.
Depreciation Expense
Depreciation expense increased $11 million, or 19%, for the three
months ended September 30, 2002 compared to the same period in the prior year.
This increase is due to a $7 million of additional depreciation expense on
routine capital additions, $2 million related to the Southeast Chicago Energy
Project, and $2 million related to two generating plants acquired in April 2002.
Taxes Other Than Income
Taxes other than income was substantially unchanged for the three
months ended September 30, 2002 compared to the same period in the prior year.
110
Interest Expense
Interest expense decreased $18 million, or 44%, for the three months
ended September 30, 2002, compared to the same period in the prior year. The
decrease is primarily due to $4 million of lower interest related to a lower
rate on the spent nuclear fuel obligation and $13 million of lower affiliate
interest expense.
Equity in Earnings of Unconsolidated Affiliates
Equity in earnings of unconsolidated affiliates increased $27 million,
or 45%, for the three months ended September 30, 2002 compared to the same
period in the prior year. This increase was due to an $18 million increase in
Generation's equity earnings in Sithe primarily due to a mark-to-market
adjustment related to the Dynegy tolling agreement with the Independence
Generating station, partially offset by an impairment adjustment for the New
Boston 1 Generating station. The increase is also due to a $9 million increase
in Generation's equity earnings in AmerGen, primarily due to better station
capacity performance and the power uprate at TMI conducted in the fourth quarter
of 2001.
Other, net
Other, net increased $39 million for the three months ended September
30, 2002 compared to the same period in the prior year primarily due to
substantial market losses on decommissioning trust investments during 2001 as
compared to the same period in 2002, partially offset by a decrease in affiliate
interest income.
Income Taxes
The effective income tax rate was 38.50% for the three months ended
September 30, 2002 and 35.78% for the three months ended September 30, 2001. The
higher effective tax rate was the result of realized losses in 2001 on qualified
decommissioning trust investments that are tax effected at a higher rate.
111
Nine Months Ended September 30, 2002 Compared to Nine Months Ended September 30,
2001
Significant Operating Trends - Generation
Nine Months Ended September 30,
--------------------------------
2002 2001 Variance % Change
- ----------------------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 5,233 $ 5,403 $ (170) (3.1%)
OPERATING EXPENSES
Purchased Power 2,581 2,589 (8) (0.3%)
Fuel 706 691 15 2.2%
Operating and Maintenance 1,234 1,173 61 5.2%
Depreciation 197 224 (27) (12.1%)
Taxes Other Than Income 126 121 5 4.1%
- -------------------------------------------------------------------------------------------------------------------
Total Operating Expense 4,844 4,798 46 1.0%
- -------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 389 605 (216) (35.7%)
- -------------------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (51) (100) 49 49.0%
Equity in Earnings (Losses) of Unconsolidated Affiliates, net 119 99 20 20.2%
Other, net 54 (7) 61 n.m.
- -------------------------------------------------------------------------------------------------------------------
Total Other Income and Deductions 122 (8) 130 n.m.
- -------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES AND CUMULATIVE
EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES 511 597 (86) (14.4%)
INCOME TAXES 198 228 (30) (13.2%)
- -------------------------------------------------------------------------------------------------------------------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGES
IN ACCOUNTING PRINCIPLES 313 369 (56) (15.2%)
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING
PRINCIPLES, NET OF INCOME TAXES 13 12 1 8.3%
- -------------------------------------------------------------------------------------------------------------------
NET INCOME $ 326 $ 381 $ (55) (14.4%)
===================================================================================================================
Net Income
Generation's net income decreased by $55 million, or 14%, for the nine
months ended September 30, 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. The decrease was
partially offset by increased revenue from affiliates, increased revenue from
the acquisition of two generating plants in April 2002, increased interest
income, decreased depreciation expense, and decreased interest expense.
Operating Revenues, Net of Purchased Power and Fuel Expenses
Operating revenues, net of purchased power and fuel were $1,946 million
for the nine months ended September 30, 2002 compared to $2,123 million for the
same period in the prior year. Marketing and trading margin decreased by $169
million, which was due to lower margin on market sales and trading losses but
partially offset by increased margin from sales to affiliates. Margin from sales
to affiliates increased by $181 million. This increase was attributable to
weather-related increased deliveries to PECO and ComEd, lower average supply
costs, and $8 million for third-party energy reconciliations. The margin gains
112
from sales to affiliates were offset by $324 million lower margin from market
sales and a $26 million decrease in trading margin. Market sales margins were
negatively impacted by lower average market sales prices of $8.40/MWh. Excluding
the benefit of $99 million of margin associated with the Texas plant
acquisition, average market prices realized for the three months ended September
30, 2002 were $10.02/MWh lower than the same 2001 period. The effect of the
lower sales prices were partially offset by lower average supply costs and
increased market sales volumes. The $26 million decrease in trading margin
reflects a $27 million loss for nine-month period ended September 30, 2002 as
compared to a $1 million loss in the same 2001 period. Average supply costs
decreased by $1.14/MWh for the period ending September 30, 2002 as compared to
the same 2001 period. This decrease was principally attributed to lower purchase
power costs associated with lower wholesale market prices realized and reduced
transmission costs.
For the nine months ended September 30, 2002 and 2001, Generation's
sales and the supply of these sales excluding the trading portfolio were as
follows:
Nine Months Ended September 30,
--------------------------------
Sales (in GWhs) 2002 2001 % Change
- ----------------------------------------------------------------------------------------------------------------------
Energy Delivery 90,579 90,001 0.6%
Exelon Energy 4,067 5,044 (19.4%)
Market Sales 61,089 53,787 13.6%
- -------------------------------------------------------------------------------------------------------
Total Sales 155,735 148,832 4.6%
=======================================================================================================
Nine Months Ended September 30,
--------------------------------
Supply of Sales (in GWhs) 2002 2001 % Change
- ----------------------------------------------------------------------------------------------------------------------
Nuclear Generation 86,127 87,397 (1.5%)
Purchases - non-trading portfolio 59,496 52,459 13.4%
Fossil and Hydro Generation 10,112 8,976 12.7%
- -------------------------------------------------------------------------------------------------------
Total Supply 155,735 148,832 4.6%
=======================================================================================================
Trading volume of 51,260 GWhs and 2,286 GWhs for the nine months ended
September 30, 2002 and 2001, respectively, is not included in the table above.
113
Generation's average margins on energy sales for the nine months ended
September 30, 2002 and 2001 are as follows:
Nine Months Ended September 30,
--------------------------------
($/MWh) 2002 2001 % Change
- ---------------------------------------------------------------------------------------------------------------------
Average Realized Revenue
Energy Delivery $ 34.33 $ 33.37 2.9%
Exelon Energy 46.75 42.28 10.6%
Market Sales 31.55 39.95 (21.0%)
Total Sales - excluding the trading portfolio 33.56 36.05 (6.9%)
Average Supply Cost (1) - excluding trading portfolio $ 21.04 $ 21.72 (3.1%)
Average Margin - excluding the trading portfolio $ 12.52 $ 14.18 (11.7%)
- ---------------------------------------------------------------------------------------------------------------------
<FN>
(1) Average supply cost includes purchase power and fuel cost.
</FN>
Generation's nuclear fleet, including AmerGen, performed at a capacity
factor 92.1% for the nine months ended September 30, 2002 compared to 95.1% for
the same period in 2001. Generation's nuclear fleet's production costs,
including AmerGen, for the nine months ended September 30, 2002 were $13.05 per
MWh compared to $12.40 per MWh for the same period in 2001. The lower capacity
factor and increased unit production costs are primarily due to 186 planned
outage days in the nine months ended September 30, 2002, versus 55 days in the
same period in 2001, including AmerGen. Increased unit production costs are
partially offset by headcount reductions and Exelon's Cost Management
Initiatives. Generation's average purchased power costs for wholesale operations
were $43.60 per MWh for the nine months ended September 30, 2002, compared to
$49.77 per MWh for the same period in 2001. The decrease in purchase power costs
was primarily due to depressed wholesale power market prices.
Operating and Maintenance Expense
Operating and maintenance expense increased $61 million, or 5%, for the
nine months ended September 30, 2002 compared to the same period in 2001. The
increase was due to the additional operating and maintenance expense of $65
million arising from an increased number of nuclear plant refueling outages
during the nine months ended September 30, 2002 compared to the same period in
2001, as well as additional allocated corporate costs including executive
severance. These additional expenses were offset by other operating cost
reductions, including $11 million related to headcount reductions, a $10 million
reduction in Generation's severance accrual and cost reductions from Exelon's
Cost Management Initiative. The severance reduction represents a reversal of
costs previously charged to operating expense.
Depreciation Expense
Depreciation expenses decreased $27 million, or 12%, for the nine
months ended September 30, 2002 compared to the same period in 2001. This
decrease is due to a $46 million reduction in depreciation expense arising from
the extension of the useful lives on certain generation facilities, partially
offset by $14 million of additional depreciation expense on capital additions
placed in service, including the Southeast Chicago Energy Project in July 2002,
and two generating plants acquired in April 2002.
114
Taxes Other Than Income
Taxes other than income increased $5 million, or 4%, for the nine
months ended September 30, 2002 compared to the same period in 2001 due
primarily to the Texas franchise taxes related to two generating plants acquired
in April 2002 and an increase in property taxes.
Interest Expense
Interest expense decreased $49 million, or 49%, for the nine months
ended September 30, 2002, compared to the same period in 2001. The decrease is
due to $16 million of capitalized interest, $17 million of lower interest
related to a lower rate on the spent nuclear fuel obligation, and $35 million of
lower affiliate interest expense. This decrease is partially offset by an $18
million increase in interest expense on long-term debt.
Equity in Earnings of Unconsolidated Affiliates
Equity in earnings of unconsolidated affiliates increased $20 million,
or 20%, for the nine months ended September 30, 2002 compared to the same period
in 2001. This increase was due to a $23 million increase in Generation's equity
earnings in Sithe primarily due to a mark-to-market adjustment related to the
Dynegy tolling agreement with the Independence Generating station, partially
offset by an impairment adjustment for the New Boston 1 Generating station. This
increase was partially offset by a decrease of $3 million in Generation's equity
earnings in AmerGen.
Other, net
Other, net increased $61 million for the nine months ended September
30, 2002 compared to the same period in 2001, primarily due to substantial
market losses on decommissioning trust investments during 2001 as compared to
the same period in 2002, partially offset by a decrease in affiliate interest
income.
Income Taxes
The effective income tax rate was substantially unchanged at 38.7% for
the nine months ended September 30, 2002 compared to 38.2% for the same period
in 2001.
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 including the issuance of commercial paper and borrowings or
capital contributions from Exelon. Generation's access to external financing at
reasonable terms is dependent on its credit ratings and its general business
condition, as well as the general business condition of the industry. Capital
115
resources are used primarily to fund Generation's capital requirements,
including construction, investments in new and existing ventures, and repayments
of maturing debt. Any future acquisitions could require external financing or
borrowings or capital contributions from Exelon.
Cash Flows from Operating Activities
Cash flows provided by operations were $771 million for the nine months
ended September 30, 2002, compared to $782 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 $1,343 million for the
nine months ended September 30, 2002, compared to $542 million for the same
period in 2001. Capital expenditures were $363 million and the investment in
nuclear fuel was $352 million in the nine months ended September 30, 2002
compared to capital expenditures of $282 million and investment in nuclear fuel
of $215 million in the same period in 2001. An increased number of nuclear
generating station refueling outages occurred during the nine months ended
September 30, 2002 compared to the same period in 2001. In addition to the 2002
capital expenditures, Generation purchased two generating plants from TXU on
April 25, 2002. The $443 million purchase was funded with available cash and
borrowings from Exelon. 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%. In July
2002, the loan agreement and the loan were increased to $100 million and the
maturity date was extended to July 1, 2003. As of September 30, 2002, the
balance of the loan to AmerGen was $42 million.
Cash Flows from Financing Activities
Cash flows provided by financing activities were $387 million for the
nine months ended September 30, 2002, compared to cash used of $34 million for
the same period in the prior year. During 2002, Generation obtained a $348
million loan from Exelon, which included $331 million for the acquisition of two
generating plants. The prior year amount represented net distributions of $156
million to Exelon and the issuance of long-term debt of $821 million. Also, in
2001, Generation repaid $696 million it had borrowed from Exelon related to the
acquisition of a 49.9% interest in Sithe.
Credit Issues
Generation meets its short-term liquidity requirements primarily
through the issuance of commercial paper, borrowings under a bank credit
facility and borrowings from Exelon's intercompany money pool. Generation, along
with Exelon, ComEd and PECO, participates in a $1.5 billion unsecured 364-day
revolving credit facility with a group of banks effective December 12, 2001.
Under the terms of this credit facility, Exelon has the flexibility to increase
or decrease the sublimits of each of the participants upon written notification
to these banks. As of September 30, 2002, Generation's sublimit under this
credit facility is zero. This credit facility requires Generation to maintain a
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debt to total capitalization ratio of 65% or less. At September 30, 2002,
Generation's debt to total capitalization ratio was 34%.
To provide an additional short-term borrowing option that will
generally be more favorable to the borrowing participants than the cost of
external financing, Exelon operates an intercompany money pool. Participation in
the money pool is subject to authorization by the Exelon Corporate Treasurer.
Exelon, ComEd and its subsidiary Commonwealth Edison of Indiana, Inc., PECO,
Generation and Business Services Company currently may participate in the money
pool. Funding of, and borrowings from, the money pool are predicated on whether
such funding results in mutual economic benefits to each of the participants,
although Exelon is not permitted to be a net borrower from the fund. Interest on
borrowings is based on short-term market rates of interest, or specific
borrowing rates if the funds are provided by external financing. There have been
no material money pool transactions in 2002.
Generation's access to the capital markets and its financing costs in
those markets are dependent on its credit ratings. None of Generation's
borrowings are subject to default or prepayment as a result of a downgrading of
credit ratings although such a downgrading could increase interest charges under
certain bank credit facilities.
At September 30, 2002, Generation's capital structure consisted of 66%
common stock, 8% notes payable, and 26% long-term debt.
From time to time Generation enters into energy commodity and other
derivative transactions that require the maintenance of investment grade
ratings. Failure to maintain investment grade ratings would allow the
counterparty to terminate the derivative and settle the transaction on a net
present value basis.
Under PUHCA and the Federal Power Act, Generation can only pay
dividends from undistributed or current earnings. At September 30, 2002,
Generation had undistributed earnings of $850 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 September 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:
o On April 25, 2002, Generation purchased two generating plants from TXU. The
$443 million purchase was funded primarily with borrowings from Exelon.
o On June 26, 2002, Generation agreed to purchase Sithe New England and
related power marketing operations, for a $543 million note. In addition,
Generation will assume various Sithe guarantees related to an equity
contribution agreement between Sithe New England and Boston Generation, a
project subsidiary of Sithe New England. The equity contribution agreement
requires, among other things, that Sithe New England, upon the occurrence
of certain events, contribute up to $38 million of equity for the purpose
of completing the construction of two generating facilities. Boston
Generation established a $1.2 billion credit facility in order to finance
the construction of these two generating facilities. The approximately $1.1
billion expected to be outstanding under the facility at the transaction
closing date, will be reflected on Exelon's Consolidated Balance Sheet.
Sithe New England has provided security interests in and has pledged the
stock of its other project subsidiaries to Boston Generation. If the
closing conditions are satisfied, the transaction could be completed in
November 2002.
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o Purchase obligations increased by $2.3 billion, primarily due to an
increase of $3.8 billion in power only purchases and a $0.1 billion
increase in transmission rights purchases partially offset by a $1.6
billion decrease in net capacity purchase commitments. Approximately $2
billion of the increase in power only purchases is due to Generation's
agreement to purchase all the energy from Unit No. 1 at Three Mile Island
after December 31, 2001 through December 31, 2014 and the remaining $1.8
billion increase is primarily due to purchase contracts entered into in
lieu of a portion of the Midwest Generation options contracts. The increase
in transmission rights purchases is primarily due to estimated commitments
in 2004 and 2005 for additional transmission rights that will be required
to fulfill firm sales contracts. The decrease in net capacity purchase
commitments is due primarily to the decision not to exercise options to
purchase 4,411 MWs of capacity from Midwest Generation in 2002 through 2004
as well as the increase in capacity sales under the TXU tolling agreement.
o At September 30, 2002, Southeast Chicago, a company 70% owned by
Generation, was obligated to make equity distributions of $55 million over
the next 20 years to the unaffiliated third party owning the remaining 30%
of Southeast Chicago. This amount reflects a return of such third party's
investment in Southeast Chicago's peaking facility in Chicago, IL.
Generation has the right to purchase, generally at a premium, and this
third party has the right to require Generation to purchase, generally at a
discount, its remaining investment in Southeast Chicago. Additionally,
Generation may be required to purchase the third party's remaining
investment in Southeast Chicago upon the occurrence of certain events,
including upon a failure by Generation to maintain an investment grade
rating.
o Guarantees decreased by approximately $80 million primarily related to $120
million of letters of credit on pollution control bonds being renewed and
no longer required to be guaranteed.
Off Balance Sheet Obligations
Generation owns 49.9% of the outstanding common stock of Sithe and has
an option, beginning on December 18, 2002 and expiring in December 2005 to
purchase the remaining common stock outstanding (Remaining Interest) in Sithe.
The purchase option expires on December 18, 2005. In addition, the Sithe
stockholders who own in the aggregate the Remaining Interest have the right to
require Generation to purchase the Remaining Interest (Put Rights) during the
same period in which Generation can exercise its purchase option. At the end of
this exercise period, if Generation has not exercised its purchase option and
the other Sithe stockholders have not 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.
118
If Generation increases its ownership in Sithe to 50.1% or more, Sithe
will become a consolidated subsidiary and Exelon's financial results will
include Sithe's financial results from the date of purchase. At September 30,
2002, Sithe had total assets of $4.2 billion and total debt of $2.1 billion,
including $1.6 billion of subsidiary debt, incurred to finance the construction
of two new generating facilities of which $1.1 billion is associated with Sithe
New England, $0.4 billion of subordinated debt, $47 million of short-term debt,
$33 million of capital leases, and excluding $430 million of non-recourse
project debt associated with Sithe's equity investments. For the nine months
ended September 30, 2002, Sithe had revenues of $0.9 billion. As of September
30, 2002, Generation had a $722 million equity investment in Sithe.
On June 26, 2002, Generation agreed to purchase Sithe New England and
related power marketing operations, for a $543 million note. In addition,
Generation will assume various Sithe guarantees related to an equity
contribution agreement between Sithe New England and Boston Generation, a
project subsidiary of Sithe New England. The equity contribution agreement
requires, among other things, that Sithe New England, upon the occurrence of
certain events, contribute up to $38 million of equity for the purpose of
completing the construction of two generating facilities. Boston Generation
established a $1.2 billion credit facility in order to finance the construction
of these two generating facilities. The approximately $1.1 billion expected to
be outstanding under the facility at the transaction closing date, will be
reflected on Exelon's Consolidated Balance Sheet. Sithe New England has provided
security interests in and has pledged the stock of its other project
subsidiaries to Boston Generation. If the closing conditions are satisfied, the
transaction could be completed in November 2002.
Additionally, the debt on the books of Exelon's unconsolidated equity
investments and joint ventures is not reflected on Exelon's Consolidated Balance
Sheets. Total investee debt, at September 30, 2002 including the debt of Sithe
described in the preceding paragraph, is currently estimated to be $2.2 billion
($1.1 billion based on Exelon's ownership interest of the investments).
Generation and British Energy, Generation's joint venture partner in
AmerGen, have each agreed to provide up to $100 million to AmerGen at any time
that the Management Committee of AmerGen determines that, in order to protect
the public health and safety and/or to comply with NRC requirements, such funds
are necessary to meet ongoing operating expenses or to safely maintain any
AmerGen plant.
Other Factors
Generation is a counterparty to Dynegy in various energy transactions.
In early July 2002, the credit ratings of Dynegy were downgraded by two credit
rating agencies to below investment grade. As of September 30, 2002, Generation
had a net receivable from Dynegy of approximately $7 million, and consistent
with the terms of the existing credit arrangement, has received collateral in
support of this receivable. Generation also has credit risk associated with
Dynegy through Generation's equity investment in Sithe. Sithe is a 60% owner of
the Independence generating station, a 1,040 MW gas-fired qualified facility
that has an energy only long-term tolling arrangement with Dynegy, with a
related financial swap arrangement. As of September 30, 2002, Sithe had
recognized an asset on its balance sheet related to the fair value of the
financial swap agreement with Dynegy that is marked-to-market under the terms of
SFAS No. 133. If Dynegy is unable to fulfill the terms of this agreement, Sithe
would be required to write-off the fair value asset, which Generation estimates
would result in an approximate $22 million reduction in its equity earnings from
Sithe, based on Generation's current 49.9% investment ownership in Sithe.
Additionally, the future economic value of Sithe's investment in the
119
Independence Station and AmerGen's purchased power arrangement with Illinois
Power, a subsidiary of Dynegy, could be impacted by events related to Dynegy's
financial condition.
Generation is a participant in Exelon's pension and postretirement
benefit plans. Generation's costs of providing pension and postretirement
benefits to its retirees is dependent up a number of factors, such as the
discount rate, rates of return on plan assets, and the assumed rate of increase
in health care costs. Approximately $13 million was included as a reduction to
operating and maintenance expense in 2001 for the cost of Generation's pension
and post-retirement benefit plans, exclusive of the 2001 charges for employees
severance programs. These costs are expected to increase in 2002 by
approximately $24 million as the result of the effects of the decline in market
value of plan assets and discount rates, and increases in health care costs.
Further increases in pension and postretirement expense are expected for the
year 2003. Although the 2003 increase will depend on market conditions,
Generation preliminarily estimates that pension and postretirement benefit costs
will increase by approximately $30 million in 2003 from 2002 cost levels.
Exelon's defined benefit pension plans, of which Generation is a
participant, currently meet the minimum funding requirements of the Employment
Retirement Income Security Act of 1974; however, Exelon currently expects to
make a discretionary plan contribution in the fourth quarter of 2002 of $100
million to $200 million and a discretionary plan contribution in 2003 of $300
million to $350 million. These contributions are expected to be funded primarily
by Exelon's internally generated cash flows from operations or through external
sources.
120
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 September 30,
2002 and 2001 include $8 million of realized losses from cash-flow hedge
contract settlements and $1 million in non-cash mark-to-market gains on other
derivative contracts, and for the nine months ended September 30, 2002 include
$47 million of realized gains from cash-flow hedge contract settlements and $1
million in non-cash mark-to market losses on other derivative contracts.
Outlined below is a summary of the changes in fair value for those
contracts included as assets and liabilities in Exelon and Generation's
Consolidated Balance Sheet for the three months and nine months ended September
30, 2002:
Three Months Ended September 30, 2002
-------------------------------------
Normal Operations Proprietary
(in millions) and Hedging Activities Trading
- ---------------------------------------------------------------------------------------------------------------------
Fair value of contracts outstanding as of July 1, 2002 $ (19) $ 1
Change in fair value during the three months ended September 30, 2002:
Contracts settled during period 4 13
Mark-to-market gain/(loss) on contracts settled during the period 12 (10)
Mark-to-market gain/(loss) on other contracts (39) (3)
Changes in fair value attributable to changes in valuation techniques and
assumptions -- --
- ---------------------------------------------------------------------------------------------------------------------
Total change in fair value (23) --
- ---------------------------------------------------------------------------------------------------------------------
Fair value of contracts outstanding at September 30, 2002 $ (42) $ 1
=====================================================================================================================
The total change in fair value during the three months ended September
30, 2002 is reflected in the 2002 financial statements as follows:
Normal Operations Proprietary
and Hedging Activities Trading
- ---------------------------------------------------------------------------------------------------------------------
Mark-to-market gain/(loss) on trading activities and non-qualifying hedge
contracts or hedge ineffectiveness reflected in earnings $ 1 $ --
Mark-to-market gain/(loss) on cash-flow hedge contracts reflected in
Other Comprehensive Income (24) --
- ---------------------------------------------------------------------------------------------------------------------
Total change in fair value $ (23) $ --
=====================================================================================================================
121
Nine Months Ended September 30, 2002
-------------------------------------
Normal Operations Proprietary
(in millions) and Hedging Activities Trading
- ---------------------------------------------------------------------------------------------------------------------
Fair value of contracts outstanding as of January 1, 2002 $ 78 $ 14
Change in fair value during the nine months ended September 30, 2002:
Contracts settled during period (60) 15
Mark-to-market gain/(loss) on contracts settled during the period 33 (17)
Mark-to-market gain/(loss) on other contracts (93) (11)
Changes in fair value attributable to changes in valuation techniques and
assumptions -- --
- ---------------------------------------------------------------------------------------------------------------------
Total change in fair value (120) (13)
- ---------------------------------------------------------------------------------------------------------------------
Fair value of contracts outstanding at September 30, 2002 $ (42) $ 1
=====================================================================================================================
The total change in fair value during the nine months ended September
30, 2002 is reflected in the 2002 financial statements as follows:
Normal Operations Proprietary
and Hedging Activities Trading
- ---------------------------------------------------------------------------------------------------------------------
Mark-to-market gain/(loss) on trading activities and non-qualifying hedge
contracts or hedge ineffectiveness reflected in earnings $ 12 $ (13)
Mark-to-market gain/(loss) on cash-flow hedge contracts reflected in
Other Comprehensive Income (132) --
- ---------------------------------------------------------------------------------------------------------------------
Total change in fair value $ (120) $ (13)
=====================================================================================================================
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 September 30,
2002 and may change as a result of future changes in these factors.
122
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 September 30, 2002 are as follows:
Maturities within
--------------------------------------------
2007 and Total Fair
(in millions) 2002 2003 2004 2005 2006 Beyond Value
- ---------------------------------------------------------------------------------------------------------------------
Normal Operations, qualifying cash flow hedge contracts (1):
Prices provided by other external sources $ (4) $ (31) $ (16) $ (2) $ (1) -- $ (54)
- ---------------------------------------------------------------------------------------------------------------------
Total $ (4) $ (31) $ (16) $ (2) $ (1) -- $ (54)
=====================================================================================================================
Normal operations, other derivative contracts (2):
Actively quoted prices $ 1 -- -- -- -- -- $ 1
Prices provided by other external sources 11 20 4 (10) 2 -- 27
Prices based on model or other valuation methods -- -- (5) (4) (7) -- (16)
- ---------------------------------------------------------------------------------------------------------------------
Total $ 12 $ 20 $ (1) $(14) $ (5) -- $ 12
=====================================================================================================================
Proprietary Trading, other derivative contracts (3):
Actively quoted prices $ 2 -- -- -- -- -- $ 2
Prices provided by other external sources (10) 3 (3) -- -- -- (10)
Prices based on model or other valuation methods 4 4 1 -- -- -- 9
- ---------------------------------------------------------------------------------------------------------------------
Total $ (4) $ 7 $ (2) -- -- -- $ 1
=====================================================================================================================
<FN>
(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.
</FN>
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 September 30, 2002, Generation
had a net receivable from Dynegy of approximately $7 million, and consistent
with the terms of the existing credit arrangement, has received collateral in
support of this receivable. Generation also has credit risk associated with
Dynegy through Generation's equity investment in Sithe. Sithe is a 60% owner of
the Independence generating station, a 1,040 MW gas-fired qualified facility
that has an energy only long-term tolling arrangement with Dynegy, with a
related financial swap arrangement. As of September 30, 2002, Sithe had
recognized an asset on its balance sheet related to the fair value of the
financial swap agreement with Dynegy that is marked-to-market under the terms of
SFAS No. 133. If Dynegy is unable to fulfill the terms of this agreement, Sithe
would be required to write-off the fair value asset, which Generation estimates
would result in an approximate $22 million reduction in its equity earnings from
Sithe, based on Generation's current 49.9% investment ownership in Sithe.
Additionally, the future economic value of Sithe's investment in the
Independence Station and AmerGen's purchased power arrangement with Illinois
Power, a subsidiary of Dynegy, could be impacted by events related to Dynegy's
financial condition.
123
Interest Rate Risk
ComEd
ComEd has fixed-to-floating interest rate swaps to manage interest rate
exposure associated with fixed-rate debt issuances in the aggregate amount of
$485 million. At September 30, 2002, these interest rate swaps, designated as
fair value hedges, had a fair market value of $40 million based on the present
value difference between the contract and market rates at September 30, 2002.
ComEd has forward starting interest rate swaps in the aggregate amount of $550
million to lock in interest rate levels in anticipation of future financing. At
September 30, 2002, these interest rate swaps, designated as cash flow hedges,
had a fair market value exposure of $43 million.
The aggregate fair value exposure of the interest rate swaps designated
as fair value hedges that would have resulted from a hypothetical 50 basis point
decrease in the spot yield at September 30, 2002 is estimated to be $49 million.
If the derivative instruments had been terminated at September 30, 2002, this
estimated fair value represents the amount to be paid by the counterparties to
ComEd.
The aggregate fair value of the interest rate swaps designated as fair
value hedges that would have resulted from a hypothetical 50 basis point
increase in the spot yield at September 30, 2002 is estimated to be $32 million.
If the derivative instruments had been terminated at September 30, 2002, this
estimated fair value represents the amount to be paid by the counterparties to
ComEd.
The aggregate fair value exposure of the interest rate swaps designated
as cash flow hedges that would have resulted from a hypothetical 50 basis point
decrease in the spot yield at September 30, 2002 is estimated to be $57 million.
If the derivative instruments had been terminated at September 30, 2002, this
estimated fair value represents the amount to be paid by ComEd to the
counterparties.
The aggregate fair value of the interest rate swaps designated as cash
flow hedges that would have resulted from a hypothetical 50 basis point increase
in the spot yield at September 30, 2002 is estimated to be $30 million. If the
derivative instruments had been terminated at September 30, 2002, this estimated
fair value represents the amount to be paid by ComEd to the counterparties.
ITEM 4. CONTROLS AND PROCEDURES
Exelon
Over several days ending October 29, 2002, the principal executive
officer and principal financial officer of Exelon evaluated Exelon's disclosure
controls and procedures related to the recording, processing, summarization and
reporting of information in Exelon's periodic reports that it files with the
Securities and Exchange Commission (SEC). These disclosure controls and
procedures have been designed to ensure that (a) material information relating
to Exelon, including its consolidated subsidiaries, is made known to Exelon's
management, including these officers, by other employees of Exelon and its
subsidiaries, and (b) this information is recorded, processed, summarized,
evaluated and reported, as applicable, within the time periods specified in the
SEC's rules and forms. As of October 29, 2002, these officers concluded that the
design of the disclosure controls and procedures is sufficient to accomplish
their purposes. In view of the restatement that was required in order to correct
the Other Comprehensive Income portion of Exelon's Consolidated Statements of
Comprehensive Income for the year ended December 31, 2001 and Exelon's and
Generation's Consolidated Statements of Income and Comprehensive Income for the
quarters ended March 31, 2002 and June 30, 2002, these officers directed that
steps be taken to enhance the understanding and implementation of the company's
controls and procedures. Exelon continually strives to improve its disclosure
controls and procedures to enhance the quality of its financial reporting.
124
There have been no significant changes in Exelon's internal controls or
in other factors that could significantly affect these controls subsequent to
the date of their evaluation.
ComEd
Over several days ending October 29, 2002, the principal executive
officer and principal financial officer of ComEd evaluated ComEd's disclosure
controls and procedures related to the recording, processing, summarization and
reporting of information in Exelon's periodic reports that it files with the
SEC. These disclosure controls and procedures have been designed to ensure that
(a) material information relating to ComEd, including its consolidated
subsidiaries, is made known to ComEd's management, including these officers, by
other employees of ComEd and its subsidiaries, and (b) this information is
recorded, processed, summarized, evaluated and reported, as applicable, within
the time periods specified in the SEC's rules and forms. As of October 29, 2002,
these officers concluded that the design of the disclosure controls and
procedures is sufficient to accomplish their purposes. In view of the
restatement that was required in order to correct the Other Comprehensive Income
portion of Exelon's Consolidated Statements of Comprehensive Income for the year
ended December 31, 2001 and Exelon's and Generation's Consolidated Statements of
Income and Comprehensive Income for the quarters ended March 31, 2002 and June
30, 2002, these officers directed that steps be taken to enhance the
understanding and implementation of the company's controls and procedures. ComEd
continually strives to improve its disclosure controls and procedures to enhance
the quality of its financial reporting.
There have been no significant changes in ComEd's internal controls or
in other factors that could significantly affect these controls subsequent to
the date of their evaluation.
PECO
Over several days ending October 29, 2002, the principal executive
officer and principal financial officer of PECO evaluated PECO's disclosure
controls and procedures related to the recording, processing, summarization and
reporting of information in PECO's periodic reports that it files with the
Securities and Exchange Commission (SEC). These disclosure controls and
procedures have been designed to ensure that (a) material information relating
to Exelon, including its consolidated subsidiaries, is made known to Exelon's
management, including these officers, by other employees of PECO and its
subsidiaries, and (b) this information is recorded, processed, summarized,
evaluated and reported, as applicable, within the time periods specified in the
SEC's rules and forms. As of October 29, 2002, these officers concluded that the
design of the disclosure controls and procedures is sufficient to accomplish
their purposes. In view of the restatement that was required in order to correct
the Other Comprehensive Income portion of Exelon's Consolidated Statements of
Comprehensive Income for the year ended December 31, 2001 and Exelon's and
Generation's Consolidated Statements of Income and Comprehensive Income for the
quarters ended March 31, 2002 and June 30, 2002, these officers directed that
steps be taken to enhance the understanding and implementation of the company's
controls and procedures. PECO continually strives to improve its disclosure
controls and procedures to enhance the quality of its financial reporting.
There have been no significant changes in PECO's internal controls or
in other factors that could significantly affect these controls subsequent to
the date of their evaluation.
Generation
Over several days ending October 29, 2002, the principal executive
officer and principal financial officer of Generation evaluated Generation's
disclosure controls and procedures related to the recording, processing,
summarization and reporting of information in Generation's periodic reports that
it files with the Securities and Exchange Commission (SEC). These disclosure
controls and procedures have been designed to ensure that (a) material
information relating to Generation, including its consolidated subsidiaries, is
made known to Generation's management, including these officers, by other
employees of Generation and its subsidiaries, and (b) this information is
recorded, processed, summarized, evaluated and reported, as applicable, within
the time periods specified in the SEC's rules and forms. As of October 29, 2002,
these officers concluded that the design of the disclosure controls and
procedures is sufficient to accomplish their purposes. In view of the
restatement that was required in order to correct the Other Comprehensive Income
portion of Exelon's Consolidated Statements of Comprehensive Income for the year
ended December 31, 2001 and Exelon's and Generation's Consolidated Statements of
Income and Comprehensive Income for the quarters ended March 31, 2002 and June
30, 2002, these officers directed that steps be taken to enhance the
understanding and implementation of the company's controls and procedures.
Generation continually strives to improve its disclosure controls and procedures
to enhance the quality of its financial reporting.
There have been no significant changes in Generation's internal
controls or in other factors that could significantly affect these controls
subsequent to the date of their evaluation.
125
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
As previously reported in Exelon's June 2002 Form 10-Q, between May 8
and June 14, 2002, several class action lawsuits were filed in the Federal
District Court in Chicago asserting nearly identical securities law claims on
behalf of purchasers of Exelon securities between April 24, 2001 and September
27, 2001 (Class Period). The complaints allege that Exelon violated Federal
securities laws by issuing a series of materially false and misleading
statements relating to its 2001 earnings expectations during the Class Period.
The Court consolidated the pending cases into one lawsuit and has appointed two
lead plaintiffs as well as lead counsel.
On October 1, 2002, the plaintiffs filed a consolidated amended
complaint. In addition to the original claims, this complaint contains
allegations of new facts and contains several new theories of liability. Exelon
believes the lawsuit is without merit and is vigorously contesting this matter.
ITEM 5. OTHER INFORMATION
Exelon, ComEd, PECO and Generation
FERC issued its standard market design notice of proposed rulemaking
(NOPR) on July 31, 2002 that proposes numerous changes to current wholesale
electric transmission arrangements and energy markets. The NOPR includes a
requirement that all jurisdictional transmission facilities be under the
operational control of an independent transmission provider, creates a new
transmission tariff that would provide a single form of transmission service to
all transmission customers, requires energy markets to operate similar to PJM,
and recognizes needs of load-serving entities.
ComEd
As previously reported in the 2001 Form 10-K, on December 20, 2000, the
ICC issued an order permitting ComEd to recover decommissioning costs from
customers through 2006. The ICC order was appealed. On August 7, 2002, the
Illinois Appellate Court for the Second District issued an opinion affirming in
all respects the ICC's order allowing ComEd to collect from customers $73
million in decommissioning costs through 2004 and up to that amount in 2005 and
2006. Several parties have asked the Illinois Supreme Court to review the case.
The petition for review has been fully briefed and is pending before the
Illinois Supreme Court.
As previously reported in the June 2002 Form 10-Q, on May 28, 2002,
ComEd filed a notice with FERC indicating its intention to join PJM
Interconnection, LLC (PJM) by placing its transmission assets under the control
of an independent transmission company (ITC) that would operate within PJM West.
FERC conditionally approved ComEd's decision to join PJM in late July 2002.
Among other conditions, FERC ordered the applicable parties to file agreements
relating to the formation of the ITC under PJM. ComEd, American Electric Power
East (AEP), Dayton Power & Light (Dayton) and National Grid USA (National Grid)
126
subsequently filed a non-binding letter of intent and detailed term sheet
relating to the formation of the ITC. National Grid is a subsidiary of National
Grid plc, a company that owns and operates transmission assets in Great Britain.
National Grid and PJM continue to negotiate the allocation of functions to an
ITC operating under PJM.
Effective as of September 30, 2002, ComEd, AEP, Dayton and National
Grid entered into a Project Implementation Agreement with PJM (Agreement)
providing for the funding and allocation of responsibilities with respect to the
integration of the parties into PJM West, either directly or through an ITC.
ComEd's share of PJM's expansion expenses under this Agreement is estimated to
be approximately $10 million. This Agreement contemplates that Illinois Power
Company (IP) and Dominion Virginia Power Company (Dominion) would enter into
similar agreements providing for the integration of IP into PJM West and
Dominion into PJM South. By coordinating these projects, PJM expected to
generate synergies and overall savings. As a result, if any of these companies
fails to join or withdraws from PJM, the costs to all of the other companies,
including ComEd, may increase. ComEd also faces significant additional expenses
under this Agreement if it withdraws from PJM.
On August 1, 2002, ComEd set a new record for highest peak load
experienced to date of 21,804 MWs.
PECO
In August 2002, Exelon's Audit Committee pre-approved the non-audit
services of its independent accountant, PricewaterhouseCoopers LLP, to:
o Provide a fact witness in a Pennsylvania Department of Revenue
tax matter that is being litigated in the Commonwealth Court.
o Perform tax compliance services related to PECO for state and
local income and franchise tax returns The cost of such services
is estimated to be $67,000.
On August 15, 2002, the International Brotherhood of Electrical Workers
filed a petition to conduct a unionization vote of certain of PECO's employees.
On August 14, 2002, PECO set a new record for highest peak load
experienced to date of 8,164 MWs.
Generation
As previously reported in the 2001 Form 10-K, in November 2000, eight
utilities with nuclear power plants filed a Joint Petition for Review with the
U.S. Court of Appeals for the Eleventh Circuit seeking to invalidate a portion
of PECO's agreement with the U.S. Department of Energy (DOE) providing for
credits against Nuclear Waste Fund (NWF) payments on the ground that such
provision is a violation of the Nuclear Waste Policy Act of 1982. To date, Peach
Bottom has been credited approximately $38 million, of which Exelon's share was
approximately $19 million, which was used to offset the cost to construct and
operate an on-site storage facility. Credits of approximately $6 million
annually are expected in the future, which Generation will recognize its share
of approximately $3 million when received. (The agreement was assigned to
Generation in connection with Exelon's 2001 restructuring.) On September 24,
127
2002, the United States Court of Appeals for the Eleventh Circuit issued a
ruling in which it held that DOE is not authorized to fund the Peach Bottom
credits out of the NWF. The ruling does not address whether Generation must
repay the NWF the amount of the credits it has received; it only invalidates the
source of funding for the Peach Bottom settlement agreement. The court's ruling
does not purport to affect the validity of the Peach Bottom settlement agreement
as a whole or the ability to enter into the agreement. Under the terms of the
agreement, DOE and Generation are required to meet and discuss alternative
funding sources for the settlement credits. The court's opinion suggests that
the federal judgment fund should be available as an alternate source. The
agreement provides that if such negotiations are unsuccessful, the agreement
will be null and void.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
4.1 - Ninety-Ninth Supplemental Indenture dated as of September 15,
2002 to PECO Energy Company's First and Refunding Mortgage.
4.2 - Ninety-Eighth Supplemental Indenture dated as of October 1,
2002 to PECO Energy Company's First and Refunding Mortgage.
10.1 - Employment Agreement by and among Exelon Corporation, Exelon
Generation Company, LLC and Oliver D. Kingsley, Jr. dated as
of September 5, 2002.
Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United
States Code (Sarbanes - Oxley Act of 2002) as to the Quarterly Report on
Form 10-Q for the quarterly period ended September 30, 2002 filed by the
following officers for the following companies:
- --------------------------------------------------------------------------------
99.1 - Filed by John W. Rowe for Exelon Corporation
99.2 - Filed by Ruth Ann M. Gillis for Exelon Corporation
99.3 - Filed by Frank M. Clark for Commonwealth Edison Company
99.4 - Filed by Robert E. Berdelle for Commonwealth Edison Company
99.5 - Filed by Kenneth G. Lawrence for PECO Energy Company
99.6 - Filed by Frank F. Frankowski for PECO Energy Company
99.7 - Filed by Oliver D. Kingsley for Exelon Generation Company, LLC
99.8 - Filed by Ruth Ann M. Gillis for Exelon Generation Company, LLC
99.9 - Management's Discussion and Analysis of Financial Condition
and Results of Operations and Index to Financial Statements of
Exelon Generation Company, LLC, filed by Exelon Generation
Company, LLC with the Securities Exchange Commission on April
24, 2002 on Registration Statement Form S-4 (File No.
333-85496).
128
(b) Reports on Form 8-K:
Exelon, ComEd, PECO and/or Generation filed Current Reports on
Form 8-K during the three months ended September 30, 2002 as follows:
Date of Earliest
Event Reported Description of Item Reported
- ---------------------------------------------------------------------------------------------------------------------------------
July 1, 2002 "ITEM 5. OTHER EVENTS" filed by Exelon and Generation, regarding Generation's notification to
Midwest Generation, LLC of its exercise of Generation's call option.
July 16, 2002 "ITEM 5. OTHER EVENTS" filed by Exelon, ComEd, PECO and Generation, reporting that Exelon's second
quarter 2002 earnings results were expected to be higher than estimates.
July 31, 2002 "ITEM 5. OTHER EVENTS" filed by Exelon, ComEd, PECO and Generation, reporting Exelon's second
quarter 2002 earnings results and "ITEM 9. REGULATION FD DISCLOSURE" filed by Exelon, ComEd, PECO
and Generation, regarding highlights of the Exelon Second Quarter Earnings Conference Call.
August 6, 2002 "ITEM 9. REGULATION FD DISCLOSURE" filed by Exelon, regarding certifications of Exelon's principal
executive officer and principal financial officer, as required by SEC Order No. 4-460.
August 27, 2002 "ITEM 5. OTHER EVENTS" filed by Exelon and ComEd, regarding a letter order from the Federal Energy
Regulatory Commission (FERC) related to the treatment of goodwill associated with the generating
assets and power marketing business that it transferred in January 2001 as part of Exelon's
corporate restructuring.
September 3, 2002 "ITEM 5. OTHER EVENTS" filed by Exelon and ComEd, announcing that ComEd will seek a rehearing of
the order by FERC related to the treatment of goodwill as a part of Exelon's corporate
restructuring in January 2001.
September 3, 2002 "ITEM 9. REGULATION FD DISCLOSURE" filed by Exelon, ComEd and PECO, regarding Exelon's anticipated
savings from its Cost Management Initiative at Energy Delivery.
September 4, 2002 "ITEM 9. REGULATION FD DISCLOSURE" filed by Exelon, ComEd, PECO and Generation, Oliver D.
Kingsley, Jr., Senior Executive Vice President, made a presentation at the Lehman Brothers
Conference. The exhibits include the presentation slides and other materials made available at
the conference.
129
September 4, 2002 "ITEM 5. OTHER EVENTS" filed by Exelon and Generation, regarding Exelon's announcement that it is
in the preliminary stages of exploring the possibility of selling its share of AmerGen Energy
Company, LLC and "ITEM 9. REGULATION FD DISCLOSURE" filed by Exelon and Generation, reporting that
Exelon does not intend, as part of its strategy, to own the international assets of Sithe.
September 18, 2002 "ITEM 9. REGULATION FD DISCLOSURE" filed by Exelon, ComEd, PECO and Generation, John W. Rowe,
Chairman and CEO, made a presentation at Merrill Lynch Global Power and Gas Leaders Conference. The
exhibits include the presentation slides and other materials made available at the conference.
September 18, 2002 "ITEM 9. REGULATION FD DISCLOSURE" filed by Exelon, ComEd, PECO and Generation, during the Power and
Gas Leaders Conference, John W. Rowe commented on the third quarter earnings outlook, the range of
guidance for 2003 earnings and the status of Exelon's discussion with FERC and the SEC regarding the
allocation of goodwill to ComEd's transmission and distribution business.
September 19, 2002 "ITEM 5. OTHER EVENTS" filed by Exelon and ComEd, related to their understanding that the Office of
the Chief Accountant of the SEC will not object to the accounting treatment for goodwill.
September 26, 2002 "ITEM 5. OTHER EVENTS" filed by Exelon and ComEd, related the letter received from FERC which states
that FERC has no objection to ComEd's determination that none of the goodwill was related to assets
transferred to Generation.
- ------------------------------------------------------------------------------------------------------------------------------------
130
SIGNATURES
- --------------------------------------------------------------------------------
Pursuant to requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
EXELON CORPORATION
/s/ John W. Rowe /s/ Ruth Ann M. Gillis
- ----------------------------- ---------------------------
JOHN W. ROWE RUTH ANN M. GILLIS
Chairman of the Board and Senior Vice President and
Chief Executive Officer Chief Financial Officer
/s/ Matthew F. Hilzinger
- -----------------------------
MATTHEW F. HILZINGER
Vice President and Corporate Controller
(Principal Accounting Officer)
October 31, 2002
- --------------------------------------------------------------------------------
Pursuant to requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
COMMONWEALTH EDISON COMPANY
/s/ Pamela B. Strobel /s/ Frank M. Clark
- ----------------------------- ---------------------------
PAMELA B. STROBEL FRANK M. CLARK
Chair President
/s/ Robert E. Berdelle
- -----------------------------
ROBERT E. BERDELLE
Vice President, Finance and
Chief Financial Officer
(Principal Financial Officer)
October 31, 2002
131
Pursuant to requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
PECO ENERGY COMPANY
/s/ Pamela B. Strobel /s/ Kenneth G. Lawrence
- ----------------------------- ---------------------------
PAMELA B. STROBEL KENNETH G. LAWRENCE
Chair President
/s/ Frank F. Frankowski
- -----------------------------
FRANK F. FRANKOWSKI
Vice President, Finance and
Chief Financial Officer
(Principal Financial Officer)
October 31, 2002
- --------------------------------------------------------------------------------
Pursuant to requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
EXELON GENERATION COMPANY, LLC
/s/ Oliver D. Kingsley Jr. /s/ Ruth Ann M. Gillis
- ----------------------------- ---------------------------
OLIVER D. KINGSLEY JR. RUTH ANN M. GILLIS
Chief Executive Officer and Senior Vice President and
President Chief Financial Officer
Exelon Corporation
(Principal Financial Officer)
/s/ Thomas Weir III
- -----------------------------
THOMAS WEIR III
Controller
October 31, 2002
132
CERTIFICATIONS
- --------------------------------------------------------------------------------
Certification Pursuant to Rule 13a-14 and 15d-14 of the Securities
and Exchange Act of 1934
I, John W. Rowe certify that:
1. I have reviewed this quarterly report on Form 10-Q of Exelon Corporation;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: October 31, 2002
/s/ John W. Rowe
-------------------------------
John W. Rowe
Chairman of the Board and Chief Executive Officer
133
Certification Pursuant to Rule 13a-14 and 15d-14 of the Securities
and Exchange Act of 1934
- --------------------------------------------------------------------------------
I, Ruth Ann M. Gillis certify that:
1. I have reviewed this quarterly report on Form 10-Q of Exelon Corporation;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: October 31, 2002
/s/ Ruth Ann M. Gillis
-------------------------------
Ruth Ann M. Gillis
Senior Vice President and Chief Financial Officer
134
Certification Pursuant to Rule 13a-14 and 15d-14 of the Securities
and Exchange Act of 1934
- --------------------------------------------------------------------------------
I, Frank M. Clark certify that:
1. I have reviewed this quarterly report on Form 10-Q of Commonwealth Edison
Company;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: October 31, 2002
/s/ Frank M. Clark
-------------------------------
Frank M. Clark
President
135
Certification Pursuant to Rule 13a-14 and 15d-14 of the Securities
and Exchange Act of 1934
- --------------------------------------------------------------------------------
I, Robert E. Berdelle certify that:
1. I have reviewed this quarterly report on Form 10-Q of Commonwealth Edison
Company;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: October 31, 2002
/s/ Robert E. Berdelle
-------------------------------
Robert E. Berdelle
Vice President, Finance and Chief Financial Officer
136
Certification Pursuant to Rule 13a-14 and 15d-14 of the Securities
and Exchange Act of 1934
- --------------------------------------------------------------------------------
I, Kenneth G. Lawrence certify that:
1. I have reviewed this quarterly report on Form 10-Q of PECO Energy Company;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: October 31, 2002
/s/ Kenneth G. Lawrence
-------------------------------
Kenneth G. Lawrence
President
137
Certification Pursuant to Rule 13a-14 and 15d-14 of the Securities
and Exchange Act of 1934
- --------------------------------------------------------------------------------
I, Frank F. Frankowski certify that:
1. I have reviewed this quarterly report on Form 10-Q of PECO Energy Company;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: October 31, 2002
/s/ Frank F. Frankowski
-------------------------------
Frank F. Frankowski
Vice President, Finance and Chief Financial Officer
138
Certification Pursuant to Rule 13a-14 and 15d-14 of the Securities
and Exchange Act of 1934
- --------------------------------------------------------------------------------
I, Oliver D. Kingsley Jr. certify that:
1. I have reviewed this quarterly report on Form 10-Q of Exelon Generation
Company, LLC;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: October 31, 2002
/s/ Oliver D. Kingsley
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Oliver D. Kingsley Jr.
Chief Executive Officer and President
139
Certification Pursuant to Rule 13a-14 and 15d-14 of the Securities
and Exchange Act of 1934
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I, Ruth Ann M. Gillis certify that:
1. I have reviewed this quarterly report on Form 10-Q of Exelon Generation
Company, LLC;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: October 31, 2002
/s/ Ruth Ann M. Gillis
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Ruth Ann M. Gillis
Senior Vice President and Chief Financial Officer
Exelon Corporation