10-Q 1 exelon10q9-02.txt 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
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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
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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 -------------------------------------------------------------------------------------------------------------------- (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.
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 --------------------------------------------------------------------------------------------------------------------- (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.
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 ======================================================================================================================= (a) The increase is a result of the identification in 2001 of additional positions to be eliminated, partially offset by the 2002 elimination of identified positions through normal attrition and changes in certain business plans. (b) The reduction results from lower estimated pension and post retirement welfare benefits reflecting revised actuarial estimates.
The following table provides a reconciliation of the reserve for employee severance and other benefits associated with the Merger:
--------------------------------------------------------------------------------------------------------------------- Adjusted employee severance and other benefits reserve $ 179 Payments to employees (October 2000-June 2002) (125) Payments to employees (July 2002-September 2002) (10) --------------------------------------------------------------------------------------------------------------------- Employee severance and other benefits reserve as of September 30, 2002 $ 44 =====================================================================================================================
ComEd
Original Adjustments Adjusted Estimate Transfer 2001 2002 Liabilities ------------------------------------------------------------------------------------------------------------------------ Employee severance payments $ 128 $ (68) $ 17 $ (7) $ 70 (a) Other benefits 21 (14) 8 (2) 13 (a) ------------------------------------------------------------------------------------------------------------------------ Employee severance payments and other benefits 149 (82) 25 (9) 83 Actuarially determined pension and postretirement costs 158 (82) 10 -- 86 (b) ------------------------------------------------------------------------------------------------------------------------ Unicom employee cost - ComEd $ 307 $ (164) $ 35 $ (9) $ 169 ======================================================================================================================== (a) The increase is a result of the identification in 2001 of additional positions to be eliminated, partially offset by the 2002 elimination of identified positions through normal attrition and changes in certain business plans. (b) The reduction results from lower estimated pension and post retirement welfare benefits reflecting revised actuarial estimates.
39 The following table provides a reconciliation of ComEd's reserve for employee severance and other benefits associated with the Merger:
--------------------------------------------------------------------------------------------------------------------- Adjusted employee severance and other benefits reserve $ 83 Payments to employees (October 2000-June 2002) (54) Payments to employees (July 2002-September 2002) (5) --------------------------------------------------------------------------------------------------------------------- Employee severance and other benefits reserve as of September 30, 2002 $ 24 =====================================================================================================================
Generation
Original Adjustments Adjusted Estimate 2001 2002 Liabilities ------------------------------------------------------------------------------------------------------------------------ Employee severance payments $ 45 $ (12) $ (2) $ 31 (a) Other benefits 5 2 -- 7 (a) ------------------------------------------------------------------------------------------------------------------------ Employee severance payments and other benefits 50 (10) (2) 38 Actuarially determined pension and postretirement costs 71 (25) -- 46 (b) ------------------------------------------------------------------------------------------------------------------------ Unicom employee cost - Generation $ 121 $ (35) $ (2) $ 84 ======================================================================================================================== (a) The increase is a result of the identification in 2001 of additional positions to be eliminated, partially offset by the 2002 elimination of identified positions through normal attrition and changes in certain business plans. (b) The reduction results from lower estimated pension and post retirement welfare benefits reflecting revised actuarial estimates.
The following table provides a reconciliation of the reserve for employee severance and other benefits associated with the Merger:
--------------------------------------------------------------------------------------------------------------------- Adjusted employee severance and other benefits reserve $ 38 Payments to employees (October 2000-June 2002) (26) Payments to employees (July 2002-September 2002) (3) --------------------------------------------------------------------------------------------------------------------- Employee severance and other benefits reserve as of September 30, 2002 $ 9 =====================================================================================================================
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 ===================================================================================================================== (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.
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 -- --------------------------------------------------------------------------------------------------------------------- (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.
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 --------------------------------------------------------------------------------------------------------------------- (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.
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 --------------------------------------------------------------------------------------------------------------------- (1) PECO provides energy to Generation for Generation's own use. (2) Effective January 1, 2001, PECO entered into a PPA with Generation. See Note 8 of Combined Notes to Consolidated Financial Statements for further information regarding the PPA. (3) PECO provides services to BSC related to invoice processing. PECO receives a variety of corporate support services from BSC, including legal, human resources, financial and information technology services. Such services are provided at cost, including applicable overhead. (4) PECO receives services from Enterprises for construction, which are capitalized, and the deployment of automated meter reading technology, which is expensed. (5) At December 31, 2000, PECO had a $400 million payable to ComEd, which was repaid in the second quarter of 2001. The average annual interest rate on this payable for the period outstanding was 6.5%. (6) PECO has a non-interest bearing receivable from Exelon related to the 2001 corporate restructuring. The receivable is expected to be settled over the years 2001 through 2010. (7) PECO received interest income from Generation in 2001 related to a loan.
46 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 -- --------------------------------------------------------------------------------------------------------------------- (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.
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% ======================================================================================================= (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
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% ======================================================================================================= (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.
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%) --------------------------------------------------------------------------------------------------------------------- (1) Average Supply costs represent purchased power and fuel costs.
Generation's nuclear fleet, including AmerGen, performed at a capacity factor of 93.9% for the three months ended September 30, 2002 compared to 93.0% for the same period in 2001. Generation's nuclear units' production costs, including AmerGen, for the three months ended September 30, 2002 were $12.40 per MWh compared to $12.52 per MWh for the same period in 2001. Reduced unit production costs reflect additional generation due to power uprates, headcount reductions and Exelon's Cost Management Initiative. Generation's average purchased power costs for wholesale operations were $53.75 per MWh for the three 59 months ended September 30, 2002, compared to $62.18 per MWh for the same period in 2001. The decrease in purchased power costs was primarily due to depressed wholesale power market prices. Results of Operations - Enterprises Business Segment
Three Months Ended September 30, -------------------------------- 2002 2001 Variance % Change --------------------------------------------------------------------------------------------------------------------- OPERATING REVENUES $ 509 $ 529 $ (20) (3.8%) OPERATING EXPENSES Purchased Power 73 88 (15) (17.0%) Fuel 60 63 (3) (4.8%) Operating and Maintenance 349 361 (12) (3.3%) Depreciation and Amortization 11 16 (5) (31.3%) Taxes Other Than Income 1 1 -- -- ------------------------------------------------------------------------------------------------------- Total Operating Expense 494 529 (35) (6.6%) ------------------------------------------------------------------------------------------------------- OPERATING INCOME 15 -- 15 n.m. ------------------------------------------------------------------------------------------------------- OTHER INCOME AND DEDUCTIONS Interest Expense (3) (9) 6 (66.7%) Equity in Earnings (Losses) of Unconsolidated Affiliates, net 8 (8) 16 (200.0%) Other, net -- (34) 34 (100.0%) ------------------------------------------------------------------------------------------------------- Total Other Income and Deductions 5 (51) 56 (109.8%) ------------------------------------------------------------------------------------------------------- INCOME BEFORE INCOME TAXES 20 (51) 71 (139.2%) INCOME TAXES 5 (18) 23 (127.8%) ------------------------------------------------------------------------------------------------------- NET INCOME $ 15 $ (33) $ 48 (145.4%) =======================================================================================================
Enterprises' net income increased $48 million for the three months ended September 30, 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% ======================================================================================================= (1) Bundled service reflects deliveries to customers taking electric service under tariffed rates, which include the cost of energy and the delivery cost of the transmission and the distribution of the energy. PECO's tariffed rates also include a CTC charge. (2) Unbundled service reflects customers electing to receive electric generation service from an alternative energy supplier or ComEd's PPO.
64
Nine Months Ended September 30, ------------------------------- Electric Revenue 2002 2001 Variance % Change --------------------------------------------------------------------------------------------------------------------- Bundled Revenues (1) Residential $ 2,880 $ 2,659 $ 221 8.3% Small Commercial & Industrial 2,007 1,910 97 5.1% Large Commercial & Industrial 1,152 1,095 57 5.2% Public Authorities & Electric Railroads 356 388 (32) (8.3%) ------------------------------------------------------------------------------------------------------- 6,395 6,052 343 5.7% ------------------------------------------------------------------------------------------------------- Unbundled Revenues (2) Alternative Energy Suppliers Residential 129 184 (55) (30.0%) Small Commercial & Industrial 107 110 (3) (2.8%) Large Commercial & Industrial 111 121 (10) (8.3%) Public Authorities & Electric Railroads 18 4 14 n.m. ------------------------------------------------------------------------------------------------------- 365 419 (54) (12.9%) ------------------------------------------------------------------------------------------------------- PPO (ComEd Only) Small Commercial & Industrial 155 167 (12) (7.2%) Large Commercial & Industrial 214 267 (53) (19.9%) Public Authorities & Electric Railroads 48 44 4 9.1% ------------------------------------------------------------------------------------------------------- 417 478 (61) (12.8%) ------------------------------------------------------------------------------------------------------- Total Unbundled Revenues 782 897 (115) (12.8%) ------------------------------------------------------------------------------------------------------- Total Electric Retail Revenues 7,177 6,949 228 3.3% ------------------------------------------------------------------------------------------------------- Wholesale and Miscellaneous Revenue (3) 438 472 (34) (7.2%) ------------------------------------------------------------------------------------------------------- Total Electric Revenue $ 7,615 $ 7,421 $ 194 2.6% ======================================================================================================= (1) Bundled revenue reflects deliveries to customers taking electric service under tariffed rates, which include the cost of energy and the delivery cost of the transmission and the distribution of the energy. PECO's tariffed rates also include a CTC charge. (2) Unbundled revenue reflects revenue from customers electing to receive electric generation service from an alternative energy supplier or ComEd's PPO. Revenue from customers choosing an alternative energy supplier includes a distribution charge and a CTC. Revenues from customers choosing ComEd's PPO includes an energy charge at market rates, transmission, and distribution charges and a CTC. Transmission charges received from alternative energy suppliers are included in wholesale and miscellaneous revenue. (3) Wholesale and miscellaneous revenues include sales to alternative energy suppliers, transmission revenue, sales to municipalities and other wholesale energy sales.
The changes in electric retail revenues for the nine months ended September 30, 2002, as compared to the same period in 2001 are attributable to the following:
Variance ------------------------------------------------------------------------------------------------- Weather $ 115 Customer Choice 84 Rate Changes (54) Other Effects 83 ------------------------------------------------------------------------------------------------- Electric Retail Revenue $ 228 =================================================================================================
o Weather. The weather impact was favorable compared to the prior year as a result of warmer summer weather in ComEd and PECO service territories partially offset by warmer winter weather in the ComEd and PECO service territories. Cooling degree days in the ComEd and PECO service territories were 27% and 14% higher, respectively, in the nine months ended September 30, 2002 as compared to the same period in 2001. Heating degree days in the 65 ComEd and PECO service territories were 7% and 16% lower, respectively, in the nine months ended September 30, 2002 as compared to the same period in 2001. o Customer Choice. The increase in electric retail revenues due to customer choice results from increased revenues of $205 million from customers in Pennsylvania selecting or returning to PECO as their electric generation supplier, partially offset by a decrease in revenues of $121 million from customers in Illinois electing to purchase energy from an ARES or the PPO, under which customers can purchase power from ComEd at a market-based rate. ComEd and PECO continue to collect delivery charges from these customers. o Rate Changes. The decrease in revenues attributable to rate changes reflects the 5% ComEd residential rate reduction, effective October 1, 2001, required by the Illinois restructuring legislation and the timing of a $60 million PECO rate reduction in effect for 2001 and 2002, offset by $39 million due to an increase in PECO's gross receipts tax rate effective January 1, 2002 and the expiration of a 6% reduction in PECO's rates during the first quarter of 2001. o Other Effects. For ComEd, other items impacting revenues were primarily a strong housing construction market in Chicago which contributed to residential and small commercial and industrial customer volume growth in the early portion of the year, partially offset by the unfavorable impact of a slower economy on large commercial and industrial customers. For PECO, other items impacting revenues were $53 million from higher delivery volume, exclusive of weather impacts, partially offset by an $11 million settlement of CTCs by a large customer in the first quarter of 2001. The reduction in wholesale revenue for the nine months ended September 30, 2002 as compared to the nine months ended September 30, 2001 was due primarily to a decrease in off-system sales due to the expiration of wholesale contracts that were offered by ComEd from June 2000 to May 2001 to support the open access program in Illinois, and a 2001 reversal of reserve for revenue refunds related to certain of ComEd's municipal customers as a result of a favorable FERC ruling, partially offset by an increase of $12 million due primarily to reimbursement from Generation for third-party energy reconciliations. Energy Delivery's gas sales statistics and revenue detail are as follows:
Nine Months Ended September 30, ------------------------------- 2002 2001 Variance --------------------------------------------------------------------------------------------------------------------- Deliveries in mmcf 56,990 58,536 (1,546) Revenue $358 $482 $ (124) ---------------------------------------------------------------------------------------------------------------------
66 The changes in gas revenue for the nine months ended September 30, 2002, as compared to the same 2001 period, are as follows:
Variance ------------------------------------------------------------------------------------------------- Rate Changes $ (67) Weather (33) Volume (23) Other (1) ------------------------------------------------------------------------------------------------- Gas Revenue $ (124) =================================================================================================
o Rate Changes. The unfavorable variance in rates is attributable to an adjustment of the purchased gas cost recovery by the PUC effective in December 2001. The average rate per million cubic feet for the nine months ended September 30, 2002 was 23% lower than the same 2001 period. o Weather. The unfavorable weather impact is attributable to warmer winter weather during the nine months ended September 30, 2002 as compared to the same 2001 period. Heating degree-days decreased 16% in the nine months ended September 30, 2002 compared to the same 2001 period. o Volume. Exclusive of weather impacts, lower delivery volume reduced revenue by $23 million in the nine months ended September 30, 2002 compared to the same 2001 period. Total deliveries to customers decreased 3% in the nine months ended September 30, 2002 compared to the same 2001 period, primarily as a result of slower economic conditions in 2002 offset by increased customer growth. 67 Results of Operations - Generation Business Segment
Nine Months Ended September 30, ------------------------------- 2002 2001 Variance % Change --------------------------------------------------------------------------------------------------------------------- OPERATING REVENUES $ 5,233 $5,403 $ (170) (3.1%) OPERATING EXPENSES Purchased Power 2,581 2,589 (8) (0.3)% Fuel 706 691 15 2.2% Operating and Maintenance 1,234 1,173 61 5.2% Depreciation and Amortization 197 224 (27) (12.1%) Taxes Other Than Income 126 121 5 4.1% ------------------------------------------------------------------------------------------------------- Total Operating Expense 4,844 4,798 46 1.0% ------------------------------------------------------------------------------------------------------- OPERATING INCOME 389 605 (216) (35.7%) ------------------------------------------------------------------------------------------------------- OTHER INCOME AND DEDUCTIONS Interest Expense (51) (100) 49 (49.0%) Equity in Earnings of Unconsolidated Affiliates, net 119 99 20 20.2% Other, net 54 (7) 61 n.m. ------------------------------------------------------------------------------------------------------- Total Other Income and Deductions 122 (8) 130 n.m. ------------------------------------------------------------------------------------------------------- INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES 511 597 (86) (14.4%) INCOME TAXES 198 228 (30) (13.2%) ------------------------------------------------------------------------------------------------------- INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES 313 369 (56) (15.2%) CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES 13 12 1 8.3% ------------------------------------------------------------------------------------------------------- NET INCOME $ 326 $ 381 $ (55) (14.4%) =======================================================================================================
Net income for the nine months ended September 30, 2002 was adversely impacted by a lower margin on wholesale energy sales due to depressed market prices for energy, a reduced supply of low-cost nuclear generation, and increased operating and maintenance expense, partially offset by an increase in revenue from affiliates, increased revenue from the acquisition of two generating plants in April 2002, increased interest income decreased depreciation and interest expense and lower nuclear decommissioning trust fund losses. Operating revenues, net of fuel and purchased power, decreased by $177 million reflecting a decrease in margin on market sales attributable to lower margin from market sales, offset by weather related increases in sales to affiliates and a decrease trading margins. Market sales margins were negatively impacted by lower average market sales prices. The effect of the lower sales prices were partially offset by lower average supply costs and increased market sales volumes. The decrease in trading margins was principally attributed to lower purchase power costs associated with lower wholesale market prices realized and reduced transmission costs. Operating and maintenance expense increased, primarily due to $65 million of costs incurred for the additional refueling outages during the nine months ended September 30, 2002 as compared to the same period in 2001, as well as additional allocated corporate costs including executive severance. These additional expenses were partially offset by other operating cost reductions, including $11 million related to headcount reductions, a $10 million reduction in Generation's severance accrual and cost 68 reductions related to Exelon's Cost Management Initiative. The decline in depreciation expense reflects extension of the estimated service lives of generating stations, partially offset by additional depreciation expense on plant placed in service, including two generating plants in April 2002 and the Southeast Chicago Energy Project. Lower interest expense is due to capitalized interest and a lower interest rate on the spent nuclear fuel obligation, partially offset by an increase in interest expense on long-term debt. Other, net increased $61 million for the nine months ended September 30, 2002 compared to the same period in the prior year primarily due to substantial market losses on decommissioning trust investments during 2001 as compared to the same period in 2002. Additionally, trading activities were initiated in April 2001. Revenue for the nine months ended September 30, 2002 includes a net trading portfolio loss of $27 million compared to a net $1 million loss in the nine months ended September 30, 2001. Generation Operating Statistics: For the nine months ended September 30, 2002 and 2001, Generation's sales and the supply of these sales, excluding the trading portfolio, were as follows:
Nine Months Ended September 30, ------------------------------- Sales (in GWhs) 2002 2001 % Change --------------------------------------------------------------------------------------------------------------------- Energy Delivery 90,579 90,001 0.6% Exelon Energy 4,067 5,044 (19.4%) Market Sales 61,089 53,787 13.6% ------------------------------------------------------------------------------------------------------- Total Sales 155,735 148,832 4.6% ======================================================================================================= Nine Months Ended September 30, Supply of Sales (in GWhs) 2002 2001 % Change --------------------------------------------------------------------------------------------------------------------- Nuclear Generation 86,127 87,397 (1.5%) Purchases - non-trading portfolio 59,496 52,459 13.4% Fossil and Hydro Generation 10,112 8,976 12.7% ------------------------------------------------------------------------------------------------------- Total Supply 155,735 148,832 4.6% =======================================================================================================
Trading volume of 51,260 GWhs and 2,286 GWhs for the nine months ended September 30, 2002 and 2001, respectively, is not included in the table above. 69 Generation's average margin data for the nine months ended September 30, 2002 and 2001 were as follows:
Nine Months Ended September 30, ------------------------------- ($/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%) --------------------------------------------------------------------------------------------------------------------- (1) Average supply cost includes purchase power and fuel cost.
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% ======================================================================================================= (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
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% ======================================================================================================= (1) Bundled revenue reflects deliveries to customers taking electric service under tariffed rates, which include the cost of energy and the delivery cost of the transmission and the distribution of the energy. (2) Revenue from customers choosing an ARES includes a distribution charge and a CTC charge. Transmission charges received from ARES are included in wholesale and miscellaneous revenue. Revenues from customers choosing the PPO includes an energy charge at market rates, transmission, and distribution charges and a CTC charge. (3) Wholesale and miscellaneous revenues include sales to ARES, transmission revenue, sales to municipalities and other wholesale energy sales.
The changes in electric retail revenues for the 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% ======================================================================================================= (1) Bundled service reflects deliveries to customers taking electric service under tariffed rates, which include the cost of energy and the delivery cost of the transmission and the distribution of the energy. (2) Unbundled service reflects customers electing to receive electric generation service from an ARES or the PPO.
86
Nine Months Ended September 30, ------------------------------- Electric Revenue 2002 2001 Variance % Change --------------------------------------------------------------------------------------------------------------------- Bundled Revenues (1) Residential $ 1,881 $ 1,852 $ 29 1.6% Small Commercial & Industrial 1,343 1,410 (67) (4.8%) Large Commercial & Industrial 324 406 (82) (20.2%) Public Authorities & Electric Railroads 297 335 (38) (11.3%) ------------------------------------------------------------------------------------------------------- 3,845 4,003 (158) (3.9%) ------------------------------------------------------------------------------------------------------- Unbundled Revenues (2) ARES Small Commercial & Industrial 94 36 58 161.1% Large Commercial & Industrial 101 60 41 68.3% Public Authorities & Electric Railroads 18 3 15 n.m. ------------------------------------------------------------------------------------------------------- 213 99 114 115.2% ------------------------------------------------------------------------------------------------------- PPO Small Commercial & Industrial 155 167 (12) (7.2%) Large Commercial & Industrial 214 267 (53) (19.9%) Public Authorities & Electric Railroads 48 44 4 9.1% ------------------------------------------------------------------------------------------------------- 417 478 (61) (12.8%) ------------------------------------------------------------------------------------------------------- Total Unbundled Revenues 630 577 53 9.2% ------------------------------------------------------------------------------------------------------- Total Electric Retail Revenues 4,475 4,580 (105) (2.3%) Wholesale and Miscellaneous Revenue (3) 259 315 (56) (17.8%) ------------------------------------------------------------------------------------------------------- Total Electric Revenue $ 4,734 $ 4,895 $ (161) (3.3%) ======================================================================================================= (1) Bundled revenue reflects deliveries to customers taking electric service under tariffed rates, which include the cost of energy and the delivery cost of the transmission and the distribution of the energy. (2) Revenue from customers choosing an ARES includes a distribution charge and a CTC charge. Transmission charges received from ARES are included in wholesale and miscellaneous revenue. Revenues from customers choosing the PPO includes an energy charge at market rates, transmission, and distribution charges and a CTC charge. (3) Wholesale and miscellaneous revenues include sales to ARES, transmission revenue, sales to municipalities and other wholesale energy sales.
The changes in electric retail revenues for the nine months ended September 30, 2002, as compared to the nine months ended September 30, 2001, are attributable to the following:
Variance ------------------------------------------------------------------------------------------------- Customer Choice $ (121) Rate Changes (99) Weather 73 Other Effects 42 ------------------------------------------------------------------------------------------------- Retail Revenue $ (105) -------------------------------------------------------------------------------------------------
o Customer Choice. The decrease in revenues reflects customers in Illinois electing to purchase energy from an ARES or the PPO. 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% ======================================================================================================= (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.
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% ======================================================================================================= (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.
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% ------------------------------------------------------------------------------------------------------- (1) Bundled service reflects deliveries to customers taking electric service under tariffed rates, which include the cost of energy, the delivery cost of the transmission and distribution of the energy and a CTC charge. (2) Unbundled service reflects customers electing to receive electric generation service from an alternative energy supplier.
Nine Months Ended September 30, -------------------------------- Electric Revenue 2002 2001 Variance % Change --------------------------------------------------------------------------------------------------------------------- Bundled Revenue (1) Residential $ 999 $ 807 $ 192 23.8% Small Commercial & Industrial 664 500 164 32.8% Large Commercial & Industrial 829 689 140 20.3% Public Authorities & Electric Railroads 58 53 5 9.4% ------------------------------------------------------------------------------------------------------- 2,550 2,049 501 24.5% ------------------------------------------------------------------------------------------------------- Unbundled Revenue (2) Residential 129 184 (55) (29.9%) Small Commercial & Industrial 13 73 (60) (82.2%) Large Commercial & Industrial 10 61 (51) (83.6%) Public Authorities & Electric Railroads -- 1 (1) (100.0%) ------------------------------------------------------------------------------------------------------- 152 319 (167) (52.4%) ------------------------------------------------------------------------------------------------------- Total Electric Retail Revenues 2,702 2,368 334 14.1% Wholesale and Miscellaneous Revenue (3) 179 158 21 13.3% ------------------------------------------------------------------------------------------------------- Total Electric Revenue $ 2,881 $ 2,526 $ 355 14.1% ======================================================================================================= (1) Bundled revenue reflects revenue from customers taking electric service under tariffed rates, which includes the cost of energy, the delivery cost of the transmission and distribution of the energy and a CTC charge. (2) Unbundled revenue reflects revenue from customers electing to receive generation from an alternate supplier, which include a distribution charge and a CTC charge. (3) Wholesale and miscellaneous revenues include transmission revenue, sales to municipalities and other wholesale energy sales.
101 The changes in electric retail revenues for the nine months ended September 30, 2002, as compared to the same 2001 period, are as follows:
Variance ----------------------------------------------------------------------------------------------------- Customer Choice $ 205 Rate Changes 45 Weather 42 Other Effects 42 ----------------------------------------------------------------------------------------------------- Electric Retail Revenue $ 334 =====================================================================================================
o Customer Choice. As of September 30, 2002, the customer load served by alternate suppliers was 973 MW or 12.5% as compared to 1,042 MW or 13.6% as of September 30, 2001. For the nine months ended September 30, 2002, the percent of PECO's total retail deliveries for which PECO was the electric supplier was 91.6% in 2002, a 14.1% increase as compared to 77.4% in 2001. As of September 30, 2002, the number of customers served by alternate suppliers was 285,549 or 18.7% as compared to September 30, 2001 of 397,396 or 26.1%. This increase in the customer load and the percentage of MWh served by PECO, and the decrease in the number of customers served by alternative suppliers primarily resulted from customers selecting or returning to PECO as their electric generation supplier. o Rate Changes. The increase in revenues attributable to rate changes primarily reflects the expiration of a 6% reduction in PECO's electric rates during the first quarter of 2001 and a $39 million increase as a result of the increase in the gross receipts tax rate effective January 1, 2002. These increases are partially offset by the timing of a $60 million rate reduction in effect for 2001 and 2002. o Weather. The weather impact was favorable compared to the prior year as a result of warmer summer weather partially offset by warmer winter weather. Cooling degree-days increased 14% for the nine months ended September 30, 2002 compared to the same 2001 period. Heating degree-days decreased 16% for the nine months ended September 30, 2002 compared to the same 2001 period. o Other Effects. Other items affecting revenue during the nine months ended September 30, 2002 include: o Volume. Exclusive of weather impacts, higher delivery volume increased PECO's revenue by $53 million compared to the same 2001 period. o Other. An $11 million settlement of CTCs by a large customer in the first quarter of 2001. PECO's gas sales statistics for the nine months ended September 30, 2002 as compared to the same 2001 period are as follows:
Nine Months Ended September 30, -------------------------------- 2002 2001 Variance --------------------------------------------------------------------------------------------------------------------- Deliveries in mmcf 56,990 58,536 (1,546) Revenue $358 $482 $ (124) ---------------------------------------------------------------------------------------------------------------------
102 The changes in gas revenue for the nine months ended September 30, 2002, as compared to the same 2001 period, are as follows:
Variance ----------------------------------------------------------------------------------------------------- Rate Changes $ (67) Weather (33) Volume (23) Other (1) ----------------------------------------------------------------------------------------------------- Gas Revenue $ (124) =====================================================================================================
o Rate Changes. The unfavorable variance in rates is attributable to an adjustment of the purchased gas cost recovery by the PUC effective in December 2001. The average rate per million cubic feet for the nine months ended September 30, 2002 was 23% lower than the same 2001 period. o Weather. The unfavorable weather impact is attributable to warmer winter weather during the nine months ended September 30, 2002 as compared to the same 2001 period. Heating degree-days decreased 16% in the nine months ended September 30, 2002 compared to the same 2001 period. o Volume. Exclusive of weather impacts, lower delivery volume reduced revenue by $23 million in the nine months ended September 30, 2002 compared to the same 2001 period. Total deliveries to customers decreased 3% in the nine months ended September 30, 2002 compared to the same 2001 period, primarily as a result of slower economic conditions in 2002 partially offset by increased customer growth. Purchased Power and Fuel Expense Purchased power and fuel expense for the nine months ended September 30, 2002 increased $139 million as compared to the same 2001 period. The increase in fuel and purchased power expense was primarily attributable to $187 million from customers in Pennsylvania selecting or returning to PECO as their electric generation supplier and higher PJM ancillary charges of $28 million. These increases were partially offset by $67 million from lower gas prices, $8 million from lower delivery volume primarily related to gas and $6 million as a result of unfavorable weather conditions. Operating and Maintenance Expense O&M expense for the nine months ended September 30, 2002 decreased $6 million, or 2%, as compared to the same 2001 period. The decrease in O&M expense was primarily attributable to $18 million of employee severance costs associated with the Merger, $12 million of incremental costs related to two storms and $5 million associated with a write-off of excess and obsolete inventory, all of which occurred in 2001. These decreases are partially offset by $16 million related to an increased allocation of corporate expense and $15 million related to the deployment of automated meter reading technology. 103 Depreciation and Amortization Expense Depreciation and amortization expense for the nine months ended September 30, 2002 increased $33 million, or 11%, as compared to the same 2001 period as follows:
Nine Months Ended September 30, -------------------------------- 2002 2001 Variance % Change --------------------------------------------------------------------------------------------------------------------- Depreciation Expense $ 94 $ 89 $ 5 5.6% Competitive Transition Charge Amortization 236 207 29 14.0% Other Amortization Expense 18 19 (1) (5.3%) ------------------------------------------------------------------------------------------------------- Total Depreciation and Amortization $ 348 $ 315 $ 33 10.5% =======================================================================================================
The increase was primarily attributable to $29 million of additional amortization of PECO's CTC and an increase of $5 million related to depreciation expense associated with additional plant in service. The additional amortization of the CTC is in accordance with PECO's original settlement under the Pennsylvania Competition Act. Taxes Other Than Income Taxes other than income for the nine months ended September 30, 2002 increased $72 million, or 53%, as compared to the same 2001 period. The increase was primarily attributable to $54 million of additional gross receipts tax related to additional revenues and an increase in the gross receipts tax rate on electric revenue effective January 1, 2002. The increase was also attributable to a reduction of $9 million in the state use tax accruals in 2001 and $7 million related to an additional assessment of real estate taxes in the third quarter of 2002. Interest Charges Interest charges decreased $52 million, or 16%, for the nine months ended September 30, 2002 as compared to the same 2001 period. The decrease was primarily attributable to lower interest expense on long-term debt of $40 million as a result of principal payments and lower interest rates, and $8 million in interest expense on a loan from ComEd in 2001. Other Income and Deductions Other income and deductions excluding interest charges decreased $23 million, or 77%, for the nine months ended September 30, 2002 as compared to the same 2001 period. The decrease in other income and deductions was primarily attributable to lower interest income of $7 million in 2002. The decrease was also attributable to intercompany interest income of $10 million, a gain on the settlement of an interest rate swap of $6 million and the favorable settlement of a customer contract of $3 million, all of which occurred in 2001. 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% =================================================================================================================== n.m. - not meaningful
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%) --------------------------------------------------------------------------------------------------------------------- (1) Average supply cost includes purchase power and fuel cost.
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%) --------------------------------------------------------------------------------------------------------------------- (1) Average supply cost includes purchase power and fuel cost.
Generation's nuclear fleet, including AmerGen, performed at a capacity factor 92.1% for the nine months ended September 30, 2002 compared to 95.1% for the same period in 2001. Generation's nuclear fleet's production costs, including AmerGen, for the nine months ended September 30, 2002 were $13.05 per MWh compared to $12.40 per MWh for the same period in 2001. The lower capacity factor and increased unit production costs are primarily due to 186 planned outage days in the nine months ended September 30, 2002, versus 55 days in the same period in 2001, including AmerGen. Increased unit production costs are partially offset by headcount reductions and Exelon's Cost Management Initiatives. Generation's average purchased power costs for wholesale operations were $43.60 per MWh for the nine months ended September 30, 2002, compared to $49.77 per MWh for the same period in 2001. The decrease in purchase power costs was primarily due to depressed wholesale power market prices. Operating and Maintenance Expense Operating and maintenance expense increased $61 million, 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 116 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. 117 o Purchase obligations increased by $2.3 billion, primarily due to an increase of $3.8 billion in power only purchases and a $0.1 billion increase in transmission rights purchases partially offset by a $1.6 billion decrease in net capacity purchase commitments. Approximately $2 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 ===================================================================================================================== (1) Mark-to-market gains and losses on contracts that qualify as cash-flow hedges are recorded in other comprehensive income. (2) Mark-to-market gains and losses on other non-trading derivative contracts that do not qualify as cash-flow hedges are recorded in earnings. (3) Mark-to-market gains and losses on trading contracts are recorded in earnings.
Credit Risk Exelon and Generation Generation is a counterparty to Dynegy in various energy transactions. In early July 2002, the credit ratings of Dynegy were downgraded by two credit rating agencies to below investment grade. As of 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 ------------------------------- 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 -------------------------------------------------------------------------------- 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 ------------------------------- Ruth Ann M. Gillis Senior Vice President and Chief Financial Officer Exelon Corporation