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, 2003
                                       OR

            [ ]         TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                        SECURITIES EXCHANGE ACT OF 1934
Commission Name of Registrant; State of Incorporation; IRS Employer File Number Address of Principal Executive Offices; and Identification Telephone Number Number - --------------------- --------------------------------------------------------- ------------------------ 1-16169 EXELON CORPORATION 23-2990190 (a Pennsylvania corporation) 10 South Dearborn Street - 37th Floor P.O. Box 805379 Chicago, Illinois 60680-5379 (312) 394-7398 1-1839 COMMONWEALTH EDISON COMPANY 36-0938600 (an Illinois corporation) 10 South Dearborn Street - 37th Floor P.O. Box 805379 Chicago, Illinois 60680-5379 (312) 394-4321 1-1401 PECO ENERGY COMPANY 23-0970240 (a Pennsylvania corporation) P.O. Box 8699 2301 Market Street Philadelphia, Pennsylvania 19101-8699 (215) 841-4000 333-85496 EXELON GENERATION COMPANY, LLC 23-3064219 (a Pennsylvania limited liability company) 300 Exelon Way Kennett Square, Pennsylvania 19348 (610) 765-6900
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [_]. The number of shares outstanding of each registrant's common stock as of September 30, 2003 was:
Exelon Corporation Common Stock, without par value 327,021,190 Commonwealth Edison Company Common Stock, $12.50 par value 127,016,483 PECO Energy Company Common Stock, without par value 170,478,507 Exelon Generation Company, LLC not applicable
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Exelon Corporation Yes [X] No [ ] Commonwealth Edison Company, PECO Energy Company and Exelon Generation Company, LLC Yes [ ] No [X].
TABLE OF CONTENTS Page No. -------- FILING FORMAT 3 FORWARD-LOOKING STATEMENTS 3 WHERE TO FIND MORE INFORMATION 3 PART I. FINANCIAL INFORMATION 4 ITEM 1. FINANCIAL STATEMENTS 4 Exelon Corporation Consolidated Statements of Income and Comprehensive Income 5 Consolidated Statements of Cash Flows 6 Consolidated Balance Sheets 7 Commonwealth Edison Company Consolidated Statements of Income and Comprehensive Income 9 Consolidated Statements of Cash Flows 10 Consolidated Balance Sheets 11 PECO Energy Company Consolidated Statements of Income and Comprehensive Income 13 Consolidated Statements of Cash Flows 14 Consolidated Balance Sheets 15 Exelon Generation Company, LLC Consolidated Statements of Income and Comprehensive Income 17 Consolidated Statements of Cash Flows 18 Consolidated Balance Sheets 19 Condensed Combined Notes to Consolidated Financial Statements 21 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 71 Exelon Corporation 76 Commonwealth Edison Company 109 PECO Energy Company 124 Exelon Generation Company, LLC 140 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK 157 ITEM 4. CONTROLS AND PROCEDURES 169 PART II. OTHER INFORMATION 172 ITEM 1. LEGAL PROCEEDINGS 172 ITEM 3. DEFAULTS UPON SENIOR SECURITIES 172 ITEM 5. OTHER INFORMATION 173 ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K 174 SIGNATURES 176
2 FILING FORMAT This combined Form 10-Q is being filed separately by Exelon Corporation (Exelon), Commonwealth Edison Company (ComEd), PECO Energy Company (PECO) and Exelon Generation Company, LLC (Generation) (Registrants). Information contained herein relating to any individual registrant has been filed by such registrant on its own behalf. No registrant makes any representation as to information relating to any other registrant. FORWARD-LOOKING STATEMENTS Except for the historical information contained herein, certain of the matters discussed in this Report are forward-looking statements, within the meaning of the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from the forward-looking statements made by a registrant include those factors discussed herein, as well as the items discussed in (a) the Registrants' 2002 Annual Report on Form 10-K - ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations--Business Outlook and the Challenges in Managing Our Business for each of Exelon, ComEd, PECO and Generation, (b) the Registrants' 2002 Annual Report on Form 10-K - ITEM 8. Financial Statements and Supplementary Data: Exelon - Note 19, ComEd - Note 16, PECO - Note 18 and Generation - Note 13 and (c) other factors discussed in filings with the United States Securities and Exchange Commission (SEC) by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Report. WHERE TO FIND MORE INFORMATION The public may read and copy any reports or other information that the Registrants file with the SEC at the SEC's public reference room at 450 Fifth Street, N.W., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. These documents are also available to the public from commercial document retrieval services, the web site maintained by the SEC at www.sec.gov and Exelon's website at www.exeloncorp.com. 3 PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS 4
EXELON CORPORATION ------------------ EXELON CORPORATION AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (Unaudited) Three Months Ended Nine Months Ended ------------------ ----------------- September 30, September 30, ------------ ------------- (in millions, except per share data) 2003 2002 2003 2002 - ---------------------------------------------------------------------------------------------------------------------------------- OPERATING REVENUES $ 4,441 $ 4,370 $ 12,236 $ 11,245 OPERATING EXPENSES Purchased power 1,179 1,233 2,765 2,543 Purchased power from unconsolidated affiliate 133 104 310 220 Fuel 551 373 1,908 1,233 Impairment of Exelon Boston Generating, LLC long-lived assets 945 -- 945 -- Operating and maintenance 1,226 1,114 3,438 3,252 Depreciation and amortization 293 345 842 1,012 Taxes other than income 131 201 489 568 - --------------------------------------------------------------------------------------------------------------------------------- Total operating expenses 4,458 3,370 10,697 8,828 - --------------------------------------------------------------------------------------------------------------------------------- OPERATING INCOME (LOSS) (17) 1,000 1,539 2,417 - --------------------------------------------------------------------------------------------------------------------------------- OTHER INCOME AND DEDUCTIONS Interest expense (213) (249) (652) (739) Interest expense to affiliates (4) -- (9) -- Distributions on preferred securities of subsidiaries (8) (11) (30) (34) Equity in earnings of unconsolidated affiliates 49 92 82 114 Other, net (21) 16 (153) 239 - --------------------------------------------------------------------------------------------------------------------------------- Total other income and deductions (197) (152) (762) (420) - --------------------------------------------------------------------------------------------------------------------------------- INCOME (LOSS) BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES (214) 848 777 1,997 INCOME TAXES (112) 297 258 724 - --------------------------------------------------------------------------------------------------------------------------------- INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES (102) 551 519 1,273 CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES (net of income taxes of $69 and $(90) for the nine months ended September 30, 2003 and 2002, respectively) -- -- 112 (230) - --------------------------------------------------------------------------------------------------------------------------------- NET INCOME (LOSS) (102) 551 631 1,043 - --------------------------------------------------------------------------------------------------------------------------------- OTHER COMPREHENSIVE INCOME (LOSS) (net of income taxes) Minimum pension liability 9 -- 9 -- Cash flow hedge adjustment 142 (32) 58 (103) Foreign currency translation adjustment -- -- 2 -- Unrealized gain (loss) on marketable securities 5 (73) 3 (158) SFAS No. 143 transition adjustment -- -- 168 -- Interest in other comprehensive income (loss) of unconsolidated affiliates 1 (20) 9 (21) - --------------------------------------------------------------------------------------------------------------------------------- Total other comprehensive income (loss) 157 (125) 249 (282) - --------------------------------------------------------------------------------------------------------------------------------- TOTAL COMPREHENSIVE INCOME $ 55 $ 426 $ 880 $ 761 ================================================================================================================================== AVERAGE SHARES OF COMMON STOCK OUTSTANDING - Basic 326 323 325 322 ================================================================================================================================== AVERAGE SHARES OF COMMON STOCK OUTSTANDING - Diluted 326 324 328 324 ================================================================================================================================== EARNINGS (LOSS) PER AVERAGE COMMON SHARE: BASIC: Income (loss) before cumulative effect of changes in accounting principles $ (0.31) $ 1.71 $ 1.60 $ 3.95 Cumulative effect of changes in accounting principles -- -- 0.34 (0.71) - --------------------------------------------------------------------------------------------------------------------------------- Net income (loss) $ (0.31) $ 1.71 $ 1.94 $ 3.24 ================================================================================================================================== DILUTED: Income (loss) before cumulative effect of changes in accounting principles $ (0.31) $ 1.70 $ 1.59 $ 3.93 Cumulative effect of changes in accounting principles -- -- 0.34 (0.71) - --------------------------------------------------------------------------------------------------------------------------------- Net income (loss) $ (0.31) $ 1.70 $ 1.93 $ 3.22 ================================================================================================================================== DIVIDENDS PER COMMON SHARE $ 0.50 $ 0.44 $ 1.42 $ 1.32 ================================================================================================================================== See Condensed Combined Notes to Consolidated Financial Statements
5
EXELON CORPORATION AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Nine Months Ended September 30, ------------------------------- (in millions) 2003 2002 - ----------------------------------------------------------------------------------------------------------------------- CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 631 $ 1,043 Adjustments to reconcile net income to net cash flows provided by operating activities: Depreciation, amortization and accretion, including nuclear fuel 1,290 1,284 Cumulative effect of changes in accounting principles (net of income taxes) (112) 230 Gain on sale of investment -- (199) Provision for uncollectible accounts 72 107 Deferred income taxes (363) 293 Equity in earnings of unconsolidated affiliates (82) (114) Impairment of investments 295 46 Impairment of long-lived assets 950 -- Employee severance-related costs 152 -- Pension and non-pension postretirement curtailment costs 26 -- Net realized (gains) losses on nuclear decommissioning trust funds (9) 32 Other operating activities 91 56 Changes in assets and liabilities: Accounts receivable (19) (358) Inventories (55) (25) Accounts payable, accrued expenses and other current liabilities 50 1 Changes in payables and receivables from unconsolidated affiliates 18 46 Other current assets (100) 68 Pension and non-pension postretirement benefits obligations (241) 22 Other noncurrent assets and liabilities (41) 131 - ----------------------------------------------------------------------------------------------------------------------- Net cash flows provided by operating activities 2,553 2,663 - ----------------------------------------------------------------------------------------------------------------------- CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures (1,501) (1,534) Proceeds from liquidated damages 92 -- Proceeds from nuclear decommissioning trust funds 1,880 1,184 Investment in nuclear decommissioning trust funds (2,043) (1,330) Note receivable from unconsolidated affiliate 35 (42) Proceeds from sale of investments 186 287 Acquisition of generating plants -- (443) Other investing activities 50 19 - ----------------------------------------------------------------------------------------------------------------------- Net cash flows used in investing activities (1,301) (1,859) - ----------------------------------------------------------------------------------------------------------------------- CASH FLOWS FROM FINANCING ACTIVITIES Issuance of long-term debt 2,105 956 Retirement of long-term debt (2,075) (1,946) Change in short-term debt (599) 428 Issuance of long-term debt to affiliate 103 -- Issuance of mandatorily redeemable preferred securities of subsidiaries 200 -- Retirement of mandatorily redeemable preferred securities of subsidiaries (250) (18) Retirement of preferred stock of subsidiaries (50) -- Dividends paid on common stock (461) (420) Payment on acquisition note payable to Sithe Energies, Inc. (210) -- Proceeds from employee stock plans 139 64 Contribution from minority interest of consolidated subsidiary -- 43 Change in restricted cash 78 81 Other financing activities (85) (16) - ----------------------------------------------------------------------------------------------------------------------- Net cash flows used in financing activities (1,105) (828) - ----------------------------------------------------------------------------------------------------------------------- INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 147 (24) CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 469 485 - ----------------------------------------------------------------------------------------------------------------------- CASH AND CASH EQUIVALENTS INCLUDING CASH CLASSIFIED AS HELD FOR SALE $ 616 $ 461 CASH CLASSIFIED AS HELD FOR SALE ON THE CONSOLIDATED BALANCE SHEET (12) -- - ----------------------------------------------------------------------------------------------------------------------- CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 604 $ 461 ======================================================================================================================= See Condensed Combined Notes to Consolidated Financial Statements
6
EXELON CORPORATION AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, December 31, (in millions) 2003 2002 - ----------------------------------------------------------------------------------------------------------------------- ASSETS CURRENT ASSETS Cash and cash equivalents $ 604 $ 469 Restricted cash 318 396 Accounts receivable, net Customer 1,952 2,076 Other 270 284 Receivable from unconsolidated affiliate --- 39 Inventories, at average cost Fossil fuel 198 175 Materials and supplies 289 306 Other 429 380 Assets held for sale 109 -- - ----------------------------------------------------------------------------------------------------------------------- Total current assets 4,169 4,125 - ----------------------------------------------------------------------------------------------------------------------- PROPERTY, PLANT AND EQUIPMENT, NET 19,476 17,126 DEFERRED DEBITS AND OTHER ASSETS Regulatory assets 5,304 5,993 Nuclear decommissioning trust funds 3,404 3,053 Investments 1,198 1,403 Goodwill 4,734 4,992 Other 859 793 - ----------------------------------------------------------------------------------------------------------------------- Total deferred debits and other assets 15,499 16,234 - ----------------------------------------------------------------------------------------------------------------------- TOTAL ASSETS $ 39,144 $ 37,485 ======================================================================================================================= See Condensed Combined Notes to Consolidated Financial Statements
7
EXELON CORPORATION AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, December 31, (in millions) 2003 2002 - ----------------------------------------------------------------------------------------------------------------------- LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES Notes payable $ 82 $ 681 Note payable to unconsolidated affiliate 326 534 Long-term debt due within one year 2,067 1,402 Accounts payable 1,692 1,607 Accrued expenses 1,242 1,354 Other 287 296 Liabilities held for sale 57 -- - ----------------------------------------------------------------------------------------------------------------------- Total current liabilities 5,753 5,874 - ----------------------------------------------------------------------------------------------------------------------- LONG-TERM DEBT 12,468 13,127 LONG-TERM DEBT TO AFFILIATE 103 -- MANDATORILY REDEEMABLE PREFERRED SECURITIES 422 -- DEFERRED CREDITS AND OTHER LIABILITIES Deferred income taxes 3,798 3,702 Unamortized investment tax credits 291 301 Nuclear decommissioning liability for retired plants -- 1,395 Asset retirement obligation 2,481 -- Pension obligation 1,609 1,959 Non-pension postretirement benefits obligation 1,033 877 Spent nuclear fuel obligation 865 858 Regulatory liabilities 880 -- Other 1,026 978 - ----------------------------------------------------------------------------------------------------------------------- Total deferred credits and other liabilities 11,983 10,070 - ----------------------------------------------------------------------------------------------------------------------- Total liabilities 30,729 29,071 - ----------------------------------------------------------------------------------------------------------------------- COMMITMENTS AND CONTINGENCIES MINORITY INTEREST OF CONSOLIDATED SUBSIDIARIES 1 77 PREFERRED SECURITIES OF SUBSIDIARIES 87 595 SHAREHOLDERS' EQUITY Common stock 7,226 7,059 Deferred compensation -- (1) Retained earnings 2,210 2,042 Accumulated other comprehensive income (loss) (1,109) (1,358) - ----------------------------------------------------------------------------------------------------------------------- Total shareholders' equity 8,327 7,742 - ----------------------------------------------------------------------------------------------------------------------- TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 39,144 $ 37,485 ======================================================================================================================= See Condensed Combined Notes to Consolidated Financial Statements
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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) 2003 2002 2003 2002 - ----------------------------------------------------------------------------------------------------------------------- OPERATING REVENUES Operating revenues $ 1,717 $ 1,912 $ 4,473 $ 4,685 Operating revenues from affiliates 20 26 49 49 - ----------------------------------------------------------------------------------------------------------------------- Total operating revenues 1,737 1,938 4,522 4,734 - ----------------------------------------------------------------------------------------------------------------------- OPERATING EXPENSES Purchased power 6 8 17 20 Purchased power from affiliate 885 967 1,984 2,046 Operating and maintenance 259 234 683 620 Operating and maintenance from affiliates 40 33 98 104 Depreciation and amortization 97 129 287 397 Taxes other than income 87 77 235 223 - ----------------------------------------------------------------------------------------------------------------------- Total operating expenses 1,374 1,448 3,304 3,410 - ----------------------------------------------------------------------------------------------------------------------- OPERATING INCOME 363 490 1,218 1,324 - ----------------------------------------------------------------------------------------------------------------------- OTHER INCOME AND DEDUCTIONS Interest expense (107) (122) (322) (374) Distributions on mandatorily redeemable preferred securities (6) (7) (20) (22) Interest income from affiliates 6 8 20 23 Other, net 9 (8) 28 6 - ----------------------------------------------------------------------------------------------------------------------- Total other income and deductions (98) (129) (294) (367) - ----------------------------------------------------------------------------------------------------------------------- INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE 265 361 924 957 INCOME TAXES 102 146 365 381 - ----------------------------------------------------------------------------------------------------------------------- INCOME BEFORE CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE 163 215 559 576 CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE (net of income taxes of $0) -- -- 5 -- - ----------------------------------------------------------------------------------------------------------------------- NET INCOME 163 215 564 576 - ----------------------------------------------------------------------------------------------------------------------- OTHER COMPREHENSIVE INCOME (LOSS) (net of income taxes) Cash flow hedge adjustment 3 (19) 31 (25) Unrealized gain (loss) on marketable securities 2 (1) 3 (3) Foreign currency translation adjustment -- -- 2 -- - ----------------------------------------------------------------------------------------------------------------------- Total other comprehensive income (loss) 5 (20) 36 (28) - ----------------------------------------------------------------------------------------------------------------------- TOTAL COMPREHENSIVE INCOME $ 168 $ 195 $ 600 $ 548 ======================================================================================================================= See Condensed Combined 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) 2003 2002 - ----------------------------------------------------------------------------------------------------------------------- CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 564 $ 576 Adjustments to reconcile net income to net cash flows provided by operating activities: Depreciation and amortization 287 397 Cumulative effect of a change in accounting principle (net of income taxes) (5) -- Gain on sale of investments (3) -- Provision for uncollectible accounts 31 29 Deferred income taxes 92 92 Employee severance-related costs 58 -- Pension and non-pension postretirement curtailment costs 2 -- Other operating activities 49 76 Changes in assets and liabilities: Accounts receivable (55) (198) Inventories 7 (4) Accounts payable, accrued expenses and other current liabilities (102) 52 Changes in receivables and payables to affiliates (45) 449 Other current assets (12) (2) Pension and non-pension postretirement benefits obligations (112) 15 Other noncurrent assets and liabilities (14) 9 - ----------------------------------------------------------------------------------------------------------------------- Net cash flows provided by operating activities 742 1,491 - ----------------------------------------------------------------------------------------------------------------------- CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures (537) (549) Investment in affiliate money pool (147) -- Notes receivable from affiliates 213 14 Proceeds from sale of investments 5 -- Other investing activities 16 7 - ----------------------------------------------------------------------------------------------------------------------- Net cash flows used in investing activities (450) (528) - ----------------------------------------------------------------------------------------------------------------------- CASH FLOWS FROM FINANCING ACTIVITIES Issuance of long-term debt 1,427 701 Retirement of long-term debt (1,139) (1,365) Issuance of mandatorily redeemable preferred securities 200 -- Retirement of mandatorily redeemable preferred securities (200) -- Change in short-term debt (71) 94 Dividends paid on common stock (305) (353) Change in restricted cash (17) (37) Settlement of cash flow hedges (45) (10) Other financing activities (36) -- - ----------------------------------------------------------------------------------------------------------------------- Net cash flows used in financing activities (186) (970) - ----------------------------------------------------------------------------------------------------------------------- INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 106 (7) CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 16 23 - ----------------------------------------------------------------------------------------------------------------------- CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 122 $ 16 ======================================================================================================================= SUPPLEMENTAL CASH FLOW INFORMATION Noncash investing and financing activities: Retirement of treasury shares $ -- $ 1,344 Adoption of SFAS No. 143 - adjustment to other paid in capital and goodwill 210 -- See Condensed Combined 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) 2003 2002 - ----------------------------------------------------------------------------------------------------------------------- ASSETS CURRENT ASSETS Cash and cash equivalents $ 122 $ 16 Restricted cash 82 65 Accounts receivable, net Customer 818 782 Other 60 72 Inventories, at average cost 50 65 Deferred income taxes 19 20 Receivables from affiliates 151 15 Other 26 14 - ----------------------------------------------------------------------------------------------------------------------- Total current assets 1,328 1,049 - ----------------------------------------------------------------------------------------------------------------------- PROPERTY, PLANT AND EQUIPMENT, NET 8,039 7,756 DEFERRED DEBITS AND OTHER ASSETS Regulatory assets -- 447 Investments 36 42 Goodwill 4,711 4,916 Receivables from affiliates 2,228 1,300 Prepaid pension asset 48 -- Other 389 320 - ----------------------------------------------------------------------------------------------------------------------- Total deferred debits and other assets 7,412 7,025 - ----------------------------------------------------------------------------------------------------------------------- TOTAL ASSETS $ 16,779 $ 15,830 ======================================================================================================================= See Condensed Combined Notes to Consolidated Financial Statements
11
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, December 31, (in millions) 2003 2002 - ----------------------------------------------------------------------------------------------------------------------- LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES Notes payable $ -- $ 71 Long-term debt due within one year 519 698 Accounts payable 207 201 Accrued expenses 465 538 Payables to affiliates 186 416 Customer deposits 78 81 Other 13 18 - ----------------------------------------------------------------------------------------------------------------------- Total current liabilities 1,468 2,023 - ----------------------------------------------------------------------------------------------------------------------- LONG-TERM DEBT 5,755 5,268 MANDATORILY REDEEMABLE PREFERRED SECURITIES 344 -- DEFERRED CREDITS AND OTHER LIABILITIES Deferred income taxes 1,776 1,650 Unamortized investment tax credits 49 51 Pension obligation -- 91 Non-pension postretirement benefits obligation 187 138 Payables to affiliates 39 224 Regulatory liabilities 880 -- Other 332 297 - ----------------------------------------------------------------------------------------------------------------------- Total deferred credits and other liabilities 3,263 2,451 - ----------------------------------------------------------------------------------------------------------------------- Total liabilities 10,830 9,742 - ----------------------------------------------------------------------------------------------------------------------- COMMITMENTS AND CONTINGENCIES MANDATORILY REDEEMABLE PREFERRED SECURITIES -- 330 SHAREHOLDERS' EQUITY Common stock 1,588 1,588 Preference stock 7 7 Other paid in capital 4,029 4,239 Receivable from parent (509) (615) Retained earnings 836 577 Accumulated other comprehensive income (loss) (2) (38) - ----------------------------------------------------------------------------------------------------------------------- Total shareholders' equity 5,949 5,758 - ----------------------------------------------------------------------------------------------------------------------- TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 16,779 $ 15,830 ======================================================================================================================= See Condensed Combined Notes to Consolidated Financial Statements
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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) 2003 2002 2003 2002 - ----------------------------------------------------------------------------------------------------------------------- OPERATING REVENUES Operating revenues $ 1,146 $ 1,221 $ 3,319 $ 3,230 Operating revenues from affiliates 3 3 9 9 - ----------------------------------------------------------------------------------------------------------------------- Total operating revenues 1,149 1,224 3,328 3,239 - ----------------------------------------------------------------------------------------------------------------------- OPERATING EXPENSES Purchased power 61 68 189 175 Purchased power from affiliate 421 441 1,101 1,090 Fuel 28 40 285 228 Operating and maintenance 178 125 414 350 Operating and maintenance from affiliates 14 15 39 57 Depreciation and amortization 134 127 370 348 Taxes other than income 12 85 123 207 - ----------------------------------------------------------------------------------------------------------------------- Total operating expenses 848 901 2,521 2,455 - ----------------------------------------------------------------------------------------------------------------------- OPERATING INCOME 301 323 807 784 - ----------------------------------------------------------------------------------------------------------------------- OTHER INCOME AND DEDUCTIONS Interest expense (73) (93) (241) (280) Interest expense to affiliate (2) -- (2) -- Distributions on mandatorily redeemable preferred securities (1) (2) (6) (7) Other, net (10) 5 -- 7 - ----------------------------------------------------------------------------------------------------------------------- Total other income and deductions (86) (90) (249) (280) - ----------------------------------------------------------------------------------------------------------------------- INCOME BEFORE INCOME TAXES 215 233 558 504 INCOME TAXES 74 76 193 166 - ----------------------------------------------------------------------------------------------------------------------- NET INCOME 141 157 365 338 Preferred stock dividends (1) (2) (4) (6) - ----------------------------------------------------------------------------------------------------------------------- NET INCOME ON COMMON STOCK $ 140 $ 155 $ 361 $ 332 ======================================================================================================================= OTHER COMPREHENSIVE INCOME (LOSS) (net of income taxes) Net income $ 141 $ 157 $ 365 $ 338 Other comprehensive income (loss) (net of income taxes): Cash flow hedge adjustment 2 (5) 2 (10) Unrealized gain (loss) on marketable securities 1 (1) 1 -- - ----------------------------------------------------------------------------------------------------------------------- Total other comprehensive income (loss) 3 (6) 3 (10) - ----------------------------------------------------------------------------------------------------------------------- TOTAL COMPREHENSIVE INCOME $ 144 $ 151 $ 368 $ 328 ======================================================================================================================= See Condensed Combined Notes to Consolidated Financial Statements
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PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Nine Months Ended September 30, -------------------------------- (in millions) 2003 2002 - ----------------------------------------------------------------------------------------------------------------------- CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 365 $ 338 Adjustments to reconcile net income to net cash flows provided by operating activities: Depreciation and amortization 370 348 Provision for uncollectible accounts 38 48 Deferred income taxes (76) (64) Employee severance-related costs 25 -- Pension and non-pension postretirement curtailment costs 16 -- Other operating activities (2) (2) Changes in assets and liabilities: Accounts receivable 25 (69) Changes in receivables and payables to affiliates 68 (27) Inventories (44) (8) Accounts payable, accrued expenses and other current liabilities 39 (107) Prepaid taxes (46) (49) Deferred energy costs (33) 50 Other current assets (4) (2) Pension and non-pension postretirement benefits obligations 17 8 Other noncurrent assets and liabilities (1) 9 - ----------------------------------------------------------------------------------------------------------------------- Net cash flows provided by operating activities 757 473 - ----------------------------------------------------------------------------------------------------------------------- CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures (191) (180) Other investing activities (2) 3 - ----------------------------------------------------------------------------------------------------------------------- Net cash flows used in investing activities (193) (177) - ----------------------------------------------------------------------------------------------------------------------- CASH FLOWS FROM FINANCING ACTIVITIES Issuance of long-term debt 450 225 Retirement of long-term debt (709) (571) Issuance of long-term debt to affiliate 103 -- Retirement of mandatorily redeemable preferred securities (50) (19) Retirement of preferred stock (50) -- Change in short-term debt (188) 274 Dividends paid on preferred and common stock (248) (261) Contribution from parent 17 30 Change in restricted cash 132 113 Other financing activities (2) (5) - ----------------------------------------------------------------------------------------------------------------------- Net cash flows used in financing activities (545) (214) - ----------------------------------------------------------------------------------------------------------------------- INCREASE IN CASH AND CASH EQUIVALENTS 19 82 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 63 32 - ----------------------------------------------------------------------------------------------------------------------- CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 82 $ 114 ======================================================================================================================= See Condensed Combined Notes to Consolidated Financial Statements 14 PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, December 31, (in millions) 2003 2002 - ----------------------------------------------------------------------------------------------------------------------- ASSETS CURRENT ASSETS Cash and cash equivalents $ 82 $ 63 Restricted cash 199 331 Accounts receivable, net Customer 326 379 Other 32 39 Inventories, at average cost Fossil fuel 111 67 Materials and supplies 8 8 Deferred energy costs 64 31 Prepaid taxes 47 1 Other 11 8 - ----------------------------------------------------------------------------------------------------------------------- Total current assets 880 927 - ----------------------------------------------------------------------------------------------------------------------- PROPERTY, PLANT AND EQUIPMENT, NET 4,239 4,159 DEFERRED DEBITS AND OTHER ASSETS Regulatory assets 5,304 5,546 Investments 23 19 Prepaid pension asset 62 41 Other 22 28 - ----------------------------------------------------------------------------------------------------------------------- Total deferred debits and other assets 5,411 5,634 - ----------------------------------------------------------------------------------------------------------------------- TOTAL ASSETS $ 10,530 $ 10,720 ======================================================================================================================= See Condensed Combined 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) 2003 2002 - ----------------------------------------------------------------------------------------------------------------------- LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES Notes payable $ 12 $ 200 Payables to affiliates 142 170 Long-term debt due within one year 292 689 Accounts payable 66 87 Accrued expenses 402 332 Deferred income taxes 27 27 Other 36 33 - ----------------------------------------------------------------------------------------------------------------------- Total current liabilities 977 1,538 - ----------------------------------------------------------------------------------------------------------------------- LONG-TERM DEBT 5,087 4,951 LONG-TERM DEBT TO AFFILIATE 103 -- MANDATORILY REDEEMABLE PREFERRED SECURITIES 78 -- DEFERRED CREDITS AND OTHER LIABILITIES Deferred income taxes 2,855 2,903 Unamortized investment tax credits 22 24 Non-pension postretirement benefits obligation 317 251 Payable to affiliate 7 -- Other 140 164 - ----------------------------------------------------------------------------------------------------------------------- Total deferred credits and other liabilities 3,341 3,342 - ----------------------------------------------------------------------------------------------------------------------- Total liabilities 9,586 9,831 - ----------------------------------------------------------------------------------------------------------------------- COMMITMENTS AND CONTINGENCIES MANDATORILY REDEEMABLE PREFERRED SECURITIES -- 128 SHAREHOLDERS' EQUITY Common stock 1,993 1,976 Receivable from parent (1,661) (1,758) Preferred stock 87 137 Retained earnings 517 401 Accumulated other comprehensive income 8 5 - ----------------------------------------------------------------------------------------------------------------------- Total shareholders' equity 944 761 - ----------------------------------------------------------------------------------------------------------------------- TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 10,530 $ 10,720 ======================================================================================================================= See Condensed Combined Notes to Consolidated Financial Statements
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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) 2003 2002 2003 2002 - ----------------------------------------------------------------------------------------------------------------------- OPERATING REVENUES Operating revenues $ 1,180 $ 750 $ 3,055 $ 1,924 Operating revenues from affiliates 1,357 1,463 3,246 3,309 - ----------------------------------------------------------------------------------------------------------------------- Total operating revenues 2,537 2,213 6,301 5,233 - ----------------------------------------------------------------------------------------------------------------------- OPERATING EXPENSES Purchased power 1,096 1,147 2,531 2,334 Purchased power from affiliates 144 110 350 247 Fuel 449 273 1,156 706 Impairment of Exelon Boston Generating, LLC long-lived assets 945 -- 945 -- Operating and maintenance 476 351 1,337 1,098 Operating and maintenance from affiliates 54 40 136 136 Depreciation and amortization 51 68 142 197 Taxes other than income 28 37 115 126 - ----------------------------------------------------------------------------------------------------------------------- Total operating expenses 3,243 2,026 6,712 4,844 - ----------------------------------------------------------------------------------------------------------------------- OPERATING INCOME (LOSS) (706) 187 (411) 389 - ----------------------------------------------------------------------------------------------------------------------- OTHER INCOME AND DEDUCTIONS Interest expense (22) (22) (52) (48) Interest expense - affiliates (3) (1) (11) (3) Equity in earnings of unconsolidated affiliates 53 87 90 119 Other, net (30) 14 (164) 54 - ----------------------------------------------------------------------------------------------------------------------- Total other income and deductions (2) 78 (137) 122 - ----------------------------------------------------------------------------------------------------------------------- INCOME (LOSS) BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES (708) 265 (548) 511 INCOME TAXES (280) 102 (209) 198 - ----------------------------------------------------------------------------------------------------------------------- INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES (428) 163 (339) 313 CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES (net of income taxes of $70 and $9 for the nine months ended September 30, 2003 and 2002, respectively) -- -- 108 13 - ----------------------------------------------------------------------------------------------------------------------- NET INCOME (LOSS) (428) 163 (231) 326 - ----------------------------------------------------------------------------------------------------------------------- OTHER COMPREHENSIVE INCOME (LOSS) (net of income taxes) Cash flow hedge adjustment 147 (11) 30 (79) Unrealized gain (loss) on marketable securities 1 (69) (1) (151) SFAS No. 143 transition adjustment -- -- 168 -- Interest in other comprehensive income (loss) of unconsolidated affiliates 1 (20) 9 (21) - ----------------------------------------------------------------------------------------------------------------------- Total other comprehensive income (loss) 149 (100) 206 (251) - ----------------------------------------------------------------------------------------------------------------------- TOTAL COMPREHENSIVE INCOME (LOSS) $ (279) $ 63 $ (25) $ 75 =======================================================================================================================
See Condensed Combined 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) 2003 2002 - ----------------------------------------------------------------------------------------------------------------------- CASH FLOWS FROM OPERATING ACTIVITIES Net income (loss) $ (231) $ 326 Adjustments to reconcile net income (loss) to net cash flows provided by operating activities: Depreciation, amortization and accretion, including nuclear fuel 594 475 Cumulative effect of changes in accounting principles (net of income taxes) (108) (13) Provision for uncollectible accounts 1 20 Deferred income taxes (393) 246 Equity in earnings of unconsolidated affiliates (90) (119) Impairment of investment 255 -- Impairment of long-lived assets 950 -- Employee severance-related costs 45 -- Pension and non-pension postretirement curtailment costs 6 -- Net realized (gains) losses on nuclear decommissioning trust funds (9) 32 Other operating activities 6 33 Changes in assets and liabilities: Accounts receivable (124) (90) Changes in receivables and payables to affiliates, net 254 (278) Inventories (10) (16) Accounts payable, accrued expenses and other current liabilities 100 153 Other current assets (16) (95) Pension and non-pension postretirement benefits obligations (91) (3) Other noncurrent assets and liabilities 2 100 - ----------------------------------------------------------------------------------------------------------------------- Net cash flows provided by operating activities 1,141 771 - ----------------------------------------------------------------------------------------------------------------------- CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures (733) (715) Proceeds from liquidated damages 92 -- Proceeds from nuclear decommissioning trust funds 1,880 1,184 Investment in nuclear decommissioning trust funds (2,043) (1,330) Notes receivable from affiliates 20 (42) Acquisition of generating plants -- (443) Other investing activities 12 3 - ----------------------------------------------------------------------------------------------------------------------- Net cash flows used in investing activities (772) (1,343) - ----------------------------------------------------------------------------------------------------------------------- CASH FLOWS FROM FINANCING ACTIVITIES Issuance of long-term debt 211 30 Retirement of long-term debt (4) (4) Payment on acquisition note payable to Sithe Energies, Inc. (210) -- Proceeds (repayment) of affiliate money pool funds (178) 348 Distribution to member (116) (30) Contribution from minority interest of consolidated subsidiary -- 43 Change in restricted cash (25) -- Other financing activities (2) -- - ----------------------------------------------------------------------------------------------------------------------- Net cash flows (used in) provided by financing activities (324) 387 - ----------------------------------------------------------------------------------------------------------------------- INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 45 (185) CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 58 224 - ----------------------------------------------------------------------------------------------------------------------- CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 103 $ 39 ======================================================================================================================= SUPPLEMENTAL CASH FLOW INFORMATION Noncash financing activities: Distribution to member $ 17 $ -- See Condensed Combined Notes to Consolidated Financial Statements
18
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, December 31, (in millions) 2003 2002 - ----------------------------------------------------------------------------------------------------------------------- ASSETS CURRENT ASSETS Cash and cash equivalents $ 103 $ 58 Restricted cash 37 -- Accounts receivable, net Customer 644 587 Other 92 57 Receivables from affiliates 313 594 Inventories, at average cost Fossil fuel 72 97 Materials and supplies 229 217 Deferred income taxes 2 7 Other 192 188 - ----------------------------------------------------------------------------------------------------------------------- Total current assets 1,684 1,805 - ----------------------------------------------------------------------------------------------------------------------- PROPERTY, PLANT AND EQUIPMENT, NET 7,010 4,800 DEFERRED DEBITS AND OTHER ASSETS Nuclear decommissioning trust funds 3,404 3,053 Investments 487 657 Receivable from affiliate 41 220 Deferred income taxes 292 271 Prepaid pension asset 98 -- Other 224 201 - ----------------------------------------------------------------------------------------------------------------------- Total deferred debits and other assets 4,546 4,402 - ----------------------------------------------------------------------------------------------------------------------- TOTAL ASSETS $ 13,240 $ 11,007 ======================================================================================================================= See Condensed Combined Notes to Consolidated Financial Statements
19
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, December 31, (in millions) 2003 2002 - ----------------------------------------------------------------------------------------------------------------------- LIABILITIES AND MEMBER'S EQUITY CURRENT LIABILITIES Long-term debt due within one year $ 1,251 $ 5 Accounts payable 1,287 1,126 Payables to affiliates 67 10 Notes payable to affiliates 477 863 Accrued expenses 397 482 Other 90 108 - ----------------------------------------------------------------------------------------------------------------------- Total current liabilities 3,569 2,594 - ----------------------------------------------------------------------------------------------------------------------- LONG-TERM DEBT 1,110 2,132 DEFERRED CREDITS AND OTHER LIABILITIES Unamortized investment tax credits 220 226 Nuclear decommissioning liability for retired plants -- 1,395 Asset retirement obligation 2,479 -- Pension obligation -- 37 Non-pension postretirement benefits obligation 480 410 Spent nuclear fuel obligation 865 858 Payable to affiliate 1,144 -- Other 421 402 - ----------------------------------------------------------------------------------------------------------------------- Total deferred credits and other liabilities 5,609 3,328 - ----------------------------------------------------------------------------------------------------------------------- Total liabilities 10,288 8,054 - ----------------------------------------------------------------------------------------------------------------------- COMMITMENTS AND CONTINGENCIES MINORITY INTEREST OF CONSOLIDATED SUBSIDIARY -- 54 MEMBER'S EQUITY Membership interest 2,490 2,296 Undistributed earnings 577 924 Accumulated other comprehensive income (loss) (115) (321) - ----------------------------------------------------------------------------------------------------------------------- Total member's equity 2,952 2,899 - ----------------------------------------------------------------------------------------------------------------------- TOTAL LIABILITIES AND MEMBER'S EQUITY $13,240 $ 11,007 ======================================================================================================================= See Condensed Combined Notes to Consolidated Financial Statements
20 EXELON CORPORATION AND SUBSIDIARY COMPANIES COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES CONDENSED COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in millions, except per share data, unless otherwise noted) 1. BASIS OF PRESENTATION (Exelon, ComEd, PECO and Generation) The consolidated financial statements of Exelon Corporation (Exelon), Commonwealth Edison Company (ComEd), PECO Energy Company (PECO) and Exelon Generation Company, LLC (Generation) include the accounts of their 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. PECO Energy Capital Trust IV (PECO Trust IV), which was created in May 2003, is a wholly owned financing subsidiary of PECO. As of July 1, 2003, PECO Trust IV is no longer consolidated within the financial statements of Exelon or PECO. See Note 2 - New Accounting Principles and Accounting Changes for further discussion of the deconsolidation of this entity. The accompanying consolidated financial statements as of September 30, 2003 and for the three and nine months then ended are unaudited, but, in the opinions of the managements of Exelon, ComEd, PECO and Generation, include all adjustments that are considered necessary for a fair presentation of their respective financial statements. All adjustments are of a normal, recurring nature, except as otherwise disclosed. The December 31, 2002 Consolidated Balance Sheets were derived from audited financial statements but do not include all disclosures required by accounting principles generally accepted in the United States of America (GAAP). Certain prior-year amounts have been reclassified for comparative purposes. These reclassifications had no effect on net income or shareholders' or member's equity. These notes should be read in conjunction with the Notes to Consolidated Financial Statements of Exelon, ComEd, PECO and Generation included in or incorporated by reference in ITEM 8 of their Annual Reports on Form 10-K for the year ended December 31, 2002. 2. NEW ACCOUNTING PRINCIPLES AND ACCOUNTING CHANGES (Exelon, ComEd, PECO and Generation) Accounting Principles with a Cumulative Effect upon Adoption SFAS No. 143 Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 143, "Accounting for Asset Retirement Obligations" (SFAS No. 143) provides accounting requirements for retirement obligations (whether statutory, contractual or as a result of principles of promissory estoppel) associated with tangible long-lived assets. Exelon, ComEd, PECO and Generation were required to adopt SFAS No. 143 as of January 1, 2003. A significant retirement obligation is Generation's obligation to decommission its nuclear plants at the end of their license 21 lives projected to be from 2029 through 2056. These nuclear plants, the decommissioning obligation and the related nuclear decommissioning trust fund investments were transferred to Generation by ComEd and PECO in connection with the Exelon corporate restructuring on January 1, 2001. Generation had decommissioning assets in trust accounts of $3,404 million and $3,053 million as of September 30, 2003 and December 31, 2002, respectively. Generation anticipates that all trust fund assets will ultimately be used to decommission Generation's nuclear plants. After considering interpretations of the transitional guidance included in SFAS No. 143, Exelon recorded income of $112 million (net of income taxes) as a cumulative effect of a change in accounting principle in connection with its adoption of this standard in the first quarter of 2003. The components of the cumulative effect of a change in accounting principle, net of income taxes, were as follows: --------------------------------------------------------------------------- Generation (net of income taxes of $52) $ 80 Generation's investments in AmerGen Energy Company, LLC and Sithe Energies, Inc. (net of income taxes of $18) 28 ComEd (net of income taxes of $0) 5 Exelon Enterprises Company, LLC (net of income taxes of $(1)) (1) --------------------------------------------------------------------------- Total $ 112 =========================================================================== The cumulative effect of the change in accounting principle in adopting SFAS No. 143 had no impact on PECO's income statement. The asset retirement obligation (ARO) as of January 1, 2003 was determined under SFAS No. 143 to be $2,366 million and $2,363 million for Exelon and Generation, respectively. As further explained below, the adoption also resulted in recording regulatory assets and liabilities. Exelon's accretion expense of the ARO for the three and nine months ended September 30, 2003 was $39 million and $117 million, respectively. Generation's accretion expense for the three and nine months ended September 30, 2003 was $39 million and $116 million, respectively. The following table provides a reconciliation of the AROs reflected on the balance sheet at December 31, 2002 and September 30, 2003:
Generation Exelon ---------------------------------------------------------------------------------------------------- Accumulated depreciation $ 2,845 $ 2,845 Nuclear decommissioning liability for retired units 1,395 1,395 ---------------------------------------------------------------------------------------------------- Decommissioning obligation at December 31, 2002 4,240 4,240 Net reduction due to adoption of SFAS No. 143 1,877 1,874 ---------------------------------------------------------------------------------------------------- Asset retirement obligation at January 1, 2003 2,363 2,366 Reclassification of Enterprises ARO to liabilities held for sale during the third quarter of 2003 -- (2) Accretion expense for nine months ended September 30, 2003 116 117 ---------------------------------------------------------------------------------------------------- Asset retirement obligation at September 30, 2003 $ 2,479 $ 2,481 ====================================================================================================
22 Determination of Asset Retirement Obligation In accordance with SFAS No. 143, a probability-weighted, discounted cash flow model with multiple scenarios was used to determine the "fair value" of the decommissioning obligation. SFAS No. 143 also stipulates that fair value represents the amount a third party would receive for assuming an entity's entire obligation. The present value of future estimated cash flows was calculated using credit-adjusted, risk-free rates applicable to the various businesses in order to determine the fair value of the decommissioning obligation at the time of adoption of SFAS No. 143. Significant changes in the assumptions underlying the items discussed above could materially affect the balance sheet amounts and future costs related to decommissioning recorded in the consolidated financial statements. The following tables set forth Exelon's net income and earnings per common share for the three and nine months ended September 30, 2002 adjusted as if SFAS No. 143 had been applied effective January 1, 2002.
Three Months Ended Nine Months Ended September 30, 2002 September 30, 2002 ----------------------------------------------------------------------------------------------------------------------- Reported income before cumulative effect of changes in accounting principles $ 551 $ 1,273 Adjustment as if SFAS No. 143 had been applied effective January 1, 2002 8 28 ----------------------------------------------------------------------------------------------------------------------- Adjusted income before cumulative effect of changes in accounting principles $ 559 $ 1,301 ======================================================================================================================= Three Months Ended Nine Months Ended September 30, 2002 September 30, 2002 ----------------------------------------------------------------------------------------------------------------------- Reported net income $ 551 $ 1,043 Adjustment as if SFAS No. 143 had been applied effective January 1, 2002: Adjustment to income before cumulative effect of changes in accounting principles 8 28 Cumulative effect of changes in accounting principles -- 132 ----------------------------------------------------------------------------------------------------------------------- Adjusted net income $ 559 $ 1,203 =======================================================================================================================
23
Three Months Ended September 30, 2002 ------------------------------------- Basic earnings per common share: Reported Adjustment (1) Adjusted ------------------------------------------------------------------------------------------------------------------ Income before cumulative effect of changes in accounting principles $ 1.71 $ 0.02 $ 1.73 Net income $ 1.71 $ 0.02 $ 1.73 ------------------------------------------------------------------------------------------------------------------ Three Months Ended September 30, 2002 ------------------------------------- Diluted earnings per common share: Reported Adjustment (1) Adjusted ------------------------------------------------------------------------------------------------------------------ Income before cumulative effect of changes in accounting principles $ 1.70 $ 0.02 $ 1.72 Net income $ 1.70 $ 0.02 $ 1.72 ------------------------------------------------------------------------------------------------------------------ (1) The adjustment represents the earnings impact as if SFAS No. 143 had been applied effective January 1, 2002. Nine Months Ended September 30, 2002 ------------------------------------- Basic earnings per common share: Reported Adjustment (1) Adjusted ------------------------------------------------------------------------------------------------------------------ Income before cumulative effect of changes in accounting principles $ 3.95 $ 0.09 $ 4.04 Net income $ 3.24 $ 0.50 $ 3.74 ------------------------------------------------------------------------------------------------------------------ Nine Months Ended September 30, 2002 ------------------------------------- Diluted earnings per common share: Reported Adjustment (1) Adjusted ------------------------------------------------------------------------------------------------------------------ Income before cumulative effect of changes in accounting principles $ 3.93 $ 0.09 $ 4.02 Net income $ 3.22 $ 0.49 $ 3.71 ------------------------------------------------------------------------------------------------------------------ (1) The adjustment represents the earnings impact as if SFAS No. 143 had been applied effective January 1, 2002.
Effect of adopting SFAS No. 143 Exelon was required to re-measure the decommissioning liabilities at fair value using the methodology prescribed by SFAS No. 143. The transition provisions of SFAS No. 143 required Exelon to apply this re-measurement back to the historical periods in which asset retirement obligations were incurred, resulting in a re-measurement of these obligations at the date the related assets were acquired. Since the nuclear plants previously owned by ComEd were acquired by Exelon on October 20, 2000 (Merger Date) as a result of the merger of Exelon, Unicom Corporation and PECO (Merger), Exelon's historical accounting for its ARO has been revised as if SFAS No. 143 had been in effect at the Merger Date. In the case of the former ComEd plants, the calculation of the SFAS No. 143 ARO yielded decommissioning obligations lower than the value of the corresponding trust assets. ComEd has previously collected amounts from customers (which were subsequently transferred to Generation) in advance of Generation's recognition of decommissioning expense under SFAS No. 143. While it is expected that the trust assets will ultimately be used entirely for the decommissioning of the plants, the current measurement required by SFAS No. 143 shows an excess of assets over related ARO liabilities. As such, in accordance with regulatory accounting practices and a December 2000 Illinois Commerce Commission (ICC) Order, a regulatory liability of $948 million and a corresponding receivable from Generation were recorded at ComEd upon the adoption of SFAS No. 143. At September 30, 2003, the regulatory liability and corresponding receivable from Generation 24 totaled $1,144 million. Exelon believes that all of the decommissioning assets, including up to $73 million of annual collections from ComEd ratepayers through 2006, will be used to decommission the former ComEd plants. Accordingly, Exelon expects the regulatory liability and corresponding receivable from Generation will be reduced to zero at or before the conclusion of the decommissioning of the former ComEd plants. In the case of the former PECO plants, the SFAS No. 143 ARO calculation yielded decommissioning obligations greater than the corresponding trust assets. As such, a regulatory asset of $20 million and a corresponding payable to Generation were recorded upon adoption at PECO. At September 30, 2003, the regulatory asset and corresponding payable to Generation totaled $7 million. Exelon believes that all of the decommissioning assets, including $29 million of annual collections from PECO ratepayers which will increase to approximately $33 million beginning in 2004, will be used to decommission the former PECO plants. Exelon also expects the regulatory asset and corresponding payable to Generation will be reduced to zero at the conclusion of the decommissioning of the former PECO plants. See Note 5 - Regulatory Issues for more information regarding the annual collections from PECO. Prior to the adoption of SFAS No. 143, Generation's accumulated depreciation included $2,845 million for decommissioning liabilities related to active nuclear plants. This amount was reclassified to an ARO upon the adoption of SFAS No. 143. Additionally, Generation adjusted the total decommissioning liability for the ComEd plants to $1,575 million and for the PECO plants to $787 million. As described above, Generation recorded a payable to ComEd of $948 million and a receivable from PECO of $20 million. Generation also recorded an asset retirement cost asset (ARC) of $172 million related to the establishment of the ARO related to former PECO plants in accordance with SFAS No. 143. The ARC is being amortized over the remaining lives of the plants. As discussed above, Exelon re-measured its 2001 decommissioning-related balances associated with the Merger purchase price allocation at ComEd and the January 2001 corporate restructuring as if SFAS No. 143 had been in effect at the Merger Date. Exelon concluded that had SFAS No. 143 been in effect, ComEd would not have recorded an impairment of its regulatory asset for decommissioning of its retired nuclear plants as a purchase price allocation adjustment in 2001 as a result of the December 2000 ICC order. Increased net assets would have been transferred to Generation by ComEd in the corporate restructuring. Accordingly, Exelon recorded a reduction of goodwill of approximately $210 million, with a corresponding reduction in its overall decommissioning obligation in connection with the implementation of SFAS No. 143 on January 1, 2003. Similarly, ComEd recorded a reduction of $210 million of goodwill and of shareholders' equity, and Generation recorded a $210 million increase in member's equity and a corresponding reduction of its decommissioning obligation. In addition, ComEd recorded a cumulative effect of a change in accounting principle of $5 million to reverse goodwill amortization that had been recorded in 2001. Exelon and ComEd also reclassified a regulatory asset related to nuclear decommissioning costs for retired units of $248 million to regulatory liabilities. In accordance with the provisions of SFAS No. 143 and regulatory accounting guidance, Exelon recorded a SFAS No. 143 transition adjustment to accumulated other comprehensive income to reclassify $168 million of 25 accumulated net unrealized losses on the nuclear decommissioning trust funds to regulatory assets and liabilities. The following tables set forth ComEd and Generation's net income and Generation's income before cumulative effect of changes in accounting principles for the three and nine months ended September 30, 2002 adjusted as if SFAS No. 143 had been applied effective January 1, 2002. ComEd's income before cumulative effect of a change in accounting principle was not affected by the adoption of SFAS No. 143.
Three Months Ended Nine Months Ended ComEd September 30, 2002 September 30, 2002 ------------------------------------------------------------------------------------------------------------------ Reported net income $ 215 $ 576 Adjustment as if SFAS No. 143 had been applied effective January 1, 2002: Cumulative effect of changes in accounting principles -- 5 ------------------------------------------------------------------------------------------------------------------ Adjusted net income $ 215 $ 581 ================================================================================================================== Three Months Ended Nine Months Ended Generation September 30, 2002 September 30, 2002 ------------------------------------------------------------------------------------------------------------------ Reported income before cumulative effect of changes in accounting principles $ 163 $ 313 Adjustment as if SFAS No. 143 had been applied effective January 1, 2002 8 28 ------------------------------------------------------------------------------------------------------------------ Adjusted income before cumulative effect of changes in accounting principles $ 171 $ 341 ================================================================================================================== Three Months Ended Nine Months Ended Generation September 30, 2002 September 30, 2002 ------------------------------------------------------------------------------------------------------------------ Reported net income $ 163 $ 326 Adjustment as if SFAS No. 143 had been applied effective January 1, 2002: Adjustment to income before cumulative effect of changes in accounting principles 8 28 Cumulative effect of changes in accounting principles -- 128 ------------------------------------------------------------------------------------------------------------------ Adjusted net income $ 171 $ 482 ==================================================================================================================
Accounting methodology under SFAS No. 143 For the former ComEd plants, realized gains and losses on decommissioning trust funds are reflected in other income and deductions in Generation's Consolidated Statements of Income and Comprehensive Income, while the unrealized gains and losses on marketable securities held in the trust funds adjust the payable Generation currently has to ComEd. The increases in the ARO are recorded in operating and maintenance expense as accretion expense, while the funds received from ComEd for decommissioning are recorded in revenue. Generation's payable to ComEd is adjusted each reporting period to reflect the difference between the decommissioning assets and the ARO levels. As such, if the ARO increases at a rate faster than the increase in the trust fund assets, ComEd's regulatory liability and receivable from Generation will decrease. If and when the trust assets are exceeded by the decommissioning liability, Generation is responsible for any shortfall in funding. The result of the above accounting will have 26 no earnings impact to Generation for as long as the trust assets exceed the decommissioning liabilities for the former ComEd plants. The above accounting practices are also applicable for the former PECO plants owned by Generation. Additionally, depreciation expense will be recognized on the ARC established upon adoption of SFAS No. 143. However, as PECO has the expectation of full recovery from ratepayers of decommissioning costs of its former plants, the result of the above accounting will ultimately reflect no earnings impact to Generation. Therefore, to the extent that the net of decommissioning revenues collected and realized investment income differ from the accretion expense to the decommissioning liability and the related depreciation of the ARC, an adjustment to net the amounts to zero would be recorded by Generation for that period with the offset to PECO's regulatory asset balance. The ongoing effects to Generation for the accounting for the decommissioning of the AmerGen Energy Company, LLC (AmerGen) plants are recorded within Generation's equity in earnings of AmerGen. AmerGen is a 50% owned subsidiary of Generation. SFAS No. 141 and SFAS No. 142 In 2001, the FASB issued SFAS No. 141, "Business Combinations" (SFAS No. 141), which requires that all business combinations be accounted for under the purchase method of accounting and establishes criteria for the separate recognition of intangible assets acquired in business combinations. In addition, SFAS No. 141 required that unamortized negative goodwill related to pre-July 1, 2001 purchases be recognized as a change in accounting principle concurrent with the adoption of SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS No. 142). 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 established new accounting and reporting standards for goodwill and intangible assets. Exelon recorded a charge of $357 million ($243 million, net of income taxes and minority interest) upon the adoption of SFAS No. 142 with respect to goodwill recorded in certain Reporting Units of Exelon Enterprises Company, LLC (Enterprises). This charge was recorded as a cumulative effect of a change in accounting principle in the first quarter of 2002. The components of the net transitional impairment loss recognized in the first quarter of 2002 as a cumulative effect of a change in accounting principle were as follows: --------------------------------------------------------------------------- Enterprises goodwill impairment (net of income taxes of $(103)) $(254) Minority interest (net of income taxes of $4) 11 Elimination of AmerGen negative goodwill (net of income taxes of $9) 13 --------------------------------------------------------------------------- Total cumulative effect of a change in accounting principle $(230) =========================================================================== At September 30, 2003, Exelon had goodwill of $4,734 million of which $4,711 million relates to ComEd and the remaining goodwill relates to Enterprises' Reporting Units. Consistent with SFAS No. 142, the remaining 27 goodwill is reviewed for impairment on an annual basis, or more frequently if significant events occur that could indicate an impairment exists. ComEd and Enterprises perform their annual reviews in the fourth quarter of their fiscal years. See Note 3 - Acquisitions, Dispositions and Retirements for a discussion of an impairment of Enterprises' goodwill related to the InfraSource Reporting Unit recorded in the second quarter of 2003. Other Accounting Principles and Accounting Changes SFAS No. 146 In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities" (SFAS No. 146). SFAS No. 146 requires that the liability for costs associated with exit or disposal activities be recognized when incurred, rather than at the date of a commitment to an exit or disposal plan. SFAS No. 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002. Exelon, ComEd, PECO and Generation's results of operations were not affected by the adoption SFAS No. 146. FIN No. 45 In November 2002, the FASB released FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN No. 45), providing for expanded disclosures and recognition of a liability for the fair value of the obligation undertaken by the guarantor. Under FIN No. 45, guarantors are required to disclose the nature of the guarantee, the maximum amount of potential future payments, the carrying amount of the liability and the nature and amount of recourse provisions or available collateral that would be recoverable by the guarantor. Exelon, ComEd, PECO and Generation adopted the disclosure requirements under FIN No. 45, which were effective for financial statements for periods ended after December 15, 2002. The recognition and measurement provisions of FIN No. 45 were effective for guarantees issued or modified after December 31, 2002. The adoption of FIN No. 45 had no material effect on Exelon, ComEd, PECO or Generation's results of operations. Liabilities associated with guarantees entered into during the nine months ended September 30, 2003 are reflected in Note 9 - Commitments and Contingencies. 28 SFAS No. 148 In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure - an amendment of FASB Statement No. 123" (SFAS No. 148). SFAS No. 148 provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation and requires disclosures in both annual and interim financial statements regarding the method of accounting for stock-based compensation and the effect of the method on financial results. SFAS No. 148 was effective for financial statements for fiscal years ended after December 15, 2002. Exelon adopted the additional disclosure requirements of SFAS No. 148 and continues to account for its stock-compensation plans under the disclosure only provision of SFAS No. 123, "Accounting for Stock-Based Compensation" (SFAS No. 123). The tables below show the effect on net income and earnings per share for Exelon and the effect on net income for ComEd, PECO and Generation had Exelon elected to account for stock-based compensation plans using the fair value method under SFAS No. 123 for the three and nine months ended September 30, 2003 and 2002:
Exelon Three Months Ended September 30, -------------------------------- 2003 2002 ------------------------------------------------------------------------------------------------------------------ Net income (loss) - as reported $ (102) $ 551 Deduct: Total stock-based compensation expense determined under fair value based method for all awards, net of income taxes (5) (8) ------------------------------------------------------------------------------------------------------------------ Pro forma net income (loss) $ (107) $ 543 ================================================================================================================== Earnings (loss) per share: Basic - as reported $ (0.31) $ 1.71 Basic - pro forma $ (0.33) $ 1.68 Diluted - as reported $ (0.31) $ 1.70 Diluted - pro forma $ (0.33) $ 1.67 ------------------------------------------------------------------------------------------------------------------ Nine Months Ended September 30, ------------------------------- 2003 2002 ------------------------------------------------------------------------------------------------------------------ Net income - as reported $ 631 $ 1,043 Deduct: Total stock-based compensation expense determined under fair value based method for all awards, net of income taxes (16) (25) ------------------------------------------------------------------------------------------------------------------ Pro forma net income $ 615 $ 1,018 ================================================================================================================== Earnings per share: Basic - as reported $ 1.94 $ 3.24 Basic - pro forma $ 1.89 $ 3.16 Diluted - as reported $ 1.93 $ 3.22 Diluted - pro forma $ 1.88 $ 3.14 ------------------------------------------------------------------------------------------------------------------ 29 ComEd Three Months Ended September 30, -------------------------------- 2003 2002 ------------------------------------------------------------------------------------------------------------------- Net income - as reported $ 163 $ 215 Deduct: Total stock-based compensation expense determined under fair value based method for all awards, net of income taxes (1) (3) ------------------------------------------------------------------------------------------------------------------- Pro forma net income $ 162 $ 212 =================================================================================================================== Nine Months Ended September 30, ------------------------------- 2003 2002 ------------------------------------------------------------------------------------------------------------------- Net income - as reported $ 564 $ 576 Deduct: Total stock-based compensation expense determined under fair value based method for all awards, net of income taxes (4) (10) ------------------------------------------------------------------------------------------------------------------- Pro forma net income $ 560 $ 566 =================================================================================================================== PECO Three Months Ended September 30, -------------------------------- 2003 2002 ------------------------------------------------------------------------------------------------------------------- Net income on common stock- as reported $ 140 $ 155 Deduct: Total stock-based compensation expense determined under fair value based method for all awards, net of income taxes (1) (3) ------------------------------------------------------------------------------------------------------------------- Pro forma net income on common stock $ 139 $ 152 =================================================================================================================== Nine Months Ended September 30, ------------------------------- 2003 2002 ------------------------------------------------------------------------------------------------------------------- Net income on common stock- as reported $ 361 $ 332 Deduct: Total stock-based compensation expense determined under fair value based method for all awards, net of income taxes (2) (10) ------------------------------------------------------------------------------------------------------------------- Pro forma net income on common stock $ 359 $ 322 =================================================================================================================== Generation Three Months Ended September 30, -------------------------------- 2003 2002 ------------------------------------------------------------------------------------------------------------------- Net income (loss) - as reported $ (428) $ 163 Deduct: Total stock-based compensation expense determined under fair value based method for all awards, net of income taxes (3) (4) ------------------------------------------------------------------------------------------------------------------- Pro forma net income (loss) $ (431) $ 159 =================================================================================================================== Nine Months Ended September 30, ------------------------------- 2003 2002 ------------------------------------------------------------------------------------------------------------------- Net income (loss) - as reported $ (231) $ 326 Deduct: Total stock-based compensation expense determined under fair value based method for all awards, net of income taxes (8) (11) ------------------------------------------------------------------------------------------------------------------- Pro forma net income (loss) $ (239) $ 315 ===================================================================================================================
30 FIN No. 46 In January 2003, the FASB issued FIN No. 46, "Consolidation of Variable Interest Entities" (FIN No. 46), which addresses the requirements for consolidating certain variable interest entities and applies immediately to variable interest entities created after January 31, 2003. FIN No. 46, as amended by FASB Staff Position (FSP) No. FIN 46-6, "Effective Date of FASB Interpretation No. 46, Consolidation of Variable Interest Entities," requires Exelon to consolidate variable interest entities, created prior to February 1, 2003, as of December 31, 2003. As of July 1, 2003, PECO Trust IV, a wholly owned financing subsidiary of PECO created in May 2003, was no longer consolidated within the financial statements of Exelon or PECO pursuant to the provisions of FIN No. 46. PECO recognized equity in earnings of less than $1 million for the three and nine months ended September 30, 2003 related to this unconsolidated subsidiary. Amounts of $103 million owed to PECO Trust IV by PECO are recorded as long-term debt to affiliate within the Consolidated Balance Sheets, and interest owed to this entity is recorded as interest expense to affiliate within the Consolidated Statements of Income and Comprehensive Income. This change in presentation had no significant impact on net income or the balance sheet of Exelon or PECO. Prior periods have not been restated. Based on management's interpretation of the current provisions of FIN No. 46, it is reasonably possible that the remaining wholly owned financing trusts and limited partnerships of ComEd and PECO will be required to be deconsolidated as of December 31, 2003. This change in presentation is anticipated to have no significant impact on net income or the balance sheet of Exelon, ComEd or PECO. Based on management's interpretation of the current provisions of FIN No. 46, it is reasonably possible that Generation will consolidate Sithe Energies, Inc. (Sithe) and AmerGen as of December 31, 2003. Generation is a 49.9% owner of Sithe and has accounted for this entity as an unconsolidated equity investment. Sithe owns and operates power generating facilities. AmerGen is a joint venture between Generation and British Energy, Inc. (British Energy) and owns and operates three nuclear units, the Clinton Power Station (Clinton), Three Mile Island Unit 1 (TMI) and Oyster Creek Generating Station (Oyster Creek). Refer to Note 17 - Unconsolidated Equity Investments in Generation's Form 10-K for the year ended December 31, 2002 and Note 4 - Unconsolidated Investments and Note 15 - Subsequent Events in this Form 10-Q for further information related to Generation's investments in Sithe and AmerGen and Exelon's agreement to purchase British Energy's interest in AmerGen. Also, see Note 13 - Related Party Transactions for a description of the activity between Exelon and Sithe and Exelon and AmerGen. SFAS No. 149 In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" (SFAS No. 149). SFAS No. 149 amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contacts, and for hedging activities under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133). SFAS No. 149 also amends SFAS No. 133 for decisions made (1) as part 31 of the Derivatives Implementation Group process that effectively required amendments to SFAS No. 133, (2) in connection with other FASB projects dealing with financial instruments, and (3) in connection with implementation issues raised in relation to the application of the definition of a derivative. SFAS No. 149 was effective for contracts entered into or modified after June 30, 2003, except as stated below, and for hedging relationships designated after June 30, 2003. In addition, except as stated below, all provisions of SFAS No. 149 were to be applied prospectively. The provisions of SFAS No. 149 that relate to SFAS No. 133 implementation issues that have been effective for fiscal quarters that began prior to June 15, 2003 should continue to be applied in accordance with their respective effective dates. In addition, certain provisions relating to forward purchases or sales of when-issued securities or other securities that do not yet exist should be applied to both existing contracts and new contracts entered into after June 30, 2003. The adoption of SFAS No. 149 had no impact on the Consolidated Balance Sheets or Statements of Income and Comprehensive Income of Exelon, ComEd, PECO and Generation. SFAS No. 150 In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" (SFAS No. 150). SFAS No. 150 requires that certain instruments that have characteristics of both liabilities and equity be classified as liabilities in the statement of financial position. SFAS No. 150 affects the accounting for three types of freestanding financial instruments: mandatorily redeemable shares, instruments that do or may require the issuer to buy back some of its shares in exchange for cash or other assets, and obligations that can be settled with shares, the monetary value of which is fixed, tied solely or predominantly to a variable such as a market index, or varies inversely with the value of the issuer's shares. Substantially all the guidance in SFAS No. 150 was effective for financial instruments entered into or modified after May 31, 2003, and otherwise was effective for Exelon as of July 1, 2003. As of July 1, 2003, ComEd and PECO reclassified mandatorily redeemable preferred securities of subsidiaries from equity to liabilities of $344 million and $78 million, respectively. There was no impact from the adoption of this standard on the Consolidated Statements of Income and Comprehensive Income of ComEd and PECO. During June 2003, PECO issued $103 million of subordinated debentures to PECO Trust IV in connection with the issuance by PECO Trust IV of $100 million of preferred securities (see Note 12 - Long-Term Debt and Preferred Securities). These preferred securities were recorded as liabilities of PECO as of June 30, 2003 in accordance with SFAS No. 150. Effective July 1, 2003, PECO Trust IV was deconsolidated from the financial statements of PECO in conjunction with the adoption of FIN No. 46. The $103 million of subordinated debentures issued by PECO to PECO Trust IV was recorded as long-term debt to affiliate within the Consolidated Balance Sheets. As previously reported in Generation's Capital Commitments footnotes to the financial statements in the 2002 Form 10-K, Generation has a 73% interest in the Southeast Chicago Project, LLC (Southeast Chicago), which owns a peaking facility in Chicago. Southeast Chicago is obligated to redeem approximately $52 million over the next 19 years to a party, not affiliated with Generation, that owns the remaining 27% interest. Under SFAS No. 150, this mandatory redemption requires Generation to classify its minority interest in Southeast Chicago as a liability at fair value. As such, at July 1, 2003, Generation reclassified $52 million of minority interest to other noncurrent liabilities on the Consolidated Balance Sheet. 32 Change in Depreciation Estimate ComEd Effective July 1, 2002, ComEd lowered its depreciation rates based on a depreciation study reflecting its significant construction program in recent years, changes in and development of new technologies, and changes in estimated plant service lives since the last depreciation study. The annualized reduction in depreciation expense, based on December 31, 2001 plant balances, was estimated to be approximately $100 million ($60 million, net of income taxes). As a result of the change, operating income for the nine months ended September 30, 2003 increased approximately $48 million ($29 million after income taxes) compared to the same period in 2002. 3. ACQUISITIONS, DISPOSITIONS AND RETIREMENTS (Exelon and Generation) InfraSource Sale On September 24, 2003, Enterprises sold the electric construction and services, underground and telecom businesses of InfraSource, Inc. (InfraSource). Cash proceeds to Enterprises from the sale were approximately $175 million, net of transaction costs and cash transferred to the buyer upon sale, plus a $30 million subordinated note receivable maturing in 2011. At September 30, 2003, the present value of the note receivable was approximately $12 million. In connection with this transaction, Enterprises entered into an agreement that may result in certain payments to InfraSource if the amount of services Exelon purchases from InfraSource during the period from closing through 2006 is below specified thresholds. Pursuant to the sales agreement, certain working capital adjustments to the purchase price may be made in 2004. In connection with the agreement to sell certain businesses of InfraSource, Enterprises recorded an impairment charge during the second quarter of 2003 of approximately $48 million (before income taxes and minority interest) pursuant to SFAS No. 142 related to the goodwill recorded within the InfraSource Reporting Unit. Management of Enterprises primarily considered the negotiated sales price and the estimated book value of InfraSource at the time of the closing of the sale in determining the amount of the goodwill impairment charge. In connection with the closing of the sale in the third quarter of 2003, Enterprises recorded a gain of $44 million (before income taxes), primarily due to the book value of InfraSource at the date of closing being lower than estimated in the second quarter of 2003. The net impact of the goodwill impairment in the second quarter and the gain recorded in the third quarter was a loss before income taxes and minority interest of $4 million for the nine months ended September 30, 2003. The net impact was recorded as an operating and maintenance expense within the Consolidated Statements of Income and Comprehensive Income for the nine months ended September 30, 2003. 33 Exelon Thermal Holdings, Inc. Enterprises classified the assets and liabilities of certain entities of Exelon Thermal Holdings, Inc. as held for sale within the Consolidated Balance Sheet pursuant to SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144) as of September 30, 2003. These businesses are reported under the Enterprises segment pursuant to SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information." The major classes of assets and liabilities classified as held for sale as of September 30, 2003 consist of the following (in millions): ------------------------------------------------------------------------- Cash $ 12 Property, plant and equipment, net 86 Other long-term assets 2 Long-term notes receivable 9 ------------------------------------------------------------------------- Total assets classified as held for sale $ 109 ========================================================================= ------------------------------------------------------------------------- Accounts payable, accrued expenses and other current liabilities $ 11 Debt 39 Asset retirement obligation 2 Other long-term liabilities 5 ------------------------------------------------------------------------- Total liabilities classified as held for sale $ 57 ========================================================================= Sale of Investment in AT&T Wireless On April 1, 2002, Enterprises sold its 49% interest in AT&T Wireless PCS of Philadelphia, LLC to a subsidiary of AT&T Wireless Services for $285 million in cash. Enterprises recorded a gain of $116 million (net of income taxes) on the $84 million investment as an other income and deduction in Exelon's Consolidated Statements of Income and Comprehensive Income. Generation Sithe New England Holdings Acquisition On November 1, 2002, Generation purchased the assets of Sithe New England Holdings, LLC (now known as Exelon New England), a subsidiary of Sithe, and related power marketing operations. The purchase price for the Exelon New England assets consisted of a $536 million note to Sithe, $14 million of direct acquisition costs and a $208 million adjustment to Generation's previously existing investment in Sithe related to Exelon New England. 34 The allocation of the purchase price to the fair value of assets acquired and liabilities assumed in the acquisition was as follows: ------------------------------------------------------------------------- Current assets (including $12 million of cash acquired) $ 85 Property, plant and equipment 1,949 Deferred debits and other assets 63 Current liabilities (154) Deferred credits and other liabilities (149) Long-term debt (1,036) ------------------------------------------------------------------------- Total purchase price $ 758 ========================================================================= In connection with the acquisition, Generation assumed certain Sithe guarantees, including a guarantee of an equity contribution to be made to Sithe Boston Generating, LLC (currently known as Exelon Boston Generating, LLC (EBG)), a project subsidiary of Exelon New England. Pursuant to Generation's assumed equity guarantee, upon the occurrence of certain events, Generation would be obligated to (1) contribute up to $38 million of equity for the purpose of completing the construction of two generating facilities and/or to fund certain reserve funds and (2) pay certain taxes. EBG has a $1.25 billion credit facility (EBG Facility), which was entered into primarily to finance the construction of Mystic 8 and 9 and Fore River. The approximately $1.1 billion of debt outstanding under the credit facility at September 30, 2003 is reflected in Generation's Consolidated Balance Sheets as a current liability due to certain events of default described below. The EBG Facility is non-recourse to Generation and an event of default under the EBG Facility does not constitute an event of default under any other debt instruments of Exelon or its subsidiaries. The EBG Facility required that all of the projects achieve "Project Completion," as defined in the EBG Facility (Project Completion), by June 12, 2003. On June 11, 2003, EBG negotiated an extension of the Project Completion date to July 11, 2003. Project Completion was not achieved by July 12, 2003, resulting in an event of default under the EBG Facility. On July 3, 2003, the lenders under the EBG Facility and EBG executed a letter agreement as a result of which the lenders were precluded during the period July 11, 2003 through August 29, 2003 from exercising any remedies resulting from the failure of all of the projects to achieve Project Completion. At that time, EBG stated that it would continue to monitor the projects, assess all of its options relating to the projects, and continue discussions with the lenders. Mystic 8 and 9 and Fore River have all begun commercial operation, although they have not yet achieved Project Completion. As a result of Generation's continuing evaluation of the projects and discussions with the lenders, Generation has commenced the process of an orderly transition out of the ownership of EBG and the projects. The transition will take place in a manner that complies with applicable regulatory requirements. For a period of time, Generation expects to continue to provide administrative and operational services to EBG in its operation of the projects. Generation informed the lenders of its decision to exit and that it will not provide additional funding to the projects 35 beyond its existing contractual obligations. Generation cannot predict the timing of the transition. In connection with the decision in late July 2003 to transition out of the ownership of EBG and the projects, Generation recorded an impairment charge of its long-lived assets pursuant to SFAS No. 144 of $945 million ($573 million net of income taxes) in operating expenses within the Consolidated Statements of Income and Comprehensive Income during the third quarter of 2003. In determining the amount of the impairment charge, management compared the carrying value of EBG's long-lived assets to the fair value of those assets. The fair value of EBG's long-lived assets was determined using the estimated future discounted cash flows from those assets. Generation used a probability-weighted approach for developing estimates of future cash flows with the most likely scenarios weighted higher. Forecasted cash flows incorporated assumptions relative to the period of time that Generation will continue to own and operate EBG. The time required to fully transition out of ownership of EBG is uncertain and subject to change. Through the extinguishment of the outstanding debt and upon the finalization of Generation's transition out of ownership of EBG and the projects, Generation's net charge (including the $573 million charge discussed above) is estimated to be $550 million after income taxes. 4. UNCONSOLIDATED INVESTMENTS (Exelon, PECO and Generation) Sithe Generation is a 49.9% owner of Sithe and has accounted for the investment as an unconsolidated equity investment through September 30, 2003. In the first quarter of 2003, Generation recorded an impairment charge of $200 million (before income taxes) in other income and deductions within the Consolidated Statements of Income and Comprehensive Income associated with a decline in the fair value of the Sithe investment, which was considered to be other-than-temporary. Generation's management considered various factors in the decision to impair this investment, including management's negotiations to sell its interest in Sithe. The discussions surrounding the sale indicated that the fair value of the Sithe investment was below its book value, and as such, an impairment was required. In the third quarter of 2003, Generation recorded an additional impairment charge of $55 million (before income taxes) in other income and deductions within the Consolidated Statements of Income and Comprehensive Income to reflect an additional decline in the fair value of its investment in Sithe. This additional decline in fair value was primarily attributable to the changes in terms with a new acquirer, which occurred in the third quarter of 2003, as described below. At December 31, 2002, Sithe had total assets of $2.6 billion (including the $534 million note from Generation which has subsequently been reduced to $326 million) and total liabilities of $1.8 billion. Of the total liabilities, Sithe had $1.3 billion of debt which included $624 million of subsidiary debt incurred primarily to finance the construction of six new generating facilities, $461 million of subordinated debt, $103 million of line of credit borrowings, $43 million of current portion of long-term debt and capital leases, $30 million of capital leases, and excludes $453 million of non-recourse debt associated with Sithe's equity investments. For the year ended December 31, 2002, Sithe had revenues of $1.0 billion and incurred a net loss of approximately $348 million. Exelon 36 contractually does not own any interest in Sithe International, a subsidiary of Sithe. As such, a portion of Sithe's net assets and results of operations would be eliminated from Generation's balance sheet and results of operations through a minority interest. The book value of Generation's investment in Sithe was $163 million at September 30, 2003. For the nine months ended September 30, 2003, Sithe had revenues of $562 million. Generation recorded $6 million of equity method income for Sithe for the nine months ended September 30, 2003. See Note 2 - New Accounting Principles and Accounting Changes for a discussion of Sithe in relation to FIN No. 46. On May 29, 2003, Exelon Fossil Holdings, Inc., a wholly owned subsidiary of Generation, issued an irrevocable call notice for the purchase of the 35.2% interest in Sithe owned by Apollo Energy, LLC and the 14.9% interest owned by subsidiaries of Marubeni Corporation. The total purchase price under the call is based on the terms of the existing Put and Call Agreement (PCA) among the parties and is $621 million. The transfer of ownership requires various regulatory approvals, including the Federal Energy Regulatory Commission (FERC), the state environmental agency in New Jersey, and expiration of the Hart Scott Rodino waiting period. Early termination of the Hart Scott Rodino waiting period was granted effective August 22, 2003. Under the terms of the PCA, the purchase price must be funded within six months of the call notice being issued. Additionally, because the Federal Power Act restricts Generation's ownership of more than 50% of a qualifying facility, the qualifying facilities owned by Sithe must be sold or restructured before closing to preserve their status as qualifying facilities. See below for information regarding a separate agreement reached by Sithe to sell six U.S. generating facilities, each a qualifying facility, and an entity holding Sithe's Canadian assets. At the closing, Sithe is expected to distribute in excess of $600 million of available cash to Generation. On August 13, 2003, Generation announced an agreement with entities controlled by Reservoir Capital Group (Reservoir), a private investment firm, to sell a 50% interest in Sithe in exchange for $75.8 million in cash. The sale will occur after Generation's purchase of the remaining 50.1% interest in Sithe. The sale requires approval by the FERC, a Hart Scott Rodino filing and a filing with the state regulatory commission in New York. Both of these filings have been made. Early termination of the Hart Scott Rodino waiting period was granted September 30, 2003. The sale is expected to close in the fourth quarter of 2003. Both Generation and Reservoir's 50% interests in Sithe will be subject to put and call options that could result in either party owning 100% of Sithe. While Generation's intent is to fully divest Sithe by the end of 2004, the timing of the put and call options vary by acquirer and can extend through March 2006. The pricing of the put and call options is dependent on numerous factors such as the acquirer, date of acquisition and assets owned by Sithe at the time of exercise. 37 In a separate transaction, Sithe has entered into an agreement with Reservoir to sell entities holding six U.S. generating facilities, each a qualifying facility under the Public Utility Regulatory Policies Act, and an entity holding Sithe's Canadian assets in exchange for $46.2 million ($26.2 million in cash and a $20 million two-year note). The sale requires approvals from Sithe's board of directors and shareholders and regulatory filings in New Jersey and Canada. Both of these filings have been made. The sale is also expected to close in the fourth quarter of 2003. This sale is not contingent on the sale of Generation's 50% interest in Sithe to Reservoir. AmerGen Generation is a 50% owner of AmerGen and has accounted for the investment as an unconsolidated equity investment through September 30, 2003. In addition to Generation's 50% ownership of AmerGen, Generation also has significant purchased power agreements (PPAs) with AmerGen. See Note 9 - Commitments and Contingencies for further discussion of Generation's PPAs with AmerGen. The book value of Generation's investment in AmerGen was $306 million at September 30, 2003. For the nine months ended September 30, 2003, AmerGen had revenues of $529 million. Generation recorded $84 million of equity method earnings for AmerGen for the nine months ended September 30, 2003. See Note 15 - Subsequent Events for information regarding Generation's agreement to purchase British Energy's 50% interest in AmerGen. See Note 2 - New Accounting Principles and Accounting Changes for discussion of AmerGen concerning FIN No. 46. At December 31, 2002, AmerGen had total assets of $1.6 billion and total liabilities of $1.3 billion. Of the total liabilities, AmerGen had $60 million of long-term debt, $35 million of notes payable to Generation, which were subsequently repaid in 2003, and $26 million of current portion of long-term debt. For the year ended December 31, 2002, AmerGen had revenues and net income of $644 million and $161 million, respectively. Other Pursuant to FIN No. 46, PECO deconsolidated PECO Trust IV during the third quarter of 2003. See Note 2 - New Accounting Principles and Accounting Changes. 5. REGULATORY ISSUES (Exelon, ComEd and PECO) ComEd On March 3, 2003, ComEd entered into an agreement with various Illinois electric retail market suppliers, key customer groups and governmental parties regarding several matters affecting ComEd's rates for electric service (Agreement). The Agreement addressed, among other things, issues related to ComEd's delivery services rate proceeding, market value index proceeding, the process for competitive service declarations for large-load customers and an amendment and extension of the PPA with Generation. During the second quarter of 2003, the ICC issued orders consistent with the Agreement which is now effective. During the first quarter of 2003, ComEd recorded a charge to earnings, associated with the funding of specified programs and initiatives associated with the Agreement, of $51 million (before income taxes) on a 38 present value basis. This amount was partially offset by the reversal of a $12 million (before income taxes) reserve established in the third quarter of 2002 for a potential capital disallowance in ComEd's delivery services rate proceeding and a credit of $10 million (before income taxes) related to the capitalization of employee incentive payments provided for in the delivery services order. The charge of $51 million and the credit of $10 million were recorded in operating and maintenance expense and the reversal of the $12 million reserve was recorded in other, net within ComEd's Consolidated Statements of Income and Comprehensive Income. The net one-time charge for these items was $29 million (before income taxes). In accordance with the Agreement, ComEd made payments of $17 million during the nine months ended September 30, 2003. ComEd filed a request on September 12, 2003 with the FERC seeking an adjustment in transmission rates to reflect nearly $500 million of infrastructure investments made during the last five years to accommodate sizeable regional growth in electricity demand. ComEd's proposed increase would adjust rates from 95 cents per kilowatt-month to $1.18 per kilowatt-month, effective November 1, 2003. Transmission rates were last set in 1999, based on 1998 costs. Because of the rate freeze and the method for calculating competitive transition charges (CTCs) in Illinois, ComEd expects that the requested rate adjustment will not significantly increase overall revenue. Several parties have intervened in this rate proceeding. The ultimate outcome of the proceeding is unknown. PECO As previously reported in the 2002 Form 10-K, the Pennsylvania Utility Commission's (PUC) Final Electric Restructuring Order established market share thresholds (MST) to promote competition. On May 1, 2003, the PUC approved the residential customer plan filed by PECO in February 2003. Under the plan and subsequent auction in September 2003, an aggregate of 267,000 residential customers will be transferred to alternative electric generation suppliers during December 2003. Customers transferred have the right to return to PECO at any time. PECO does not expect the transfer of customers pursuant to the MST plan to have a material impact on its results of operations, financial position or cash flows. On July 25, 2003, the PUC approved an adjustment to the Nuclear Decommissioning Cost Adjustment clause. Effective January 1, 2004, PECO will be permitted to recover an additional $3.6 million annually, or $33 million compared to $29 million previously. 39 6. 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 September 30, Nine Months Ended September 30, -------------------------------- ------------------------------- 2003 2002 2003 2002 ------------------------------------------------------------------------------------------------------------------- Average Common Shares Outstanding 326 323 325 322 Assumed Exercise of Stock Options -- 1 3 2 ------------------------------------------------------------------------------------------------------------------- Average Dilutive Common Shares Outstanding 326 324 328 324 ===================================================================================================================
The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was 15 million and 5 million for the three and nine months ended September 30, 2003, respectively, and 5 million for the three and nine months ended September 30, 2002. 40 7. SEGMENT INFORMATION (Exelon, ComEd, PECO and Generation) Exelon operates in three business segments: Energy Delivery (ComEd and PECO), Generation and Enterprises. Exelon evaluates the performance of its business segments on the basis of net income. ComEd, PECO and Generation each operate in a single business segment; as such, no separate segment information is provided for these registrants. Exelon's segment information for the three and nine months ended September 30, 2003 and 2002 and at September 30, 2003 and December 31, 2002 is as follows: Three Months Ended September 30, 2003 and 2002
Corporate and Energy Intersegment Delivery Generation Enterprises Eliminations Consolidated ------------------------------------------------------------------------------------------------------------------- Total Revenues (1): 2003 $ 2,886 $ 2,537 $ 437 $ (1,419) $ 4,441 2002 3,162 2,213 509 (1,514) 4,370 Intersegment Revenues: 2003 $ 23 $ 1,357 $ 38 $ (1,418) $ -- 2002 29 1,463 22 (1,514) -- Income (Loss) Before Income Taxes: 2003 $ 479 $ (708) $ 26 $ (11) $ (214) 2002 591 265 20 (28) 848 Income Taxes: 2003 $ 176 $ (280) $ 10 $ (18) $ (112) 2002 221 102 5 (31) 297 Net Income (Loss): 2003 $ 303 $ (428) $ 16 $ 7 $ (102) 2002 370 163 15 3 551 ------------------------------------------------------------------------------------------------------------------- (1) $65 million and $67 million in utility taxes are included in the revenues and expenses for the three months ended September 30, 2003 and 2002, respectively, for ComEd. $61 million and $64 million in utility taxes are included in the revenues and expenses for the three months ended September 30, 2003 and 2002, respectively, for PECO.
41 Nine Months Ended September 30, 2003 and 2002, September 30, 2003, and December 31, 2002
Corporate and Energy Intersegment Delivery Generation Enterprises Eliminations Consolidated ------------------------------------------------------------------------------------------------------------------- Total Revenues (1): 2003 $ 7,850 $ 6,301 $ 1,459 $ (3,374) $ 12,236 2002 7,973 5,233 1,475 (3,436) 11,245 Intersegment Revenues: 2003 $ 58 $ 3,246 $ 74 $ (3,378) $ -- 2002 59 3,309 72 (3,440) -- Income (Loss) Before Income Taxes and the Cumulative Effect of Changes in Accounting Principles: 2003 $ 1,478 $ (548) $ (99) $ (54) $ 777 2002 1,455 511 115 (84) 1,997 Income Taxes: 2003 $ 558 $ (209) $ (37) $ (54) $ 258 2002 547 198 46 (67) 724 Cumulative Effect of Changes in Accounting Principles: 2003 $ 5 $ 108 $ (1) $ -- $ 112 2002 -- 13 (243) -- (230) Net Income (Loss): 2003 $ 925 $ (231) $ (63) $ -- $ 631 2002 908 326 (174) (17) 1,043 Total Assets: September 30, 2003 $ 27,309 $ 13,240 $ 877 $ (2,282) $ 39,144 December 31, 2002 26,550 11,007 1,297 (1,369) 37,485 ------------------------------------------------------------------------------------------------------------------- (1) $178 million and $181 million in utility taxes are included in the revenues and expenses for the nine months ended September 30, 2003 and 2002, respectively, for ComEd. $159 million and $157 million in utility taxes are included in the revenues and expenses for the nine months ended September 30, 2003 and 2002, respectively, for PECO.
8. FAIR VALUE OF FINANCIAL ASSETS AND LIABILITIES (Exelon, ComEd, PECO and Generation) During the three and nine months ended September 30, 2003 and 2002, Exelon recorded pre-tax gains (losses) in other comprehensive income relating to mark-to-market (MTM) adjustments of contracts designated as cash flow hedges as follows:
ComEd PECO Generation Enterprises Exelon ------------------------------------------------------------------------------------------------------------------- Three months ended September 30, 2003 $ 12 $ 6 $ 241 $ (12) $ 247 Three months ended September 30, 2002 (36) -- (24) 4 (56) Nine months ended September 30, 2003 7 11 50 (10) 58 Nine months ended September 30, 2002 (52) (1) (130) 19 (164) -------------------------------------------------------------------------------------------------------------------
42 During the three and nine months ended September 30, 2003 and 2002, Generation recognized net MTM gains (losses) in purchased power on outstanding non-trading energy derivative contracts not designated as cash flow hedges included in the Consolidated Balance Sheets at September 30, 2003 and 2002 as follows:
2003 2002 ------------------------------------------------------------------------------------------------------------------- Three months ended September 30, $ (18) $ 1 Nine months ended September 30, (17) 11 -------------------------------------------------------------------------------------------------------------------
During the three and nine months ended September 30, 2003 and 2002, Generation recognized net MTM losses in operating revenues on outstanding proprietary trading contracts included in the consolidated balance sheets at September 30, 2003 and 2002 as follows:
2003 2002 ------------------------------------------------------------------------------------------------------------------- Three months ended September 30, $ -- $ -- Nine months ended September 30, (4) (13) -------------------------------------------------------------------------------------------------------------------
Amounts in accumulated other comprehensive income related to interest rate cash flow hedges are reclassified into earnings when the forecasted interest payment occurs. Amounts in accumulated other comprehensive income related to energy commodity cash flows are reclassified into earnings when the forecasted purchase or sale of the energy commodity occurs. As of September 30, 2003, deferred net gains (losses) on derivative instruments accumulated in other comprehensive income that are expected to be reclassified to earnings during the next twelve months are as follows:
ComEd PECO Generation Enterprises Exelon ------------------------------------------------------------------------------------------------------------------- Net gains (losses) expected to be reclassified $ -- $ 11 $ (103) $ 12 $ (80) -------------------------------------------------------------------------------------------------------------------
As of September 30, 2003, ComEd expects to amortize during the next twelve months $6 million of regulatory assets for settled cash flow swaps. During the three and nine months ended September 30, 2003 and 2002, ComEd reclassified amounts between other comprehensive income and regulatory assets for cash flow swaps settled as follows:
2003 2002 ------------------------------------------------------------------------------------------------------------------- Three months ended September 30, (net of tax of $2 and $0, respectively) $ (4) $ -- Nine months ended September 30, (net of tax of ($19) and ($4), respectively) 26 6 -------------------------------------------------------------------------------------------------------------------
In 2003, ComEd entered into forward-starting interest rate swaps with an aggregate notional amount of $440 million to manage interest rate exposure associated with an anticipated debt issuance. In connection with the 2003 issuances of First Mortgage Bonds, forward-starting interest rate swaps with an aggregate notional amount of $1,070 million were settled with net proceeds to counterparties of $45 million ($19 million, net of income taxes) that has been deferred in regulatory assets and is being amortized over the life of the First Mortgage Bonds as a net increase to interest expense. See Note 12 - Long-Term Debt and Preferred Securities for additional information regarding the issuance of the First Mortgage Bonds. At September 30, 2003, ComEd had settled all of its forward-starting swaps. 43 ComEd has entered into interest rate swaps to effectively convert $485 million in fixed-rate debt to floating rate debt. These swaps have been designated as fair-value hedges as defined in SFAS No. 133, and as such, changes in the fair value of the swaps are recorded in earnings. However, as long as the hedge remains effective, changes in the fair value of the swaps are offset by changes in the fair value of the hedged liabilities. Any change in the fair value of the hedge as a result of ineffectiveness would be recorded immediately in earnings. As of September 30, 2003, these swaps had an aggregate fair market value of $39 million, which was classified as other deferred debits and other assets within the Consolidated Balance Sheets. PECO has entered into interest rate swaps to manage interest rate exposure associated with the floating rate series of transition bonds issued to securitize PECO's stranded cost recovery. These interest rate swaps were designated as cash flow hedges as defined by SFAS No. 133, and as such, changes in fair value of the swaps will be recorded in other comprehensive income. At September 30, 2003, these interest rate swaps had an aggregate fair market value exposure of $11 million based on the present value difference between the contract and market rates at September 30, 2003. In 2003, PECO entered into forward-starting interest rate swaps with an aggregate notional amount of $360 million to manage interest rate exposure associated with an anticipated debt issuance. In connection with the April 28, 2003 issuance of $450 million of First and Refunding Mortgage Bonds, PECO settled the swaps for net proceeds of $1 million (before income taxes), which was recorded in other comprehensive income and is being amortized over the life of the debt issuance. See Note 12 - Long-Term Debt and Preferred Securities for additional information regarding the issuance of the First and Refunding Mortgage Bonds. Under the terms of the EBG Facility, EBG is required to effectively fix the interest rate on 50% of borrowings under the facility through its maturity in 2007. As of September 30, 2003, EBG has entered into interest rate swap agreements, which have effectively fixed the interest rate on $861 million of notional principal, or approximately 80% of borrowings outstanding under the EBG Facility. The fair market value exposure of these swaps, designated as cash flow hedges, is $91 million. Generation has entered into interest rate swaps with an aggregate notional amount of $400 million to manage interest rate exposures associated with an anticipated debt issuance. As of September 30, 2003, these swaps had an aggregate fair market value exposure of less than $1 million based on the present value difference between the contract and market rates at September 30, 2003. 44 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 for the securities held in these trust accounts.
September 30, 2003 --------------------------------------------------------------- Gross Gross Amortized Unrealized Unrealized Estimated Cost Gains Losses Fair Value ------------------------------------------------------------------------------------------------------------------- Cash and cash equivalents $ 85 $ -- $ -- $ 85 Equity securities 1,918 161 (369) 1,710 Debt securities Government obligations 1,018 51 (4) 1,065 Other debt securities 538 30 (24) 544 ------------------------------------------------------------------------------------------------------------------- Total debt securities 1,556 81 (28) 1,609 ------------------------------------------------------------------------------------------------------------------- Total available-for-sale securities $ 3,559 $ 242 $ (397) $ 3,404 ===================================================================================================================
Net unrealized losses of $155 million were recognized in regulatory assets, regulatory liabilities or accumulated other comprehensive income in Exelon's Consolidated Balance Sheet at September 30, 2003. Net unrealized losses of $155 million were recognized in noncurrent affiliate payables, noncurrent affiliate receivables or accumulated other comprehensive income in Generation's Consolidated Balance Sheet as of September 30, 2003. Net unrealized losses of $346 million were recognized in accumulated depreciation and accumulated other comprehensive income in the Consolidated Balance Sheets of Generation at December 31, 2002. During the three and nine months ended September 30, 2003 and 2002, proceeds from the sale of decommissioning trust investments and gross realized gains and losses on those sales were as follows:
Three Months Ended September 30, Nine Months Ended September 30, -------------------------------- ------------------------------- 2003 2002 2003 2002 - --------------------------------------------------------------------------------------------------------- Proceeds from sales $ 618 $ 295 $ 1,880 $ 1,184 Gross realized gains 138 12 203 43 Gross realized losses (141) (21) (194) (77) - ---------------------------------------------------------------------------------------------------------
Net realized losses of $3 million and $11 million for the three months ended September 30, 2003 and 2002, respectively, were recorded in other income and deductions. Net realized gains of $9 million and net realized losses of $32 million for the nine months ended September 30, 2003 and 2002, respectively, were recorded in other income and deductions. Net realized losses of $2 million were recognized in accumulated depreciation at September 30, 2002. The available-for-sale securities held at September 30, 2003 have an average maturity of six to ten years. The cost of these securities was determined on the basis of specific identification. 45 9. COMMITMENTS AND CONTINGENCIES (Exelon, ComEd, PECO and Generation) For information regarding capital commitments, nuclear decommissioning and spent fuel storage, see the Commitments and Contingencies and Nuclear Decommissioning and Spent Fuel Storage Notes in the Notes to Consolidated Financial Statements of Exelon, ComEd, PECO and Generation in the 2002 Form 10-K. See Note 2 - New Accounting Principles and Accounting Changes of this Form 10-Q for further discussion of nuclear decommissioning commitments and contingencies. Environmental Liabilities As of September 30, 2003, Exelon had accrued $117 million for environmental investigation and remediation costs that currently can be reasonably estimated, including $93 million for manufactured gas plant (MGP) investigation and remediation. Exelon has identified 70 sites where former MGP activities have or may have resulted in actual site contamination. As of September 30, 2003, ComEd had accrued $74 million for environmental investigation and remediation costs that currently can be reasonably estimated. This reserve included $69 million (discounted) for MGP investigation and remediation. As of September 30, 2003, PECO had accrued $33 million (undiscounted) for environmental investigation and remediation costs that currently can be reasonably estimated, including $24 million for MGP investigation and remediation. Pursuant to a PUC order, PECO is currently recovering a provision for environmental costs annually for the remediation of sites of former MGP facilities, for which PECO has recorded a regulatory asset (see Note 14 - Supplemental Financial Information). As of September 30, 2003, Generation had accrued $10 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. 46 Energy Commitments Generation had long-term commitments as of September 30, 2003 relating to the net purchase and sale of energy, capacity and transmission rights from unaffiliated utilities, including Midwest Generation, LLC (Midwest Generation), AmerGen and others, as expressed in the following table:
Power Only Purchases from Net Capacity Power Only --------------------------- Transmission Rights Purchases(1) Non-Affiliate Sales AmerGen(2) Non-Affiliates Purchases(3) ------------------------------------------------------------------------------------------------------------------------ 2003 $ 129 $ 939 $ 98 $ 537 $ 19 2004 753 2,064 515 1,324 110 2005 415 867 410 378 86 2006 405 236 423 251 3 2007 488 81 431 237 -- Thereafter 4,113 1 1,863 878 -- ------------------------------------------------------------------------------------------------------------------------ Total $ 6,303 $ 4,188 $ 3,740 $ 3,605 $ 218 ======================================================================================================================== (1) Net Capacity Purchases includes Midwest Generation commitments as of September 30, 2003. 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 optional capacity under the Coal Generation PPA. On June 25, 2003, Generation notified Midwest Generation of its exercise of its call option under the Coal Generation PPA for 2004. Generation exercised its call option on 687 MWs of capacity for 2004 generated by Waukegan Unit 8 and Fisk Unit 19 and did not exercise its option on 578 MWs of capacity at Waukegan Unit 6, Crawford Unit 7, and Will County Unit 3. See Note 15 - Subsequent Events for additional information regarding the PPAs with Midwest Generation, including the MWs contracted for in 2004. Net Capacity Purchases also include capacity sales to TXU Corp. (TXU) under the PPA entered into in connection with the purchase of two generating plants in April 2002, which states that TXU will purchase the plant output from May through September from 2002 through 2006. The combined capacity of the two plants is 2,334 MWs. (2) Generation has entered into PPAs dated June 26, 2003, December 18, 2001, and November 22, 1999 with AmerGen. Generation has agreed to purchase 100% of the energy generated by Oyster Creek through April 9, 2009. Generation has agreed to purchase all the energy from TMI from January 1, 2002 through December 31, 2014. Generation has agreed to purchase all of the residual energy from Clinton not sold to Illinois Power through December 31, 2004. Currently, the residual output is approximately 31% of the total output of Clinton, but will increase to 100% and the obligation will continue until Clinton's license issued by the U.S. Nuclear Regulatory Commission (NRC) expires in 2026. See Note 15 - Subsequent Events regarding Generation's agreement to purchase British Energy's interest in AmerGen. (3) Transmission Rights Purchases include estimated commitments in 2004 and 2005 for additional transmission rights that will be required to fulfill firm sales contracts.
Additionally, Generation has the following energy commitments: In connection with the 2001 corporate restructuring, Generation entered into a PPA with ComEd under which Generation has agreed to supply all of ComEd's load requirements through 2004. Under the ComEd PPA, prices for energy vary depending upon the time of day and month of delivery. During 2005 and 2006, ComEd's PPA is a partial requirements agreement under which ComEd will purchase all of its required energy and capacity from Generation, up to the available capacity of the nuclear generating plants formerly owned by ComEd and transferred to Generation. Under the terms of the PPA, Generation is responsible for obtaining any required transmission service, subject to ComEd's obligation to obtain network service over the ComEd system. The PPA also specifies that prior to 2005, ComEd and Generation will jointly determine and agree on a market-based price for energy delivered under the PPA for 2005 and 2006, which is expected to exceed current pricing. In the event that the parties cannot agree to market-based prices for 2005 and 2006 prior to July 1, 2004, ComEd has the option of terminating the PPA effective December 31, 2004. ComEd will obtain any additional supply required from market sources in 2005 and 2006, and subsequent to 2006, will obtain all of its supply from market sources, 47 which could include Generation. The ComEd PPA for 2005 and 2006 may be extended to a full requirements contract as a result of the Agreement (see Note 5 - Regulatory Issues). Under the Agreement, various interested parties have agreed to not oppose such an extension. In connection with the 2001 corporate restructuring, Generation entered into a PPA with PECO under which Generation has agreed to supply PECO with substantially all of PECO's electric supply needs through 2010. Also, under the restructuring, PECO assigned its rights and 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, currently totaling $73 million per year. Under an agreement effective September 2001, PECO remits to Generation any amounts collected from customers for nuclear decommissioning, currently totaling $29 million per year. This amount will increase to $33 million effective January 1, 2004 as a result of a July 2003 PUC order. See Note 5 - Regulatory Issues. See Note 2 - New Accounting Principles and Accounting Changes for further discussion of the impact of the adoption of SFAS No. 143 on these collections. 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. See Note 19 - Commitments and Contingencies in Exelon's 2002 Form 10-K for additional information regarding this litigation. On June 13, 2003, the court dismissed the amended complaint with prejudice. The plaintiffs have not appealed the court's order of dismissal, thereby terminating the case. ComEd FERC Municipal Request for Refund. Three of ComEd's wholesale municipal customers filed a complaint and request for refund with the FERC, alleging that ComEd failed to properly adjust its rates, as provided for under the terms of the electric service contracts with the municipal customers and to track certain refunds made to ComEd's retail customers in the years 1992 through 1994. In July 2003, ComEd and the municipal customers executed a settlement agreement ending the litigation. Under the settlement, ComEd paid a total of approximately $3 million to the three municipalities during the third quarter of 2003. 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 and for breach of contract. On November 25, 2002, the court 48 granted the developers' motions for summary judgment. The judge also entered a permanent injunction enjoining ComEd from refusing to pay the retail rate on the grounds of the amendment, and Illinois from denying ComEd a tax credit on account of such purchases. ComEd and Illinois have each appealed the ruling. ComEd believes that it did not breach the contracts in question and that the damages claimed far exceed any loss that any project incurred by reason of its ineligibility for the subsidized rate. ComEd intends to prosecute its appeal and defend each case vigorously. While ComEd cannot currently predict the outcome of this action, ComEd does not believe that it will have a material adverse impact on ComEd's results of operations. 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. The court approved conditional class certification for the sole purpose of exploring settlement. ComEd filed a motion to dismiss the complaints. On April 24, 2001, the court dismissed four of the five counts of the consolidated complaint without prejudice and the sole remaining count was dismissed in part. On June 1, 2001, the plaintiffs filed a second amended consolidated complaint and ComEd has filed an answer. On December 5, 2002, a settlement was reached, whereby ComEd will pay up to $8 million, which includes $4 million paid to date. In an order dated October 3, 2003, the court approved the settlement. A portion of the settlement may be covered by insurance. ComEd has remaining reserves of approximately $3 million related to unpaid claims and costs. PECO and Generation Real Estate Tax Appeals. PECO and Generation are each challenging real estate taxes assessed on nuclear plants since 1997. PECO is involved in litigation in which it is contesting Pennsylvania Public Utility Realty Tax Act of March 4, 1971, as amended (PURTA) taxes assessed in 1997 and has appealed local real estate assessments for 1998 and 1999 on its formerly owned Limerick Generating Station (Montgomery County, PA) (Limerick) and Peach Bottom Atomic Power Station (York County, PA) (Peach Bottom) plants. Generation is involved in real estate tax appeals for 2000 through 2003, also regarding the valuation of its Limerick and Peach Bottom plants, its Quad Cities Station (Rock Island County, IL) and, through its ownership interest in AmerGen, TMI (Dauphin County, PA). During the third quarter of 2003, upon completion of updated nuclear plant appraisal studies, PECO and Generation recorded reductions of $58 million and $15 million, respectively, to reserves recorded for exposures associated with the real estate taxes. While PECO and Generation believe the resulting reserve balances as of September 30, 2003 reflect the most likely probable expected outcome of the litigation and appeals proceedings in accordance with SFAS No. 5, "Accounting for Contingencies," the ultimate outcome of such matters could result in additional unfavorable or favorable adjustments to the consolidated financial statements of PECO or Generation, and such adjustments could be material. 49 Generation Cotter Corporation Litigation. During 1989 and 1991, actions were brought in Federal and state courts in Colorado against ComEd and its subsidiary, Cotter Corporation (Cotter), seeking unspecified damages and injunctive relief based on allegations that Cotter permitted radioactive and other hazardous material to be released from its mill into areas owned or occupied by the plaintiffs, resulting in property damage and potential adverse health effects. In 1994, a Federal jury returned nominal dollar verdicts against Cotter on eight plaintiffs' claims in the 1989 cases, which verdicts were upheld on appeal. The remaining claims in the 1989 actions were settled or dismissed. In 1998, a jury verdict was rendered against Cotter in favor of 14 of the plaintiffs in the 1991 cases, totaling approximately $6 million in compensatory and punitive damages, interest and medical monitoring. On appeal, the Tenth Circuit Court of Appeals reversed the jury verdict and remanded the case for new trial. These plaintiffs' cases were consolidated with the remaining 26 plaintiffs' cases, which had not been tried. The consolidated trial was completed on June 28, 2001. The jury returned a verdict against Cotter and awarded $16 million in various damages. On November 20, 2001, the District Court entered an amended final judgment that included an award of both pre-judgment and post-judgment interests, costs, and medical monitoring expenses that totaled $43 million. In November 2000, another trial involving a separate sub-group of 13 plaintiffs seeking $19 million in damages plus interest was completed in Federal District Court in Denver. The jury awarded nominal damages of $42,500 to 11 of 13 plaintiffs but awarded no damages for any personal injury or health claims, other than requiring Cotter to perform periodic medical monitoring at minimal cost. Cotter appealed these judgments to the Tenth Circuit Court of Appeals. On April 22, 2003, the Tenth Circuit Court of Appeals reversed both judgments and remanded the cases for retrial. On September 5, 2003, plaintiffs appealed the Tenth Circuit's decision to the United States Supreme Court. Cotter has filed its response to the plaintiff's petition. 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. Generation cannot predict the ultimate outcome of the cases. The U.S. Environmental Protection Agency (EPA) has advised Cotter that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. Cotter is alleged to have disposed of approximately 39,000 tons of soils mixed with 8,700 tons of leached barium sulfate at the site. Cotter, along with three other companies identified by the EPA as potentially responsible parties (PRPs), has submitted a draft feasibility study addressing options for remediation of the site. The PRPs are also engaged in discussions with the State of Missouri and the EPA. The estimated costs of remediation for the site range from $0 to $87 million. Once a remedy is selected, it is expected that the PRPs will agree on an allocation of responsibility for the costs. Until an agreement is reached, Generation cannot predict its share of the costs, and, as such, no amounts have been accrued as of September 30, 2003. 50 Raytheon Litigation. In March 2001, two subsidiaries of Sithe New England acquired in November 2002 brought an action in the New York Supreme Court against Raytheon Corporation (Raytheon) relating to its failure to honor its guaranty with respect to the performance of the Mystic and Fore River projects, as a result of the abandonment of the projects by the turnkey contractor. In a related proceeding, in May 2002, Raytheon submitted claims to the International Chamber of Commerce Court of Arbitration (Arbitration Court) seeking equitable relief and damages for alleged owner-caused performance delays in connection with the Fore River Power Plant Engineering, Procurement & Construction Agreement (EPC Agreement). The EPC Agreement, executed by a Raytheon subsidiary and guaranteed by Raytheon, governs the design, engineering, construction, start-up, testing and delivery of an 800-MW combined-cycle power plant in Weymouth, Massachusetts. Hearings by the Arbitration Court with respect to liability were held in January and February 2003. On May 12, 2003, the Arbitration Court issued an interim order finding in favor of Raytheon on liability but limited the grounds upon which Raytheon could claim schedule and cost relief. After the interim order, Raytheon amended its claim to seek 110 days of schedule relief (which would reduce Raytheon's liquidated damage payment for late delivery by approximately $20 million) and additional damages of $12 million. Raytheon also has asserted a claim in the amount of approximately $13 million for loss of efficiency and productivity as a result of an alleged constructive acceleration. The aggregate amount of Raytheon's asserted claims is approximately $45 million, not including general and administrative costs, profit and interest that Raytheon asserts are due under the EPC Agreement. Hearings by the Arbitration Court with respect to damages were conducted and a final decision is expected in the fourth quarter of 2003. Generation believes that Sithe New England properly rejected Raytheon's request for a change order and that Raytheon's damage claims are inflated. In addition to its asserted claims, Raytheon has indicated that it will bring additional claims for damages. Generation will continue to vigorously defend its position in the litigation and contest any additional claims that may be asserted. On August 29, 2003, Raytheon filed an action against two subsidiaries of EBG (Project Companies) and BNP Paribas in the Superior Court of the Commonwealth of Massachusetts. Raytheon alleged that the Project Companies and BNP Paribas failed to provide adequate assurance that Raytheon would be paid the remaining amounts due under the Fore River and Mystic construction contracts. Raytheon sought: (1) an injunction preventing the Project Companies and BNP Paribas from drawing upon certain letters of credit guaranteeing Raytheon's performance; (2) the right to terminate the construction contracts; and (3) an order allowing Raytheon to seize project funds totaling approximately $40 million. Raytheon subsequently dismissed BNP Paribas from the litigation. On October 9, 2003, the court issued a preliminary injunction preserving the status quo and preventing the Project Companies from drawing upon the letters of credit until such time as the court decides Raytheon's pending motion for partial summary judgment. The court has heard argument on Raytheon's motion for partial summary judgment but has not announced any decision. Generation is unable to predict the ultimate outcome of these legal proceedings. Clean Air Act. On June 1, 2001, the EPA issued to EBG a Notice of 51 Violation (NOV) and Reporting Requirement pursuant to Sections 113 and 114 of the Clean Air Act, alleging numerous exceedances of opacity limits and violations of opacity-related monitoring, recording and reporting requirements at certain generating units in Everett, Massachusetts (Mystic Station). On January 8, 2002, the EPA indicated that it had decided to resolve the NOV through an administrative compliance order and a judicial civil penalty action. In March 2002, the EPA issued and Exelon Mystic LLC, a wholly owned subsidiary of EBG, voluntarily entered a Compliance Order and Reporting Requirement (Compliance Order) regarding Mystic Station, under which Mystic Station installed new ignition equipment on three of the four operating units at the plant. Mystic Station also undertook an extensive opacity monitoring and testing program for all four operating units at the plant to help determine if additional compliance measures were needed. Pursuant to the requirements of the Compliance Order, EBG switched three of the four operating units to a lower sulfur fuel oil by September 1, 2002. The Compliance Order did not address civil penalties. By a letter dated April 21, 2003, the United States Department of Justice notified EBG that, at the request of the EPA, it intended to bring a civil penalty action but also offered the opportunity to resolve the matter through settlement discussions. EBG is pursuing settlement discussions with the EPA and the Department of Justice. Generation cannot reasonably predict the ultimate outcome of the settlement discussions. Exelon, ComEd, PECO and Generation Exelon, ComEd, PECO and Generation are involved in various other litigation matters that are being defended and handled in the ordinary course of business, and Exelon, ComEd, PECO and Generation maintain accruals for such costs that are probable of being incurred and subject to reasonable estimation. 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. 52 Commercial Commitments Exelon, ComEd, PECO and Generation's commercial commitments as of September 30, 2003, representing commitments not recorded on the balance sheet but potentially triggered by future events, including obligations to make payment on behalf of other parties and financing arrangements to secure their obligations, were as follows:
Expiration within ----------------------------------------------------------------------- 2008 Exelon Total 2003 2004-2005 2006-2007 and beyond ------------------------------------------------------------------------------------------------------------------ Related to Obligations Recorded on the Balance Sheet ---------------------------------------------------- Letters of credit (non-debt) (a) $ 121 $ 29 $ 92 $ -- $ -- Letters of credit (long-term debt) (b) 413 50 363 -- -- Preferred securities guarantees (c) 528 -- -- -- 528 Guarantees of long-term debt (d) 41 -- 2 -- 39 Midwest Generation Capacity Reservation Agreement guarantee (e) 33 1 7 7 18 Other ----- Guarantees of letters of credit (f) 28 4 24 -- -- Performance guarantees (g) 112 -- -- -- 112 Surety bonds (h) 622 197 256 12 157 Energy marketing contract guarantees (i) 208 91 113 4 -- Nuclear insurance guarantees (j) 1,559 -- -- -- 1,559 Lease guarantees (k) 10 -- -- 1 9 EBG equity guarantee (l) 38 38 -- -- -- Fuel purchase agreements (m) 2,130 139 791 586 614 ------------------------------------------------------------------------------------------------------------------ Total $ 5,843 $ 549 $ 1,648 $ 610 $ 3,036 ================================================================================================================== Expiration within ----------------------------------------------------------------------- 2008 ComEd Total 2003 2004-2005 2006-2007 and beyond ------------------------------------------------------------------------------------------------------------------ Related to Obligations Recorded on the Balance Sheet ---------------------------------------------------- Letters of credit (non-debt) (a) $ 26 $ 1 $ 25 $ -- $ -- Letters of credit (long-term debt) (b) 50 50 -- -- -- Preferred securities guarantees (c) 350 -- -- -- 350 Midwest Generation Capacity Reservation Agreement guarantee (e) 33 1 7 7 18 Other ----- Surety bonds (h) 21 -- 3 -- 18 ------------------------------------------------------------------------------------------------------------------ Total $ 480 $ 52 $ 35 $ 7 $ 386 ================================================================================================================== 53 Expiration within ----------------------------------------------------------------------- 2008 PECO Total 2003 2004-2005 2006-2007 and beyond ------------------------------------------------------------------------------------------------------------------ Related to Obligations Recorded on the Balance Sheet ---------------------------------------------------- Letters of credit (non-debt) (a) $ 29 $ -- $ 29 $ -- $ -- Preferred securities guarantees (c) 178 -- -- -- 178 Other ----- Surety bonds (h) 46 -- 46 -- -- ------------------------------------------------------------------------------------------------------------------ Total $ 253 $ -- $ 75 $ -- $ 178 ================================================================================================================== Expiration within ----------------------------------------------------------------------- 2008 Generation Total 2003 2004-2005 2006-2007 and beyond ------------------------------------------------------------------------------------------------------------------ Related to Obligations Recorded on the Balance Sheet ---------------------------------------------------- Letters of credit (non-debt) (a) $ 16 $ 9 $ 7 $ -- $ -- Letters of credit (long-term debt) (b) 363 -- 363 -- -- Other ----- Performance guarantees (g) 101 -- -- -- 101 Energy marketing contract guarantees (i) 36 36 -- -- -- EBG equity guarantee (l) 38 38 -- -- -- Fuel purchase agreements (m) 2,130 139 791 586 614 Nuclear insurance guarantee (n) 151 -- -- -- 151 ------------------------------------------------------------------------------------------------------------------ Total $ 2,835 $ 222 $ 1,161 $ 586 $ 866 ================================================================================================================== (a) Letters of credit (non-debt) - Exelon and certain of its subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties. (b) Letters of credit (long-term debt) - Direct-pay letters of credit issued in connection with variable-rate debt in order to provide liquidity in the event that it is not possible to remarket all of the debt as required following specific events, including changes in the basis of determining the interest rate on the debt. (c) Preferred securities guarantees - Guarantees issued to guarantee the preferred securities of the unconsolidated and consolidated subsidiary trusts of ComEd and PECO. (d) Guarantees of long-term debt - Issued to guarantee payment of Enterprises' debt. (e) Midwest Generation Capacity Reservation Agreement guarantee - In connection with ComEd's agreement with the City of Chicago (Chicago) entered into on February 20, 2003, Midwest Generation assumed from Chicago a Capacity Reservation Agreement that Chicago had entered into with Calumet Energy Team, LLC. ComEd will reimburse Chicago for any nonperformance by Midwest Generation under the Capacity Reservation Agreement. The estimated fair value of this guarantee under FIN 45 of $4 million is included as a liability on ComEd's Consolidated Balance Sheets. Additional information regarding this liability is included within this section under the heading "General" below. (f) Guarantees of letters of credit - Guarantees issued to provide support for letters of credit as required by third parties. These guarantees could be called upon only in the event of non-payment by a subsidiary. (g) Performance guarantees - Guarantees issued to ensure performance under specific contracts. (h) Surety bonds - Guarantees issued related to contract and commercial surety bonds, excluding bid bonds. (i) Energy marketing contract guarantees - Guarantees issued to ensure performance under energy commodity contracts. (j) Nuclear insurance guarantees - Guarantees of nuclear insurance required under the Price-Anderson Act. $1.0 billion of this total exposure is exempt from the $4.5 billion PUHCA guarantee limit by SEC rule. (k) Lease guarantees - Guarantees issued to ensure payments on building leases. (l) EBG equity guarantee- See Note 3 - Acquisitions, Dispositions and Retirements for further information on the $38 million guarantee. Pursuant to existing guarantees, after construction of the EBG facilities is complete, Exelon could be required to pay up to an additional $42 million relating to various construction and tax obligations. (m) Fuel purchase agreements - Commitments to purchase fuel supplies for nuclear and fossil generation. (n) Nuclear insurance guarantee - Guarantees of nuclear insurance required under the Price-Anderson Act. This amount relates to Generation's guarantee of AmerGen's plants. Exelon has a $1.4 billion guarantee relating to Generation's directly owned plants that is not included in this amount.
54 Credit Contingencies Generation is a counterparty to Dynegy in various energy transactions. The credit ratings of Dynegy are considered below investment grade by two credit rating agencies. Generation has credit risk associated with Dynegy through Generation's equity investment in Sithe. Sithe is a 60% owner of the Independence generating station (Independence), a 1,040-MW gas-fired qualified facility that has an energy-only long-term tolling agreement with Dynegy with a related financial swap arrangement. As of September 30, 2003, Sithe had recognized an asset on its balance sheet related to the fair market value of the financial swap agreement with Dynegy that is marked to market under the provisions of SFAS No. 133. If Dynegy is unable to fulfill the terms of this agreement, Sithe would be required to impair this financial swap asset. Generation estimates, as a 49.9% owner of Sithe, that the impairment would result in an after-tax reduction of its earnings of approximately $16 million. In addition to the impairment of the financial swap asset, if Dynegy were unable to fulfill its obligations under the financial swap agreement and the tolling agreement, Generation may incur a further impairment associated with Independence. Additionally, the future economic value of AmerGen's PPA with Illinois Power Company, a subsidiary of Dynegy, could be impacted by events related to Dynegy's financial condition. ComEd and Generation are parties to various transactions with Midwest Generation. Midwest Generation's credit ratings have been downgraded by certain credit rating agencies. Furthermore, the June 30, 2003 Form 10-Q filed by Edison Mission Energy (EME), an intermediate parent company of Edison Mission Midwest Holdings (EMMH) and Midwest Generation, indicates that EMMH is not expected to have sufficient cash to repay $911 million of debt when it matures on December 11, 2003; a failure to repay, extend, or refinance the EMMH obligation would likely result in a default under the senior secured notes and term loan of Mission Energy Holding Company, EME's parent company; and these events could make it necessary for EME to file a petition for reorganization under Chapter 11 of the United States Bankruptcy Code. Reorganization under Chapter 11 of the United States Bankruptcy Code does not assure non-performance under all contracts; however, the reorganization would increase the possibility of the obligations described in the following two paragraphs reverting to ComEd or Generation. In connection with ComEd's sale in December 1999 of fossil generating assets to Midwest Generation, ComEd entered into an agency agreement with EMMH and EME whereby EMMH assumed the benefits and liabilities of a long-term coal purchase contract and a railcar lease. EME guaranteed EMMH's performance. EMMH did not become a direct party to the obligations, and ComEd remained obligated and was not released. In connection with the Merger and subsequent restructuring, Generation assumed any contingent obligation on these contracts from ComEd. In the event of EMMH and EME's non-performance under the coal purchase contract, Generation would be required to fulfill the purchase commitments that extend through 2012. The contract requires the purchase of two million tons of coal annually or specifies a minimum payout. Based upon current market prices, Generation's contingent obligations for the minimum purchase obligation for the contract years 2003 to 2012 are estimated to be approximately $81 million (the net present value of the obligation approximates $51 million) related to this agreement. The railcar lease covers approximately 1,400 coal transport railcars through 2014. In the event of EMMH and EME's non-performance under the railcar lease, Generation would be required to fulfill the lease payments that extend through 2014. The remaining lease payments for the railcars approximate $65 million (the net present value of the obligation approximates $38 million). However, based on current prices for railcars in these particular markets, Generation believes it would be able to effectively sublease the railcars without incurring any exposure related to this obligation. 55 Generation and ComEd have entered into other agreements with Midwest Generation and have other related exposures. In connection with ComEd's fossil generating asset sale to Midwest Generation, Midwest Generation and EME agreed to indemnify ComEd for various environmental exposures or penalties. Generation assumed any contingent obligations relating to generation-related environmental issues of ComEd in connection with the Merger and subsequent restructuring. Exelon cannot reasonably estimate the possible environmental exposures or penalties that could arise if Midwest Generation or EME do not honor their indemnity to ComEd or if the indemnity is discharged in bankruptcy. Midwest Generation also indemnified Generation and ComEd for approximately 50% of any post-acquisition asbestos claims relating to the plants sold to Midwest Generation. Generation assumed any contingent obligations of ComEd relating to these asbestos claims in connection with the Merger and subsequent restructuring. The bankruptcy of or non-performance of Midwest Generation of its obligations to Generation and ComEd for asbestos claims could result in contingent obligations to Generation and ComEd of up to an estimated $5 million. In addition, ComEd is exposed to risks associated with accounts receivable from transmission and station power services provided by ComEd to Midwest Generation. The bankruptcy of or non-performance of Midwest Generation of its obligations to ComEd for transmission and station power services provided by ComEd could result in ComEd recording a write-off of up to an estimated $3 million. Generation accounts for certain derivative financial instruments under the normal purchases and normal sales exemption of SFAS No. 133. As of September 30, 2003, Generation is a party to forward energy purchase and sale contracts with Midwest Generation, which are accounted for in that manner and, as such, are not marked-to-market. If Generation determines that the possibility of non-performance by Midwest Generation on these contracts becomes more than remote, these contracts will be required to be marked-to-market through earnings, which would be expected to result in a charge to Exelon and Generation's results of operations and such charge could be material. Spent Fuel Storage In July 2000, PECO and the U. S. Department of Energy (DOE) entered into a settlement agreement whereby, in return for foregoing a breach of contract lawsuit against the DOE, PECO agreed to receive credits against its contributions to the Nuclear Waste Fund to cover its costs of having to construct and maintain an independent spent fuel storage facility at Peach Bottom, a facility co-owned by PECO (now Generation). In September 2002, the U.S. Courts of Appeals for the 11th Circuit ruled that the settlement agreement's credit-based funding mechanism violated provisions of the Nuclear Waste Policy Act. Generation, as successor to PECO, currently is in good faith discussions with the DOE regarding a new settlement agreement with a different funding mechanism. On August 14, 2003, Generation received a letter from the DOE demanding repayment of $40 million of previously received credits from the Nuclear Waste Fund. The letter also demanded $1.5 million of accrued interest expense. Although a new settlement would offset Generation's payments, Generation nonetheless has reserved its 50% ownership share of these amounts. Because Generation 56 expenses the casks and capitalizes the permanent components of its spent fuel storage facilities, these reserves increased Generation's operating and maintenance expense approximately $11 million and its capital base approximately $9 million during the third quarter of 2003. The remainder of the recorded obligation to the DOE will be recovered from the co-owner of the facility. See Note 9 - Nuclear Decommissioning and Spent Nuclear Fuel Storage in Generation's 2002 Form 10-K for additional information regarding this matter. General On February 20, 2003, ComEd entered into separate agreements with Chicago and with Midwest Generation (Midwest Agreement). Under the terms of the agreement with Chicago, ComEd will pay Chicago $60 million over ten years ($6 million was paid during the first quarter of 2003) and be relieved of a requirement, originally transferred to Midwest Generation upon the sale of ComEd's fossil stations in 1999, to build a 500-MW generation facility. Under the Midwest Agreement, ComEd received $22 million from Midwest Generation during the first quarter 2003 and $10 million during April 2003, to relieve Midwest Generation's obligation under the fossil sale agreement. Midwest Generation also assumed from Chicago a Capacity Reservation Agreement that Chicago had entered into with Calumet Energy Team, LLC (CET), which is effective through June 2012. ComEd is obligated to reimburse Chicago for any nonperformance by Midwest Generation under the Capacity Reservation Agreement and paid approximately $2 million for amounts owed to CET by Chicago at the time the agreement was executed. In the first quarter of 2003, ComEd recorded a guarantee liability of $4 million under the provisions of FIN No. 45 related to its obligation to reimburse Chicago for any nonperformance by Midwest Generation. The net effect of the settlement to ComEd will be amortized over the remaining life of the franchise agreement with Chicago. ComEd and PECO have entered into several agreements with a tax consultant related to the filing of refund claims with the Internal Revenue Service (IRS) and have made refundable prepayments of $11 million and $1 million, respectively, during the nine months ended September 30, 2003 for potential fees associated with these agreements. The fees for these agreements are contingent upon a successful outcome and are based upon a percentage of the refunds recovered from the IRS, if any. As such, ultimate net cash outflows to ComEd and PECO related to these agreements will either be positive or neutral depending upon the outcome of the refund claim with the IRS. These potential tax benefits and associated fees could be material to the financial position, results of operations and cash flows of ComEd and PECO. ComEd's tax benefits for periods prior to the Merger would be recorded as a reduction of goodwill pursuant to a reallocation of the Merger purchase price. ComEd and PECO cannot predict the timing of the final resolution of these refund claims. 10. SEVERANCE BENEFITS (Exelon, ComEd, PECO and Generation) Exelon, ComEd, PECO and Generation provide severance and health and welfare benefits to terminated employees pursuant to pre-existing severance plans primarily based upon each individual employee's years of service with Exelon and compensation level. The registrants account for 57 their ongoing severance plans in accordance with SFAS No. 112, "Employer's Accounting for Postemployment Benefits, an amendment of FASB Statements No. 5 and 43" (SFAS No. 112) and accrue amounts associated with severance benefits that are considered probable and that can be reasonably estimated. As part of the implementation of Exelon's new business model referred to as The Exelon Way during the third quarter of 2003, Exelon identified 1,042 positions for elimination by the end of 2004. The majority of the headcount reductions are professional and managerial employees. Exelon recorded a charge for cash severance of $87 million during the third quarter of 2003, which represented cash severance costs that were probable and could be reasonably estimated as of September 30, 2003. In addition to cash severance, Exelon incurred pension and postretirement benefit costs associated with The Exelon Way during the third quarter of 2003 of $80 million. In total, Exelon recorded a charge of $167 million in the third quarter for severance and related postretirement health and welfare benefits and pension and postretirement curtailment costs associated with The Exelon Way. See Note 11 - Retirement Benefits for a description of the charges for the pension and postretirement benefit plans. Exelon based its estimate of the number of positions to be eliminated on management's current plans and its ability to determine the appropriate staffing levels to effectively operate the businesses. Exelon anticipates incurring further costs associated with The Exelon Way upon identifying additional positions to be eliminated. These costs will be recorded in the period in which the costs can be reasonably estimated. The following table details, by segment, Exelon's total cash severance expense recorded as an operating and maintenance expense within the Consolidated Statements of Income and Comprehensive Income for the three and nine months ended September 30, 2003.
Corporate and Energy Intersegment Cash severance charges Delivery Generation Enterprises Eliminations Consolidated ------------------------------------------------------------------------------------------------------------------ Expense Recorded in Three Months Ended September 30, 2003 $ 50 $ 20 $ 7 $ 10 $ 87 Expense Recorded in Nine Months Ended September 30, 2003 53 24 7 11 95 ------------------------------------------------------------------------------------------------------------------
The following table provides information on total cash severance expense recorded as an operating and maintenance expense within the Consolidated Statements of Income and Comprehensive Income of ComEd, PECO and Generation:
Cash severance charges ComEd PECO Generation ------------------------------------------------------------------------------------------------------------------ Expense Recorded in Three Months Ended September 30, 2003 $ 37 $ 13 $ 20 Expense Recorded in Nine Months Ended September 30, 2003 37 16 24 ------------------------------------------------------------------------------------------------------------------
58 The following tables provide a reconciliation of the liability recorded by Exelon, ComEd, PECO and Generation for severance benefits:
Balance at Other Balance at Cash severance obligations January 1, 2003 Additions Payments Adjustments September 30, 2003 ------------------------------------------------------------------------------------------------------------------ Exelon $ 45 $ 95 $ (25) $ 3 $ 118 ComEd 15 37 (10) -- 42 PECO -- 16 -- -- 16 Generation 14 24 (4) 3 37 ------------------------------------------------------------------------------------------------------------------
11. RETIREMENT BENEFITS (Exelon, ComEd, PECO and Generation) During the third quarter of 2003, Exelon announced an amendment related to the benefit provisions of its postretirement welfare benefit plans. The amendment was effective August 1, 2003 and reduced the benefits attributable to prior service through increased retiree cost-sharing for medical coverage. The changes in the postretirement welfare plan design due to the amendment were incorporated into the August 1, 2003 remeasurement of the plan obligation discussed below. The amendment resulted in a reduction of the accumulated projected benefit obligation related to the postretirement welfare benefit plans of approximately $337 million and a reduction of cost of $36 million. Exelon recognized approximately $14 million of this cost reduction in the third quarter of 2003 with the remainder to be recognized in the fourth quarter of 2003. Due to The Exelon Way and the overall reduction in active employees during the third quarter of 2003, certain defined benefit pension plans and postretirement welfare benefit plans were subject to remeasurement as of August 1, 2003. The threshold basis for curtailment remeasurement was a reduction in future service greater than 5%. The curtailment of certain of the pension plans resulted in a reduction of the additional minimum liability and a decrease in the intangible pension asset of $10 million. Overall, the projected benefit obligation of the pension plan increased by $1 million due to the curtailment. The projected benefit obligation associated with the postretirement benefit plans increased by $17 million due to the curtailment. The remeasurements of the plan obligations resulted in accelerated recognition of a portion of the prior service cost generated by the pension and postretirement benefit plans, resulting in the recognition of curtailment charges during the third quarter of 2003. The magnitude of the curtailment charge differed by registrant based on the number of participants identified for termination and the amount of the unrecognized prior service costs at the date of remeasurement. The following table provides information regarding the curtailment charges recorded in operating and maintenance expense within the Consolidated Statements of Income and Comprehensive Income during the three months ended September 30, 2003 due to the accelerated recognition of a portion of the prior service cost: 59
Curtailment charges Pension plans Other postretirement plans ------------------------------------------------------------------------------------------------------------------ Exelon $ 11 $ 15 ComEd 1 1 PECO 6 10 Generation 3 4 ------------------------------------------------------------------------------------------------------------------
During the third quarter of 2003, Exelon recognized an additional charge associated with special health and welfare benefits offered through The Exelon Way. The following table provides information regarding the charges recorded as an operating and maintenance expense within the Consolidated Statements of Income and Comprehensive Income during the three months ended September 30, 2003:
Special health and welfare charges Other postretirement plans ------------------------------------------------------------------------------------------------------------------ Exelon $ 54 ComEd 20 PECO 12 Generation 20 ------------------------------------------------------------------------------------------------------------------
12. LONG-TERM DEBT AND PREFERRED SECURITIES (Exelon, ComEd, PECO and Generation) Effective July 1, 2003, ComEd and PECO reclassified the carrying values of their preferred securities issued prior to June 1, 2003 from equity to liabilities in conjunction with the adoption of SFAS No. 150. The total amounts reclassified from equity to liabilities were $422 million, $344 million and $78 million for Exelon, ComEd and PECO, respectively. See Note 2 - New Accounting Principles and Accounting Changes for additional information regarding the adoption of FIN No. 46 and SFAS No. 150. On September 30, 2003, ComEd retired $250 million of variable interest medium term notes due September 30, 2003. On September 30, 2003, ComEd redeemed $42 million of variable rate Pollution Control Revenue Bonds, 1994 B Series, due October 15, 2014 originally issued through the Illinois Development Finance Authority. On September 24, 2003, ComEd issued $42 million of variable interest Pollution Control Revenue Refunding Bonds due November 1, 2019 through the Illinois Development Finance Authority. On August 25, 2003, ComEd issued $250 million of 4.74% First Mortgage Bonds, due in 2010. These bond issuances were used to finance the repayment and early retirement of long-term debt. 60 On July 15, 2003, ComEd retired $100 million of its First Mortgage Bonds due July 15, 2003. The 6.625% bonds were refinanced with long-term debt issued on August 25, 2003. On May 15, 2003, ComEd redeemed $42 million of 5.875% Pollution Control Revenue Bonds 1977 Series A, due May 15, 2007 originally issued through the Illinois Industrial Pollution Control Financing Authority. On May 8, 2003, ComEd issued $40 million of variable interest Pollution Control Revenue Refunding Bonds due May 15, 2017 through the Illinois Development Finance Authority. On April 15, 2003, ComEd redeemed $160 million of its First Mortgage Bonds, at a redemption price of 103.664% of the principal amount, plus accrued interest. The bonds, which carried an interest rate of 8%, were refinanced with long-term debt issued on April 7, 2003. On April 7, 2003, ComEd issued $395 million of 4.70% First Mortgage Bonds, due on April 15, 2015. The proceeds of these bonds were used to refund other First Mortgage Bonds. On March 20, 2003, ComEd Financing I, a wholly owned financing subsidiary of ComEd, redeemed $200 million of trust preferred securities at a redemption price of 100% of the principal amount, plus accrued distributions. ComEd redeemed $206 million of subordinated debentures issued to ComEd Financing I. The preferred securities, which carried an interest rate of 8.48%, were refinanced with the proceeds from a March 17, 2003 issue of $200 million of trust preferred securities by ComEd Financing III, a wholly owned financing subsidiary of ComEd, which have an annual distribution rate of 6.35% and are mandatorily redeemable in 2033. The subordinated debentures, which carried an interest rate of 8.48%, were refinanced with the proceeds from a March 17, 2003 issue of $206 million of subordinated debentures from ComEd to ComEd Financing III, which have an annual distribution rate of 6.35% and are mandatorily redeemable in 2033. On March 18, 2003, ComEd redeemed $236 million of its First Mortgage Bonds, at a redemption price of 103.863% of the principal amount, plus accrued interest. The bonds, which carried an interest rate of 8.375%, were refinanced with long-term debt issued on April 7, 2003. On January 22, 2003, ComEd issued $350 million of 3.70% First Mortgage Bonds, due in 2008 and $350 million of 5.875% First Mortgage Bonds, due in 2033. These bond issuances were used to refinance long-term debt that had been previously retired during the third and fourth quarters of 2002. During the nine months ended September 30, 2003, Exelon and ComEd retired $267 million and $52 million of commercial paper classified as long-term debt, respectively. During the nine months ended September 30, 2003, Exelon retired $493 million of transitional funding trust notes, comprised of $254 million for ComEd and $239 million for PECO. 61 During the nine months ended September 30, 2003, ComEd recorded prepayment premiums of $15 million and net unamortized premiums, discounts and debt issuance expenses of $57 million associated with the early retirement of debt in 2003 that have been deferred by ComEd in regulatory assets and will be amortized to interest expense over the life of the related new debt issuance consistent with regulatory recovery. During June 2003, PECO issued $103 million of subordinated debentures to PECO Trust IV in connection with the issuance by PECO Trust IV of $100 million of preferred securities with an annual distribution rate of 5.75% that are mandatorily redeemable in 2033. The trust preferred securities were recorded as liabilities of PECO as of June 30, 2003 in accordance with SFAS No. 150. Effective July 1, 2003, PECO Trust IV was deconsolidated from the financial statements of PECO in conjunction with the adoption of FIN No. 46. See Note 2 - New Accounting Principles and Accounting Changes for further information. The $103 million of subordinated debentures issued by PECO to PECO Trust IV was recorded as long-term debt to affiliate within the Consolidated Balance Sheets. The proceeds of the issue were used to redeem the trust preferred securities and preferred stock discussed below. Also on June 24, 2003, PECO Energy Capital Trust II, a wholly owned financing subsidiary of PECO, redeemed $50 million of its 8.00% trust preferred securities at a redemption price of $25 per trust receipt, plus accrued and unpaid distributions. PECO redeemed $52 million of subordinated debentures to PECO Energy Capital Trust II. On June 11, 2003, PECO redeemed $50 million of its $7.48 preferred stock at a redemption price of $103.74 per share, plus accrued and unpaid dividends. On April 28, 2003, PECO issued $450 million of 3.50% First and Refunding Mortgage Bonds due on May 1, 2008. The proceeds from the sale of the bonds were used to repay aggregate principal of maturing debt and to repay commercial paper that was used to refinance long-term debt. On June 3, 2003, Generation issued $17 million of variable rate Pollution Control Revenue Refunding Bonds, Series A, due June 1, 2027 through the Indiana County Industrial Development Authority (Pennsylvania). The proceeds of these bonds were used to refund $17 million of Pollution Control Revenue Refunding Bonds, due June 1, 2027, issued on behalf of PECO. During the third quarter of 2003, an event of default occurred related to the EBG Facility. See Note 3 - Acquisitions, Dispositions and Retirements for further information. On September 29, 2003, Generation closed on an $850 million revolving credit facility that replaced a $550 million revolving credit facility that had originally closed on June 13, 2003. Generation used the facility to make the first payment to Sithe relating to the $536 million note that was used to purchase Exelon New England. This note was restructured in June 2003 to provide for a payment of $210 million of the principal on June 16, 2003, payment of $236 million of the principal on the earlier of December 1, 2003 or change of control of Generation, and payment 62 of the remaining principal on the earlier of December 1, 2004 or change of control of Generation. At September 30, 2003, Generation had $640 million available under this credit facility. Exelon, ComEd, PECO and Generation maintain a $1.5 billion 364-day credit facility to support commercial paper issuances. At September 30, 2003, sublimits under the credit facility were $1.0 billion, $100 million and $400 million for Exelon Corporate, ComEd and PECO, respectively. Generation did not have a sublimit under the facility at September 30, 2003. Exelon Corporate, ComEd and PECO had approximately $720 million, $360 million and $75 million available under the credit facility, respectively, reflecting commercial paper, letters of credit and loans outstanding at September 30, 2003. At September 30, 2003, commercial paper outstanding was $70 million and $12 million at Exelon Corporate and PECO, respectively. ComEd and Generation did not have any commercial paper outstanding at September 30, 2003. See Note 8 - Fair Value of Financial Assets and Liabilities for additional information regarding interest rate swaps of ComEd, PECO and Generation. 63 13. RELATED-PARTY TRANSACTIONS (Exelon, ComEd, PECO and Generation) 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, ------------------- ------------------- 2003 2002 2003 2002 ----------------------------------------------------------------------------------------------------------------------- Operating revenues from affiliates Generation (1) $ 16 $ 22 $ 42 $ 41 Enterprises (1) 4 4 7 8 Purchased power from affiliate Generation (2) 885 967 1,984 2,046 Operating & maintenance from affiliates BSC (3) 32 29 84 94 Enterprises (4, 5) 8 4 14 10 Interest income from affiliates UII (6) 5 8 17 23 Exelon intercompany money pool (10) 1 -- 2 -- Other -- -- 1 -- Capitalized costs BSC (3) 1 3 3 6 Enterprises (5) 10 3 21 16 Cash dividends paid to parent 94 118 305 353 ----------------------------------------------------------------------------------------------------------------------- September 30, 2003 December 31, 2002 ----------------------------------------------------------------------------------------------------------------------- Receivables from affiliates (current) UII (6) $ -- $ 15 Exelon intercompany money pool (10) 147 -- Other 4 -- Receivables from affiliates (noncurrent) UII (6) 1,071 1,284 Generation (8) 1,144 -- Other 13 16 Payables to affiliates (current) Generation decommissioning (7) 11 59 Generation (1, 2) 162 339 BSC (3) 13 18 Payables to affiliates (noncurrent) Generation decommissioning obligation (7) 33 218 Other 6 6 Shareholders' equity - receivable from parent (9) 509 615 ----------------------------------------------------------------------------------------------------------------------- (1) ComEd provides electric, transmission, and other ancillary services to Generation and Enterprises. (2) Effective January 1, 2001, ComEd entered into a PPA with Generation. See Note 9 - Commitments and Contingencies for further information regarding the PPA. The Generation payable primarily consists of services related to the PPA. (3) ComEd receives a variety of corporate support services from Exelon Business Services Company (BSC), including legal, human resource, financial, information technology, supply management and corporate governance services. A portion of such services, provided at cost including applicable overhead, is capitalized. (4) ComEd has contracted with Exelon Services (an Enterprises company) to provide energy conservation services to ComEd customers. (5) ComEd receives substation and transmission engineering and construction services under contracts with InfraSource. A portion of such services is capitalized. 64 (6) ComEd has a note and interest receivable with a variable interest rate of the one month forward LIBOR rate plus 50 basis points from Unicom Investments Inc. (UII) relating to the December 1999 fossil plant sale. This note matures in December 2011. (7) ComEd has 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. (8) ComEd has a receivable from Generation related to a regulatory liability as a result of the adoption of SFAS No. 143. For further information see Note 2 - New Accounting Principles and Accounting Changes. (9) ComEd has a non-interest bearing receivable from Exelon related to Exelon's agreement to fund future income tax payments resulting from the collection by ComEd of instrument funding changes. The receivable is expected to be settled over the years 2003 through 2008. (10) ComEd participates in Exelon's intercompany money pool. ComEd earns interest on its investments in the money pool at a market rate of interest.
Exelon and PECO Exelon and PECO's financial statements reflect related-party transactions with its unconsolidated financing subsidiary, PECO Trust IV, as reflected in the tables below.
Three Months Nine Months ------------ ----------- Ended September 30, Ended September 30, ------------------- ------------------- 2003 2002 2003 2002 ------------------------------------------------------------------------------------------------------------------ Interest expense to PECO Trust IV (1) $ 2 $ -- $ 2 $ -- ------------------------------------------------------------------------------------------------------------------ September 30, 2003 December 31, 2002 ------------------------------------------------------------------------------------------------------------------ Note receivable from PECO Trust IV (long-term) (1) $ 1 $ -- Debt to PECO Trust IV (1) 103 -- ------------------------------------------------------------------------------------------------------------------ (1) As of July 1, 2003, PECO Trust IV, a wholly owned financing subsidiary of PECO created in May 2003, is no longer consolidated within the financial statements of Exelon or PECO pursuant to the provisions of FIN No. 46. Amounts owed to PECO Trust IV are recorded as long-term debt to affiliate within the Consolidated Balance Sheets, and interest owed to PECO Trust IV is recorded as interest expense within the Consolidated Statements of Income and Comprehensive Income. A note receivable was recorded as of July 1, 2003 representing amounts owed to PECO from PECO Trust IV related to debt issuance costs paid by PECO. PECO holds $3 million of the common securities issued by PECO Trust IV.
65 PECO In addition to the transactions described above, 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, ------------------- ------------------- 2003 2002 2003 2002 ------------------------------------------------------------------------------------------------------------------ Operating revenues from affiliate Generation (1) $ 3 $ 3 $ 8 $ 9 Other -- -- 1 -- Purchased power from affiliate Generation (2) 421 441 1,101 1,090 Operating & maintenance from affiliates BSC (3) 14 10 36 36 Enterprises (4) -- 5 3 21 Capitalized costs BSC (3) 1 2 6 8 Enterprises (4) 10 6 23 16 Cash dividends paid to parent 79 85 244 255 ------------------------------------------------------------------------------------------------------------------ September 30, 2003 December 31, 2002 ------------------------------------------------------------------------------------------------------------------ Payables to affiliates (current) Generation (2) $ 123 $ 124 BSC (3) 18 26 Enterprises (4) -- 19 Other 1 1 Payable to affiliate (noncurrent) Generation (5) 7 -- Shareholders' equity - receivable from parent (6) 1,661 1,758 ------------------------------------------------------------------------------------------------------------------ (1) PECO provides energy to Generation for Generation's own use. (2) Effective January 1, 2001, PECO entered into a PPA with Generation. See Note 9 - Commitments and Contingencies for further information regarding the PPA. (3) PECO receives a variety of corporate support services from BSC, including legal, human resource, financial, information technology, supply management and corporate governance services. Such services are provided at cost, including applicable overhead. Some of these costs are capitalized. (4) PECO receives services from Enterprises for construction, which are capitalized, and the implementation of automated meter reading technology, which are expensed. (5) PECO has a payable to Generation related to a regulatory asset as a result of the adoption of SFAS No. 143. See Note 2 - New Accounting Principles and Accounting Changes for further discussion of the adoption of SFAS No. 143. (6) PECO has a non-interest bearing receivable from Exelon related to Exelon's agreement to fund future income tax payments resulting from the collection of PECO's stranded costs recovery. The receivable is expected to be settled over the years 2003 through 2010.
66 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, ------------------- ------------------- 2003 2002 2003 2002 ------------------------------------------------------------------------------------------------------------------ Purchased power from AmerGen (1) $ 133 $ 104 $ 310 $ 220 Interest income from AmerGen (2) -- 1 1 2 Interest expense to Sithe (3) 2 -- 7 -- Services provided to AmerGen (4) 50 16 85 46 Services provided to Sithe (5) -- -- 1 1 Services provided by Sithe (6,7) -- 3 5 5 ------------------------------------------------------------------------------------------------------------------ September 30, 2003 December 31, 2002 ------------------------------------------------------------------------------------------------------------------ Net receivable from AmerGen (1,2,4) $ -- $ 39 Net payable to AmerGen (1,2,4) 22 -- Net receivable from Sithe (3,5,6,7) 1 -- Net payable to Sithe (3,5,6,7) -- 7 Note payable to Sithe (3) 326 534 ------------------------------------------------------------------------------------------------------------------ (1) Generation has entered into PPAs dated June 26, 2003, December 18, 2001, and November 22, 1999 with AmerGen. Generation has agreed to purchase 100% of the energy generated by Oyster Creek through April 9, 2009. Generation has agreed to purchase all the energy from Unit No. 1 at Three Mile Island Nuclear Station from January 1, 2002 through December 31, 2014. Generation agreed to purchase all of the residual energy from Clinton not sold to Illinois Power through December 31, 2004. Currently, the residual output is approximately 31% of the total output of Clinton, but will increase to 100% and the obligation will continue until the Clinton NRC license expires in 2026. See Note 15 - Subsequent Events regarding Generation's agreement to purchase British Energy's interest in AmerGen. (2) In February 2002, Generation entered into an agreement to loan AmerGen up to $75 million at an interest rate equal to the one-month London Interbank Offering Rate plus 2.25%. In July 2002, the limit of the loan agreement was increased to $100 million and the maturity date was extended to July 1, 2003. The principal balance of the loan was paid in full during the second quarter of 2003. (3) Under the terms of the agreement to acquire Exelon New England dated November 1, 2002, Generation issued a $534 million note due on June 18, 2003 to Sithe. In June 2003, the principal of the note was increased $2 million, and the payment terms of the note were changed. Generation paid $210 million of principal in June 2003, $236 million of the principal is to be paid by December 1, 2003 or upon change of control of Generation, and the balance of the note is to be paid by December 1, 2004 or upon change of control of Generation. The note bears interest at the rate equal to LIBOR plus 0.875%. Interest accrued on the note as of September 30, 2003 was less than $1 million. (4) Under a service agreement dated March 1, 1999, Generation provides certain operation and support services to the nuclear facilities owned by AmerGen. This service agreement has an indefinite term and may be terminated by Generation or AmerGen with 90 days notice. Generation is compensated for these services at cost. (5) Under a service agreement dated December 18, 2000, Generation provides engineering and environmental services for fossil facilities owned by Sithe and for certain developmental projects. Generation is compensated for these services at cost. (6) Under a service agreement dated December 18, 2000, Sithe provides Generation fuel and project development services. Sithe is compensated for these services at cost. (7) Under a service agreement dated November 1, 2002, Sithe provides Generation certain transition services related to the transition of the Exelon New England asset acquisition, which occurred November 2002.
67 Generation In addition to the transactions described above, Generation's financial statements reflect a number of related-party transactions as reflected in the tables below.
Three Months Ended September 30, Nine Months Ended September 30, -------------------------------- ------------------------------- 2003 2002 2003 2002 ------------------------------------------------------------------------------------------------------------------ Operating revenues from affiliates ComEd (1) $ 885 $ 949 $ 1,984 $ 2,029 PECO (1) 421 441 1,101 1,090 Exelon Energy Company (2) 51 73 161 190 Purchased power from affiliates ComEd (4) 11 -- 31 13 PECO (4) -- -- -- 1 Exelon Energy Company (4) -- 6 9 13 Operating & maintenance from affiliates ComEd (4) 5 4 11 11 PECO (4) 3 3 8 8 BSC (6) 46 33 117 117 Interest expense - affiliate Exelon intercompany money pool (8) 1 -- 2 -- Exelon (3) -- 1 2 3 Cash distribution paid to member 71 30 116 30 ------------------------------------------------------------------------------------------------------------------ September 30, 2003 December 31, 2002 ------------------------------------------------------------------------------------------------------------------ Receivables from affiliates (current) ComEd (1) $ 162 $ 339 ComEd decommissioning receivable (7) 11 59 PECO (1) 123 124 BSC (6) -- 14 Exelon Energy Company (2) 16 19 Other 1 -- Receivables from affiliates (noncurrent) ComEd decommissioning receivable (7) 33 218 PECO decommissioning receivable (5) 7 -- Other -- 2 Payables to affiliates (current) Exelon (3) 2 3 BSC (6) 43 -- Payable to affiliate (noncurrent) ComEd decommissioning (5) 1,144 -- Notes payable to affiliate - Exelon (3) 4 329 Notes payable to affiliates - Exelon intercompany money pool (8) 147 -- ------------------------------------------------------------------------------------------------------------------ (1) Effective January 1, 2001, Generation entered into PPAs with ComEd and PECO. See Note 9 - Commitments and Contingencies for further information on the PPAs. In 2002, Generation recorded transmission expense to ComEd of $18 million and $17 million in the three and nine months, respectively, as a reduction of revenue. (2) Generation sells power to Exelon Energy Company (an Enterprises company). (3) Generation has a payable to Exelon related to certain compensation plans. 68 (4) Generation purchases power from PECO for Generation's own use, buys back excess power from Exelon Energy Company and purchases transmission and ancillary services from ComEd and PECO. In 2002, Generation recorded transmission expense to ComEd of $18 million and $17 million in the three and nine months, respectively, as a reduction of revenue. (5) Generation has a long-term payable to ComEd and a long-term receivable from PECO as a result of the adoption of SFAS No. 143. See Note 2 - New Accounting Principles and Accounting Changes for further discussion of the adoption of SFAS No. 143. (6) Generation receives a variety of corporate support services from BSC, including legal, human resource, financial, information technology, supply management and corporate governance services. Such services are provided at cost, including applicable overhead. Some third-party reimbursements due Generation are recovered through BSC. (7) Generation has a short-term and had a long-term receivable from ComEd, primarily representing ComEd's legal requirements to remit collections of nuclear decommissioning costs from customers to Generation resulting from the 2001 corporate restructuring. (8) Generation participates in Exelon's intercompany money pool. Generation pays interest on its borrowings from the money pool at a market rate of interest.
14. SUPPLEMENTAL FINANCIAL INFORMATION (Exelon, ComEd and PECO)
September 30, December 31, ComEd 2003 2002 ------------------------------------------------------------------------------------------------------------------ Regulatory Assets (Liabilities) Nuclear decommissioning (see Note 2 - New Accounting Principles and Accounting Changes) $ (1,144) $ -- Nuclear decommissioning costs for retired plants -- 248 Recoverable transition costs 141 175 Reacquired debt costs and interest rate swap settlements 163 84 Recoverable deferred income taxes (64) (68) Other 24 8 ------------------------------------------------------------------------------------------------------------------ Total $ (880) $ 447 ================================================================================================================== September 30, December 31, PECO 2003 2002 ------------------------------------------------------------------------------------------------------------------ Regulatory Assets Competitive transition charge $ 4,381 $ 4,639 Recoverable deferred income taxes 752 729 Non-pension postretirement benefits 60 64 Reacquired debt costs 49 53 Nuclear decommissioning and decontamination funds 27 32 Nuclear decommissioning (see Note 2 - New Accounting Principles and Accounting Changes) 7 -- MGP regulatory asset (see Note 9 - Commitments and Contingencies) 16 20 Compensated absences 9 6 Postemployment benefits 3 3 ------------------------------------------------------------------------------------------------------------------ Long-term regulatory assets 5,304 5,546 Deferred energy costs (current asset) 64 31 ------------------------------------------------------------------------------------------------------------------ Total $ 5,368 $ 5,577 ==================================================================================================================
69 Exelon's long-term regulatory assets and liabilities as of September 30, 2003 were $5,304 million and $880 million, respectively. Exelon's long-term regulatory assets as of December 31, 2002 were $5,993 million. ComEd's depreciation, which is included in cost of service for rate purposes, includes an estimated cost of dismantling and removing plant from service upon retirement. ComEd has estimated future removal costs embedded in accumulated depreciation related to rate-regulated plant assets were approximately $1.2 billion at September 30, 2003 in accordance with regulatory accounting practice. PECO has historically incurred removal costs in excess of amounts recovered in rates. As such, PECO does not have any amounts embedded in accumulated depreciation as of September 30, 2003. 15. SUBSEQUENT EVENTS (Exelon, ComEd and Generation) ComEd On October 7, 2003, ComEd redeemed $150 million of First Mortgage Bonds, at a redemption price of 103.765% of the principal amount, plus accrued interest. The bonds, which carried an interest rate of 7.750%, were refinanced with long-term debt issued on August 25, 2003. Generation On October 1, 2003, Generation notified Midwest Generation of its exercise of certain termination options under the existing Collins Generation Station and Peaking Unit Purchase Power Agreements, releasing 303 MWs for 2004, the fifth and final year of the contract. With the exercise of the termination options on the peaking plants in addition to the exercise of the options on the coal plants in June 2003 (see Note 9 - Commitments and Contingencies for further information regarding the Coal Generation PPA), the contract with Midwest Generation is finalized for 2004. Generation will take 1,696 MWs of non-option coal capacity, 687 MWs of option coal capacity, 1,084 MWs of Collins Station capacity and 392 MWs of peaking capacity from Midwest Generation in 2004. In total, Generation has retained 3,859 MWs of capacity under the terms of the three existing PPAs with Midwest Generation. On October 2, 2003, Mitsubishi Heavy Industries, LTD (MHI) and Mitsubishi Heavy Industries of America (MHIA) filed a New York state court action against Exelon Mystic Development, LLC (Mystic) and Exelon Fore River Development, LLC (Fore River) seeking to enjoin these indirect subsidiaries of Generation from drawing upon letters of credit posted to guarantee MHI's performance under certain gas turbine contracts. MHI and MHIA also seek $34 million from these entities in connection with work performed on these contracts. Generation believes that Mystic and Fore River's contracts with MHI and MHIA have been assigned to Raytheon and that the claims against the Generation entities are without merit. On October 10, 2003, Exelon executed an agreement to purchase British Energy's 50% interest in AmerGen for $276.5 million. The transaction is expected to close in the first half of 2004. The purchase 70 price matched the offer by FPL Energy, which announced on September 11, 2003 that it intended to buy British Energy's share of AmerGen. Under the AmerGen limited liability company operating agreement between Exelon and British Energy, either party can exercise a right of first refusal by matching any bona fide third-party offer agreed to by the other member. See Note 4 - Unconsolidated Investments for additional information regarding AmerGen. 71 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Dollars in millions, unless otherwise noted) GENERAL Exelon Corporation (Exelon), a registered public utility holding company, through its subsidiaries, operates in three business segments: o Energy Delivery, whose businesses include the regulated sale of electricity and distribution and transmission services by Commonwealth Edison Company (ComEd) in northern Illinois and PECO Energy Company (PECO) in southeastern Pennsylvania and the sale of natural gas and distribution services by PECO in the Pennsylvania counties surrounding the City of Philadelphia. o Generation, consisting of Exelon Generation Company, LLC's (Generation) owned and contracted for electric generating facilities, energy marketing operations, and equity interests in Sithe Energies, Inc. (Sithe) and AmerGen Energy Company, LLC (AmerGen). o Enterprises, consisting of Exelon Enterprises Company, LLC's (Enterprises) competitive retail energy sales, energy and infrastructure services, communications and other investments (primarily weighted towards the energy services and retail services industries). See Note 7 of the Condensed Combined Notes to Consolidated Financial Statements for further segment information. CRITICAL ACCOUNTING ESTIMATES Management of each of the registrants makes a number of significant estimates, assumptions and judgments in the preparation of their financial statements. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Critical Accounting Estimates" in the 2002 Form 10-K for a discussion of the estimates and judgments necessary in the registrants' accounting for derivative instruments, regulatory assets and liabilities, nuclear decommissioning, asset impairments, defined benefit pension and other postretirement welfare benefits, stock-based compensation plans, business combinations, unbilled energy revenues, long-term contract accounting and environmental costs. Set forth below is an update to the 2002 Form 10-K. Asset Impairments (Exelon, ComEd, PECO and Generation) Exelon evaluates the carrying value of long-lived assets, excluding goodwill, when circumstances indicate the carrying value of those assets may not be recoverable. The review of assets for impairment requires significant assumptions about operating strategies and estimates of future cash flows. A variation in an assumption could result in a different conclusion regarding the realizability of the asset. The potential impact of recognizing an impairment on the 72 assets reported within the Consolidated Balance Sheets, as well as on net income, could be and has been material to the consolidated financial statements. During the second quarter of 2003, Exelon recorded an impairment charge related to investments held by Enterprises of approximately $35 million (before income taxes). Management determined that an other-than-temporary decline in the fair value of these investments had occurred and considered various factors in the decision to record an impairment of the investments, including recent third-party valuations of the investments. The other-than-temporary determination was significant because any increase in fair value of these investments will not be recoverable until they are sold. Had management determined otherwise, no impairment charge would have been recorded. The valuations of these investments, which form the basis for the impairment charge, required assumptions regarding the future earnings potential of these investments. Actual results from these investments have fluctuated in the past and are expected to continue. During the first and third quarters of 2003, Generation recorded impairment charges totaling $255 million (before income taxes) associated with a decline in the fair value of its investment in Sithe. In reaching that decision, management considered various factors, including negotiations to sell its investment in Sithe, which indicated an other-than-temporary decline in fair value. The charges included estimates of potential guarantees under FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others" (FIN No. 45) associated with the sale of the investment, which are subject to change. During the third quarter of 2003, Generation recorded an impairment charge related to the long-lived assets of Exelon Boston Generating, LLC (EBG), an indirect subsidiary of Generation, of $945 million (before income taxes) due to its decision to transition out of the ownership of EBG. See Note 3 of the Condensed Combined Notes to Consolidated Financial Statements for further information. In determining the amount of the impairment charge, management compared the carrying value of EBG's long-lived assets to their estimated fair value. The fair value was determined using the estimated future discounted cash flows from those assets. Forecasted cash flows incorporated assumptions relative to the period of time that Generation will continue to own and operate EBG. The time required to fully transition out of ownership of EBG is uncertain and subject to change. Exelon used a probability-weighted approach for developing estimates of future cash flows with the most likely scenarios weighted higher. A change in Exelon's probability assessment for each scenario could have a significant impact on the estimated future cash flows. Exelon utilized a discount rate based upon valuations of the business developed at the purchase date. Goodwill (Exelon, ComEd) ComEd had approximately $4.7 billion of goodwill recorded at September 30, 2003. The goodwill will remain at its recorded amount unless it is determined to be impaired, which is based upon an analysis of expected future cash flows. Exelon and ComEd perform an assessment for impairment of their goodwill at least annually, or more frequently, if events or circumstances indicate that goodwill might be impaired. The annual goodwill impairment assessment will be performed in the fourth quarter of 2003. Discounted cash flow models will 73 be used to determine the fair value of the Reporting Units in the annual assessment. The discounted cash flow models include significant assumptions regarding revenue growth rates, general expense escalation rates, impacts of The Exelon Way, allowed return on equity and a risk-adjusted discount rate. These assumptions are subject to change from period to period. If an impairment is determined at ComEd, the amount of the impaired goodwill will be written-off and expensed at ComEd. Under current regulations, a significant goodwill impairment may restrict ComEd's ability to pay dividends. ComEd is pursuing various solutions to address ComEd's ability to pay dividends if a significant goodwill impairment exists. Based upon Illinois legislation, goodwill impairments are excluded from determining whether or not the earnings cap amount has been met or exceeded. A goodwill impairment charge at ComEd may not affect Exelon's results of operations. Exelon's goodwill impairment test would include assessing the cash flows of the entire Energy Delivery business segment (a single Reporting Unit, which includes PECO, as defined under current accounting guidance), not just ComEd's cash flows. In connection with an agreement to sell certain businesses of InfraSource, Inc. (InfraSource), Exelon recorded an impairment charge during the second quarter of 2003 of approximately $48 million (before minority interest and income taxes) related to the goodwill recorded within the InfraSource Reporting Unit. Management of Enterprises primarily considered the negotiated sales price of InfraSource in determining the amount of the goodwill impairment charge. This charge was partially offset by a gain recorded during the third quarter of 2003 upon the closing of the sale. Severance Accounting (Exelon, ComEd, PECO and Generation) As part of the implementation of The Exelon Way, Exelon has identified 1,042 positions for elimination by the end of 2004 and anticipates identifying additional positions for elimination in 2005 and 2006. Exelon will provide severance benefits to terminated employees pursuant to pre-existing severance plans primarily based upon each individual employee's years of service with Exelon and compensation level. The registrants have recorded charges in the third quarter of 2003 related to severance benefits that are considered probable and can be reasonably estimated in accordance with Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 112, "Employer's Accounting for Postemployment Benefits, an amendment of FASB Statements No. 5 and 43" (SFAS No. 112). A significant assumption in calculating the severance charge was the determination of the number of positions to be eliminated. The registrants based their estimates on management's current plans and its ability to determine the appropriate staffing levels to effectively operate the businesses. Exelon anticipates incurring further costs associated with The Exelon Way upon identifying additional positions to be eliminated. These costs will be recorded in the period in which the costs can be reasonably estimated. Defined Benefit Pension and Other Postretirement Welfare Benefits (Exelon, ComEd, PECO and Generation) During the third quarter of 2003, Exelon announced a benefit plan amendment that reduced the benefits attributable to prior service through increased retiree cost-sharing for medical coverage. Furthermore, in connection with the implementation of The Exelon Way 74 during the third quarter of 2003, the overall reduction in active employees triggered a curtailment charge related to certain defined benefit pension and postretirement welfare benefit plans. Curtailment accounting applies when an event occurs that significantly reduces the expected years of future service of active plan participants. The expected reduction in plan participants ranged between five and ten percent of the total eligible participants of each plan that qualified for curtailment accounting. The plan amendment and curtailments resulted in remeasurements of the plan obligations as of August 1, 2003. The total increase in net periodic benefit costs due to the curtailments recorded during the third quarter of 2003 was $26 million. Pension and postretirement costs are anticipated to total $234 million in 2003, including the effects of the amendment and curtailments, compared to $111 million in 2002. The selection of key actuarial assumptions utilized in the measurement of the plan obligations drives the results of the analysis and the resulting charges. The long-term expected rate of return on plan assets (EROA) assumption used in calculating pension cost was 9.00% at August 1, 2003 compared to 9.50% at December 31, 2002. The EROA assumption used in calculating the other postretirement benefit obligation ranged from 7.52% to 8.68% at August 1, 2003 compared to 8.80% at December 31, 2002. A lower EROA is used in the calculation of other postretirement benefit costs as the other postretirement benefit trust activity is partially taxable while the pension trust activity is non-taxable. The Moody's Aa Corporate Bond Index was used as a basis in selecting the discount rate, using 6.60% at August 1, 2003 compared to 6.75% at December 31, 2002 in the estimate of pension expense and other postretirement benefit costs. The reduction in discount rate is due to the decline in Moody's Aa Corporate Bond Index during 2003. Real Estate Tax Assessments (Exelon, PECO and Generation) PECO and Generation are challenging real estate taxes assessed on nuclear plants since 1997. PECO is involved in litigation in which it is contesting Pennsylvania Public Utility Realty Tax Act of March 4, 1971, as amended (PURTA) taxes assessed in 1997 and has appealed local real estate assessments for 1998 and 1999 on its formerly owned Limerick Generating Station (Montgomery County, PA) (Limerick) and Peach Bottom Atomic Power Station (York County, PA) (Peach Bottom) plants. Generation is involved in real estate tax appeals for 2000 through 2003, also regarding the valuation of its Limerick and Peach Bottom plants, its Quad Cities Station (Rock Island County, IL) and, through its ownership interest in AmerGen, Three Mile Island (Dauphin County, PA). During the third quarter of 2003, upon completion of updated nuclear plant appraisal studies, PECO and Generation recorded reductions of $58 million and $15 million, respectively, to reserves recorded for exposures associated with the real estate taxes. While PECO and Generation believe the resulting reserve balances as of September 30, 2003 reflect the most likely probable expected outcome of the litigation and appeals proceedings in accordance with SFAS No. 5, "Accounting for Contingencies," the ultimate outcome of such matters could result in additional unfavorable or favorable adjustments to the consolidated financial statements of PECO or Generation, and such adjustments could be material. 75 Nuclear Decommissioning (Exelon and Generation) Generation adopted SFAS No. 143, "Asset Retirement Obligations" (SFAS No. 143) on January 1, 2003. SFAS No. 143 primarily affected the accounting for the decommissioning of Generation's nuclear generating plants and changed the method used to report the decommissioning obligation. Exelon and Generation recorded income of $112 million and $108 million (net of income taxes), respectively, as a cumulative effect of a change in accounting principle in connection with their adoptions of this standard in the first quarter of 2003. To estimate the fair value of the decommissioning obligation, management used a probability-weighted, discounted cash flow model with multiple scenarios. Key assumptions used in the determination of fair value included decommissioning cost studies prepared by a third party, annual cost escalation studies to determine escalation factors based on inflation indices, and the assignment of probabilities to various cost levels and various timing scenarios. These timing scenarios incorporated current license lives and life extensions and the timing of Department of Energy (DOE) acceptance for disposal of spent nuclear fuel. The estimated probability-weighted cash flows using these various scenarios were discounted using credit-adjusted, risk-free rates applicable to the various businesses. Significant changes in the assumptions underlying the items discussed above could materially affect the balance sheet amounts and future costs related to decommissioning recorded in the consolidated financial statements. Under SFAS No. 143, the fair value of the nuclear decommissioning obligation will continue to be adjusted on an ongoing basis as the model input factors change. NEW ACCOUNTING PRONOUNCEMENTS See Note 2 of the Condensed Combined Notes to Consolidated Financial Statements for discussion of new accounting pronouncements. EXELON CORPORATION ------------------ RESULTS OF OPERATIONS Three Months Ended September 30, 2003 Compared To Three Months Ended September 30, 2002 Net Income and Earnings Per Share Exelon's net loss for the three months ended September 30, 2003 was $102 million compared to net income of $551 million in 2002. Loss per diluted common share for the three months ended September 30, 2003 was $0.31 compared to income per diluted share of $1.70 in 2002. The overall decrease in income of $653 million resulted from charges recorded in 2003 associated with the impairment of the long-lived assets of EBG, severance and related postretirement health and welfare benefits accruals and pension and postretirement curtailment costs associated with The Exelon Way, and a decline in the fair value of Generation's investment in Sithe. These charges were partially offset by the reduction of property tax reserves at PECO and Generation and a gain recognized at Enterprises due to the sale of InfraSource during 2003. 76 Results of Operations by Business Segment Exelon evaluates its performance on a business segment basis. The comparisons presented under this heading are comparisons of operating results and other statistical information for the three months ended September 30, 2003 to operating results and other statistical information for the same period in 2002. These results reflect intercompany transactions, which are eliminated in Exelon's consolidated financial statements. Exelon corporate operations provide the business segments a variety of support services including legal, human resources, financial, information technology, supply management and corporate governance services. These costs are allocated to the business segments. Additionally, the results of Exelon's corporate operations include costs for strategic long-term planning, certain governmental affairs, and interest costs and income from various investment and financing activities. Net Income (Loss) by Business Segment
Three Months Ended September 30, -------------------------------- 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Energy Delivery $ 303 $ 370 $ (67) (18.1%) Generation (428) 163 (591) n.m. Enterprises 16 15 1 6.7% Corporate 7 3 4 133.3% ------------------------------------------------------------------------------------------------- Total $ (102) $ 551 $ (653) (118.5%) ================================================================================================= n.m. - not meaningful
Results of Operations - Energy Delivery
Three Months Ended September 30, -------------------------------- Energy Delivery 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Operating revenues $ 2,886 $ 3,162 $ (276) (8.7%) Revenue, net of purchased power & fuel expense 1,485 1,637 (152) (9.3%) Operating income 664 812 (148) (18.2%) Income before income taxes 479 591 (112) (19.0%) Net income 303 370 (67) (18.1%) -------------------------------------------------------------------------------------------------------------------
The changes in Energy Delivery's revenue, net of purchased power and fuel expense, for the three months ended September 30, 2003 compared to the same period in 2002, included the following: o unfavorable weather impacts of $75 million, primarily the result of cooler summer weather, o unfavorable variance of $52 million due to changes in customer rates due to lower competitive transition charge (CTC) collections at ComEd, o unfavorable rate mix of $21 million at PECO as a result of changes in monthly usage patterns by all customer classes, o unfavorable pricing changes of $20 million related to ComEd's purchased power agreement (PPA) with Generation, 77 o unfavorable variance of $16 million under the ComEd PPA with Generation related to decommissioning collections associated with the adoption of SFAS No. 143 in 2003, which had no impact on net income as these amounts were recorded in depreciation and amortization expense in 2002 (see Note 2 of the Condensed Combined Notes to Consolidated Financial Statements), o net favorable change of $8 million at ComEd as a result of 2002 third-party energy reconciliations, o lower PJM ancillary charges at PECO resulting in a favorable variance of $4 million, and o net favorable changes due to customer choice of $3 million. The changes in operating income, other than changes in revenue, net of purchased power and fuel expense, for the three months ended September 30, 2003 compared to the same period in 2002, included the following: o decreased costs of $67 million associated with PECO's real estate taxes, including a reduction of reserves for real estate taxes of $58 million in 2003, o decreased payroll expense of $22 million due to fewer employees, o lower amortization of ComEd's recoverable transition costs of $21 million in 2003, o a 2002 increase in the reserve for manufactured gas plant (MGP) investigation and remediation of $17 million, net of 2003 increases, o reduction of amortization expense of $16 million at ComEd for nuclear decommissioning of retired plants due to the adoption of SFAS No. 143 (see Note 2 of the Condensed Combined Notes to Consolidated Financial Statements), which had no impact on net income as these amounts were recorded as purchased power in 2003, o decreased costs of $10 million associated with the initial implementation of automated meter reading services at PECO in 2002, o unfavorable variance of $101 million due to severance and related postretirement health and welfare benefits accruals and pension and postretirement curtailment costs associated with The Exelon Way, o unfavorable variance of $30 million due to higher storm-related costs, o unfavorable variance of $9 million due to employee fringe benefits, and o $8 million in 2003 at ComEd for use tax payments for periods prior to the merger of Exelon, Unicom Corporation and PECO on October 20, 2000 (Merger). The changes in other income and deductions for the three months ended September 30, 2003 compared to the same period in 2002 included a reduction in interest expense primarily related to a decrease of $21 million attributable to less outstanding debt and refinancing of existing debt at lower interest rates and a reduction of $12 million as a result of a 2002 reserve accrual for a potential plant disallowance from an audit performed in conjunction with ComEd's delivery services rate case. This $12 million was reversed in March 2003 as a result of the March 3, 2003 agreement. See the Contractual Obligations, Commercial Commitments and Off-Balance Sheet Obligations section below for further information regarding the agreement. Energy Delivery's effective income tax rate was 36.7% for the three months ended September 30, 2003, compared to 37.4% for the same period in 2002. 78 Energy Delivery Operating Statistics and Revenue Detail Energy Delivery's electric sales statistics and revenue detail were as follows:
Three Months Ended September 30, -------------------------------- Retail Deliveries - (in gigawatthours (GWhs))(1) 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Bundled Deliveries (2) Residential 11,530 12,543 (1,013) (8.1%) Small Commercial & Industrial 7,502 8,095 (593) (7.3%) Large Commercial & Industrial 5,552 6,079 (527) (8.7%) Public Authorities & Electric Railroads 1,486 1,836 (350) (19.1%) ----------------------------------------------------------------------------------------------------- Total Bundled Deliveries 26,070 28,553 (2,483) (8.7%) ----------------------------------------------------------------------------------------------------- Unbundled Deliveries (3) Alternative Energy Suppliers ---------------------------- Residential 258 371 (113) (30.5%) Small Commercial & Industrial 2,241 1,794 447 24.9% Large Commercial & Industrial 3,142 2,428 714 29.4% Public Authorities & Electric Railroads 426 299 127 42.5% ----------------------------------------------------------------------------------------------------- 6,067 4,892 1,175 24.0% ----------------------------------------------------------------------------------------------------- PPO (ComEd Only) ---------------- Small Commercial & Industrial 884 782 102 13.0% Large Commercial & Industrial 896 1,249 (353) (28.3%) Public Authorities & Electric Railroads 428 345 83 24.1% ----------------------------------------------------------------------------------------------------- 2,208 2,376 (168) (7.1%) ----------------------------------------------------------------------------------------------------- Total Unbundled Deliveries 8,275 7,268 1,007 13.9% ----------------------------------------------------------------------------------------------------- Total Retail Deliveries 34,345 35,821 (1,476) (4.1%) ===================================================================================================== (1) One GWh is the equivalent of one million kilowatthours (kWh). (2) Bundled service reflects deliveries to customers taking electric generation service under tariffed rates. (3) Unbundled service reflects customers electing to receive electric generation service from an alternative energy supplier or ComEd's Power Purchase Option (PPO).
79
Three Months Ended September 30, -------------------------------- Electric Revenue 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Bundled Revenues (1) Residential $ 1,226 $ 1,318 $ (92) (7.0%) Small Commercial & Industrial 698 757 (59) (7.8%) Large Commercial & Industrial 373 402 (29) (7.2%) Public Authorities & Electric Railroads 102 125 (23) (18.4%) ----------------------------------------------------------------------------------------------------- Total Bundled Revenues 2,399 2,602 (203) (7.8%) ----------------------------------------------------------------------------------------------------- Unbundled Revenues (2) Alternative Energy Suppliers ---------------------------- Residential 20 32 (12) (37.5%) Small Commercial & Industrial 62 60 2 3.3% Large Commercial & Industrial 46 67 (21) (31.3%) Public Authorities & Electric Railroads 8 10 (2) (20.0%) ----------------------------------------------------------------------------------------------------- 136 169 (33) (19.5%) ----------------------------------------------------------------------------------------------------- PPO (ComEd Only) ---------------- Small Commercial & Industrial 65 57 8 14.0% Large Commercial & Industrial 56 74 (18) (24.3%) Public Authorities & Electric Railroads 26 19 7 36.8% ----------------------------------------------------------------------------------------------------- 147 150 (3) (2.0%) ----------------------------------------------------------------------------------------------------- Total Unbundled Revenues 283 319 (36) (11.3%) ----------------------------------------------------------------------------------------------------- Total Electric Retail Revenues 2,682 2,921 (239) (8.2%) ----------------------------------------------------------------------------------------------------- Wholesale and Miscellaneous Revenue (3) 151 174 (23) (13.2%) ----------------------------------------------------------------------------------------------------- Total Electric Revenue $ 2,833 $ 3,095 $ (262) (8.5%) ===================================================================================================== (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 competitive transition 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. Revenue from customers choosing ComEd's PPO includes an energy charge at market rates, transmission and distribution charges and a CTC. Transmission charges received from alternative energy suppliers are included in wholesale and miscellaneous revenue. (3) Wholesale and miscellaneous revenues include transmission revenue, sales to municipalities and other wholesale energy sales.
The differences in electric retail revenues for the three months ended September 30, 2003 as compared to the same period in 2002 were attributable to the following: Variance -------------------------------------------------------------------------- Weather $ (161) Rate changes (52) Customer choice (50) Rate mix (21) Volume 41 Other effects 4 -------------------------------------------------------------------------- Electric retail revenue $ (239) ========================================================================== o Weather. The demand for electricity is impacted by weather conditions. Very warm weather in summer months and very cold weather in other months are 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, 2003 was unfavorable compared to the same period in 2002 as a result of 80 cooler summer weather in 2003. Cooling degree-days in the ComEd and PECO service territories were 25% lower and 11% lower, respectively, in 2003 as compared to 2002. o Rate Changes. The decrease in revenues attributable to rate changes reflects decreased collections of $81 million in CTCs in 2003 by ComEd due to a decrease in CTC rates effective June 1, 2003, partially offset by higher wholesale market prices which increased energy revenue received under ComEd's PPO by $29 million. o Customer Choice. All ComEd and PECO customers have the choice to purchase energy from alternative suppliers. This affects revenues from the sale of energy but not revenue from the delivery of electricity since ComEd and PECO continue to deliver electricity that is purchased from alternative suppliers. For the three months ended September 30, 2003 and 2002, 18% and 14%, respectively, of energy delivered to Energy Delivery's customers was provided by alternative electric suppliers. The decrease in electric retail revenues includes a decrease in revenues of $36 million from customers in Illinois electing to purchase energy from an alternative retail electric supplier (ARES) or ComEd's PPO, and a decrease in revenues of $14 million from customers in Pennsylvania selecting an alternative electric generation supplier. The Pennsylvania Utility Commission's (PUC) Final Electric Restructuring Order established market share thresholds (MST) to promote competition. The MST requirements provide that if, as of January 1, 2003, less than 50% of residential and commercial customers have chosen an alternative electric generation supplier, the number of customers sufficient to meet the MST shall be randomly selected and assigned to an alternative electric generation supplier through a PUC determined process. On January 1, 2003, the number of customers choosing an alternative electric generation supplier did not meet the MST. In January 2003, PECO submitted to the PUC an MST plan to meet the 50% threshold requirement for its commercial customers, which was approved by the PUC in February 2003. As of March 31, 2003, an auction had been completed for the commercial customers. In May 2003, the customer enrollment phase was completed, and customers that did not choose to opt out of the program were transferred to the alternative electric generation suppliers. In February 2003, PECO filed a residential customer MST plan, and on May 1, 2003, the PUC approved the plan. The approved plan provides for a two-step process with a total of up to 400,000 residential customers being assigned to winning alternative electric generation supplier bidders: up to 100,000 in July 2003 and another 300,000 in December 2003. The auction for the first phase of the residential program received no supplier bids. Therefore, according to the MST plan requirements, 75% of those customers are required to be added to the auction for the second phase of the residential program for a total of 375,000 customers. In September 2003, the auction for the second phase of the residential customer MST plan resulted in two winning bidders who were awarded an aggregate of 267,000 customers. The selected customers will be transferred during December 2003. No renewable bids were received for any customers. Any customer transferred has the right to return to PECO at any time. PECO does not expect the transfer of customers pursuant to the MST plan to have a material impact on its results of operations, financial position or cash flows. o Rate Mix. Revenues related to changes in rate mix at PECO decreased $21 million due to changes in monthly usage patterns in all customer classes for the three months ended September 30, 2003 as compared to the same period in 2002. 81 o Volume. Revenues from higher delivery sales, exclusive of the effect of weather, increased $40 million at ComEd due to an increased number of customers and increased usage per customer, primarily residential and small commercial and industrial. Revenues from delivery sales, exclusive of the effect of weather, increased $1 million at PECO. Energy Delivery's gas sales statistics and revenue detail were as follows:
Three Months Ended September 30, -------------------------------- Deliveries to customers in million cubic feet (mmcf) 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Retail sales 3,498 3,805 (307) (8.1%) Transportation 6,012 7,542 (1,530) (20.3%) ----------------------------------------------------------------------------------------------------- Total 9,510 11,347 (1,837) (16.2%) ===================================================================================================== Three Months Ended September 30, -------------------------------- Revenue 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Retail sales $ 47 $ 43 $ 4 9.3% Transportation 4 5 (1) (20.0%) Resales and other 2 19 (17) (89.5%) ----------------------------------------------------------------------------------------------------- Total $ 53 $ 67 $ (14) (20.9%) =====================================================================================================
The changes in gas retail revenue for the three months ended September 30, 2003 as compared to the same period in 2002, were as follows:
Variance ------------------------------------------------------------------------------------------------------------------- Rate changes $ 6 Volume (2) ------------------------------------------------------------------------------------------------------------------- Total gas retail revenues $ 4 ===================================================================================================================
o Rate Changes. The favorable variance in rate changes is attributable to increases of 15% and 7% in the purchased gas adjustment by the PUC effective March 1, 2003 and June 1, 2003, respectively. The average rate per million cubic feet for the three months ended September 30, 2003 was 18% higher than the same period in 2002. PECO's gas rates are subject to periodic adjustments by the PUC and are designed to recover from or refund to customers the difference between the 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 Volume. Delivery volume was lower in the three months ended September 30, 2003 compared to the same period in 2002 due to decreased retail sales in all customer classes. The reduction in transportation volumes and revenues was primarily the result of lower intercompany deliveries to Generation during the three months ended September 30, 2003 compared to the same period in 2002. 82 Lower resale revenues are attributable to a decrease in off-system sales, exchanges and capacity releases during the three months ended September 30, 2003 compared to the same period in 2002. Results of Operations - Generation
Three Months Ended September 30, -------------------------------- 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Operating revenues $ 2,537 $ 2,213 $ 324 14.6% Revenue, net of purchased power & fuel expense 848 683 165 24.2% Operating income (loss) (706) 187 (893) n.m. Income (loss) before income taxes (708) 265 (973) n.m. Net income (loss) (428) 163 (591) n.m. ------------------------------------------------------------------------------------------------------------------- n.m. - not meaningful
The changes in Generation's revenue, net of purchased power and fuel expense, for the three months ended September 30, 2003 compared to the same period in 2002, included the following: o increased market sales of electricity of $167 million primarily attributable to regional demand and higher prices, and reduced capacity payments as a result of releasing Midwest Generation options, o unfavorable weather conditions in the ComEd and PECO service territories in 2003 resulted in a net volume decrease, partially offset by price increases, resulting in a $121 million unfavorable variance on revenues from Energy Delivery, o increased decommissioning revenue from ComEd of $16 million associated with the adoption of SFAS No. 143, which was effective January 1, 2003, o mark-to-market losses on hedging activities of $18 million in 2003 compared to no gains or losses in 2002, and o increases of $13 million as a result of reduced proprietary trading activity and overall trade portfolio performance. Other significant factors affecting the changes in revenue, net of purchased power and fuel, include the impacts of the plants acquired during 2002 resulting in a net favorable variance of $60 million. In addition, the impacts of lower volumes of purchased power, which were partially offset by higher fuel costs, resulted in a net favorable impact of $49 million. The changes in operating income (loss), other than changes in revenue, net of purchased power and fuel expense, for the three months ended September 30, 2003 compared to the same period in 2002, included the following: o impairment charge of $945 million related to the long-lived assets of EBG, o $46 million in severance and related postretirement health and welfare benefits accruals and pension and postretirement curtailment costs associated with The Exelon Way, o higher costs of $15 million for employee medical, pension and other employee payroll and benefit costs in 2003, o increased operating and maintenance (O&M) costs of $30 million due to the acquisition of Exelon New England in the fourth quarter of 2002, 83 o reduced refueling outage costs of $9 million, resulting from fewer total refueling outage days in 2003, o additional depreciation of $17 million due to capital additions placed in service and plant acquisitions made after the third quarter of 2002, o accretion expense of $60 million recognized in 2003 to increase the asset retirement obligation established at the adoption of SFAS No. 143, and to adjust the earnings impact of certain of the nuclear decommissioning revenues earned from ComEd and PECO, nuclear decommissioning trust fund investment income, income taxes incurred on nuclear decommissioning trust fund activities, partially offset by the elimination of decommissioning expense of $29 million, also as a result of the adoption of SFAS No. 143 (see Note 2 of the Condensed Combined Notes to Consolidated Financial Statements for further discussion of SFAS No. 143), and o decreased property taxes of $15 million as a result of reductions in reserves in the third quarter of 2003 recorded for exposures associated with real estate taxes. The changes in other income and deductions for the three months ended September 30, 2003 compared to the same period in 2002, included the following: o impairment charge of $55 million related to Generation's investment in Sithe, o increased decommissioning trust investment income of $9 million, which is almost entirely offset by accretion expense, net of depreciation, recorded in O&M, and o decreased equity in earnings of unconsolidated affiliates of $34 million due to the purchase of Exelon New England in November 2002, the negative impacts of power trading activity at Sithe and reduced earnings from AmerGen. Generation's effective income tax rate was 39.5% for the three months ended September 30, 2003 compared to 38.5% for the same period in 2002. This increase was primarily attributable to the impact of changes in income before income taxes as a result of the impairment charges recorded in the third quarter of 2003 related to Generation's investment in Sithe and the long-lived assets of EBG. 84 Generation Operating Statistics Generation's sales and the supply of these sales, excluding the trading portfolio, were as follows:
Three Months Ended September 30, -------------------------------- Sales (in GWhs) 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Energy Delivery and Exelon Energy Company 32,237 35,996 (3,759) (10.4%) Market Sales 29,613 21,177 8,436 39.8% ----------------------------------------------------------------------------------------------------- Total Sales 61,850 57,173 4,677 8.2% ===================================================================================================== Three Months Ended September 30, -------------------------------- Supply of Sales (in GWhs) 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Nuclear Generation (1) 30,152 29,817 335 1.1% Purchases - non-trading portfolio (2) 24,062 23,425 637 2.7% Fossil and Hydro Generation 7,636 3,931 3,705 94.3% ----------------------------------------------------------------------------------------------------- Total Supply 61,850 57,173 4,677 8.2% ===================================================================================================== (1) Excluding AmerGen. (2) Including PPAs with AmerGen.
Trading volumes of 11,086 GWhs and 28,455 GWhs for the three months ended September 30, 2003 and 2002, respectively, are not included in the table above. The decrease in trading volume is a result of reduced volumetric and Value-at-Risk (VaR) trading limits in 2003, which are set by Exelon's Risk Management Committee and approved by the Board of Directors. Generation's average margin and other operating data for the three months ended September 30, 2003 and 2002 were as follows:
Three Months Ended September 30, -------------------------------- ($/MWh) 2003 2002 % Change ------------------------------------------------------------------------------------------------------------------- Average Revenue Energy Delivery and Exelon Energy Company $ 41.51 $ 40.56 2.3% Market Sales 38.43 35.50 8.3% Total - excluding the trading portfolio 40.03 38.69 3.5% Average Supply Cost (1) - excluding the trading portfolio $ 27.31 $ 26.66 2.4% Average Margin - excluding the trading portfolio $ 12.72 $ 12.04 5.6% ----------------------------------------------------------------------------------------------------------------- (1) Average supply cost includes purchased power and fuel costs. (2) Including PPAs with AmerGen.
Three Months Ended September 30, -------------------------------- 2003 2002 ------------------------------------------------------------------------------------------------------------------- Nuclear fleet capacity factor (1) 95.3% 93.9% Nuclear fleet production cost per MWh (1) $ 11.69 $ 12.40 Average purchased power cost for wholesale operations per MWh (2) $ 51.53 $ 53.75 ------------------------------------------------------------------------------------------------------------------- (1) Including AmerGen and excluding Salem, which is operated by Public Service Enterprise Group Incorporated (PSE&G). (2) Including PPAs with AmerGen.
The factors below contributed to the overall increase in Generation's average margin for the three months ended September 30, 2003 as compared to the same period in 2002. 85 Generation's average revenue per MWh was affected by: o higher market prices as a result of increased fuel prices, and o increased weighted average on and off-peak prices per MWh for supply agreements with ComEd and PECO. Generation's supply mix changed as a result of: o increased nuclear generation due to a lower number of refueling and unplanned outages during 2003 compared to 2002, o increased fossil generation due to the effect of the Exelon New England plants acquired in November 2002, which in total account for an increase of 3,570 GWhs, and o a new PPA with AmerGen entered into during the second quarter of 2003, resulting in 1,228 GWhs purchased from Oyster Creek Nuclear Generating Station (Oyster Creek) in the third quarter of 2003. Higher nuclear capacity factors and decreased nuclear production costs are primarily due to 16 fewer planned refueling outage days, resulting in a $9 million decrease in outage costs, in the three months ended September 30, 2003 as compared to the same period in 2002. The three months ended September 30, 2003 included nine unplanned outages compared to seven unplanned outages during the three months ended September 30, 2002. Results of Operations - Enterprises
Three Months Ended September 30, -------------------------------- 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Operating revenues $ 437 $ 509 $ (72) (14.1%) Operating income 24 15 9 60.0% Income before income taxes 26 20 6 30.0% Net income 16 15 1 6.7% -------------------------------------------------------------------------------------------------------------------
The changes in Enterprises' operating income for the three months ended September 30, 2003 compared to the same period in 2002, included the following: o a gain on sale of $44 million, net of transaction costs and before income taxes, related to the sale of the electric construction and services, underground and telecom businesses of InfraSource, o lower operating income at InfraSource of $21 million primarily resulting from a decrease in the electric business of $26 million and a decrease in the underground business of $2 million, partially offset by lower depreciation of $8 million as a result of the classification of InfraSource's property, plant and equipment as held for sale in the second quarter of 2003, o lower operating income at Exelon Services of $2 million, primarily resulting from reduced construction projects, o lower operating income at Exelon Energy Company of $4 million primarily resulting from the reversal of mark-to-market adjustments of $1 million and additional gas supply costs and business wind-down costs of $4 million for Northeast operations, partially 86 offset by higher gross margins of $2 million in the Midwest attributable to increased unit margins and higher volumes, and o higher allocated O&M costs of $6 million. The change in other income and deductions for the three months ended September 30, 2003 compared to the same period in 2002 was primarily due to lower equity in earnings of unconsolidated affiliates of $9 million primarily resulting from the recovery of trade receivables in 2002 that were previously considered uncollectible at a communications joint venture. The effective income tax rate was 38.5% for the three months ended September 30, 2003, compared to 25.0% for the same period in 2002. The increase in the effective tax rate was primarily attributable to a reduction in estimated state income tax recorded during the three months ended September 30, 2002. Nine Months Ended September 30, 2003 and Nine Months Ended September 30, 2002 Net Income and Earnings Per Share Exelon's net income for the nine months ended September 30, 2003 decreased $412 million or 40%, compared to the same period in 2002. Diluted earnings per common share on the same basis decreased $1.29 per share. Net income for the nine months ended September 30, 2003 reflects $112 million of income for the cumulative effect of a change in accounting principle as a result of the adoption of SFAS No. 143 while net income for the nine months ended September 30, 2002 reflects a $230 million charge for the cumulative effect of a change in accounting principle, reflecting goodwill impairment upon the adoption of SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS No. 142). See Note 2 of the Condensed Combined Notes to Consolidated Financial Statements for further information regarding the adoptions of SFAS No. 143 and SFAS No. 142. Income before cumulative effect of changes in accounting principles for the nine months ended September 30, 2003 decreased $754 million, or 59%, compared to the same period in 2002. Diluted earnings per common share on the same basis decreased $2.34 per share. The decrease in income before cumulative effect of changes in accounting principles reflects an impairment of the long-lived assets of EBG recorded during the third quarter of 2003, impairment charges related to Generation's investment in Sithe recorded in the first and third quarters of 2003 and severance and related postretirement health and welfare benefits accruals and pension and post-employment curtailment costs associated with The Exelon Way. These reductions in income were partially offset by reductions in property tax reserves at PECO and Generation during the third quarter of 2003, increased energy margins at Generation due to the acquisition of Exelon New England in November 2002 and decreased interest expense at Energy Delivery due to refinancing of outstanding debt at lower interest rates. Additionally, a gain was recorded in the second quarter of 2002 due to the sale of an investment in AT&T Wireless held by Enterprises. 87 Results of Operations by Business Segment The comparisons presented under this heading are comparisons of operating results and other statistical information for the nine months ended September 30, 2003 to operating results and other statistical information for the same period in 2002. These results reflect intercompany transactions, which are eliminated in Exelon's consolidated financial statements. Net Income (Loss) Before Cumulative Effect of Changes in Accounting Principles by Business Segment
Nine Months Ended September 30, ------------------------------- 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Energy Delivery $ 920 $ 908 $ 12 1.3% Generation (339) 313 (652) n.m. Enterprises (62) 69 (131) (189.9%) Corporate -- (17) 17 (100.0%) ------------------------------------------------------------------------------------------------- Total $ 519 $ 1,273 $ (754) (59.2%) ================================================================================================= n.m. - not meaningful
Net Income (Loss) by Business Segment
Nine Months Ended September 30, ------------------------------- 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Energy Delivery $ 925 $ 908 $ 17 1.9% Generation (231) 326 (557) (170.9%) Enterprises (63) (174) 111 (63.8%) Corporate -- (17) 17 (100.0%) ------------------------------------------------------------------------------------------------- Total $ 631 $ 1,043 $ (412) (39.5%) =================================================================================================
Results of Operations - Energy Delivery
Nine Months Ended September 30, ------------------------------- Energy Delivery 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Operating revenues $ 7,850 $ 7,973 $ (123) (1.5%) Revenue, net of purchased power & fuel expense 4,274 4,414 (140) (3.2%) Operating income 2,025 2,108 (83) (3.9%) Income before income taxes and cumulative effect of a change in accounting principle 1,478 1,455 23 1.6% Income before cumulative effect of a change in accounting principle 920 908 12 1.3% Net income 925 908 17 1.9% -------------------------------------------------------------------------------------------------------------------
The changes in Energy Delivery's revenue, net of purchased power and fuel expense, for the nine months ended September 30, 2003 compared to the same period in 2002, included the following: o net unfavorable weather impacts of $63 million, primarily the result of cooler summer weather partially offset by colder winter weather, o unfavorable pricing changes of $60 million related to ComEd's PPA with Generation, o unfavorable variance of $47 million under the ComEd PPA with Generation related to decommissioning collections associated with the adoption of SFAS No. 143 in 2003, 88 which had no impact on net income as these amounts were recorded in depreciation and amortization expense in 2002 (see Note 2 of the Condensed Combined Notes to Consolidated Financial Statements), o unfavorable rate mix variance of $28 million at PECO as a result of changes in monthly usage patterns by all customer classes, o net unfavorable changes due to customer choice of $25 million, including ComEd's customers electing to purchase energy from alternative energy suppliers or electing ComEd's PPO, under which non-residential customers can purchase power from ComEd at a market-based rate, o increases in weather normalized volumes of $32 million as a result of increases in the number of customers and additional average usage per customer, primarily residential and small commercial and industrial customers at ComEd, and small and large commercial and industrial customers at PECO, o favorable variance of $23 million due to changes in customer rates due to additional CTC collections at ComEd, and o net favorable change of $8 million at ComEd as a result of 2002 third-party energy reconciliations. The changes in operating income, other than changes in revenue, net of purchased power and fuel expense, for the nine months ended September 30, 2003 compared to the same period in 2002, included the following: o a decrease in real estate taxes at PECO of $70 million, including a reduction of $58 million of reserves for real estate taxes in 2003, o decreased payroll expense of $64 million due to fewer employees, o reduction in depreciation expense of $48 million due to the impact of lower depreciation rates at ComEd effective July 1, 2002, partially offset by increased depreciation expense in 2003 of $24 million due to higher plant in service balances, o reduction of amortization expense of $47 million for nuclear decommissioning of retired plants at ComEd due to the adoption of SFAS No. 143, which had no impact on net income as these amounts were recorded as purchased power in 2003 (see Note 2 of the Condensed Combined Notes to Consolidated Financial Statements), o lower amortization of ComEd's recoverable transition costs of $41 million in 2003, o decreased costs of $23 million associated with the initial implementation of automated meter reading services at PECO in 2002, o decreased costs of $12 million in the reserve for MGP investigation and remediation in 2002 net of 2003 increases, o a reversal of $12 million of accrued use tax at PECO as a result of an audit settlement, o unfavorable variance of $101 million due to severance and related postretirement health and welfare benefits accruals and pension and postretirement curtailment costs associated with The Exelon Way, o unfavorable variance of $35 million due to higher storm-related costs, o a net one-time charge of $41 million in 2003 at ComEd as the result of an agreement described in Note 5 of Condensed Combined Notes to Consolidated Financial Statements, o unfavorable variance of $28 million due to employee fringe benefits, and o additional amortization in 2003 of $20 million at PECO related to PECO's CTC in accordance with the Pennsylvania Competitive Act. 89 The changes in other income and deductions for the nine months ended September 30, 2003 compared to the same period in 2002, included the following: o a reduction in interest expense primarily related to a decrease of $66 million attributable to less outstanding debt and refinancing of existing debt at lower interest rates, and o a reduction of $12 million as a result of a 2002 reserve accrual for a potential plant disallowance from an audit performed in conjunction with ComEd's delivery services rate case, and the reversal in 2003 of this reserve as the result of an agreement described in Note 5 of the Condensed Combined Notes to Consolidated Financial Statements. Energy Delivery's effective income tax rate was 37.8% for the nine months ended September 30, 2003, compared to 37.6% for the same period in 2002. ComEd recorded a gain due to the adoption of SFAS No. 143 as a cumulative effect of a change in accounting principle of $5 million, net of income taxes, in the first quarter of 2003. See Note 2 of the Condensed Combined Notes to Consolidated Financial Statements for further discussion of these effects. Energy Delivery Operating Statistics and Revenue Detail Energy Delivery's electric sales statistics and revenue detail were as follows:
Nine Months Ended September 30, ------------------------------- Retail Deliveries - (GWhs) 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Bundled Deliveries (1) Residential 28,969 28,984 (15) (0.1%) Small Commercial & Industrial 21,555 22,782 (1,227) (5.4%) Large Commercial & Industrial 15,896 17,436 (1,540) (8.8%) Public Authorities & Electric Railroads 4,710 5,715 (1,005) (17.6%) ----------------------------------------------------------------------------------------------------- Total Bundled Deliveries 71,130 74,917 (3,787) (5.1%) ----------------------------------------------------------------------------------------------------- Unbundled Deliveries (2) Alternative Energy Suppliers ---------------------------- Residential 708 1,720 (1,012) (58.8%) Small Commercial & Industrial 5,371 4,075 1,296 31.8% Large Commercial & Industrial 7,504 5,551 1,953 35.2% Public Authorities & Electric Railroads 954 618 336 54.4% ----------------------------------------------------------------------------------------------------- 14,537 11,964 2,573 21.5% ----------------------------------------------------------------------------------------------------- PPO (ComEd Only) ---------------- Small Commercial & Industrial 2,546 2,384 162 6.8% Large Commercial & Industrial 3,646 3,952 (306) (7.7%) Public Authorities & Electric Railroads 1,497 861 636 73.9% ----------------------------------------------------------------------------------------------------- 7,689 7,197 492 6.8% ----------------------------------------------------------------------------------------------------- Total Unbundled Deliveries 22,226 19,161 3,065 16.0% ----------------------------------------------------------------------------------------------------- Total Retail Deliveries 93,356 94,078 (722) (0.8%) ===================================================================================================== (1) Bundled service reflects deliveries to customers taking electric generation service under tariffed rates. (2) Unbundled service reflects customers electing to receive electric generation service from an alternative energy supplier or ComEd's PPO.
90
Nine Months Ended September 30, ------------------------------- Electric Revenue 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Bundled Revenues (1) Residential $ 2,899 $ 2,880 $ 19 0.7% Small Commercial & Industrial 1,874 2,007 (133) (6.6%) Large Commercial & Industrial 1,065 1,152 (87) (7.6%) Public Authorities & Electric Railroads 309 356 (47) (13.2%) ----------------------------------------------------------------------------------------------------- Total Bundled Revenues 6,147 6,395 (248) (3.9%) ----------------------------------------------------------------------------------------------------- Unbundled Revenues (2) Alternative Energy Suppliers ---------------------------- Residential 52 129 (77) (59.7%) Small Commercial & Industrial 161 107 54 50.5% Large Commercial & Industrial 149 111 38 34.2% Public Authorities & Electric Railroads 25 18 7 38.9% ----------------------------------------------------------------------------------------------------- 387 365 22 6.0% ----------------------------------------------------------------------------------------------------- PPO (ComEd Only) ---------------- Small Commercial & Industrial 174 155 19 12.3% Large Commercial & Industrial 199 214 (15) (7.0%) Public Authorities & Electric Railroads 81 48 33 68.8% ----------------------------------------------------------------------------------------------------- 454 417 37 8.9% ----------------------------------------------------------------------------------------------------- Total Unbundled Revenues 841 782 59 7.5% ----------------------------------------------------------------------------------------------------- Total Electric Retail Revenues 6,988 7,177 (189) (2.6%) ----------------------------------------------------------------------------------------------------- Wholesale and Miscellaneous Revenue (3) 414 438 (24) (5.5%) ----------------------------------------------------------------------------------------------------- Total Electric Revenue $ 7,402 $ 7,615 $ (213) (2.8%) ===================================================================================================== (1) Bundled revenue reflects deliveries to customers taking electric service under tariffed rates, which include the cost of energy and the delivery cost of the transmission and the distribution of the energy. PECO's tariffed rates also include a CTC charge. (2) Unbundled revenue reflects revenue from customers electing to receive electric generation service from an alternative energy supplier or ComEd's PPO. Revenue from customers choosing an alternative energy supplier includes a distribution charge and a CTC. Revenues from customers choosing ComEd's PPO includes an energy charge at market rates, transmission and distribution charges and a CTC. Transmission charges received from alternative energy suppliers are included in wholesale and miscellaneous revenue. (3) Wholesale and miscellaneous revenues include transmission revenue, sales to municipalities and other wholesale energy sales.
The differences in electric retail revenues for the nine months ended September 30, 2003 as compared to the same period in 2002 were attributable to the following:
Variance ------------------------------------------------------------------------------------------------------------------- Weather $ (189) Customer choice (116) Rate mix (28) Volume 109 Rate changes 23 Other effects 12 ------------------------------------------------------------------------------------------------------------------- Electric retail revenue $ (189) ===================================================================================================================
o Weather. The weather impact for the nine months ended September 30, 2003 was unfavorable compared to the same period in 2002 as a result of cooler summer weather in 2003, partially offset by colder winter weather. Cooling degree-days in the ComEd and 91 PECO service territories were 36% lower and 19% lower, respectively, in 2003 as compared to 2002. Heating degree-days in the ComEd and PECO service territories were 15% higher and 35% higher, respectively, in 2003 as compared to 2002. o Customer Choice. For the nine months ended September 30, 2003 and September 30, 2002, 16% and 13%, respectively, of energy delivered to Energy Delivery's customers was provided by alternative electric suppliers. The decrease in electric retail revenues includes a decrease in revenues of $113 million from customers in Illinois electing to purchase energy from an ARES or ComEd's PPO, and a decrease in revenues of $3 million from customers in Pennsylvania selecting and alternative electric generation supplier. o Rate Mix. Revenues related to changes in rate mix at PECO decreased $28 million due to changes in monthly usage patterns in all customer classes for the nine months ended September 30, 2003 as compared to the same period in 2002. o Volume. Revenues from higher delivery volume, exclusive of the effect of weather, increased due to an increased number of customers and increased usage per customer, primarily in the residential and small commercial and industrial customer classes for ComEd and in the small and large commercial and industrial customer classes for PECO. o Rate Changes. The increase in revenues attributable to rate changes reflects the collection of additional CTCs in 2003 by ComEd through June 1, 2003, offset by lower collections since then. The net increase for the nine months ended September 30, 2003 was $65 million. Starting in the June 2003 billing cycle, the increased wholesale market price of electricity, net of increased mitigation factors, as a result of an agreement described in Note 5 of the Condensed Combined Notes to Consolidated Financial Statements, decreased the collections of CTCs as compared to the respective period in 2002 by $81 million. Changes in wholesale market prices decreased energy revenue received under ComEd's PPO by $42 million. Energy Delivery's gas sales statistics and revenue detail were as follows:
Nine Months Ended September 30, ------------------------------- Deliveries to customers in mmcf 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Retail sales 44,183 34,128 10,055 29.5% Transportation 19,954 22,862 (2,908) (12.7%) ----------------------------------------------------------------------------------------------------- Total 64,137 56,990 7,147 12.5% ===================================================================================================== n.m. - not meaningful Nine Months Ended September 30, ------------------------------- Revenue 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Retail sales $ 418 $ 309 $ 109 35.3% Transportation 14 15 (1) (6.7%) Resales and other 16 34 (18) (52.9%) ----------------------------------------------------------------------------------------------------- Total $ 448 $ 358 $ 90 25.1% =====================================================================================================
92 The changes in gas retail revenue for the nine months ended September 30, 2003 as compared to the same period in 2002, were as follows:
Variance ------------------------------------------------------------------------------------------------------------------- Weather $ 73 Volume 21 Rate changes 15 ------------------------------------------------------------------------------------------------------------------- Total gas retail revenue $ 109 ===================================================================================================================
o Weather. The weather impact was favorable compared to the prior year as a result of colder winter weather. Heating degree-days increased 35% in the nine months ended September 30, 2003 compared to the same period in 2002. Retail sales deliveries increased approximately 8,600 mmcf due to the colder weather. o Volume. Exclusive of weather impacts, higher delivery volume increased revenue in the nine months ended September 30, 2003 compared to the same period in 2002 resulting from increased retail sales in all classes. Deliveries to retail customers increased approximately 1,500 mmcf, or 4% in the nine months ended September 30, 2003 compared to the same period in 2002. o Rate Changes. The favorable variance in rates is attributable to increases of 15% and 7% in the purchased gas adjustment by the PUC effective March 1, 2003 and June 1, 2003, respectively. The average rate per mmcf for the nine months ended September 30, 2003 was 5% higher than the rate in the same 2002 period. PECO's gas rates are subject to periodic adjustments by the PUC and are designed to recover from or refund to customers the difference between actual cost of purchased gas and the amount included in base rates and to recover or refund increases or decreases in certain state taxes not recovered in base rates. The reduction in transportation volumes and revenues was primarily the result of lower intercompany deliveries to Generation during the nine months ended September 30, 2003 compared to the same period in 2002. Lower resale revenues are attributable to a decrease in off-system sales, exchanges and capacity releases during the nine months ended September 30, 2003 compared to the same period in 2002. 93 Results of Operations - Generation
Nine Months Ended September 30, ------------------------------- 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Operating revenues $ 6,301 $ 5,233 $ 1,068 20.4% Revenue, net of purchased power & fuel expense 2,264 1,946 318 16.3% Operating income (loss) (411) 389 (800) n.m. Income (loss) before income taxes and cumulative effect of changes in accounting principles (548) 511 (1,059) n.m. Income (loss) before cumulative effect of changes in accounting principles (339) 313 (652) n.m. Net income (loss) (231) 326 (557) (170.9%) ------------------------------------------------------------------------------------------------------------------- n.m. - not meaningful
The changes in Generation's revenue, net of purchased power and fuel expense, for the nine months ended September 30, 2003 compared to the same period in 2002, included the following: o increased market sales of $593 million primarily attributable to higher regional demand and higher prices, and reduced capacity payments as a result of releasing Midwest Generation options, o unfavorable weather conditions in the ComEd and PECO service territories in 2003 resulted in a net volume decrease, partially offset by price increases, resulting in a $112 million unfavorable variance on revenue from Energy Delivery, o increased decommissioning revenue from ComEd of $47 million associated with the adoption of SFAS No. 143, which was not included in revenue in 2002, o mark-to-market losses on hedging activities of $17 million in 2003 compared to a gain of $11 million in 2002, o favorable changes in trade book activity of $26 million were a result of lower losses from decreased trading volumes in 2003 compared to 2002, and o additional nuclear fuel amortization of $16 million in 2003 resulting from under performing fuel at the Quad Cities Unit 1. Other significant factors affecting the changes in revenue, net of purchased power and fuel, include the impacts of the plants acquired during 2002 resulting in a net favorable variance of $111 million. In addition, the impacts of higher prices of purchased power and fuel costs, partially offset by lower volumes of purchased power, resulted in a net unfavorable impact of $301 million. The changes in operating income (loss), other than changes in revenue, net of purchased power and fuel expense, for the nine months ended September 30, 2003 compared to the same period in 2002, included the following: o impairment charge of $945 million related to the long-lived assets of EBG, o increased accretion expense of $162 million due to the adoption of SFAS No. 143, partially offset by reduced decommissioning expense of $93 million, o higher costs of $51 million for employee medical, pension and other employee payroll and benefit costs in 2003, partially offset by a one-time executive severance charge of $19 million in 2002, 94 o increased O&M costs of $68 million due to asset acquisitions made during 2002 and a $5 million asset impairment charge recorded in 2003 related to Mystic Station Units 4, 5, and 6, o $46 million in severance and related postretirement health and welfare benefits accruals and pension and postretirement curtailment costs associated with The Exelon Way, o reduced refueling outage costs of $61 million, including $17 million at one of Generation's co-owned facilities, resulting from fewer refueling outage days in 2003, o additional depreciation of $39 million due to capital additions placed in service and plant acquisitions made during 2002 and $13 million due to plant acquisitions made after the third quarter of 2002, partially offset by a $12 million reduction to depreciation expense due to life extensions made in 2002, and o reduction in worker's compensation expense of $8 million compared to 2002. The changes in other income and deductions for the nine months ended September 30, 2003 compared to the same period in 2002, included the following: o impairment charges of $255 million related to Generation's equity investment in Sithe, o increased decommissioning trust investment income of $41 million, which is almost entirely offset with accretion expense, net of depreciation, recorded in O&M, o decreased equity in earnings of unconsolidated affiliates of $29 million and o increased interest expense of $12 million primarily due to $8 million of interest expense on the long-term debt assumed as a part of the Exelon New England asset acquisition, reduced capitalized interest in 2003, and $7 million of interest incurred on the note payable to Sithe. Generation's effective income tax rate was 38.1% for the nine months ended September 30, 2003 compared to 38.7% for the same period in 2002. This decrease was primarily attributable to the impact of changes in income before taxes as a result of the impairments of Generation's investment in Sithe and the long-lived assets of EBG. Cumulative effect of changes in accounting principles recorded in the nine months ended September 30, 2003 and 2002 included income of $108 million, net of income taxes, recorded in the first quarter of 2003 related to the adoption of SFAS No. 143 and income of $13 million, net of income taxes, recorded in 2002 related to the adoption of SFAS No. 141, "Business Combinations" (SFAS No. 141) and SFAS No. 142. See Note 2 of the Condensed Combined Notes to Consolidated Financial Statements for further discussion of these effects. 95 Generation Operating Statistics Generation's sales and the supply of these sales, excluding the trading portfolio, were as follows:
Nine Months Ended September 30, ------------------------------- Sales (in GWhs) 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Energy Delivery and Exelon Energy Company 89,700 94,646 (4,946) (5.2%) Market Sales 80,877 61,089 19,788 32.4% ----------------------------------------------------------------------------------------------------- Total Sales 170,577 155,735 14,842 9.5% ===================================================================================================== Nine Months Ended September 30, ------------------------------- Supply of Sales (in GWhs) 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Nuclear Generation (1) 89,101 86,127 2,974 3.5% Purchases - non-trading portfolio (2) 63,435 59,496 3,939 6.6% Fossil and Hydro Generation 18,041 10,112 7,929 78.4% ----------------------------------------------------------------------------------------------------- Total Supply 170,577 155,735 14,842 9.5% ===================================================================================================== (1) Excluding AmerGen. (2) Including PPAs with AmerGen.
Trading volumes of 28,532 GWhs and 51,260 GWhs for the nine months ended September 30, 2003 and 2002, respectively, are not included in the table above. The decrease in trading volume is a result of reduced volumetric and VaR trading limits in 2003, which are set by the Risk Management Committee and approved by the Board of Directors. Generation's average margin and other operating data for the nine months ended September 30, 2003 and 2002 were as follows:
Nine Months Ended September 30, ------------------------------- ($/MWh) 2003 2002 % Change ------------------------------------------------------------------------------------------------------------------- Average Revenue Energy Delivery and Exelon Energy Company $ 35.45 $ 34.86 1.7% Market Sales 37.11 31.55 17.6% Total - excluding the trading portfolio 36.24 33.56 8.0% Average Supply Cost (1) - excluding the trading portfolio $ 23.67 $ 21.04 12.5% Average Margin - excluding the trading portfolio $ 12.57 $ 12.52 0.4% ----------------------------------------------------------------------------------------------------------------- (1) Average supply cost includes purchased power and fuel costs.
Nine Months Ended September 30, ------------------------------- 2003 2002 ------------------------------------------------------------------------------------------------------------------- Nuclear fleet capacity factor (1) 94.5% 92.1% Nuclear fleet production cost per MWh (1) $ 12.16 $ 13.05 Average purchased power cost for wholesale operations per MWh (2) $ 45.42 $ 43.60 ------------------------------------------------------------------------------------------------------------------- (1) Including AmerGen and excluding Salem, which is operated by PSE&G. (2) Including PPAs with AmerGen.
The factors below contributed to the overall increase in Generation's average margin for the nine months ended September 30, 2003 as compared to the same period in 2002. 96 Generation's average revenue per MWh was affected by: o higher market prices as a result of increased fuel prices and o increased weighted average on and off-peak prices per MWh for supply agreements with ComEd and PECO. Generation's supply mix changed as a result of: o increased nuclear generation due to a lower number of refueling and unplanned outages during 2003 compared to 2002, o increased fossil generation due to the effect of the acquisition of two generating plants in Texas in April 2002, and the Exelon New England plants acquired in November 2002, which in total account for an increase of 6,565 GWhs, o increased quantity of purchased power at higher prices, and o a new PPA with AmerGen entered into during the second quarter of 2003, resulting in 2,481 GWhs purchased from Oyster Creek in 2003. Higher nuclear capacity factors and decreased nuclear production costs are primarily due to 66 fewer planned refueling outage days, resulting in a $44 million decrease in outage costs, in the nine months ended September 30, 2003 as compared to the same period in 2002. The nine months ended September 30, 2003 and 2002 included 20 unplanned outages in each year. Generation's financial results are greatly dependent on the performance of its nuclear units, including Generation's ability to maintain stable cost levels and high nuclear capacity factors. Problems that may occur at nuclear facilities that result in increased costs include accelerated replacement of suspect fuel assemblies and reduced generation due to maintenance and mid-cycle outages. For example, in the second quarter of 2003, the Quad Cities Unit 1 required a significant repair and did not operate above 85% capacity factor until a root cause analysis was completed. Although this individual matter did not result in a significant decrease in operating income, this type of reduction in operational capacity can adversely affect Generation's financial results. Generation completed the analysis and returned the unit to its normal operating capacity in August 2003. Results of Operations - Enterprises
Nine Months Ended September 30, ------------------------------- 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Operating revenues $ 1,459 $ 1,475 $ (16) (1.1%) Operating loss (60) (35) (25) 71.4% Income (loss) before income taxes and cumulative effect of changes in accounting principles (99) 115 (214) (186.1%) Income (loss) before cumulative effect of changes in accounting principles (62) 69 (131) (189.9%) Net loss (63) (174) 111 (63.8%) -------------------------------------------------------------------------------------------------------------------
97 The changes in Enterprises' operating loss for the nine months ended September 30, 2003 compared to the same period in 2002, included the following: o an impairment charge of $48 million, before income taxes and minority interest, related to the goodwill of InfraSource recorded during the second quarter of 2003, partially offset by a gain of $44 million, before income taxes, related to the sale of the electric construction and services, underground and telecom business of InfraSource recorded during the third quarter of 2003, o lower operating income at InfraSource of $25 million primarily resulting from a decrease in the electric business of $37 million, partially offset by lower depreciation of $10 million as a result of the classification of InfraSource's property, plant and equipment as held for sale during the second quarter of 2003, o lower operating income at Exelon Services of $3 million as a result of reduced construction projects, o higher operating income at Exelon Energy Company of $3 million resulting from lower operating expense from the discontinuance of retail sales in the PJM region including 2002 costs for accelerated depreciation of $14 million and general and administrative costs of $2 million. These costs were partially offset by lower gross margins of $13 million in 2003. The lower gross margins resulted from the reversal of mark-to-market adjustments of $13 million and additional gas supply costs and business wind-down costs of $12 million for Northeast operations, partially offset by higher gross margins of $10 million in the Midwest attributable to increased unit margins, higher volumes, and higher natural gas prices, and a $2 million favorable variance related to the wind-down of a contract, and o higher operating income at Exelon Thermal of $4 million resulting from lower production costs. The changes in other income and deductions for the nine months ended September 30, 2003 compared to the same period in 2002, include the following additional impacts: o a gain of $198 million, before income taxes, in the second quarter of 2002 due to the sale of the investment in AT&T Wireless, and o an impairment charge in 2003 of energy-related investments of $22 million, communications investments of $13 million, and $5 million of software-related investments due to an other-than-temporary decline in value, partially offset by an impairment charge in 2002 of communications investments of $29 million, energy-related investments of $11 million and a net impairment of other assets of $4 million. The effective income tax rate was 37.4% for the nine months ended September 30, 2003, compared to 40.0% for the same period in 2002. This decrease in the effective tax rate was attributable to lower effective income tax rates on the impairment charges and sale of the InfraSource businesses. The cumulative effect of a change in accounting principle recorded in the first quarter of 2003 due to the adoption of SFAS No. 143 reduced net income by $1 million, net of income taxes. The cumulative effect of a change in accounting principle recorded in the first quarter of 2002 for the adoption of SFAS No. 142 reduced net income by $243 million, net of income 98 taxes. See Note 2 of the Condensed Combined Notes to Consolidated Financial Statements for further discussion of these effects. Enterprises continues to pursue the divestiture of other businesses; however, it may be unable to successfully implement its divestiture strategy of certain businesses for a number of reasons, including an inability to locate appropriate buyers or to negotiate acceptable terms for the transactions. In addition, the amount that Enterprises may realize from a divestiture is subject to fluctuating market conditions that may contribute to pricing and other terms that are materially different than expected and could result in a loss on the sale. Timing of any divestitures may positively or negatively affect the results of operations as Exelon expects certain businesses to be profitable going forward. General Due to revenue needs in the states in which Exelon operates, various state income tax and fee increases have been proposed or are being contemplated. If these changes are enacted, they could increase Exelon's state income tax expense. At this time, however, Exelon cannot predict whether legislation or regulation will be introduced, the form of any legislation or regulation, whether any such legislation or regulation will be passed by the state legislatures or regulatory bodies, and, if enacted, whether any such legislation or regulation would be effective retroactively or prospectively. As a result, Exelon cannot currently estimate the effect of these potential changes in tax laws or regulation. LIQUIDITY AND CAPITAL RESOURCES Exelon's businesses are capital intensive and require considerable capital resources. These capital resources are primarily provided by internally generated cash flows from Energy Delivery and Generation's operations. When necessary, Exelon obtains funds from external sources in the capital markets and through bank borrowings. Exelon's access to external financing at reasonable terms depends on Exelon's and its subsidiaries' credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where Exelon no longer has access to external financing sources at reasonable terms, Exelon has access to a $1.5 billion revolving credit facility that Exelon currently utilizes to support its commercial paper program. See the Credit Issues section of Liquidity and Capital Resources for further discussion. Exelon primarily uses its capital resources to fund capital requirements, including construction, to invest in new and existing ventures, to repay maturing debt and to pay common stock dividends. Future acquisitions that Exelon may undertake may require external financing, which might include Exelon issuing common stock. Exelon is in the process of implementing its new business model referred to as The Exelon Way. This business model is focused on improving operating cash flows while meeting service and financial commitments through integration of operations and consolidation of support functions. Exelon has targeted approximately $300 million of annual cash savings beginning in 2004 and increasing the annual cash savings to $600 million in 2006. As part of the implementation of The Exelon Way, Exelon has identified 1,042 positions 99 for elimination by the end of 2004 and anticipates identifying additional positions for elimination in 2005 and 2006. Exelon recorded a charge for cash severance of $87 million during the third quarter 2003, which Exelon anticipates will be paid by December 31, 2004. Exelon anticipates incurring further costs associated with The Exelon Way upon identifying additional positions to be eliminated. These costs will be recorded in the period in which the costs can be reasonably estimated. On September 26, 2003 Exelon announced that it was exploring the possibility of acquiring Illinois Power Company from Dynegy Corporation. Cash Flows from Operating Activities Cash flows provided by operations for the nine months ended September 30, 2003 were $2.6 billion compared to $2.7 billion in the nine months ended September 30, 2002. The decrease in cash flows was primarily attributable to the $360 million funding of pension benefit obligations partially offset by a $162 million increase in cash flows generated from working capital. Energy Delivery's cash flow from operating activities primarily results from sales of electricity and gas to a stable and diverse base of retail customers at fixed prices. Energy Delivery's future cash flows will depend upon the ability to achieve cost savings in operations and the impact of the economy, weather, customer choice and future regulatory proceedings 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 used in Investing Activities Cash flows used in investing activities for the nine months ended September 30, 2003 were $1.3 billion, compared to $1.9 billion for the nine months ended September 30, 2002. The decrease in cash used for investing activities during the current year is primarily attributable to the plant acquisition costs of $443 million during the nine months ended September 30, 2002, the reduction of capital expenditures of $33 million, the receipt of liquated damages from Raytheon of $92 million during the nine months ended September 30, 2003 and an increase in cash proceeds from related parties of $77 million, partially offset by increased investments in nuclear decommissioning trust fund assets of $17 million. Additionally, cash flows from investing activities in 2002 include the cash proceeds from the sale of AT&T of $285 million, while cash proceeds from the sale of InfraSource during the current year were $175 million. 100 Capital expenditures by business segment for the nine months ended September 30, 2003 and 2002 were as follows:
Nine Months Ended September 30, -------------------------------- 2003 2002 ------------------------------------------------------------------------------------------------------------------- Energy Delivery $ 728 $ 729 Generation 641 715 Enterprises 19 34 Corporate and other 21 56 ------------------------------------------------------------------------------------------------------------------- Total capital expenditures (net of liquidated damages received) $ 1,409 $ 1,534 ===================================================================================================================
Energy Delivery's capital expenditures for 2003 reflect continuing efforts to further improve the reliability of its transmission and distribution systems and capital additions to support new business and customer growth. Exelon anticipates that Energy Delivery's capital expenditures will be funded by internally generated funds, borrowings, the issuance of preferred securities, or capital contributions from Exelon. Generation's capital expenditures for 2003 reflect the construction of three EBG generating facilities with capacity of 2,421 MWs of energy, additions to and upgrades of existing facilities (including nuclear refueling outages), and nuclear fuel. During the nine months ended September 30, 2003, EBG received $92 million of liquidated damages from Raytheon as a result of Raytheon not meeting the expected completion date and certain contractual performance criteria in connection with Raytheon's construction of Exelon New England's Mystic 8 and 9 and Fore River. Exelon anticipates that Generation's capital expenditures will be funded by internally generated funds, borrowings or capital contributions from Exelon. Enterprises' capital expenditures for 2003 are primarily for additions of equipment. All of Enterprises' capital expenditures are expected to be funded by internally generated funds, capital contributions or borrowings from Exelon. Cash Flows used in Financing Activities Cash flows used in financing activities were $1.1 billion for the nine months ended September 30, 2003 compared to $828 million for the same period in 2002. The increased use of cash over the prior year is primarily attributable to the $210 million payment of the acquisition note payable to Sithe in June 2003 and increased interest rate swap settlement payments of $35 million over the same period in 2002, partially offset by an increase in cash proceeds from the exercise of stock options of $75 million and a net increase in cash proceeds from the issuance of debt and preferred securities of $14 million over the same period in 2002. See Note 12 of the Condensed Combined Notes to Consolidated Financial Statements for further discussion of Exelon's debt and preferred securities financing activities in 2003. Dividends paid on common stock increased from $420 million for the nine months ended September 30, 2002 to $461 million for the nine months ended September 30, 2003. On July 29, 2003, the Exelon Board of Directors declared a dividend of $0.50 per share on Exelon's common stock, representing an increase of $0.16 per share annually or approximately 8.7%. Payment of future dividends is subject to approval and declaration by the Board. 101 Credit Issues Exelon meets its short-term liquidity requirements primarily through the issuance of commercial paper by the Exelon corporate holding company (Exelon Corporate) and by ComEd and PECO. Exelon Corporate participates, along with ComEd, PECO and Generation, in a $1.5 billion unsecured 364-day revolving credit facility with a group of banks. The credit facility became effective on November 22, 2002 and includes a term-out option that allows any outstanding borrowings at the end of the revolving credit period to be repaid on November 21, 2004. Exelon Corporate may increase or decrease the sublimits of each of the participants upon written notification to the banks. At September 30, 2003, sublimits under the credit facility were $1.0 billion, $100 million and $400 million for Exelon Corporate, ComEd and PECO, respectively. Generation did not have a sublimit under the facility at September 30, 2003. The credit facility is used principally to support the commercial paper programs of Exelon Corporate, ComEd and PECO. At September 30, 2003, Exelon's Consolidated Balance Sheet reflected $82 million of commercial paper outstanding. For the nine months ended September 30, 2003, the average interest rate on notes payable was approximately 1.28%. The credit facility requires Exelon Corporate, ComEd, PECO and Generation to maintain a minimum cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The ratios exclude revenues and interest expenses attributable to securitization debt, certain changes in working capital, distributions on preferred securities of subsidiaries and, in the case of Exelon Corporate and Generation, revenues from Exelon New England and interest on the debt of Exelon New England's project subsidiaries. Exelon Corporate is measured at the Exelon consolidated level. At September 30, 2003, Exelon Corporate, ComEd, PECO and Generation were in compliance with the credit agreement thresholds. The following table summarizes the threshold reflected in the credit agreement that the ratio cannot be less than for the twelve-month period ended September 30, 2003:
Exelon Corporate ComEd PECO Generation ------------------------------------------------------------------------------------------------------------------- Credit agreement threshold 2.65 to 1 2.25 to 1 2.25 to 1 3.25 to 1 -------------------------------------------------------------------------------------------------------------------
To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, Exelon operates an intercompany money pool. Participation in the money pool is subject to authorization by Exelon's corporate treasurer. ComEd, PECO, Generation and Exelon Business Services Company (BSC) may participate in the money pool as lenders and borrowers, and Exelon Corporate may participate as a lender. Funding of, and borrowings from, the money pool are predicated on whether the contributions and borrowings result in economic benefits to all the participants. Interest on borrowings is based on short-term market rates of interest, or, if from an external source, specific borrowing rates. During the nine months ended September 30, 2003, ComEd had various investments in the money pool, and Generation had various loans from the money pool. The maximum amount of ComEd's investments and Generation's loans outstanding at any time during 2003 was $344 million. As of September 30, 2003, the outstanding ComEd investment and Generation loan balance was $147 million. During the nine months ended September 30, 2003, PECO had various investments in the money pool, and BSC had various loans from the money pool. The maximum amount of PECO's investments and 102 BSC's loans outstanding at any time during 2003 was $59 million. As of September 30, 2003, there were no outstanding PECO investments or BSC loan balances. EBG has approximately $1.1 billion of debt outstanding under a $1.25 billion credit facility (EBG Facility) at September 30, 2003. The EBG Facility was entered into primarily to finance the construction of Mystic 8 and 9 and Fore River. The EBG Facility required that all of the projects achieve "Project Completion," as defined in the EBG Facility (Project Completion), by June 12, 2003. On June 11, 2003, EBG negotiated an extension of the Project Completion date to July 11, 2003. On July 3, 2003, the lenders under the EBG Facility and EBG executed a letter agreement as a result of which the lenders were precluded during the period July 11, 2003 through August 29, 2003 from exercising any remedies resulting from the failure of all of the projects to achieve Project Completion. At that time, EBG stated that it would continue to monitor the projects, assess all of its options relating to the projects, and continue discussions with the lenders. Project Completion was not achieved by July 12, 2003, resulting in an event of default under the EBG Facility. The EBG Facility is non-recourse to Generation and an event of default under the EBG Facility does not constitute an event of default under any other debt instruments of Exelon or its subsidiaries. Mystic 8 and 9 and Fore River are in commercial operation, although they have not yet achieved Project Completion. As a result of Exelon's continuing evaluation of the projects and discussions with the lenders, Exelon has commenced the process of an orderly transition out of the ownership of EBG and the projects. The transition will take place in a manner that complies with applicable regulatory requirements. For a period of time, Exelon expects to continue to provide administrative and operational services to EBG in its operation of the projects. Exelon informed the lenders of its decision to exit and that it will not provide additional funding to the projects beyond its existing contractual obligations. Exelon cannot predict the timing of the transition. The debt outstanding under the EBG Facility of approximately $1.1 billion at September 30, 2003 is reflected in Exelon's Consolidated Balance Sheet as a current liability. On June 13, 2003, Generation closed on a $550 million revolving credit facility. Generation used the facility to make the first payment to Sithe of $210 million relating to the $536 million note, which was established in connection with the acquisition of Exelon New England. On September 29, 2003, Generation replaced the $550 million facility with a new $850 million revolving credit facility. The existing $210 million of borrowings under the original facility remain outstanding under the new credit facility. The note with Sithe was restructured in the third quarter to provide for the remaining balance of $326 million to be paid in two installments. Generation will be required to repay $236 million of the principal on the earlier of December 1, 2003 or change of control, and the remaining principal balance on the earlier of December 1, 2004 or change of control. Generation's $850 million facility is also expected to provide the initial funding of the acquisition of British Energy's 50% interest in AmerGen. 103 Exelon's access to the capital markets, including the commercial paper market, and its financing costs in those markets depend on the securities ratings of the entity that is accessing the capital markets. None of Exelon's borrowings is subject to default or prepayment as a result of a downgrading of securities ratings although such a downgrading could increase fees and interest charges under Exelon's $1.5 billion credit facility and certain other credit facilities. From time to time, Exelon enters into energy commodity and other contracts that require the maintenance of investment grade ratings. Failure to maintain investment grade ratings would allow counterparties to certain energy commodity contracts to terminate the contracts and settle the transactions on a net present value basis. As part of the normal course of business, Exelon and Generation routinely enter into physical or financially settled contracts for the purchase and sale of capacity, energy, fuels and emissions allowances. These contracts either contain express provisions or otherwise permit Exelon, Generation and its counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if Exelon or Generation is downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is possible that a counterparty could attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance. Depending on Exelon or Generation's net position with a counterparty, the demand could be for the posting of collateral. In the absence of expressly agreed to provisions that specify the collateral that must be provided, the obligation to supply the collateral requested will be a function of the facts and circumstances of Exelon or Generation's situation at the time of the demand. If Exelon or Generation can reasonably claim that it is willing and financially able to perform its obligations, it may be possible to successfully argue that no collateral should be posted or that only an amount equal to two or three months of future payments should be sufficient. Exelon obtained an order from the United States Securities and Exchange Commission (SEC) under PUHCA authorizing through March 31, 2004 financing transactions, including the issuance of common stock, preferred securities, long-term debt and short-term debt, in an aggregate amount not to exceed $4 billion. As of September 30, 2003, there was $2.7 billion of financing authority remaining under the SEC order. Exelon's request for an additional $4 billion in financing authorization is pending with the SEC. The current order limits Exelon's short-term debt outstanding to $3 billion of the $4 billion total financing authority. Exelon's request that the short-term debt sub-limit restriction be eliminated is pending with the SEC. The SEC order also authorized Exelon to issue guarantees of up to $4.5 billion outstanding at any one time. At September 30, 2003, Exelon had provided $1.85 billion of guarantees under the SEC order. See Contractual Obligations, Commercial Commitments and Off-Balance Sheet Obligations in this section for further discussion of guarantees. The SEC order requires Exelon and ComEd to maintain a ratio of common equity to total capitalization (including securitization debt) on and after September 30, 2002 of not less than 30%. At September 30, 2003, Exelon and ComEd's common equity ratios were 35% and 47%, respectively. Exelon and ComEd expect that they will maintain a common equity ratio of at least 30%. Under PUHCA, Exelon, ComEd, PECO and Generation can pay dividends only from retained, undistributed or current earnings. Furthermore, a significant loss recorded at ComEd 104 may limit the dividends that ComEd can distribute to Exelon. However, the SEC order granted permission to ComEd, and to Exelon, to the extent Exelon receives dividends from ComEd paid from ComEd additional paid-in-capital, to pay up to $500 million in dividends out of additional paid-in capital, although Exelon may not pay dividends out of paid-in capital after December 31, 2002 if its common equity is less than 30% of its total capitalization. At September 30, 2003, Exelon had retained earnings of $2.2 billion, including ComEd's retained earnings of $836 million, PECO's retained earnings of $517 million and Generation's undistributed earnings of $577 million. Exelon is also limited by order of the SEC under PUHCA to an aggregate investment of $4 billion in exempt wholesale generators (EWGs) and foreign utility companies (FUCOs). At September 30, 2003, Exelon had invested $2.8 billion in EWGs, leaving $1.2 billion of investment authority under the order. Exelon's request for an additional $1.5 billion in EWG investment authorization is pending with the SEC. Contractual Obligations, Commercial Commitments and Off-Balance Sheet Obligations Contractual obligations represent cash obligations that are considered to be firm commitments and commercial commitments represent commitments triggered by future events. Exelon's contractual obligations and commercial commitments as of September 30, 2003 were materially unchanged, other than the normal course of business, from the amounts set forth in the 2002 Form 10-K except for the following: o On March 3, 2003, ComEd entered into an agreement with various Illinois electric retail market suppliers, key customer groups and governmental parties regarding several matters affecting ComEd's rates for electric service (Agreement). The Agreement addressed, among other things, issues related to ComEd's delivery services rate proceeding, market value index proceeding, the process for competitive service declarations for large-load customers and an extension of the PPA with Generation. During the second quarter of 2003, the ICC issued orders consistent with the Agreement, which is now effective. The Agreement provides for a modification of the methodology used to determine ComEd's market value energy credit. That credit is used to determine the price for specified market-based rate offerings and the amount of the CTC that ComEd is allowed to collect from customers who select an ARES or the PPO. The credit was adjusted upwards through agreed upon "adders" which took effect in June 2003 and will have the effect of reducing ComEd's CTC charges to customers. Prior to the Agreement, all CTC charges were subject to annual mid-year adjustments based on the forward market prices for on-peak energy and historical market prices for off-peak energy. The Agreement provides that the annual market price adjustment will reflect forward market prices for energy, rather than historical, and allows customers an option to lock in current levels of CTC charges for multi-year periods during the regulatory transition period ending in 2006. These changes provide customers and suppliers greater price certainty and are expected to result in an increase in the number of customers electing to purchase energy from alternate suppliers. The annual market price adjustments to the CTC effective in June 2002 and June 2003 had the effect of significantly increasing the CTC charge in June 2002, and subsequently significantly reducing the CTC charge in June 2003. In 2002, ComEd collected $306 million in CTC revenue. Based on the changes in the CTC as part of the Agreement and 105 on current assumptions about the competitive price of delivered energy and customers' choice of electric supplier, ComEd estimates that CTC revenue will be approximately $300 million in 2003 and approximately $140 million for each of the years 2004 through 2006. During the first quarter of 2003, ComEd recorded a charge to earnings associated with the funding of specified programs and initiatives associated with the Agreement of $51 million on a present value basis before income taxes. This amount was partially offset by the reversal of a $12 million (before income taxes) reserve established in the third quarter of 2002 for a potential capital disallowance in ComEd's delivery services rate proceeding and a credit of $10 million (before income taxes) related to the capitalization of employee incentive payments provided for in the delivery services order. The net one-time charge for these items was $29 million (before income taxes). o ComEd and PECO have entered into several agreements with a tax consultant related to the filing of refund claims with the Internal Revenue Service (IRS) and have made refundable prepayments of $11 million and $1 million, respectively, for potential fees associated with these agreements. The fees for these agreements are contingent upon a successful outcome and are based upon a percentage of the refunds recovered from the IRS, if any. As such, ultimate net cash flows to ComEd and PECO related to these agreements will either be positive or neutral depending upon the outcome of the refund claim with the IRS. These potential tax benefits and associated fees could be material to the financial position, results of operations and cash flows of Energy Delivery. ComEd's tax benefits for periods prior to the Merger would be recorded as a reduction of goodwill pursuant to a reallocation of the Merger purchase price. Energy Delivery cannot predict the timing of the final resolution of these refund claims. o See Note 12 to the Condensed Combined Notes to Consolidated Financial Statements for discussion of material changes in Exelon's debt and preferred securities obligations from those set forth in the 2002 Form 10-K. o Generation entered into a PPA dated June 26, 2003 with AmerGen. Under the PPA, Generation has agreed to purchase 100% of energy generated by Oyster Creek through April 9, 2009. See Note 9 of the Condensed Combined Notes to Consolidated Financial Statements for the commercial commitments table representing Exelon's commitments not recorded on the balance sheet but potentially triggered by future events, including obligations to make payment on behalf of other parties and financing arrangements to secure their obligations. o On May 29, 2003, Exelon Fossil Holdings, Inc., a wholly owned subsidiary of Generation, issued an irrevocable call notice for the purchase of the 35.2% interest in Sithe owned by Apollo Energy, LLC and the 14.9% interest owned by subsidiaries of Marubeni Corporation. The total purchase price under the call was based on the terms of the existing Put and Call Agreement (PCA) among the parties and is $621 million. The transfer of ownership requires various regulatory approvals, including the Federal Energy Regulatory Commission (FERC), the state environmental agency in New Jersey, and expiration of the Hart Scott Rodino 106 waiting period. Early termination of the Hart Scott Rodino waiting period was granted effective August 22, 2003. Under the terms of the PCA, the purchase price must be funded within six months of the call notice being issued. Additionally, because the Federal Power Act restricts Generation's ownership of more than 50% of qualifying facilities, the qualifying facilities owned by Sithe must be sold or restructured before closing to preserve their status as qualifying facilities. See below for information regarding a separate agreement reached by Sithe to sell six U.S. generating facilities, each a qualifying facility, and an entity holding Sithe's Canadian assets. At the closing, Sithe is expected to distribute in excess of $600 million of available cash to Generation. On August 13, 2003, Generation announced an agreement with entities controlled by Reservoir Capital Group (Reservoir), a private investment firm, to sell 50% of Sithe in exchange for $75.8 million in cash. The sale will occur after Generation's purchase of the remaining 50.1% interest in Sithe. The sale requires FERC approval, a Hart Scott Rodino filing and a filing with the state regulatory commission in New York. Both of these filings have been made. Early termination of the Hart Scott Rodino waiting period was granted September 30, 2003. The sale is expected to close in the fourth quarter of 2003. Both Generation and Reservoir's 50% interests in Sithe will be subject to put and call options that could result in either party owning 100% of Sithe. While Generation's intent is to fully divest Sithe by the end of 2004, the timing of the put and call options vary by acquirer and can extend through March 2006. The pricing of the put and call options is dependent on numerous factors such as the acquirer, date of acquisition and assets owned by Sithe at the time of exercise. In a separate transaction, Sithe has entered into an agreement with Reservoir to sell entities holding six U.S. generating facilities, each a qualifying facility under the Public Utility Regulatory Policies Act, and an entity holding Sithe's Canadian assets in exchange for $46.2 million ($26.2 million in cash and a $20 million two-year note). The sale requires approvals from Sithe's board of directors and shareholders and regulatory filings in New Jersey and Canada. Both of these filings have been made. The sale is also expected to close in the fourth quarter of 2003. This sale is not contingent on the sale of Exelon's 50% interest in Sithe to Reservoir. o In June 2003, Generation entered an agreement with USEC Inc. to purchase approximately $700 million of nuclear fuel from 2005 through 2010. o On August 14, 2003, Generation received a letter from the DOE demanding repayment of $40 million of previously received credits from the Nuclear Waste Fund. The letter also demanded $1.5 million of accrued interest expense. Although a new settlement would offset Generation's payments, Generation nonetheless has reserved its 50% ownership share of these amounts. Because Generation expenses the casks and capitalizes the permanent components of its spent fuel storage facilities, these reserves increased Generation's operating and maintenance expense approximately $11 million and its capital base 107 approximately $9 million during the third quarter of 2003. The remainder of the recorded obligation to the DOE will be recovered from the co-owner of the facility. See Note 9 - Nuclear Decommissioning and Spent Nuclear Fuel Storage in Generation's 2002 Form 10-K for additional information regarding this matter. o Under the Price-Anderson Act, all nuclear reactor licensees can be assessed a maximum charge per reactor per incident. Effective August 20, 2003, the maximum assessment for all nuclear operators per reactor per incident (including a 5% surcharge) increased from $89 million to $101 million. The maximum payable per reactor per incident per year of $10 million is unchanged. The change in the maximum assessment is the result of an inflation adjustment, required by the Price-Anderson Act. Based on the increase of the maximum assessment, Exelon's nuclear insurance guarantees increased from $1,380 million to $1,559 million. o On October 10, 2003, Exelon executed an agreement to purchase British Energy's 50% interest in AmerGen for $276.5 million. The transaction is expected to close in the first half of 2004. The purchase price matched the offer by FPL Energy, which announced on September 11, 2003 that it intended to buy British Energy's share of AmerGen. Under the AmerGen limited liability company operating agreement between Exelon and British Energy, either can exercise a right of first refusal by matching any bona fide third-party offer agreed to by the other member. See Note 4 of the Condensed Combined Notes to Consolidated Financial Statements for additional information regarding AmerGen. 108 COMMONWEALTH EDISON COMPANY --------------------------- GENERAL ComEd operates in a single business segment and its operations consist of the regulated sale of electricity and distribution and transmission services in northern Illinois. RESULTS OF OPERATIONS Three Months Ended September 30, 2003 Compared to Three Months Ended September 30, 2002 Significant Operating Trends - ComEd
Three Months Ended September 30, -------------------------------- 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- OPERATING REVENUES $ 1,737 $ 1,938 $ (201) (10.4%) OPERATING EXPENSES Purchased power 891 975 (84) (8.6%) Operating and maintenance 299 267 32 12.0% Depreciation and amortization 97 129 (32) (24.8%) Taxes other than income 87 77 10 13.0% ----------------------------------------------------------------------------------------------------- Total operating expenses 1,374 1,448 (74) (5.1%) ----------------------------------------------------------------------------------------------------- OPERATING INCOME 363 490 (127) (25.9%) ----------------------------------------------------------------------------------------------------- OTHER INCOME AND DEDUCTIONS Interest expense (107) (122) 15 (12.3%) Distributions on mandatorily redeemable preferred securities (6) (7) 1 (14.3%) Other, net 15 -- 15 n.m. ----------------------------------------------------------------------------------------------------- Total other income and deductions (98) (129) 31 (24.0%) ----------------------------------------------------------------------------------------------------- INCOME BEFORE INCOME TAXES 265 361 (96) (26.6%) INCOME TAXES 102 146 (44) (30.1%) ----------------------------------------------------------------------------------------------------- NET INCOME $ 163 $ 215 $ (52) (24.2%) ===================================================================================================== n.m. - not meaningful
Net Income Net income decreased $52 million, or 24%, for the three months ended September 30, 2003 as compared to the same period in 2002. Net income was negatively impacted by lower operating revenues net of purchased power expense primarily due to unfavorable weather, and charges associated with The Exelon Way severance partially offset by lower amortization expense and lower interest expense. 109 Operating Revenues ComEd's electric sales statistics were as follows:
Three Months Ended September 30, -------------------------------- Retail Deliveries - (in GWhs) 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Bundled Deliveries (1) Residential 8,197 9,121 (924) (10.1%) Small Commercial & Industrial 5,749 6,029 (280) (4.6%) Large Commercial & Industrial 1,539 2,073 (534) (25.8%) Public Authorities & Electric Railroads 1,269 1,612 (343) (21.3%) ------------------------------------------------------------------------------------------------- 16,754 18,835 (2,081) (11.0%) ------------------------------------------------------------------------------------------------- Unbundled Deliveries (2) ARES ---- Small Commercial & Industrial 1,721 1,640 81 4.9% Large Commercial & Industrial 2,934 2,192 742 33.9% Public Authorities & Electric Railroads 426 299 127 42.5% ------------------------------------------------------------------------------------------------- 5,081 4,131 950 23.0% ------------------------------------------------------------------------------------------------- PPO --- Small Commercial & Industrial 884 782 102 13.0% Large Commercial & Industrial 896 1,249 (353) (28.3%) Public Authorities & Electric Railroads 428 345 83 24.1% ------------------------------------------------------------------------------------------------- 2,208 2,376 (168) (7.1%) ------------------------------------------------------------------------------------------------- Total Unbundled Deliveries 7,289 6,507 782 12.0% ------------------------------------------------------------------------------------------------- Total Retail Deliveries 24,043 25,342 (1,299) (5.1%) ================================================================================================= (1) Bundled service reflects deliveries to customers taking electric service under tariffed rates. (2) Unbundled service reflects customers electing to receive electric generation service from an ARES or the PPO.
110
Three Months Ended September 30, -------------------------------- Electric Revenue 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Bundled Revenues (1) Residential $ 760 $ 840 $ (80) (9.5%) Small Commercial & Industrial 487 506 (19) (3.8%) Large Commercial & Industrial 82 106 (24) (22.6%) Public Authorities & Electric Railroads 82 104 (22) (21.2%) ------------------------------------------------------------------------------------------------- 1,411 1,556 (145) (9.3%) ------------------------------------------------------------------------------------------------- Unbundled Revenues (2) ARES ---- Small Commercial & Industrial 34 51 (17) (33.3%) Large Commercial & Industrial 41 60 (19) (31.7%) Public Authorities & Electric Railroads 8 10 (2) (20.0%) ------------------------------------------------------------------------------------------------- 83 121 (38) (31.4%) ------------------------------------------------------------------------------------------------- PPO --- Small Commercial & Industrial 65 57 8 14.0% Large Commercial & Industrial 56 74 (18) (24.3%) Public Authorities & Electric Railroads 26 19 7 36.8% ------------------------------------------------------------------------------------------------- 147 150 (3) (2.0%) ------------------------------------------------------------------------------------------------- Total Unbundled Revenues 230 271 (41) (15.1%) ------------------------------------------------------------------------------------------------- Total Electric Retail Revenues 1,641 1,827 (186) (10.2%) Wholesale and Miscellaneous Revenue (3) 96 111 (15) (13.5%) ------------------------------------------------------------------------------------------------- Total Electric Revenue $ 1,737 $ 1,938 $ (201) (10.4%) ================================================================================================= (1) Bundled revenue reflects deliveries to customers taking electric service under tariffed rates, which include the cost of energy and the delivery cost of the transmission and the distribution of the energy. (2) Revenue from customers choosing an ARES includes a distribution charge and a CTC charge. Transmission charges received from ARES are included in wholesale and miscellaneous revenue. Revenue from customers choosing the PPO includes an energy charge at market rates, transmission and distribution charges, and a CTC charge. (3) Wholesale and miscellaneous revenues include transmission revenue, sales to municipalities and other wholesale energy sales.
The changes in electric retail revenues for the three months ended September 30, 2003, as compared to the same period in 2002, are attributable to the following:
Variance ------------------------------------------------------------------------------------------------------------------- Weather $ (143) Rate changes (52) Customer choice (36) Volume 40 Other effects 5 ------------------------------------------------------------------------------------------------------------------- Electric retail revenue $ (186) ===================================================================================================================
o Weather. The demand for electricity is impacted by weather conditions. Very warm weather in summer months and very cold weather in other months are 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, 2003 was unfavorable compared to the same period in 2002 as a result of cooler summer weather in 2003. Cooling degree-days decreased 25% in the three months 111 ended September 30, 2003 compared to the same period in 2002, and were 3% lower than normal. o Rate Changes. The decrease in collection of CTCs in 2003 by ComEd of $81 million due to a decrease in the CTC rates due to higher wholesale market prices of electricity, net of increased mitigation factors. This was partially offset by increased wholesale market prices which increased energy revenue received under ComEd's PPO by $29 million. Starting in the June 2003 billing cycle the increased wholesale market price of electricity, net of increased mitigation factors, as a result of the Agreement described in Note 5 of the Condensed Combined Notes to Consolidated Financial Statements, decreases the collection of CTCs as compared to the respective period in 2002. o Customer Choice. All ComEd customers have the choice to purchase energy from other suppliers. This choice generally does not impact the volume of deliveries, but affects revenue collected from customers related to energy supplied by ComEd. However, as of September 30, 2003, no ARES has sought approval from the ICC, and no electric utilities have chosen to enter the ComEd residential market for the supply of electricity. For the three months ended September 30, 2003, the energy provided by alternative suppliers was 5,081 GWhs, or 21.1%, as compared to 4,131 GWhs, or 16.3%, for the three months ended September 30, 2002. The decrease in revenues reflects customers in Illinois electing to purchase energy from an ARES or the PPO. As of September 30, 2003, the number of retail customers that had elected to purchase energy from an ARES or the ComEd PPO was approximately 20,000, or 0.6%, as compared to 22,700, or 0.6%, as of September 30, 2002. MWhs delivered to such customers increased from approximately 6.5 million for the three months ended September 30, 2002 to 7.3 million for the three months ended September 30, 2003, or from 26% to 30% of total quarterly retail deliveries. o Volume. Revenues from higher delivery volume, exclusive of weather, increased due to an increased usage per customer, primarily residential and small commercial and industrial. Wholesale and miscellaneous revenue for the three months ended September 30, 2003 compared to the three months ended September 30, 2002 decreased $15 million primarily due to a 2002 reimbursement from Generation of $12 million for third-party energy reconciliations. Purchased Power Purchased power expense decreased $84 million, or 9%, for the three months ended September 30, 2003. The decrease in purchased power expense was primarily attributable to a $75 million decrease due to unfavorable weather conditions, a $42 million decrease as a result of customers choosing to purchase energy from an ARES, a $20 million decrease due to additional energy billed in 2002 under the PPA with Generation as a result of third-party energy reconciliations discussed in the operating revenue section above, partially offset by an increase of $22 million due to higher volume, $21 million increase due to pricing changes related to ComEd's PPA with Generation and an increase of $16 million under the PPA related to decommissioning collections associated with the adoption of SFAS No. 143. The $16 million increase in purchased power expense related to SFAS No. 143 had no impact on net income as it was offset by lower regulatory asset amortization in depreciation and amortization expense. 112 Operating and Maintenance O&M expense increased $32 million, or 12%, for the three months ended September 30, 2003. The increase in O&M expense was primarily attributable to $60 million of The Exelon Way severance and related postretirement health and welfare benefits accruals and pension and postretirement curtailment costs and $12 million of additional storm-related costs, partially offset by a 2002 $17 million increase in manufactured gas plant (MGP) investigation and remediation reserve charges net of 2003 increases, a decrease in payroll expenses of $15 million due to fewer employees, and a decrease of $6 million in bad debt expense. Depreciation and Amortization Depreciation and amortization expense decreased $32 million, or 25%, for the three months ended September 30, 2003 as follows:
Three Months Ended September 30, -------------------------------- 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Depreciation expense $ 77 $ 75 $ 2 2.7% Recoverable transition costs amortization 12 33 (21) (63.6%) Other amortization expense 8 21 (13) (61.9%) ------------------------------------------------------------------------------------------------- Total depreciation and amortization $ 97 $ 129 $ (32) (24.8%) =================================================================================================
The increase in depreciation expense is primarily due to higher property, plant and equipment balances. Recoverable transition costs amortization decreased in the three months ended September 30, 2003 compared to the same period in 2002. The decrease is a result of additional amortization in 2002. ComEd expects to fully recover its recoverable transition costs regulatory asset balance of $141 million by 2006. Consistent with the provision of the Illinois legislation, regulatory assets may be recovered at amounts that provide ComEd an earned return on common equity within the Illinois legislation earnings threshold. The decrease in other amortization primarily relates to the reclassification of a regulatory asset for nuclear decommissioning as a result of the adoption of SFAS No. 143 in 2003 (see Note 2 of the Condensed Combined Notes to Consolidated Financial Statements). This decrease had no impact on net income as it was offset by increased purchased power from Generation. Taxes Other Than Income Taxes other than income increased by $10 million, or 13%, as a result of a $5 million real estate tax refund in 2002 and $8 million in 2003 for use tax payments for periods prior to the Merger. Interest Charges Interest charges consist of interest expense and distributions on mandatorily redeemable preferred securities. Interest charges decreased $16 million, or 12%, for the three months ended September 30, 2003 as a result of scheduled principal payments and refinancing existing debt at lower interest rates. 113 Other, Net Other, net increased by $15 million for the three months ended September 30, 2003 as compared to the same period in 2002. In 2002, ComEd recorded a $12 million reserve accrual for a potential plant disallowance from an audit performed in conjunction with ComEd's delivery services rate case. This $12 million was reversed in March 2003 as a result of the March 3, 2003 agreement - as more fully described in Note 5 to the Condensed Combined Notes to Consolidated Financial Statements. Income Taxes The effective income tax rate was 38.5% for the three months ended September 30, 2003, compared to 40.4% for the three months ended September 30, 2002. Nine Months Ended September 30, 2003 Compared to Nine Months Ended September 30, 2002 Significant Operating Trends - ComEd
Nine Months Ended September 30, ------------------------------- 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- OPERATING REVENUES $ 4,522 $ 4,734 $ (212) (4.5%) OPERATING EXPENSES Purchased power 2,001 2,066 (65) (3.1%) Operating and maintenance 781 724 57 7.9% Depreciation and amortization 287 397 (110) (27.7%) Taxes other than income 235 223 12 5.4% ----------------------------------------------------------------------------------------------------- Total operating expenses 3,304 3,410 (106) (3.1%) ----------------------------------------------------------------------------------------------------- OPERATING INCOME 1,218 1,324 (106) (8.0%) ----------------------------------------------------------------------------------------------------- OTHER INCOME AND DEDUCTIONS Interest expense (322) (374) 52 (13.9%) Distributions on mandatorily redeemable preferred securities (20) (22) 2 (9.1%) Other, net 48 29 19 65.5% ----------------------------------------------------------------------------------------------------- Total other income and deductions (294) (367) 73 (19.9%) ----------------------------------------------------------------------------------------------------- INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE 924 957 (33) (3.4%) INCOME TAXES 365 381 (16) (4.2%) ----------------------------------------------------------------------------------------------------- NET INCOME BEFORE CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE 559 576 (17) (3.0%) CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE 5 -- 5 n.m. ----------------------------------------------------------------------------------------------------- NET INCOME $ 564 $ 576 $ (12) (2.1%) ===================================================================================================== n.m. - not meaningful
Net Income Net income decreased $12 million, or 2%, for the nine months ended September 30, 2003 as compared to the same period in 2002. Net income was negatively impacted by lower operating revenues net of purchased power expense primarily due to unfavorable weather, and 114 charges associated with The Exelon Way severance partially offset by lower depreciation and amortization expense and lower interest expense. Operating Revenues ComEd's electric sales statistics were as follows:
Nine Months Ended September 30, ------------------------------- Retail Deliveries - (in GWhs) 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Bundled Deliveries (1) Residential 20,246 21,392 (1,146) (5.4%) Small Commercial & Industrial 16,490 17,078 (588) (3.4%) Large Commercial & Industrial 4,706 6,151 (1,445) (23.5%) Public Authorities & Electric Railroads 4,018 5,097 (1,079) (21.2%) ------------------------------------------------------------------------------------------------- 45,460 49,718 (4,258) (8.6%) ------------------------------------------------------------------------------------------------- Unbundled Deliveries (2) ARES ---- Small Commercial & Industrial 4,327 3,822 505 13.2% Large Commercial & Industrial 6,894 5,200 1,694 32.6% Public Authorities & Electric Railroads 954 618 336 54.4% ------------------------------------------------------------------------------------------------- 12,175 9,640 2,535 26.3% ------------------------------------------------------------------------------------------------- PPO --- Small Commercial & Industrial 2,546 2,384 162 6.8% Large Commercial & Industrial 3,646 3,952 (306) (7.7%) Public Authorities & Electric Railroads 1,497 861 636 73.9% ------------------------------------------------------------------------------------------------- 7,689 7,197 492 6.8% ------------------------------------------------------------------------------------------------- Total Unbundled Deliveries 19,864 16,837 3,027 18.0% ------------------------------------------------------------------------------------------------- Total Retail Deliveries 65,324 66,555 (1,231) (1.8%) ================================================================================================= (1) Bundled service reflects deliveries to customers taking electric service under tariffed rates. (2) Unbundled service reflects customers electing to receive electric generation service from an ARES or the PPO.
115
Nine Months Ended September 30, ------------------------------- Electric Revenue 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Bundled Revenues (1) Residential $ 1,778 $ 1,881 $ (103) (5.5%) Small Commercial & Industrial 1,289 1,343 (54) (4.0%) Large Commercial & Industrial 240 324 (84) (25.9%) Public Authorities & Electric Railroads 247 297 (50) (16.8%) ------------------------------------------------------------------------------------------------- 3,554 3,845 (291) (7.6%) ------------------------------------------------------------------------------------------------- Unbundled Revenues (2) ARES ---- Small Commercial & Industrial 106 94 12 12.8% Large Commercial & Industrial 133 101 32 31.7% Public Authorities & Electric Railroads 25 18 7 38.9% ------------------------------------------------------------------------------------------------- 264 213 51 23.9% ------------------------------------------------------------------------------------------------- PPO --- Small Commercial & Industrial 174 155 19 12.3% Large Commercial & Industrial 199 214 (15) (7.0%) Public Authorities & Electric Railroads 81 48 33 68.8% ------------------------------------------------------------------------------------------------- 454 417 37 8.9% ------------------------------------------------------------------------------------------------- Total Unbundled Revenues 718 630 88 14.0% ------------------------------------------------------------------------------------------------- Total Electric Retail Revenues 4,272 4,475 (203) (4.5%) Wholesale and Miscellaneous Revenue (3) 250 259 (9) (3.5%) ------------------------------------------------------------------------------------------------- Total Electric Revenue $ 4,522 $ 4,734 $ (212) (4.5%) ================================================================================================= (1) Bundled revenue reflects deliveries to customers taking electric service under tariffed rates, which include the cost of energy and the delivery cost of the transmission and the distribution of the energy. (2) Revenue from customers choosing an ARES includes a distribution charge and a CTC charge. Transmission charges received from ARES are included in wholesale and miscellaneous revenue. Revenue from customers choosing the PPO includes an energy charge at market rates, transmission and distribution charges, and a CTC charge. (3) Wholesale and miscellaneous revenues include transmission revenue, sales to municipalities and other wholesale energy sales.
The changes in electric retail revenues for the nine months ended September 30, 2003, as compared to the same period in 2002, are attributable to the following:
Variance ------------------------------------------------------------------------------------------------------------------- Weather $ (197) Customer choice (113) Volume 72 Rate changes 23 Other effects 12 ------------------------------------------------------------------------------------------------------------------- Electric retail revenue $ (203) ===================================================================================================================
o Weather. The weather impact for the nine months ended September 30, 2003 was unfavorable compared to the same period in 2002 as a result of cooler summer weather in 2003. Cooling degree-days decreased 36% in the nine months ended September 30, 2003 compared to the same period in 2002 and were partially offset by a 15% increase in heating degree days in the nine months ended September 30, 2003 compared to the same period in 2002. 116 o Customer Choice. The decrease in revenues reflects customers in Illinois electing to purchase energy from an ARES or the PPO. For the nine months ended September 30, 2003, the energy provided by alternative suppliers was 12,175 GWhs, or 18.6%, as compared to 9,640 GWhs, or 14.5%, for the nine months ended September 30, 2002. As of September 30, 2003, the number of retail customers that had elected to purchase energy from an ARES or the ComEd PPO was approximately 20,000, or 0.6%, as compared to 22,700, or 0.6%, as of September 30, 2002. MWhs delivered to such customers increased from approximately 16.8 million for the nine months ended September 30, 2002 to 19.9 million for the nine months ended September 30, 2003, or from 25% to 30% of total year-to-date retail deliveries. o Volume. Revenues from higher delivery volume, exclusive of weather, increased due to an increased number of customers and increased usage per customer, primarily residential and small commercial and industrial. o Rate Changes. The increase in revenues attributable to rate changes reflects the collection of additional CTCs in 2003 by ComEd of $65 million due to an increase in sales to customers choosing an ARES or the ComEd PPO and an increase in CTC rates due to the lower wholesale market price of electricity, net of increased mitigation factors. Lower wholesale market prices decreased revenue received under ComEd's PPO by $42 million. Starting in the June 2003 billing cycle, the increased wholesale market price of electricity, net of increased mitigation factors, as a result of the Agreement described in Note 5 of the Condensed Combined Notes to Consolidated Financial Statements, decreases the collection of CTCs as compared to the respective period in 2002. Wholesale and miscellaneous revenue for the nine months ended September 30, 2003 compared to the nine months ended September 30, 2002 decreased $9 million primarily due to a 2002 reimbursement from Generation of $12 million for third-party energy reconciliations. Purchased Power Purchased power expense decreased $65 million, or 3%, for the nine months ended September 30, 2003. The decrease in purchased power expense was primarily attributable to a $102 million decrease due to unfavorable weather and a $91 million decrease as a result of customers choosing to purchase energy from an ARES, a $20 million decrease due to additional energy billed in 2002 under the PPA with Generation as a result of third-party energy reconciliations discussed in the operating revenue section above, partially offset by an increase of $44 million due to higher volume, an increase of $60 million due to pricing changes related to ComEd's PPA with Generation and an increase of $47 million under the PPA related to decommissioning collections associated with the adoption of SFAS No. 143 that were not included in purchased power in 2002. The $47 million increase in purchased power expense related to SFAS No. 143 had no impact on net income as it was offset by lower regulatory asset amortization in depreciation and amortization expense. Operating and Maintenance O&M expense increased $57 million, or 8%, for the nine months ended September 30, 2003. The increase in O&M expense was primarily attributable to a net one-time charge of $41 million in 2003 as the result of the Agreement as more fully described in Note 5 of the 117 Condensed Combined Notes to Consolidated Financial Statements, $60 million due to The Exelon Way severance and related postretirement health and welfare benefits accruals and pension and postretirement curtailment costs, $13 million of additional storm-related costs and $16 million increase in employee fringe benefits partially offset by $5 million of higher corporate allocations in 2002 due to executive severance, $12 million lower MGP investigation and remediation reserve charges, net of 2003 increases, and $53 million decrease in payroll expenses due to fewer employees. Depreciation and Amortization Depreciation and amortization expense decreased $110 million, or 28%, for the nine months ended September 30, 2003 as follows:
Nine Months Ended September 30, ------------------------------- 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Depreciation expense $ 229 $ 258 $ (29) (11.2%) Recoverable transition costs amortization 34 75 (41) (54.7%) Other amortization expense 24 64 (40) (62.5%) ------------------------------------------------------------------------------------------------- Total depreciation and amortization $ 287 $ 397 $ (110) (27.7%) =================================================================================================
The decrease in depreciation expense is primarily due to lower depreciation rates effective July 1, 2002, partially offset by higher property, plant and equipment balances. ComEd completed a depreciation study and implemented lower depreciation rates effective July 1, 2002. The new depreciation rates reflect ComEd's significant construction program in recent years, changes in and development of new technologies, and changes in estimated plant service lives since the last depreciation study. The annual reduction in depreciation expense is estimated to be approximately $100 million ($60 million, net of income taxes) based on December 31, 2001 plant balances. As a result of the change, depreciation expense decreased $48 million ($29 million, net of income taxes) for the nine months ended September 30, 2003. The decrease in depreciation expense is partially offset by increased depreciation due to capital additions. Recoverable transition costs amortization decreased in the nine months ended September 30, 2003 compared to the same period in 2002. The decrease is a result of additional amortization in 2002. ComEd expects to fully recover its recoverable transition costs regulatory asset balance of $141 million by 2006. Consistent with the provision of the Illinois legislation, regulatory assets may be recovered at amounts that provide ComEd an earned return on common equity within the Illinois legislation earnings threshold. The decrease in other amortization primarily relates to the reclassification of a regulatory asset for nuclear decommissioning as a result of the adoption of SFAS No. 143 in 2003 (see Note 2 of the Condensed Combined Notes to Consolidated Financial Statements). This decrease had no impact on net income as it was offset by increased purchased power from Generation. Taxes Other Than Income Taxes other than income increased $12 million or 5%, for the nine months ended September 30, 2003 primarily as a result of $5 million in Illinois Public Utility Fund taxes that were not charged in 2002, a $5 million real estate tax refund in 2002 and $8 million in 2003 for 118 use tax payments for periods prior to the Merger, partially offset by a $5 million refund in 2003 of Illinois Electricity Distribution taxes. Interest Charges Interest charges consist of interest expense and distributions on mandatorily redeemable preferred securities. Interest charges decreased $54 million, or 14%, for the nine months ended September 30, 2003. The decrease in interest expense was primarily attributable to the impact of lower interest rates as a result of refinancing existing debt at lower interest rates for the nine months ended September 30, 2003 as compared to the nine months ended September 30, 2002 and the annual retirement of $340 million in Transitional Trust Notes. Other, Net Other, net increased $19 million or 66%, for the nine months ended September 30, 2003 as compared to the same period in 2002. In 2002, ComEd recorded a $12 million reserve accrual for a potential plant disallowance from an audit performed in conjunction with ComEd's delivery services rate case. This $12 million was reversed in March 2003 as a result of the March 3, 2003 agreement - as more fully described in Note 5 to the Condensed Combined Notes to Consolidated Financial Statements. Income Taxes The effective income tax rate was 39.5% for the nine months ended September 30, 2003, compared to 39.8% for the nine months ended September 30, 2002. Due to revenue needs in the states in which ComEd operates, various state income tax and fee increases have been proposed or are being contemplated. If these changes are enacted, they could increase ComEd's state income tax expense. At this time, however, ComEd cannot predict whether legislation or regulation will be introduced, the form of any legislation or regulation, whether any such legislation or regulation will be passed by the state legislatures or regulatory bodies, and, if enacted, whether any such legislation or regulation would be effective retroactively or prospectively. As a result, ComEd cannot currently estimate the effect of these potential changes in tax laws or regulation. Cumulative Effect of a Change in Accounting Principle On January 1, 2003, ComEd adopted SFAS No. 143, resulting in income of $5 million, net of tax. See Note 2 of the Condensed Combined Notes to Consolidated Financial Statements for further discussion of the adoption of SFAS No. 143. 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, participation in the intercompany money pool or capital contributions from Exelon. ComEd's access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where ComEd no longer has access to external financing sources at reasonable 119 terms, ComEd has access to a revolving credit facility that ComEd currently utilizes to support its commercial paper program. See the Credit Issues section of Liquidity and Capital Resources for further discussion. Capital resources are used primarily to fund ComEd's capital requirements, including construction, repayments of maturing debt and the payment of dividends. As part of the implementation of The Exelon Way, ComEd has identified 451 positions for elimination by the end of 2004 and anticipates identifying additional positions for elimination in 2005 and 2006. ComEd recorded a charge for cash severance of $37 million during the third quarter 2003, which ComEd anticipates will be paid by December 31, 2004. ComEd anticipates incurring further costs associated with The Exelon Way upon identifying additional positions to be eliminated. These costs will be recorded in the period in which the costs can be reasonably estimated. Cash Flows from Operating Activities Cash flows provided by operations were $742 million for the nine months ended September 30, 2003 compared to $1.5 billion for the nine months ended September 30, 2002. The decrease in cash flows in 2003 was primarily attributable to a $504 million decrease in working capital as a result of the paydown of payables to affiliates and other outstanding liabilities, a decrease of $127 million for pension and non-pension postretirement benefits obligation, a decrease in depreciation and amortization of $110 million. ComEd's future cash flows will depend upon the ability to achieve cost savings in operations and the impact of the economy, weather, customer choice and future regulatory proceedings 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 $450 million for the nine months ended September 30, 2003 compared to $528 million for the nine months ended September 30, 2002. The decrease in cash flows used in investing activities in 2003 was primarily attributable to the receipt of $213 million from Unicom Investments Inc. related to an intercompany note payable partially offset by $147 million invested in the Exelon intercompany money pool. ComEd estimates that it will spend approximately $720 million in total capital expenditures for 2003. Approximately two-thirds of the budgeted 2003 expenditures are for continuing efforts to further improve the reliability of its transmission and distribution systems. The remaining one third is for capital additions to support new business and customer growth. ComEd anticipates that its capital expenditures will be funded by internally generated funds, borrowings, the issuance of preferred securities, or capital contributions from Exelon. ComEd's proposed capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors. 120 Cash Flows from Financing Activities Cash flows used in financing activities were $186 million for the nine months ended September 30, 2003 as compared to cash flows used in financing of $970 million for the nine months ended September 30, 2002. Cash flows used in financing activities were primarily attributable to debt issuances and payments of dividends to Exelon, partially offset by retirements and redemptions. The decrease in cash flows used in financing activities is primarily attributable to increased debt and preferred securities issuances of $926 million, partially offset by increased debt and preferred securities redemptions of $139 million and increased interest rate swap settlement payments of $35 million. See Note 12 of the Condensed Combined Notes to Consolidated Financial Statements for further discussion of ComEd's debt and preferred securities financing activities. ComEd paid a $305 million dividend to Exelon during the nine months ended September 30, 2003 compared to a $353 million dividend for the nine months ended September 30, 2002. Credit Issues ComEd meets its short-term liquidity requirements primarily through the issuance of commercial paper. ComEd, along with Exelon, PECO and Generation, participates in a $1.5 billion unsecured 364-day revolving credit facility with a group of banks. The credit facility that became effective on November 22, 2002 includes a term-out option that allows any outstanding borrowings at the end of the revolving credit period to be repaid on November 21, 2004. Exelon may increase or decrease the sublimits of each of the participants upon written notification to the banks. As of September 30, 2003, ComEd's sublimit was $100 million. The credit facility is used principally to support ComEd's commercial paper program. At September 30, 2003, ComEd had no commercial paper outstanding. For the nine months ended September 30, 2003, the average interest rate on notes payable was approximately 1.47%. The credit facility requires ComEd to maintain a cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The ratio excludes revenues and interest expenses attributable to securitization of debt, certain changes in working capital, and distributions on preferred securities of subsidiaries. ComEd's threshold for the ratio reflected in the credit agreement cannot be less than 2.25 to 1 for the twelve-month period ended September 30, 2003. At September 30, 2003, ComEd was in compliance with the credit agreement thresholds. To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, Exelon operates an intercompany money pool. Participation in the money pool is subject to authorization by the Exelon corporate treasurer. ComEd, PECO, Generation and BSC may participate in the money pool as lenders and borrowers, and Exelon Corporate may participate as a lender. Funding of, and borrowings from, the money pool are predicated on whether such funding results in mutual economic benefits to each of the participants. Interest on borrowings is based on short-term market rates of interest, or, if from an external source, specific borrowing rates. There were no material money pool transactions in 2002. During the nine months ended September 30, 2003, ComEd had various investments in the money pool. The maximum amount of outstanding 121 investments at any time during 2003 was $344 million. As of September 30, 2003, ComEd's investment in the money pool was $147 million. For the nine months ended September 30, 2003, ComEd earned $2 million in interest. ComEd's access to the capital markets, including the commercial paper market, and its financing costs in those markets are dependent on its securities ratings. None of ComEd's borrowings is subject to default or prepayment as a result of a downgrading of securities ratings although such a downgrading could increase interest charges under certain bank credit facilities. Under PUHCA, ComEd is precluded from lending or extending credit or indemnity to Exelon and can only pay dividends from retained or current earnings. Furthermore, a significant loss recorded at ComEd may limit the dividends that ComEd can distribute to Exelon. 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, 2003, ComEd had retained earnings of $836 million and its common equity ratio was 47%. Long-term debt included $1.7 billion of transitional trust notes. Contractual Obligations, Commercial Commitments and Off-Balance Sheet Obligations Contractual obligations represent cash obligations that are considered to be firm commitments and commercial commitments represent commitments triggered by future events. ComEd's contractual obligations and commercial commitments as of September 30, 2003 were materially unchanged, other than in the normal course of business, from the amounts set forth in the 2002 Form 10-K except for the following: o On March 3, 2003, ComEd entered into the Agreement with various Illinois electric retail market suppliers, key customer groups and governmental parties regarding several matters affecting ComEd's rates for electric service. The Agreement addressed, among other things, issues related to ComEd's delivery services rate proceeding, market value index proceeding, the process for competitive service declarations for large-load customers and an extension of the PPA with Generation. During the second quarter of 2003, the ICC issued orders consistent with the Agreement, which is now effective. The Agreement provides for a modification of the methodology used to determine ComEd's market value energy credit. That credit is used to determine the price for specified market-based rate offerings and the amount of the CTC that ComEd is allowed to collect from customers who select an ARES or the PPO. The credit was adjusted upwards through agreed upon "adders" which took effect in June 2003 and will have the effect of reducing ComEd's CTC charges to customers. Prior to the Agreement, all CTC charges were subject to annual mid-year adjustments based on the forward market prices for on-peak energy and historical market prices for off-peak energy. The Agreement provides that the annual market price adjustment will reflect forward market prices for energy, rather than historical, and allows customers an option to lock in current levels of CTC charges for multi-year periods during the regulatory transition period ending in 2006. These changes provide customers and 122 suppliers greater price certainty and are expected to result in an increase in the number of customers electing to purchase energy from alternate suppliers. The annual market price adjustments to the CTC effective in June 2002 and June 2003 had the effect of significantly increasing the CTC charge in June 2002, and subsequently significantly reducing the CTC charge in June 2003. In 2002, ComEd collected $306 million in CTC revenue. Based on the changes in the CTC as part of the Agreement and on current assumptions about the competitive price of delivered energy and customers' choice of electric supplier, ComEd estimates that CTC revenue will be approximately $300 million in 2003 and approximately $140 million for each of the years 2004 through 2006. In the first quarter of 2003, ComEd recorded a charge to earnings associated with the funding of specified programs and initiatives associated with the Agreement of $51 million on a present value basis before income taxes. This amount is partially offset by the reversal of a $12 million (before income taxes) reserve established in the third quarter of 2002 for a potential capital disallowance in ComEd's delivery services rate proceeding and a credit of $10 million (before income taxes) related to the capitalization of employee incentive payments provided for in the delivery services order. The net one-time charge for these items is $29 million (before income taxes). o ComEd has entered into several agreements with a tax consultant related to the filing of refund claims with the IRS and has made refundable prepayments of $11 million for potential fess associated with these agreements. The fees for these agreements are contingent upon a successful outcome and are based upon a percentage of the refunds recovered from the IRS, if any. As such, ultimate net cash flows to ComEd related to these agreements will either be positive or neutral depending upon the outcome of the refund claim with the IRS. These potential tax benefits and associated fees could be material to the financial position, results of operations and cash flows of ComEd. ComEd's tax benefits for periods prior to the Merger would be recorded as a reduction of goodwill pursuant to a reallocation of the Merger purchase price. ComEd cannot predict the timing of the final resolution of these refund claims. o See Note 12 to the Condensed Combined Notes to Consolidated Financial Statements for discussion of material changes in ComEd's debt and preferred securities obligations from those set forth in the 2002 Form 10-K. o See Note 9 of the Condensed Combined Notes to Consolidated Financial Statements for the commercial commitments table representing ComEd's commitments not recorded on the balance sheet but potentially triggered by future events, including obligations to make payment on behalf of other parties and financing arrangements to secure their obligations. 123 PECO ENERGY COMPANY ------------------- GENERAL PECO operates in a single business segment, and its operations consist of the regulated sale of electricity and distribution and transmission in southeastern Pennsylvania and the sale of natural gas and distribution services in the Pennsylvania counties surrounding the City of Philadelphia. RESULTS OF OPERATIONS Three Months Ended September 30, 2003 Compared to Three Months Ended September 30, 2002 Significant Operating Trends - PECO
Three Months Ended September 30, -------------------------------- 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- OPERATING REVENUES $ 1,149 $ 1,224 $ (75) (6.1%) OPERATING EXPENSES Purchased power 482 509 (27) (5.3%) Fuel 28 40 (12) (30.0%) Operating and maintenance 192 140 52 37.1% Depreciation and amortization 134 127 7 5.5% Taxes other than income 12 85 (73) (85.9%) ----------------------------------------------------------------------------------------------------- Total operating expenses 848 901 (53) (5.9%) ----------------------------------------------------------------------------------------------------- OPERATING INCOME 301 323 (22) (6.8%) ----------------------------------------------------------------------------------------------------- OTHER INCOME AND DEDUCTIONS Interest expense (73) (93) 20 (21.5%) Interest expense to affiliate (2) -- (2) n.m. Distributions on mandatorily redeemable preferred securities (1) (2) 1 (50.0%) Other, net (10) 5 (15) n.m. ----------------------------------------------------------------------------------------------------- Total other income and deductions (86) (90) 4 (4.4%) ----------------------------------------------------------------------------------------------------- INCOME BEFORE INCOME TAXES 215 233 (18) (7.7%) INCOME TAXES 74 76 (2) (2.6%) ----------------------------------------------------------------------------------------------------- NET INCOME 141 157 (16) (10.2%) Preferred stock dividends (1) (2) 1 (50.0%) ----------------------------------------------------------------------------------------------------- NET INCOME ON COMMON STOCK $ 140 $ 155 $ (15) (9.7%) ===================================================================================================== n.m. - not meaningful
124 Net Income Net income on common stock decreased $15 million, or 10%, for the three months ended September 30, 2003 as compared to the same period in 2002. The decrease was a result of lower sales volume, unfavorable weather conditions, increased O&M related to storm-related damage, and The Exelon Way severance costs, partially offset by lower other operating and maintenance expenses, taxes other than income and interest expense on debt. Operating Revenue PECO's electric sales statistics were as follows:
Three Months Ended September 30, -------------------------------- Retail Deliveries - (in GWhs) 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Bundled Deliveries (1) Residential 3,333 3,422 (89) (2.6%) Small Commercial & Industrial 1,753 2,066 (313) (15.2%) Large Commercial & Industrial 4,013 4,006 7 0.2% Public Authorities & Electric Railroads 217 224 (7) (3.1%) ------------------------------------------------------------------------------------------------- 9,316 9,718 (402) (4.1%) ------------------------------------------------------------------------------------------------- Unbundled Deliveries (2) Residential 258 371 (113) (30.5%) Small Commercial & Industrial 520 154 366 n.m. Large Commercial & Industrial 208 236 (28) (11.9%) Public Authorities & Electric Railroads (3) -- -- -- -- ------------------------------------------------------------------------------------------------- 986 761 225 29.6% ------------------------------------------------------------------------------------------------- Total Retail Deliveries 10,302 10,479 (177) (1.7%) ================================================================================================= (1) Bundled service reflects deliveries to customers taking electric service under tariffed rates. (2) Unbundled service reflects customers electing to receive electric generation service from an alternative energy supplier. (3) PECO's unbundled sales to Public Authorities and Electric Railroads were less than one GWh per quarter.
125
Three Months Ended September 30, -------------------------------- Electric Revenue 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Bundled Revenue (1) Residential $ 466 $ 478 $ (12) (2.5%) Small Commercial & Industrial 211 251 (40) (15.9%) Large Commercial & Industrial 292 296 (4) (1.4%) Public Authorities & Electric Railroads 19 21 (2) (9.5%) ------------------------------------------------------------------------------------------------- 988 1,046 (58) (5.5%) ------------------------------------------------------------------------------------------------- Unbundled Revenue (2) Residential 20 32 (12) (37.5%) Small Commercial & Industrial 28 9 19 n.m. Large Commercial & Industrial 5 7 (2) (28.6%) Public Authorities & Electric Railroads (3) -- -- -- -- ------------------------------------------------------------------------------------------------- 53 48 5 10.4% ------------------------------------------------------------------------------------------------- Total Electric Retail Revenues 1,041 1,094 (53) (4.8%) Wholesale and Miscellaneous Revenue (4) 55 63 (8) (12.7%) ------------------------------------------------------------------------------------------------- Total Electric Revenue $ 1,096 $ 1,157 $ (61) (5.3%) ================================================================================================= (1) Bundled revenue reflects revenue from customers taking electric service under tariffed rates, which includes the cost of energy, the delivery cost of the transmission and the distribution of the energy and a CTC charge. (2) Unbundled revenue reflects revenue from customers electing to receive generation from an alternative supplier, which includes a distribution charge and a CTC charge. (3) PECO's unbundled sales to Public Authorities and Electric Railroads were less than $1 million per quarter. (4) Wholesale and miscellaneous revenues include transmission revenue and other wholesale energy sales.
The changes in electric retail revenues for the three months ended September 30, 2003, as compared to the same period in 2002, were as follows:
Variance ------------------------------------------------------------------------------------------------------------------- Rate mix $ (21) Weather (18) Customer choice (14) Volume 1 Other effects (1) ------------------------------------------------------------------------------------------------------------------- Retail revenue $ (53) ===================================================================================================================
o Rate Mix. The decrease in revenues from rate mix is due to changes in monthly usage patterns in all customer classes during the three months ended September 30, 2003 as compared to the same period in 2002. o Weather. The demand for electricity is impacted by weather conditions. Very warm weather in summer months and very cold weather in other months are referred to as "favorable weather conditions" because these weather conditions result in increased sales of electricity. Conversely, mild weather reduces demand. The weather impact was unfavorable compared to the prior year as a result of cooler summer weather during the quarter. Cooling degree-days decreased 11%. o Customer Choice. All PECO customers may choose to purchase energy from other suppliers. This choice generally does not impact kWh deliveries, but reduces revenue collected from customers because they are not obtaining generation supply from PECO. 126 For the three months ended September 30, 2003, the energy provided by alternative suppliers was 986 GWhs, or 9.6%, as compared to 761 GWhs, or 7.3%, for the three months ended September 30, 2002. As of September 30, 2003, the number of customers served by alternative suppliers was 297,821, or 19.6%, as compared to 285,549, or 18.7%, as of September 30, 2002. The PUC's Final Electric Restructuring Order established MST to promote competition. The MST requirements provide that if, as of January 1, 2003, less than 50% of residential and commercial customers have chosen an alternative electric generation supplier, the number of customers sufficient to meet the MST shall be randomly selected and assigned to an alternative electric generation supplier through a PUC determined process. On January 1, 2003, the number of customers choosing an alternative electric generation supplier did not meet the MST. In January 2003, PECO submitted to the PUC an MST plan to meet the 50% threshold requirement for its commercial customers, which was approved by the PUC in February 2003. As of March 31, 2003, an auction had been completed for the commercial customers. In May 2003, the customer enrollment phase was completed and customers that did not choose to opt out of the program were transferred to the alternative electric generation suppliers. In February 2003, PECO filed a residential customer MST plan, and on May 1, 2003, the PUC approved the plan. The approved plan provides for a two-step process with a total of up to 400,000 residential customers being assigned to winning alternative electric generation supplier bidders: up to 100,000 in July 2003, and another 300,000 in December 2003. The auction for the first phase of the residential program received no supplier bids. Therefore, according to the MST plan requirements, 75% of those customers are required to be added to the auction for the second phase of the residential program for a total of 375,000 customers. In September 2003, the auction for the second phase of the residential customer MST plan resulted in two winning bidders who were awarded an aggregate of 267,000 residential customers. The selected customers will be transferred during December 2003. No renewable bids were received for any customers. Any customer transferred has the right to return to PECO at any time. PECO does not expect the transfer of customers pursuant to the MST plan to have a material impact on its results of operations, financial position or cash flows. o Volume. Exclusive of weather impacts, higher delivery volume affected PECO's revenue by $1 million compared to the same period in 2002 primarily related to decreases in usage by the residential class offset by an increase in usage by the small commercial and industrial class. 127 PECO's gas sales statistics for the three months ended September 30, 2003 as compared to the same period in 2002 were as follows:
Three Months Ended September 30, -------------------------------- Deliveries to customers in mmcf 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Retail sales 3,498 3,805 (307) (8.1%) Transportation 6,012 7,542 (1,530) (20.3%) ----------------------------------------------------------------------------------------------------- Total 9,510 11,347 (1,837) (16.2%) ===================================================================================================== Three Months Ended September 30, -------------------------------- Revenue 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Retail sales $ 47 $ 43 $ 4 9.3% Transportation 4 5 (1) (20.0%) Resales and other 2 19 (17) (89.5%) ----------------------------------------------------------------------------------------------------- Total $ 53 $ 67 $ (14) (20.9%) =====================================================================================================
The changes in gas retail revenue for the three months ended September 30, 2003 as compared to the same period in 2002, were as follows:
Variance ------------------------------------------------------------------------------------------------------------------- Rate changes $ 6 Volume (2) ------------------------------------------------------------------------------------------------------------------- Total gas retail revenues $ 4 ===================================================================================================================
o Rate Changes. The favorable variance in rate changes is attributable to increases of 15% and 7% in the purchased gas adjustment by the PUC effective March 1, 2003 and June 1, 2003, respectively. The average rate per million cubic feet for the three months ended September 30, 2003 was 18% higher than the same period in 2002. PECO's gas rates are subject to periodic adjustments by the PUC and are designed to recover from or refund to customers the difference between the 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 Volume. Delivery volume was lower in the three months ended September 30, 2003 compared to the same period in 2002 due to decreased retail sales in all customer classes. The reduction in transportation volumes and revenues are primarily the result of lower intercompany deliveries to Generation during the three months ended September 30, 2003 compared to the same period in 2002. Lower resale revenues are attributable to a decrease in off-system sales, exchanges and capacity releases during the three months ended September 30, 2003 compared to the same period in 2002. 128 Purchased Power Purchased power expense for the three months ended September 30, 2003 decreased $27 million, or 5%, as compared to the same period in 2002. The decrease in purchased power expense was primarily attributable to $11 million of unfavorable weather conditions, $11 million from customers in Pennsylvania selecting an alternative electric generation supplier and $9 million related to lower PJM ancillary charges, partially offset by higher delivery volumes of $3 million. Fuel Fuel expense for the three months ended September 30, 2003 decreased $12 million, or 30%, as compared to the same period in 2002. This decrease was primarily attributable to lower wholesale sales of gas of $17 million, partially offset by higher gas prices and volumes of $4 million. Operating and Maintenance O&M expense for the three months ended September 30, 2003 increased $52 million, or 37%, as compared to the same period in 2002. The increase in O&M expense was primarily attributable to $41 million of severance and related postretirement health and welfare benefits accruals and pension and postretirement curtailment costs associated with The Exelon Way, $18 million of higher storm-related costs, $4 million of higher corporate allocations, and $2 million of higher expense related to the allowance for the uncollectible accounts, partially offset by $10 million of lower costs associated with the initial implementation of automated meter reading services in 2002 and a $7 million decrease in payroll expense. Depreciation and Amortization Depreciation and amortization expense for the three months ended September 30, 2003 increased $7 million, or 6%, as compared to the same period in 2002 was as follows:
Three Months Ended September 30, -------------------------------- 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Competitive transition charge amortization $ 96 $ 90 $ 6 6.7% Depreciation expense 33 31 2 6.5% Other amortization expense 5 6 (1) (16.7%) ------------------------------------------------------------------------------------------------- Total depreciation and amortization $ 134 $ 127 $ 7 5.5% =================================================================================================
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 three months ended September 30, 2003 decreased $73 million, or 86%, as compared to the same period in 2002. The decrease was primarily attributable to $58 million related to the reversal of real estate tax accruals during the third quarter of 2003, $9 million related to 2002 real estate tax expense, $3 million related to 2002 capital stock tax and $3 million of lower gross receipts tax related to lower revenues. 129 Interest Charges Interest charges consist of interest expense, interest expense to affiliate and distributions on mandatorily redeemable preferred securities. Interest charges decreased $19 million, or 20%, in the three months ended September 30, 2003 as compared to the same period in 2002. The decrease was primarily attributable to lower interest expense on long-term debt of $10 million as a result of less outstanding debt and refinancing of existing debt at lower rates, and a reversal of accrued interest expense on federal income taxes of $8 million. Other, Net Other, net decreased income by $15 million in the three months ended September 30, 2003 as compared to the same period in 2002. The decrease was attributable to reversal of interest income on federal income taxes. Income Taxes The effective tax rate was 34.4% for the three months ended September 30, 2003 as compared to 32.6% for the same period in 2002. The increase in the effective tax rate primarily reflects the impact of changes in income before income taxes. Preferred Stock Dividends Preferred stock dividends for the three months ended September 30, 2003 were consistent as compared to the same period in 2002. 130 Nine Months Ended September 30, 2003 Compared to Nine Months Ended September 30, 2002 Significant Operating Trends - PECO
Nine Months Ended September 30, ------------------------------- 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- OPERATING REVENUES $ 3,328 $ 3,239 $ 89 2.7% OPERATING EXPENSES Purchased power 1,290 1,265 25 2.0% Fuel 285 228 57 25.0% Operating and maintenance 453 407 46 11.3% Depreciation and amortization 370 348 22 6.3% Taxes other than income 123 207 (84) (40.6%) ----------------------------------------------------------------------------------------------------- Total operating expenses 2,521 2,455 66 2.7% ----------------------------------------------------------------------------------------------------- OPERATING INCOME 807 784 23 2.9% ----------------------------------------------------------------------------------------------------- OTHER INCOME AND DEDUCTIONS Interest expense (241) (280) 39 (13.9%) Interest expense to affiliate (2) -- (2) n.m. Distributions on mandatorily redeemable preferred securities (6) (7) 1 (14.3%) Other, net -- 7 (7) n.m. ----------------------------------------------------------------------------------------------------- Total other income and deductions (249) (280) 31 (11.1%) ----------------------------------------------------------------------------------------------------- INCOME BEFORE INCOME TAXES 558 504 54 10.7% INCOME TAXES 193 166 27 16.3% ----------------------------------------------------------------------------------------------------- NET INCOME 365 338 27 8.0% Preferred stock dividends (4) (6) 2 (33.3%) ----------------------------------------------------------------------------------------------------- NET INCOME ON COMMON STOCK $ 361 $ 332 $ 29 8.7% ===================================================================================================== n.m. - not meaningful
Net Income Net income on common stock increased $29 million, or 9%, for the nine months ended September 30, 2003 as compared to the same period in 2002. The increase was a result of higher sales volume, favorable weather conditions, lower interest expense and taxes other than income, partially offset by increased O&M resulting from storm-related damage, and The Exelon Way severance costs, increased income taxes and depreciation and amortization expense. 131 Operating Revenue PECO's electric sales statistics were as follows:
Nine Months Ended September 30, ------------------------------- Retail Deliveries (in GWhs) 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Bundled Deliveries (1) Residential 8,723 7,592 1,131 14.9% Small Commercial & Industrial 5,065 5,704 (639) (11.2%) Large Commercial & Industrial 11,190 11,285 (95) (0.8%) Public Authorities & Electric Railroads 692 617 75 12.2% ------------------------------------------------------------------------------------------------- 25,670 25,198 472 1.9% ------------------------------------------------------------------------------------------------- Unbundled Deliveries (2) Residential 708 1,720 (1,012) (58.8%) Small Commercial & Industrial 1,044 253 791 n.m. Large Commercial & Industrial 610 351 259 73.8% Public Authorities & Electric Railroads (3) -- -- -- -- ------------------------------------------------------------------------------------------------- 2,362 2,324 38 1.6% ------------------------------------------------------------------------------------------------- Total Retail Deliveries 28,032 27,522 510 1.9% ================================================================================================= (1) Bundled service reflects deliveries to customers taking electric service under tariffed rates. (2) Unbundled service reflects customers electing to receive electric generation service from an alternative energy supplier. (3) PECO's unbundled sales to Public Authorities and Electric Railroads were less than one GWh per quarter.
Nine Months Ended September 30, ------------------------------- Electric Revenue 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Bundled Revenue (1) Residential $ 1,122 $ 999 $ 123 12.3% Small Commercial & Industrial 585 664 (79) (11.9%) Large Commercial & Industrial 825 829 (4) (0.5%) Public Authorities & Electric Railroads 62 58 4 6.9% ------------------------------------------------------------------------------------------------- 2,594 2,550 44 1.7% ------------------------------------------------------------------------------------------------- Unbundled Revenue (2) Residential 52 129 (77) (59.7%) Small Commercial & Industrial 54 13 41 n.m. Large Commercial & Industrial 16 10 6 60.0% Public Authorities & Electric Railroads (3) -- -- -- -- ------------------------------------------------------------------------------------------------- 122 152 (30) (19.7%) ------------------------------------------------------------------------------------------------- Total Electric Retail Revenues 2,716 2,702 14 0.5% Wholesale and Miscellaneous Revenue (4) 164 179 (15) (8.4%) ------------------------------------------------------------------------------------------------- Total Electric Revenue $ 2,880 $ 2,881 $ (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 the distribution of the energy and a CTC charge. (2) Unbundled revenue reflects revenue from customers electing to receive generation from an alternative supplier, which includes a distribution charge and a CTC charge. (3) PECO's unbundled sales to Public Authorities and Electric Railroads were less than $1 million per quarter. (4) Wholesale and miscellaneous revenues include transmission revenue and other wholesale energy sales.
132 The changes in electric retail revenues for the nine months ended September 30, 2003, as compared to the same period in 2002, were as follows:
Variance ------------------------------------------------------------------------------------------------------------------- Volume $ 37 Weather 8 Rate Mix (28) Customer choice (3) ------------------------------------------------------------------------------------------------------------------- Retail revenue $ 14 ===================================================================================================================
o Volume. Exclusive of weather impacts, higher delivery volume affected PECO's revenue by $37 million compared to the same period in 2002 primarily related to increases in the small and large commercial and industrial customer classes. o Weather. The weather impact was favorable compared to the prior year as a result of colder winter weather partially offset by cooler summer weather. Heating degree-days increased 35% and cooling degree-days decreased 19% for the nine months ended September 30, 2003 compared to the same period in 2002. o Rate Mix. The decrease in revenues from rate mix is due to changes in monthly usage patterns in all customer classes during the nine months ended September 30, 2003 as compared to the same period in 2002. o Customer Choice. All PECO customers may choose to purchase energy from other suppliers. This choice generally does not impact kWh deliveries, but reduces revenue collected from customers because they are not obtaining generation supply from PECO. For the nine months ended September 30, 2003, the energy provided by alternative suppliers was 2,362 GWhs, or 8.4%, as compared to 2,324 GWhs, or 8.4%, for the nine months ended September 30, 2002. As of September 30, 2003, the number of customers served by alternative suppliers was 297,821, or 19.6%, as compared to 285,549, or 18.7%, as of September 30, 2002. PECO's gas sales statistics and revenue detail were as follows:
Nine Months Ended September 30, ------------------------------- Deliveries to customers in mmcf 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Retail sales 44,183 34,128 10,055 29.5% Transportation 19,954 22,862 (2,908) (12.7%) ----------------------------------------------------------------------------------------------------- Total 64,137 56,990 7,147 12.5% ===================================================================================================== Nine Months Ended September 30, ------------------------------- Revenue 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Retail sales $ 418 $ 309 $ 109 35.3% Transportation 14 15 (1) (6.7%) Resales and other 16 34 (18) (52.9%) ----------------------------------------------------------------------------------------------------- Total $ 448 $ 358 $ 90 25.1% =====================================================================================================
133 The changes in gas retail revenue for the nine months ended September 30, 2003 as compared to the same period in 2002, were as follows:
Variance ------------------------------------------------------------------------------------------------------------------- Weather $ 73 Volume 21 Rate changes 15 ------------------------------------------------------------------------------------------------------------------- Total gas retail revenue $ 109 ===================================================================================================================
o Weather. The weather impact was favorable compared to the prior year as a result of colder winter weather. Heating degree-days increased 35% in the nine months ended September 30, 2003 compared to the same period in 2002. Retail sales deliveries increased approximately 8,600 mmcf due to the colder weather. o Volume. Exclusive of weather impacts, higher delivery volume increased revenue in the nine months ended September 30, 2003 compared to the same period in 2002 resulting from increased retail sales in all classes. Deliveries to retail customers increased approximately 1,500 mmcf, or 4% in the nine months ended September 30, 2003 compared to the same period in 2002. o Rate Changes. The favorable variance in rates is attributable to increases of 15% and 7% in the purchased gas adjustment by the PUC effective March 1, 2003 and June 1, 2003, respectively. The average rate per mmcf for the nine months ended September 30, 2003 was 5% higher than the rate in the same 2002 period. PECO's gas rates are subject to periodic adjustments by the PUC and are designed to recover from or refund to customers the difference between actual cost of purchased gas and the amount included in base rates and to recover or refund increases or decreases in certain state taxes not recovered in base rates. The reduction in transportation volumes and revenues are primarily the result of lower intercompany deliveries to Generation during the nine months ended September 30, 2003 compared to the same period in 2002. Lower resale revenues are attributable to a decrease in off-system sales, exchanges and capacity releases during the nine months ended September 30, 2003 compared to the same period in 2002. Purchased Power Purchased power expense for the nine months ended September 30, 2003 increased $25 million, or 2%, as compared to the same period in 2002. The increase in purchased power expense was primarily attributable to $24 million of higher electric delivery volume and $2 million related to higher PJM ancillary charges. Fuel Fuel expense for the nine months ended September 30, 2003 increased $57 million, or 25%, as compared to the same period in 2002. This increase was primarily attributable to $50 million of favorable weather conditions, $15 million from higher gas prices and $11 million of higher delivery volumes, partially offset by $24 million in reductions from resale transactions. 134 Operating and Maintenance O&M expense for the nine months ended September 30, 2003 increased $46 million, or 11% as compared to the same period in 2002. The increase in O&M expense was primarily attributable to $41 million of severance and related postretirement health and welfare benefits accruals and pension and postretirement curtailment costs associated with The Exelon Way, $22 million of higher storm-related costs, $12 million of increased employee fringe benefits, partially offset by $23 million of lower costs associated with the initial implementation of automated meter reading services in 2002, $7 million of lower expense related to the allowance for uncollectible accounts and $6 million of additional miscellaneous other net positive impacts. Depreciation and Amortization Depreciation and amortization expense for the nine months ended September 30, 2003 increased $22 million, or 6%, as compared to the same period in 2002 as follows:
Nine Months Ended September 30, ------------------------------- 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Competitive transition charge amortization $ 256 $ 236 $ 20 8.5% Depreciation expense 99 94 5 5.3% Other amortization expense 15 18 (3) (16.7%) ------------------------------------------------------------------------------------------------- Total depreciation and amortization $ 370 $ 348 $ 22 6.3% =================================================================================================
The additional amortization of the CTC is in accordance with PECO's original settlement under the Pennsylvania Competition Act and the increase in depreciation expense resulted from additional plant in service. Taxes Other Than Income Taxes other than income for the nine months ended September 30, 2003 decreased $84 million, or 41%, as compared to the same period in 2002. The decrease was primarily attributable to a $58 million reversal of real estate tax accruals during the third quarter of 2003, a $12 million reversal of the use tax accrual due to an audit settlement and a $12 million decrease in 2003 real estate tax expense. Interest Charges Interest charges consist of interest expense, interest expense to affiliates and distributions on mandatorily redeemable preferred securities. Interest charges decreased $38 million, or 13%, in the nine months ended September 30, 2003 as compared to the same period in 2002. The decrease was primarily attributable to lower interest expense on long-term debt of $28 million as a result of scheduled principal payments and refinancing of existing debt at lower interest rates and an $8 million reversal of accrued interest expense on federal income taxes. Other, Net Other, net decreased $7 million in the nine months ended September 30, 2003 as compared to the same period in 2002. The decrease was primarily attributable to reversal of interest income on federal income taxes of $14 million, partially offset by $4 million related to higher interest income and the favorable settlement of a customer contract of $3 million. 135 Income Taxes The effective tax rate was 34.6% for the nine months ended September 30, 2003 as compared to 32.9% for the same period in 2002. The increase in the effective tax rate primarily reflects the impact of changes in income before income taxes. Due to revenue needs in the states in which PECO operates, various state income tax and fee increases have been proposed or are being contemplated. If these changes are enacted, they could increase PECO's state income tax expense. At this time, however, PECO cannot predict whether legislation or regulation will be introduced, the form of any legislation or regulation, whether any such legislation or regulation will be passed by the state legislatures or regulatory bodies, and, if enacted, whether any such legislation or regulation would be effective retroactively or prospectively. As a result, PECO cannot currently estimate the effect of these potential changes in tax laws or regulation. Preferred Stock Dividends Preferred stock dividends for the nine months ended September 30, 2003 were consistent as compared to the same period in 2002. LIQUIDITY AND CAPITAL RESOURCES PECO's business is capital intensive and requires considerable capital resources. PECO's capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing including the issuance of commercial paper, participation in the intercompany money pool or capital contributions from Exelon. PECO's access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where PECO no longer has access to external financing sources at reasonable terms, PECO has access to a revolving credit facility that PECO currently utilizes to support its commercial paper program. See the Credit Issues section of Liquidity and Capital Resources for further discussion. Capital resources are used primarily to fund PECO's capital requirements, including construction, repayments of maturing debt and payment of dividends. As part of the implementation of The Exelon Way, PECO has identified 140 positions for elimination by the end of 2004 and anticipates identifying additional positions for elimination in 2005 and 2006. PECO recorded a charge for cash severance of $13 million during the third quarter 2003, which PECO anticipates will be paid by December 31, 2004. PECO anticipates incurring further costs associated with The Exelon Way upon identifying additional positions to be eliminated. These costs will be recorded in the period in which the costs can be reasonably estimated. 136 Cash Flows from Operating Activities Cash flows provided by operations for the nine months ended September 30, 2003 and 2002 were $757 million and $473 million, respectively. The increase in cash flows was primarily attributable to a $300 million increase in working capital and by a $27 million increase in net income, partially offset by an $83 million change in deferred energy costs. PECO's cash flow from operating activities primarily results from sales of electricity and gas to a stable and diverse base of retail customers at fixed prices. PECO's future cash flows will depend upon the ability to achieve operating cost reductions and the impact of the economy, weather, customer choice and future regulatory proceedings 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, 2003 and 2002 were $193 million and $177 million, respectively. The increase in cash flows used in investing activities was primarily attributable to an increase in capital expenditures. PECO's projected capital expenditures for 2003 are $272 million. Approximately 60% of the budgeted 2003 expenditures are for continuing efforts to further improve the reliability of its transmission and distribution systems. The remainder is for capital additions to support new business and customer growth. PECO anticipates that its capital expenditures will be funded by internally generated funds, borrowings, the issuance of preferred securities, or capital contributions from Exelon. PECO's proposed capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors. 137 Cash Flows from Financing Activities Cash flows used in financing activities for the nine months ended September 30, 2003 and 2002 were $545 million and $214 million, respectively. Cash flows used in financing activities are primarily attributable to debt service and payment of dividends to Exelon. The increase in cash flows used in financing activities is primarily attributable to increased debt and preferred securities redemptions of $681 million, partially offset by additional issuances of long-term debt of $328. See Note 12 of the Condensed Combined Notes to Consolidated Financial Statements for further discussion of PECO's debt financing activities. For the nine months ended September 30, 2003, PECO paid Exelon $244 million in common stock dividends compared to $255 million for the same period in 2002. Credit Issues PECO meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from Exelon's intercompany money pool. PECO, along with Exelon, ComEd and Generation, participates in a $1.5 billion unsecured 364-day revolving credit facility with a group of banks. The credit facility became effective November 22, 2002 and includes a term-out option that allows any outstanding borrowings at the end of the revolving credit period to be repaid on November 21, 2004. Exelon may increase or decrease the sublimits of each of the participants upon written notification to the banks. As of September 30, 2003, PECO's sublimit was $400 million. The credit facility is used by PECO principally to support its commercial paper program. At September 30, 2003, PECO's Consolidated Balance Sheet reflected $12 million in commercial paper outstanding. For the nine months ended September 30, 2003, the average interest rate on notes payable was approximately 1.25%. The credit facility requires PECO to maintain a cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The ratio excludes revenues and interest expenses attributable to securitization debt, certain changes in working capital and distributions on preferred securities of subsidiaries. PECO's threshold for the ratio reflected in the credit agreement cannot be less than 2.25 to 1 for the twelve-month period ended September 30, 2003. At September 30, 2003, PECO was in compliance with the credit agreement thresholds. To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, Exelon operates an intercompany money pool. Participation in the money pool is subject to authorization by Exelon's corporate treasurer. ComEd, PECO, Generation and BSC may participate in the money pool as lenders and borrowers, and Exelon Corporate may participate as a lender. Funding of, and borrowings from, the money pool are predicated on whether such funding results in mutual economic benefits to each of the participants. Interest on borrowings is based on short-term market rates of interest, or, if from an external source, specific borrowing rates. During the nine months ended September 30, 2003, PECO had various investments in the money pool. The maximum amount of outstanding investments at any time during 2003 was $59 million. As of September 30, 2003, there was no outstanding investment balance. For the nine months ended September 30, 2003, PECO earned less than $1 million in interest. 138 PECO's access to the capital markets, including the commercial paper market, and its financing costs in those markets are dependent on its securities ratings. None of PECO's borrowings is subject to default or prepayment as a result of a downgrading of securities ratings although such a downgrading could increase interest charges under certain bank credit facilities. Under PUHCA, PECO is precluded from lending or extending credit or indemnity to Exelon and can pay dividends only from retained or current earnings. At September 30, 2003, PECO had retained earnings of $517 million. Long-term debt included $4 billion of transition bonds. Contractual Obligations, Commercial Commitments and Off-Balance Sheet Obligations Contractual obligations represent cash obligations that are considered to be firm commitments and commercial commitments represent commitments triggered by future events. PECO's contractual obligations and commercial commitments as of September 30, 2003 were materially unchanged, other than in the normal course of business, from the amounts set forth in the 2002 Form 10-K except for the following: o PECO has entered into several agreements with a tax consultant related to the filing of refund claims with the IRS and has made refundable prepayments of $1 million for potential fees associated with these agreements. The fees for these agreements are contingent upon a successful outcome and are based upon a percentage of the refunds recovered from the IRS, if any. As such, ultimate net cash flows to PECO related to these agreements will either be positive or neutral depending upon the outcome of the refund claim with the IRS. These potential tax benefits and associated fees could be material to the financial position, results of operations and cash flows of PECO. PECO cannot predict the timing of the final resolution of these refund claims. o See Note 12 of the Condensed Combined Notes to Consolidated Financial Statements for further discussion of material changes in PECO's debt and preferred securities obligations from those set forth in the 2002 Form 10-K. o See Note 9 of the Condensed Combined Notes to Consolidated Financial Statements for the commercial commitments table representing PECO's commitments not recorded on the balance sheet but potentially triggered by future events, including obligations to make payment on behalf of other parties and financing arrangements to secure their obligations. 139 EXELON GENERATION COMPANY, LLC ------------------------------ GENERAL Generation operates as a single segment and its operations consist of electric generating facilities, energy marketing operations and equity interests in Sithe and AmerGen. RESULTS OF OPERATIONS Three Months Ended September 30, 2003 Compared to Three Months Ended September 30, 2002 Significant Operating Trends - Generation
Three Months Ended September 30, -------------------------------- 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- OPERATING REVENUES $ 2,537 $ 2,213 $ 324 14.6% OPERATING EXPENSES Purchased power 1,240 1,257 (17) (1.4%) Fuel 449 273 176 64.5% Impairment of Exelon Boston Generating, LLC 945 -- 945 n.m. Operating and maintenance 530 391 139 35.5% Depreciation and amortization 51 68 (17) (25.0%) Taxes other than income 28 37 (9) (24.3%) ----------------------------------------------------------------------------------------------------- Total operating expenses 3,243 2,026 1,217 60.1% ----------------------------------------------------------------------------------------------------- OPERATING INCOME (LOSS) (706) 187 (893) n.m. ----------------------------------------------------------------------------------------------------- OTHER INCOME AND DEDUCTIONS Interest expense (25) (23) (2) 8.7% Equity in earnings of unconsolidated affiliates 53 87 (34) (39.1%) Other, net (30) 14 (44) n.m. ----------------------------------------------------------------------------------------------------- Total other income and deductions (2) 78 (80) (102.6%) ----------------------------------------------------------------------------------------------------- INCOME (LOSS) BEFORE INCOME TAXES (708) 265 (973) n.m. INCOME TAXES (280) 102 (382) n.m. ----------------------------------------------------------------------------------------------------- NET INCOME (LOSS) $ (428) $ 163 $ (591) n.m. ===================================================================================================== n.m. - not meaningful
Net Income (Loss) Generation's net income decreased by $591 million for the three months ended September 30, 2003 compared to the same period in 2002 primarily due to a $945 million ($573 million, net of income taxes) impairment charge related to Generation's long-lived assets in EBG, an additional $55 million ($36 million, net of income taxes) impairment charge related to Generation's investment in Sithe, and $46 million ($30 million, net of income taxes) due to severance and related postretirement health and welfare benefits accruals and pension and postretirement curtailment costs associated with The Exelon Way. The decrease was partially offset by a $165 million increase in revenue, net of purchased power and fuel. Net income (loss) was additionally affected by a net decrease in the equity in earnings of unconsolidated affiliates. 140 Operating Revenues Revenues increased by $324 million, or 15% for the three months ended September 30, 2003 compared to the same period in 2002. For the three months ended September 30, 2003 and 2002, Generation's sales were as follows:
Three Months Ended September 30, -------------------------------- Revenue (in millions) 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Energy Delivery and Exelon Energy Company $ 1,338 $ 1,461 $ (123) (8.4%) Market Sales 1,138 752 386 51.3% ----------------------------------------------------------------------------------------------------- Total Energy Sales Revenue 2,476 2,213 263 11.9% Trading Portfolio 1 (12) 13 (108.3%) Other Revenue 60 12 48 n.m. ----------------------------------------------------------------------------------------------------- Total Revenue $ 2,537 $ 2,213 $ 324 14.6% ===================================================================================================== Three Months Ended September 30, -------------------------------- Sales (in GWhs) 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Energy Delivery and Exelon Energy Company 32,237 35,996 (3,759) (10.4%) Market Sales 29,613 21,177 8,436 39.8% ----------------------------------------------------------------------------------------------------- Total Sales 61,850 57,173 4,677 8.2% =====================================================================================================
Trading volumes of 11,086 GWhs and 28,455 GWhs for the three months ended September 30, 2003 and 2002, respectively, are not included in the table above. The decrease in trading volume is a result of reduced volumetric and VaR trading limits in 2003, which are set by the Risk Management Committee and approved by the Board of Directors. Generation's average revenue (per MWh) on energy sales for the three months ended September 30, 2003 and 2002 is as follows:
Three Months Ended September 30, -------------------------------- ($/MWh) 2003 2002 % Change ------------------------------------------------------------------------------------------------------------------- Average Revenue Energy Delivery and Exelon Energy Company $ 41.51 $ 40.56 2.3% Market Sales 38.43 35.50 8.3% Total - excluding the trading portfolio 40.03 38.69 3.5% -------------------------------------------------------------------------------------------------------------------
Energy Delivery and Exelon Energy Company. Sales to Energy Delivery decreased by $102 million primarily due to unfavorable weather in ComEd and PECO's service territories during the three months ended September 30, 2003 compared to the same period in 2002. Generation's average revenue per MWh was affected by increased weighted average on and off-peak prices per MWh for supply agreements with ComEd and PECO. Sales to Exelon Energy Company decreased $21 million for the three months ended September 30, 2003 compared to the same period in 2002 primarily due to the discontinuance of Exelon Energy Company operations in the PJM region. 141 Market Sales. The increase in market sales was primarily attributable to a $227 million increase resulting from increased production from generating assets acquired during 2002. In addition, market sales increased $149 million as a result of favorable market prices, primarily driven by increased fossil fuel prices, and a $19 million increase due to lower load requirements to affiliates. Trading Revenues. Trading activity increased revenue by $1 million during the three months ended September 30, 2003 compared to a $12 million decrease for the same period in 2002 due to reduced trading volume and overall portfolio performance improvement in 2003. Other Revenues. Other revenues increased primarily due to increases in natural gas market sales. As a result of natural gas supply contracts assigned to Generation with the 2002 asset acquisitions, Generation had an excess supply of natural gas. Other revenues also include nuclear decommissioning cost recoveries from ComEd and PECO. Purchased Power and Fuel Generation's supply source of its sales and average supply costs are summarized below:
Three Months Ended September 30, -------------------------------- Supply of Sales (in GWhs) 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Nuclear Generation (1) 30,152 29,817 335 1.1% Purchases - non-trading portfolio (2) 24,062 23,425 637 2.7% Fossil and Hydro Generation 7,636 3,931 3,705 94.3% ----------------------------------------------------------------------------------------------------- Total Supply 61,850 57,173 4,677 8.2% ===================================================================================================== (1) Excluding AmerGen. (2) Including PPAs with AmerGen.
Three Months Ended September 30, -------------------------------- ($/MWh) 2003 2002 % Change ----------------------------------------------------------------------------------------------------------------- Average Supply Cost (1) - excluding trading portfolio $ 27.31 $ 26.66 2.4% ----------------------------------------------------------------------------------------------------------------- (1) Average supply cost includes purchased power and fuel costs.
Generation's supply mix changed as a result of: o increased nuclear generation due to a lower number of refueling and unplanned outages during 2003 compared to 2002, o increased fossil generation due to the Exelon New England plants acquired in November 2002, which in total account for an increase of 3,570 GWhs, and o Generation entered into a new PPA with AmerGen in the second quarter of 2003. As a result, 1,228 GWhs were purchased from Oyster Creek in the third quarter of 2003. Purchased power decreased $17 million, or 1%, for the three months ended September 30, 2003 compared to the same period in 2002, primarily due to the positive impact of the Exelon New England plants becoming operational during the three months ended September 30, 2003 and reduced capacity payments as a result of releasing Midwest Generation options. Generation's demand for counterparty purchased power was decreased due to a $29 million increase in purchased power from AmerGen as a result of the June 2003 PPA to purchase 100% of the output of Oyster Creek. The decrease in purchased power was partially offset by a $18 million loss on mark-to-market hedging activity for the three months ended September 30, 2003 compared to no gain or loss in the same period in 2002. 142 Fuel expense increased $176 million, or 65%, for the three months ended September 30, 2003 compared to the same period in 2002, as summarized below:
Three Months Ended September 30, -------------------------------- (in millions) 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Nuclear Generation (1) $ 125 $ 124 $ 1 0.8% Fossil and Hydro Generation 324 149 175 117.4% ----------------------------------------------------------------------------------------------------- Total $ 449 $ 273 $ 176 64.5% ===================================================================================================== (1) Excluding AmerGen
This increase was primarily due to a $154 million increase in fossil fuel costs for generation plant assets acquired in 2002. In addition, fuel expense increased $10 million due to the write down of coal inventory as a result of a fuel burn analysis and $8 million increase due to increased emission allowance trade activity. Impairment of Exelon Boston Generating, LLC In connection with the decision to transition out of the ownership of EBG and the projects, Generation recorded a long-lived asset impairment charge of $945 million ($573 million net of income taxes). Operating and Maintenance O&M expense increased $139 million, or 36%, for the three months ended September 30, 2003 compared to the same period in 2002. The increase in O&M expense was primarily attributable to a $46 million increase in severance and related postretirement health and welfare benefits accruals and pension and postretirement curtailment costs associated with The Exelon Way and $60 million of accretion expense related to SFAS No. 143. Accretion expense includes $39 million of accretion of the asset retirement obligation and $21 million to adjust the earnings impact of certain of the nuclear decommissioning revenues earned from ComEd and PECO, nuclear decommissioning trust fund investment income, income taxes incurred on nuclear decommissioning trust fund activities, accretion of the asset retirement obligation and depreciation of the asset retirement cost asset to zero. For a further discussion of SFAS No. 143, see Note 2 of the Condensed Combined Notes to Consolidated Financial Statements. Operating and maintenance expense also included $30 million of additional expenses due to asset acquisitions made after the third quarter of 2002, and $15 million of additional employee payroll and benefits costs. These increases were partially offset by $9 million of lower nuclear refueling outage costs and $4 million reduction in other O&M costs.
Three Months Ended September 30, -------------------------------- 2003 2002 ------------------------------------------------------------------------------------------------------------------- Nuclear fleet capacity factor (1) 95.3% 93.9% Nuclear fleet production cost per MWh (1) $ 11.69 $ 12.40 Average purchased power cost for wholesale operations per MWh (2) $ 51.53 $ 53.75 ------------------------------------------------------------------------------------------------------------------- (1) Including AmerGen and excluding Salem, which is operated by PSE&G. (2) Including PPAs with AmerGen.
The higher nuclear capacity factor and decreased nuclear production costs were primarily due to 16 fewer planned refueling outage days, resulting in a $9 million decrease in outage costs, in the three months ended September 30, 2003 as compared to the same period in 2002. 143 Additionally, the three months ended September 30, 2003 and 2002 included 9 and 7 unplanned outages, respectively. Depreciation and Amortization Depreciation and amortization expense decreased $17 million, or 25%, for the three months ended September 30, 2003 as compared to the same period in 2002. The decrease was primarily attributable to a $29 million net reduction in decommissioning expense, net of ARC depreciation, as these costs are included in operating and maintenance expense after the adoption of SFAS No. 143, and a $3 million decrease due to life extensions of asset additions in 2002. These decreases were partially offset by $10 million of additional depreciation expense on capital additions placed in service after the third quarter of 2002, and $7 million related to plant acquisitions made after the third quarter of 2002. For a further discussion of SFAS No. 143, see Note 2 of the Condensed Combined Notes to Consolidated Financial Statements. Taxes Other Than Income Taxes other than income decreased $9 million, or 24%, for the three months ended September 30, 2003 compared to the same period in 2002 primarily resulting from a $15 million reduction to reserves recorded for exposures associated with real estate taxes. This decrease was partially offset by a $7 million increase in property taxes related to asset acquisitions made after the third quarter of 2002. Interest Expense Interest expense increased $2 million, or 9%, for the three months ended September 30, 2003 compared to the same period in 2002. The increase was primarily due to $6 million of interest expense on the long-term debt obtained as a part of the Exelon New England asset acquisition and $2 million of interest expense on the $536 million note payable issued to Sithe in November 2002. This increase is partially offset by a $2 million decrease in interest on Generation's spent fuel obligation to the Department of Energy due to lower interest rates, and a $2 million increase in capitalized interest due to a change in capitalized interest rates. Equity in Earnings of Unconsolidated Affiliates Equity in earnings of unconsolidated affiliates decreased $34 million, or 39%, for the three months ended September 30, 2003 compared to the same period in 2002. The decrease was partly due to a $17 million decrease in Generation's equity earnings of AmerGen. AmerGen's earnings were primarily affected by decreased power sales due to changes in PPAs that resulted in lower prices in the summer months and higher expenses at AmerGen related to severance costs associated with The Exelon Way. Conversely, the change in PPAs resulted in higher prices in all non-summer months during 2003 as compared to 2002. The decrease was also due to a $17 million decrease in Generation's equity in earnings of Sithe. Sithe's earnings were primarily affected by Generation's purchase of Sithe New England's assets in November 2002 and unfavorable mark-to-market losses at Sithe. Other, Net Other, net decreased $44 million for the three months ended September 30, 2003 compared to the same period in 2002. The decrease was due to a $55 million impairment charge as a result of a change in fair 144 value of Generation's investment in Sithe. This decrease was offset by $9 million of higher net realized gains and investment income related to the nuclear decommissioning trust funds. These net realized gains and investment income are almost entirely offset with accretion expense in 2003, which is included in O&M expense. Income Taxes The effective income tax rate was 39.5% for the three months ended September 30, 2003 compared to 38.5% for the same period in 2002. This increase was primarily attributable to the impact of changes in income before taxes as a result of the impairments recorded in the third quarter related to Generation's investment in Sithe and long-lived assets of EBG. Nine Months Ended September 30, 2003 Compared to Nine Months Ended September 30, 2002 Significant Operating Trends - Generation
Nine Months Ended September 30, ------------------------------- 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- OPERATING REVENUES $ 6,301 $ 5,233 $ 1,068 20.4% OPERATING EXPENSES Purchased power 2,881 2,581 300 11.6% Fuel 1,156 706 450 63.7% Impairment of Exelon Boston Generating, LLC 945 -- 945 n.m. Operating and maintenance 1,473 1,234 239 19.4% Depreciation and amortization 142 197 (55) (27.9%) Taxes other than income 115 126 (11) (8.7%) ----------------------------------------------------------------------------------------------------- Total operating expenses 6,712 4,844 1,868 38.6% ----------------------------------------------------------------------------------------------------- OPERATING INCOME (LOSS) (411) 389 (800) n.m. ----------------------------------------------------------------------------------------------------- OTHER INCOME AND DEDUCTIONS Interest expense (63) (51) (12) 23.5% Equity in earnings of unconsolidated affiliates 90 119 (29) (24.4%) Other, net (164) 54 (218) n.m. ----------------------------------------------------------------------------------------------------- Total other income and deductions (137) 122 (259) n.m. ----------------------------------------------------------------------------------------------------- INCOME (LOSS) BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES (548) 511 (1,059) n.m. INCOME TAXES (209) 198 (407) n.m ----------------------------------------------------------------------------------------------------- INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES (339) 313 (652) n.m. CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES, NET OF INCOME TAXES 108 13 95 n.m. ----------------------------------------------------------------------------------------------------- NET INCOME (LOSS) $ (231) $ 326 $ (557) (170.9%) ===================================================================================================== n.m. - not meaningful
Net Income (Loss) Generation's net income decreased by $557 million, or 171%, for the nine months ended September 30, 2003 compared to the same period in 2002. Income before cumulative effect of changes in accounting principles decreased by $652 million for the nine months ended September 30, 2003 145 compared to the same period in 2002 primarily due to the third quarter impairment charge for the long-lived assets of EBG of $945 million ($573 million, net of income taxes), first and third quarter impairment charges for Generation's equity investment in Sithe totaling $255 million ($166 million, net of income taxes), and a $46 million charge ($30 million, net of income taxes) due to severance and related postretirement health and welfare benefit accruals and pension and postretirement curtailment costs associated with The Exelon Way. These decreases were partially offset by higher revenue resulting from increased market electric sales. Net income (loss) was additionally affected by a net decrease in equity in earnings of unconsolidated affiliates. Operating Revenues Revenues increased by $1,068 million, or 20%, for the nine months ended September 30, 2003 compared to the same period in 2002. For the nine months ended September 30, 2003 and 2002, Generation's sales were as follows:
Nine Months Ended September 30, ------------------------------- Revenue (in millions) 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Energy Delivery and Exelon Energy Company $ 3,180 $ 3,299 $ (119) (3.6%) Market Sales 3,001 1,927 1,074 55.7% ----------------------------------------------------------------------------------------------------- Total Energy Sales Revenue 6,181 5,226 955 18.3% ----------------------------------------------------------------------------------------------------- Trading Portfolio (1) (27) 26 (96.3%) Other Revenue 121 34 87 n.m. ----------------------------------------------------------------------------------------------------- Total Revenue $ 6,301 $ 5,233 $ 1,068 20.4% ===================================================================================================== Nine Months Ended September 30, ------------------------------- Sales (in GWhs) 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Energy Delivery and Exelon Energy Company 89,700 94,646 (4,946) (5.2%) Market Sales 80,877 61,089 19,788 32.4% ----------------------------------------------------------------------------------------------------- Total Sales 170,577 155,735 14,842 9.5% =====================================================================================================
Trading volumes of 28,532 GWhs and 51,260 GWhs for the nine months ended September 30, 2003 and 2002, respectively, are not included in the table above. The decrease in trading volume is a result of reduced volumetric and VaR trading limits in 2003, which are set by the Risk Management Committee and approved by the Board of Directors. Generation's average revenues (per MWh) on energy sales for the nine months ended September 30, 2003 and 2002 were as follows:
Nine Months Ended September 30, ------------------------------- ($/MWh) 2003 2002 % Change ------------------------------------------------------------------------------------------------------------------- Average Revenue Energy Delivery and Exelon Energy Company $ 35.45 $ 34.86 1.7% Market Sales 37.11 31.55 17.6% Total - excluding the trading portfolio 36.24 33.56 8.0% -------------------------------------------------------------------------------------------------------------------
Energy Delivery and Exelon Energy Company. Sales to Energy Delivery decreased by $85 million as a result of a net overall reduction in volume demand that resulted from unfavorable weather and customers choosing alternative suppliers under the customer choice program. The decrease was 146 partially offset by increased prices per MWh for supply agreements with ComEd and PECO. Sales to Exelon Energy Company decreased by $34 million for the nine months ended September 30, 2003 compared to the same period in 2002 primarily due to the discontinuance of Exelon Energy Company operations in the PJM region. Market Sales. The increase of $1,074 million resulted primarily from increased production from generating assets acquired during 2002, and from lower load requirements of affiliates and higher wholesale market prices, primarily attributable to higher fossil fuel prices. Trading Revenues. Trading activity reduced revenue by $1 million during the nine months ended September 30, 2003 compared to a reduction of $27 million during the same period in 2002 due to lower trading activity in 2003. Other Revenues. Other revenues increased primarily due to increases in natural gas market sales. As a result of natural gas supply contracts assigned to Generation with the 2002 asset acquisitions, Generation had an excess supply of natural gas. Other revenues also include nuclear decommissioning cost recoveries from ComEd and PECO. Purchased Power and Fuel Generation's supply source of its sales and average supply costs are summarized below:
Nine Months Ended September 30, ------------------------------- Supply of Sales (in GWhs) 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Nuclear Generation (1) 89,101 86,127 2,974 3.5% Purchases - non-trading portfolio (2) 63,435 59,496 3,939 6.6% Fossil and Hydro Generation 18,041 10,112 7,929 78.4% ----------------------------------------------------------------------------------------------------- Total Supply 170,577 155,735 14,842 9.5% ===================================================================================================== (1) Excluding AmerGen. (2) Including PPAs with AmerGen.
Nine Months Ended September 30, ------------------------------- ($/MWh) 2003 2002 % Change ------------------------------------------------------------------------------------------------------------------ Average Supply Cost (1) - excluding trading portfolio $ 23.67 $ 21.04 12.5% ------------------------------------------------------------------------------------------------------------------ (1) Average supply cost includes purchased power and fuel costs.
Generation's supply mix changed as a result of: o increased nuclear generation due to a lower number of refueling and unplanned outages during 2003 compared to 2002, o increased fossil generation due to the effect of the acquisition of two generating plants in Texas in April 2002 and the Exelon New England plants acquired in November 2002, which in total account for an increase of 6,565 GWhs, and o increased quantity of purchased power at higher prices. In addition, Generation entered into a new PPA with AmerGen in the second quarter of 2003. As a result, 2,481 GWhs were purchased from Oyster Creek in the second and third quarters of 2003. Purchased power increased $300 million, or 12%, for the nine months ended September 30, 2003 compared to the same period in 2002 due to a $339 million increase related to higher market prices and the commencement of Exelon New England commercial operations resulting in an additional $35 million increase. The increase in purchased power also reflects mark-to-market hedging losses of $17 million for the nine months ended September 30, 2003 compared to gains of $11 million in the same period in 2002. The increase was partially offset by $114 million related to decreased volume and reduced capacity 147 payments as a result of releasing Midwest Generation options. Generation's demand for counterparty purchased power decreased $91 million because of an increase in purchased power from AmerGen due to a June 2003 PPA to purchase 100% of the output of Oyster Creek. Fuel expense increased $450 million, or 64%, for the nine months ended September 30, 2003 compared to the same period in 2002, as summarized below:
Nine Months Ended September 30, ------------------------------- (in millions) 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Nuclear Generation (1) $ 385 $ 360 $ 25 6.9% Fossil and Hydro Generation 771 346 425 122.8% ----------------------------------------------------------------------------------------------------- Total $ 1,156 $ 706 $ 450 63.7% ===================================================================================================== (1) Excluding AmerGen
This increase is primarily the result of increases in fossil fuel generation required to meet increased market demand for energy, operation of new base load plants in New England and increased demand in all regions during the first quarter of 2003. Fossil and other fuel expense increased $415 million as a result of acquisitions of generating plants in 2002. In addition, fuel expense increased $10 million due to the writedown of coal inventory as a result of a fuel burn analysis Nuclear fuel expense increased $25 million, including $9 million due to higher nuclear generation and $16 million due to additional fuel amortization resulting from under-performing fuel at the Quad Cities Unit 1, which was completely replaced in May 2003. Impairment of Exelon Boston Generating, LLC In connection with the decision to transition out of the ownership of EBG and the projects, Generation recorded a long-lived asset impairment charge of $945 million ($573 million net of income taxes). Operating and Maintenance O&M expense increased $239 million, or 19%, for the nine months ended September 30, 2003 compared to the same period in 2002. The increase in O&M expense was primarily attributable to $46 million of severance and related postretirement health and welfare benefits accruals and pension and postretirement curtailment costs associated with The Exelon Way and $162 million of accretion expense related to SFAS No. 143. Accretion expense includes $116 million of accretion of the asset retirement obligation and $46 million to adjust the earnings impact of certain of the nuclear decommissioning revenues earned from ComEd and PECO, nuclear decommissioning trust fund investment income, income taxes incurred on nuclear decommissioning trust fund activities, accretion of the asset retirement obligation and depreciation of the asset retirement cost asset to zero. For a further discussion of SFAS No. 143, see Note 2 of the Condensed Combined Notes to Consolidated Financial Statements. The increase in O&M was also due to $51 million of additional employee payroll and benefits costs and $68 million of additional expenses due to asset acquisitions made after the third quarter of 2002. Also, Generation recorded an impairment charge of $5 million in 2003 related to the pending retirement of Mystic Station Units 4, 5 and 6. These increases were partially offset by $61 million of lower nuclear refueling outage costs, including $17 million for Generation's ownership interest in Salem, which is operated by the co-owner, PSE&G, a one-time executive severance expense 148 recorded in 2002 of $19 million, and an $8 million reduction in worker's compensation expense.
Nine Months Ended September 30, ------------------------------- 2003 2002 ------------------------------------------------------------------------------------------------------------------- Nuclear fleet capacity factor (1) 94.5% 92.1% Nuclear fleet production cost per MWh (1) $ 12.16 $ 13.05 Average purchased power cost for wholesale operations per MWh (2) $ 45.42 $ 43.60 ------------------------------------------------------------------------------------------------------------------- (1) Including AmerGen and excluding Salem, which is operated by PSE&G. (2) Including PPAs with AmerGen.
The higher nuclear capacity factor and decreased nuclear production costs are primarily due to 66 fewer planned refueling outage days, resulting in a $44 million decrease in outage costs, in the nine months ended September 30, 2003 as compared to the same period in 2002. The nine months ended September 30, 2003 and 2002 included 20 unplanned outages. Generation's financial results are greatly dependent on the performance of its nuclear units, including Generation's ability to maintain stable cost levels and high nuclear capacity factors. Problems that may occur at nuclear facilities that result in increased costs include accelerated replacement of suspect fuel assemblies, reduced generation due to maintenance and mid-cycle outages. For example, in the second quarter of 2003, the Quad Cities Unit 1 required a significant repair and did not operate above an 85% capacity factor until a root cause analysis was completed. Although this individual matter did not result in a significant decrease in operating income, this type of reduction in operational capacity can adversely affect Generation's financial results. Generation completed the analysis and returned the unit to its normal operating capacity in August 2003. Depreciation and Amortization Depreciation and amortization expense decreased $55 million, or 28%, for the nine months ended September 30, 2003 compared to the same period in 2002. The decrease was primarily attributable to a $93 million reduction in decommissioning expense net of ARC depreciation, as these costs are included in operating and maintenance expense after the adoption of SFAS No. 143, and a $12 million decrease due to life extensions of asset additions in 2002. The decrease was partially offset by $39 million of additional depreciation expense on capital additions placed in service after the second quarter of 2002, and $13 million of expense related to plant acquisitions made after the third quarter of 2002. For a further discussion of SFAS No. 143 see Note 2 of the Condensed Combined Notes to Consolidated Financial Statements. Taxes Other Than Income Taxes other than income decreased $11 million, or 9%, for the nine months ended September 30, 2003 compared to the same period in 2002 primarily due to a $20 million decrease in property taxes, including a $15 million reduction to reserves recorded for exposures associated with real estate taxes. This decrease was partially offset by a $17 million increase in property taxes related to asset acquisitions made after the third quarter of 2002. 149 Interest Expense Interest expense increased $12 million, or 24%, for the nine months ended September 30, 2003 compared to the same period in 2002. The increase was primarily due to $8 million of interest expense on the long-term debt assumed as a part of the Exelon New England asset acquisition, $7 million of additional interest expense on the $536 million note payable issued to Sithe in November 2002, and a $4 million decrease in capitalized interest. This increase is partially offset by a $3 million decrease in interest on Generation's obligation to the Department of Energy due to lower interest rates. Equity in Earnings of Unconsolidated Affiliates Equity in earnings of unconsolidated affiliates decreased $29 million, or 24%, for the nine months ended September 30, 2003 compared to the same period in 2002. This decrease resulted from a $31 million decrease in Generation's equity in earnings of Sithe. Sithe's earnings were primarily affected by Generation's purchase of Exelon New England's assets from Sithe in November 2002 and unfavorable mark-to-market losses at Sithe. This decrease was partially offset by a $3 million increase in Generation's equity in earnings of AmerGen. AmerGen's earnings were favorably affected in the nine months ended September 30, 2003 by increased power sales, reduced outage costs, and lower accretion expense resulting from the adoption of SFAS No. 143. This favorable impact was offset by decreased power sales due to changes in PPAs that resulted in lower prices in the summer months. Conversely, the change in PPAs resulted in higher prices in the non-summer months during 2003 as compared to 2002. Other, Net Other, net decreased $218 million for the nine months ended September 30, 2003 compared to the same period in 2002. This decrease is primarily a result of $255 million of impairment charges related to Generation's equity investment in Sithe due to an other-than-temporary decline in value. This charge was partially offset by $41 million of higher net realized gains and investment income related to the decommissioning trust funds. These net realized gains and investment income were almost entirely offset with accretion expense in 2003, which is included in operating and maintenance expense. Income Taxes The effective income tax rate was 38.1% for the nine months ended September 30, 2003 compared to 38.7% for the same period in 2002. The decrease was primarily attributed to the impact of changes in income before income taxes as a result of the impairments of Generation's investment in Sithe and the long-lived assets of EBG. Due to revenue needs in the states in which Generation operates, various state income tax and fee increases have been proposed or are being contemplated. If these changes are enacted, they could increase Generation's state income tax expense. At this time, however, Generation cannot predict whether legislation or regulation will be introduced, the form of any legislation or regulation, whether any such legislation or regulation will be passed by the state legislatures or regulatory bodies, and, if enacted, whether any such legislation or regulation would be effective retroactively or prospectively. As a result, Generation cannot currently estimate the effect of potential changes in tax law or regulation. 150 Cumulative Effect of Changes in Accounting Principles On January 1, 2003, Generation adopted SFAS No. 143 resulting in a benefit of $108 million, net of income taxes of $70 million. On January 1, 2002, Generation adopted SFAS No. 141 resulting in a benefit of $13 million, net of income taxes of $9 million. See Note 2 of the Condensed Combined Notes to Consolidated Financial Statements for further discussion of the adoption of SFAS No. 143 and SFAS No. 141. 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 participation in the intercompany money pool and/or capital contributions from Exelon. Generation's access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where Generation no longer has access to external financing sources at reasonable terms, Generation has access to a revolving credit facility. See the Credit Issues section of Liquidity and Capital Resources for further discussion. Capital resources are used primarily to fund Generation's capital requirements, including construction, investments in new and existing ventures, repayments of maturing debt and the payment of distributions to Exelon. Any future acquisitions could require external financing or borrowings or capital contributions from Exelon. As part of the implementation of The Exelon Way, Generation has identified 317 positions for elimination by the end of 2004 and anticipates identifying additional positions for elimination in 2005 and 2006. Generation recorded a charge for cash severance of $20 million during the third quarter 2003, which Generation anticipates will be paid by December 31, 2004. Generation anticipates incurring further costs associated with The Exelon Way upon identifying additional positions to be eliminated. These costs will be recorded in the period in which the costs can be reasonably estimated. Cash Flows from Operating Activities Cash flows provided by operations were $1,141 million for the nine months ended September 30, 2003, compared to $771 million for the same period in 2002. The increase in cash flows from operating activities was primarily attributable to a $530 million increase in cash flows derived from working capital. Cash flows used in operating activities for collateral were $1 million as of September 30, 2003, compared to $48 million for the same period in 2002. The use of cash for collateral will depend upon future market prices for energy and to the extent forward energy deals are entered into under agreements with negotiated collateral provisions. When power prices return to previous levels or when Generation delivers the power under its forward contracts, the collateral would be returned to Generation with no impact on its results of operations. 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 151 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 $772 million for the nine months ended September 30, 2003, compared to $1,343 million for the same period in 2002. The decrease in cash flows used in investing activities during the current year was primarily attributable to plant acquisition costs of $443 million during the nine months ended September 30, 2002, and $92 million for liquidated damages received from Raytheon in 2003 (see Note 9 of the Condensed Combined Notes to Consolidated Financial Statements). Generation's capital expenditures for 2003 reflect the construction of three EBG generating facilities with projected capacity of 2,421 MWs of energy and additions to and upgrades of existing facilities (including nuclear refueling outages) and nuclear fuel. During the nine months ended September 30, 2003, EBG received $92 million of liquidated damages from Raytheon as a result of Raytheon not meeting the expected completion date and certain contractual performance criteria in connection with Raytheon's construction of Mystic 8 and 9 and Fore River. Exelon anticipates that Generation's capital expenditures will be funded by internally generated funds, borrowings or capital contributions from Exelon. Cash Flows from Financing Activities Cash flows used in financing activities were $324 million for the nine months ended September 30, 2003, compared to cash flows provided by financing activities of $387 million for the same period in 2002. The decrease in cash flows from financing activities was primarily due to a $526 million decrease in cash receipts from affiliates, $86 million increase in distributions paid to Exelon, the $210 million partial payment of the acquisition note payable to Sithe, a reduction in contributions from minority interest holders of $43 million and a $25 million reduction in restricted cash during the nine months ended September 30, 2003 compared to the same period in 2002. The decrease in cash provided by financing activities was partially offset by an increase in borrowings under the revolving credit facility of $181 million during the current year over the same period in 2002. See Note 12 of the Condensed Combined Notes to Consolidated Financial Statements for further discussion of Generation's debt financing activities. Credit Issues Generation meets its short-term liquidity requirements primarily through intercompany borrowings from Exelon and participation in the intercompany money pool. Generation, along with Exelon, ComEd and PECO, participates in a $1.5 billion unsecured 364-day revolving credit facility with a group of banks. The credit facility became effective on November 22, 2002 and includes a term-out option that allows any outstanding borrowings at the end of the revolving credit period to be repaid on November 21, 2004. Exelon may increase or decrease the sublimits of each of the participants upon written notification to the banks. As of September 30, 2003, the sublimit for Generation was zero. 152 The credit facility requires Generation to maintain a cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The ratio excludes certain changes in working capital, revenues from Exelon New England and interest on the debt of Exelon New England's project subsidiaries. Generation's threshold for the ratio reflected in the credit agreement cannot be less than 3.25 to 1 for the twelve-month period ended September 30, 2003. At September 30, 2003, Generation was in compliance with the credit agreement thresholds. To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, Exelon operates an intercompany money pool. Participation in the money pool is subject to authorization by the Exelon corporate treasurer. ComEd, PECO, Generation and BSC may participate in the money pool as lenders and borrowers, and Exelon Corporate may participate as a lender. Funding of, and borrowings from, the money pool are predicated on whether such funding results in mutual economic benefits to each of the participants. Interest on borrowings is based on short-term market rates of interest, or, if from an external source, specific borrowing rates. During the nine months ended September 30, 2003, Generation had various borrowings under the money pool. The maximum amount of loans outstanding at any time during the quarter was $344 million. As of September 30, 2003, Generation owed the money pool $147 million on these loans. For the nine months ended September 30, 2003, Generation paid $2 million in interest to the money pool. EBG has approximately $1.1 billion of debt outstanding under the EBG Facility at September 30, 2003. The EBG Facility was entered into primarily to finance the construction of Mystic 8 and 9 and Fore River. The EBG Facility required that all of the projects achieve Project Completion, by June 12, 2003. On June 11, 2003, EBG negotiated an extension of the Project Completion date to July 11, 2003. On July 3, 2003, the lenders under the EBG Facility and EBG executed a letter agreement as a result of which the lenders were precluded during the period July 11, 2003 through August 29, 2003 from exercising any remedies resulting from the failure of all of the projects to achieve Project Completion. At that time, EBG stated that it would continue to monitor the projects, assess all of its options relating to the projects, and continue discussions with the lenders. Project Completion was not achieved by July 12, 2003, resulting in an event of default under the EBG Facility. The EBG Facility is non-recourse to Generation and an event of default under the EBG Facility does not constitute an event of default under any other debt instruments of Exelon or its subsidiaries. Mystic 8 and 9 and Fore River are in commercial operation, although they have not yet achieved Project Completion. As a result of Generation's continuing evaluation of the projects and discussions with the lenders, Generation has commenced the process of an orderly transition out of the ownership of EBG and the projects. The transition will take place in a manner that complies with applicable regulatory requirements. For a period of time, Generation expects to continue to provide administrative and operational services to EBG in its operation of the projects. Generation informed the lenders of its decision to exit and that it will not provide additional funding to the projects beyond its existing contractual obligations. Generation cannot predict the timing of the transition. 153 The debt outstanding under the EBG Facility of approximately $1.1 billion at September 30, 2003 is reflected in Generation's Consolidated Balance Sheet as a current liability. On June 13, 2003, Generation closed on a $550 million revolving credit facility. Generation used the facility to make the first payment to Sithe of $210 million relating to the $536 million note, which was established in connection with the acquisition of Exelon New England. On September 29, 2003, Generation replaced the $550 million facility with a new $850 million revolving credit facility. The existing $210 million of borrowings under the original facility remain outstanding under the new credit facility. The note with Sithe has been restructured in the third quarter to provide for the remaining balance of $326 million to be paid in two installments. Generation will be required to repay $236 million of the principal on the earlier of December 1, 2003 or change of control, and the remaining principal balance on the earlier of December 1, 2004 or change of control. Generation's $850 million facility is also expected to provide the initial funding of the acquisition of British Energy's 50% interest in AmerGen. Generation's access to the capital markets and its financing costs in those markets are dependent on its securities ratings. None of Generation's borrowings is subject to default or prepayment as a result of a downgrading of securities ratings although such a downgrading could increase interest charges under certain bank credit facilities. From time to time Generation enters into energy commodity and other derivative transactions that require the maintenance of investment grade ratings. Failure to maintain investment grade ratings would allow the counterparty to terminate the derivative and settle the transaction on a net present value basis. As part of the normal course of business, Exelon and Generation routinely enter into physical or financially settled contracts for the purchase and sale of capacity, energy, fuels and emissions allowances. These contracts either contain express provisions or otherwise permit Exelon, Generation and its counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if Exelon or Generation is downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is possible that a counterparty could attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance. Depending on Exelon or Generation's net position with a counterparty, the demand could be for the posting of collateral. In the absence of expressly agreed to provisions that specify the collateral that must be provided, the obligation to supply the collateral requested will be a function of the facts and circumstances of Exelon or Generation's situation at the time of the demand. If Exelon or Generation can reasonably claim that it is willing and financially able to perform its obligations, it may be possible to successfully argue that no collateral should be posted or that only an amount equal to two or three months of future payments should be sufficient. 154 Under PUHCA, Generation is precluded from lending or extending credit or indemnity to Exelon and can only pay dividends from undistributed or current earnings. At September 30, 2003, Generation had undistributed earnings of $577 million. Contractual Obligations, Commercial Commitments and Off-Balance Sheet Obligations Contractual obligations represent cash obligations that are considered to be firm commitments and commercial commitments represent commitments triggered by future events. Generation's contractual obligations and commercial commitments as of September 30, 2003 were materially unchanged from the amounts set forth in the 2002 Form 10-K except for the following: o Generation entered into a PPA dated June 26, 2003 with AmerGen. Under the PPA, Generation has agreed to purchase 100% of energy generated by Oyster Creek through April 9, 2009. See Note 9 of the Condensed Combined Notes to Consolidated Financial Statements for the commercial commitments table representing Generation's commitments not recorded on the balance sheet but potentially triggered by future events, including obligations to make payment on behalf of other parties and financing arrangements to secure their obligations. o On May 29, 2003, Exelon Fossil Holdings, Inc., a wholly owned subsidiary of Generation, issued an irrevocable call notice to purchase the 35.2% interest in Sithe owned by Apollo Energy, LLC and the 14.9% interest owned by subsidiaries of Marubeni Corporation. The total purchase price under the call is based on the terms of the existing PCA among the parties and is $621 million. The transfer of ownership requires various regulatory approvals, including the FERC, the state environmental agency in New Jersey, and expiration of the Hart Scott Rodino waiting period. Early termination of the Hart Scott Rodino waiting period was granted effective August 22, 2003. Under the terms of the PCA, the purchase price must be funded within six months of the call notice being issued. Additionally, because the Federal Power Act restricts Generation's ownership of more than 50% of a qualifying facility, the qualifying facilities owned by Sithe must be sold or restructured before closing to preserve their status as qualifying facilities. See below for information regarding a separate agreement reached by Sithe to sell six U.S. generating facilities, each a qualifying facility, and an entity holding Sithe's Canadian assets. At the closing, Sithe is expected to distribute in excess of $600 million of available cash to Generation. On August 13, 2003, Generation announced an agreement with entities controlled by Reservoir, a private investment firm, to sell 50% of Sithe in exchange for $75.8 million in cash. The sale will occur after Generation's purchase of the remaining 50.1% interest in Sithe. The sale requires FERC approval, a Hart Scott Rodino filing and a filing with the state regulatory commission in New York. Both of these filings have been made. Early termination of the Hart Scott Rodino waiting period was granted September 30, 2003. The sale is expected to close in the fourth quarter of 2003. 155 Both Exelon and Reservoir's 50% interests in Sithe will be subject to put and call options that could result in either party owning 100% of Sithe. While Exelon's intent is to fully divest Sithe by the end of 2004, the timing of the put and call options vary by acquirer and can extend through March 2006. The pricing of the put and call options is dependent on numerous factors such as the acquirer, date of acquisition and assets owned by Sithe at the time of exercise. In a separate transaction, Sithe has entered into an agreement with Reservoir to sell entities holding six U.S. generating facilities, each a qualifying facility under the Public Utility Regulatory Policies Act, and an entity holding Sithe's Canadian assets in exchange for $46.2 million ($26.2 million in cash and a $20 million two-year note). The sale requires approvals from Sithe's board of directors and shareholders and regulatory filings in New Jersey and Canada. Both these filing have been made. The sale is also expected to close in the fourth quarter of 2003. This sale is not contingent on the sale of Generation's 50% interest in Sithe to Reservoir. o In June 2003, Generation entered an agreement with USEC Inc. to purchase approximately $700 million of nuclear fuel from 2005 through 2010. o On August 14, 2003, Generation received a letter from the Department of Energy (DOE) demanding repayment of $40 million of previously received credits from the Nuclear Waste Fund. The letter also demanded $1.5 million of accrued interest expense. Although a new settlement would offset Generation's payments, Generation nonetheless has reserved its 50% ownership share of these amounts. Because Generation expenses the casks and capitalizes the permanent components of its spent fuel storage facilities, these reserves increased Generation's operating and maintenance expense approximately $11 million and its capital base approximately $9 million during the third quarter of 2003. The remainder of the recorded obligation to the DOE will be recovered from the co-owner of the facility. See Note 9 - Nuclear Decommissioning and Spent Nuclear Fuel Storage in Generation's 2002 Form 10-K for additional information regarding this matter. o Under the Price-Anderson Act, all nuclear reactor licensees can be assessed a maximum charge per reactor per incident. Effective August 20, 2003, the maximum assessment for all nuclear operators per reactor per incident (including a 5% surcharge) increased from $89 million to $101 million. The maximum payable per reactor per incident per year of $10 million is unchanged. The change in the maximum assessment is the result of an inflation adjustment, required by the Price-Anderson Act. Based on the increase of the maximum assessment, Generation's nuclear insurance guarantee of AmerGen's plants increased from $134 million to $151 million. 156 o On October 10, 2003, Exelon executed an agreement to purchase British Energy's 50% interest in AmerGen for $276.5 million. The transaction is expected to close in the first half of 2004. The purchase price matched the offer by FPL Energy, which announced on September 11, 2003 that it intended to buy British Energy's share of AmerGen. Under the AmerGen limited liability company operating agreement between Exelon and British Energy, either can exercise a right of first refusal by matching any bona fide third-party offer agreed to by the other member. See Note 4 of the Condensed Combined Notes to Financial Statements for additional information regarding AmerGen. As discussed in Note 2 of the Condensed Combined Notes to Consolidated Financial Statements, it is reasonably possible that Generation will consolidate Sithe and AmerGen as of December 31, 2003 pursuant to FIN No. 46, "Consolidation of Variable Interest Entities." See Note 4 of the Condensed Combined Notes to Consolidated Financial Statements for further discussion of Generation's investments in Sithe and AmerGen. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK Commodity Price Risk Generation Commodity price risk is associated with market price movements resulting from excess or insufficient generation, changes in fuel costs, market liquidity and other factors. Trading activities and non-trading marketing activities include the purchase and sale of electric capacity and energy and fossil fuels, including oil, gas, coal and emission allowances. The availability and prices of energy and energy-related commodities are subject to fluctuations due to factors such as weather, governmental environmental policies, changes in supply and demand, state and Federal regulatory policies and other events. Normal Operations and Hedging Activities Electricity available from Generation's owned or contracted generation supply in excess of its obligations to customers, including Energy Delivery's retail load, is sold into the wholesale markets. To reduce price risk caused by market fluctuations, Generation enters into physical contracts as well as derivative contracts, including forwards, futures, swaps, and options, with approved counterparties to hedge its anticipated exposures. The maximum length of time over which cash flows related to energy commodities are currently being hedged is four years. Generation has an estimated 94% hedge ratio in 2003 for its energy marketing portfolio. This hedge ratio represents the percentage of Generation's forecasted aggregate annual economic generation supply that is committed to firm sales, including sales to ComEd and PECO's retail load. ComEd and PECO's retail load assumptions are based on forecasted average demand. The hedge ratio is not fixed and will vary from time to time depending upon market conditions, demand, and energy market option volatility and actual loads. During peak periods, the amount hedged declines to meet the commitment to ComEd and PECO. 157 Market price risk exposure is the risk of a change in the value of unhedged positions. Absent any opportunistic efforts to mitigate market price exposure, the estimated market price exposure for Generation's non-trading portfolio associated with a ten percent reduction in the annual average around-the-clock market price of electricity is an approximately $6 million decrease in net income, or approximately $0.02 per share. This sensitivity assumes a consistent hedge ratio and that price changes occur evenly throughout the year and across all markets. The sensitivity also assumes a static portfolio. Generation expects to actively manage its portfolio to mitigate market price exposure. Actual results could differ depending on the specific timing of, and markets affected by, price changes, as well as future changes in Generation's portfolio. Proprietary Trading Activities Generation uses financial contracts for proprietary trading purposes. Proprietary trading includes all contracts entered into purely to profit from market price changes as opposed to hedging an exposure. These activities are accounted for on a mark-to-market basis. The proprietary trading activities are a complement to Generation's energy marketing portfolio and represent a very small portion of its overall energy marketing activities. For example, the limit on open positions in electricity for any forward month represents less than 1% of Generation's owned and contracted supply of electricity. The trading portfolio is subject to stringent risk management limits and policies, including volume, stop-loss and value-at-risk limits. Generation's energy contracts are accounted for under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133). Most non-trading contracts qualify for the normal purchases and normal sales exemption to SFAS No. 133 discussed in the Critical Accounting Estimates section of Management's Discussion and Analysis of Financial Condition and Result of Operations of the 2002 Form 10-K. Those that do not are recorded as assets or liabilities on the balance sheet at fair value. Changes in the fair value of qualifying hedge contracts are recorded in Other Comprehensive Income (OCI), and gains and losses are recognized in earnings when the underlying transaction occurs. Changes in the fair value of derivative contracts that do not meet hedge criteria under SFAS No. 133 and the ineffective portion of hedge contracts are recognized in earnings on a current basis. The following detailed presentation of the trading and non-trading marketing activities at Generation is included to address the recommended disclosures by the energy industry's Committee of Chief Risk Officers. Generation does not consider its proprietary trading to be a significant activity in its business; however, Generation believes it is important to include these risk management disclosures. 158 The following tables describe the drivers of Generation's energy trading and marketing business and gross margin included in the income statement for the three and nine months ended September 30, 2003. Normal operations and hedging activities represent the marketing of electricity available from Generation's owned or contracted generation sold into the wholesale market, including to ComEd and PECO to serve their retail loads. As the information in these tables highlights, mark-to-market activities represent a small portion of the overall gross margin for Generation. Accrual activities, including normal purchases and sales, account for the majority of the gross margin. The mark-to-market activities reported here are those relating to changes in fair value due to external movement in prices. Further delineation of gross margin by the type of accounting treatment typically afforded each type of activity is also presented (i.e., mark-to-market vs. accrual accounting treatment).
Three Months Ended September 30, 2003 ----------------------------------------------------- Normal Operations and Proprietary Hedging Activities (a) Trading Total ------------------------------------------------------------------------------------------------------------------ Mark-to-market activities: -------------------------- Unrealized mark-to-market gain/(loss) Origination unrealized gain/(loss) at inception $ -- $ -- $ -- Changes in fair value prior to settlements 47 1 48 Changes in valuation techniques and assumptions -- -- -- Reclassification to realized at settlement of contracts (65) (1) (66) ------------------------------------------------------------------------------------------------------------------ Total change in unrealized fair value (18) -- (18) Realized net settlement of transactions subject to mark-to-market 65 1 66 ------------------------------------------------------------------------------------------------------------------ Total mark-to-market activities gross margin $ 47 $ 1 $ 48 ------------------------------------------------------------------------------------------------------------------ Accrual activities: ------------------- Accrual activities revenue $ 1,642 $ -- $ 1,642 Hedge gains/(losses) reclassified from OCI 710 -- 710 ------------------------------------------------------------------------------------------------------------------ Total revenue - accrual activities 2,352 -- 2,352 ------------------------------------------------------------------------------------------------------------------ Purchased power and fuel 765 -- 765 Hedges of purchased power and fuel reclassified from OCI 787 -- 787 ------------------------------------------------------------------------------------------------------------------ Total purchased power and fuel 1,552 -- 1,552 ------------------------------------------------------------------------------------------------------------------ Total accrual activities gross margin 800 -- 800 ------------------------------------------------------------------------------------------------------------------ Total gross margin $ 847 $ 1 $ 848 (b) ================================================================================================================== (a) Normal Operations and Hedging Activities only include derivative contracts Generation enters into to hedge anticipated exposures related to its owned and contracted generation supply, but excludes its owned and contracted generating assets. (b) Total Gross Margin represents revenue, net of purchased power and fuel expense for Generation.
159
Nine Months Ended September 30, 2003 ---------------------------------------------------------- Normal Operations and Proprietary Hedging Activities (a) Trading Total ------------------------------------------------------------------------------------------------------------------ Mark-to-market activities: -------------------------- Unrealized mark-to-market gain/(loss) Origination unrealized gain/(loss) at inception $ -- $ -- $ -- Changes in fair value prior to settlements 182 (1) 181 Changes in valuation techniques and assumptions -- -- -- Reclassification to realized at settlement of contracts (199) (3) (202) ------------------------------------------------------------------------------------------------------------------ Total change in unrealized fair value (17) (4) (21) Realized net settlement of transactions subject to mark-to-market 199 3 202 ------------------------------------------------------------------------------------------------------------------ Total mark-to-market activities gross margin $ 182 $ (1) $ 181 ------------------------------------------------------------------------------------------------------------------ Accrual activities: ------------------- Accrual activities revenue $ 4,099 $ -- $ 4,099 Hedge gains/(losses) reclassified from OCI 1,724 -- 1,724 ------------------------------------------------------------------------------------------------------------------ Total revenue - accrual activities 5,823 -- 5,823 ------------------------------------------------------------------------------------------------------------------ Purchased power and fuel 1,745 -- 1,745 Hedges of purchased power and fuel reclassified from OCI 1,995 -- 1,995 ------------------------------------------------------------------------------------------------------------------ Total purchased power and fuel 3,740 -- 3,740 ------------------------------------------------------------------------------------------------------------------ Total accrual activities gross margin 2,083 -- 2,083 ------------------------------------------------------------------------------------------------------------------ Total gross margin $ 2,265 $ (1) $ 2,264 (b) ================================================================================================================== (a) Normal Operations and Hedging Activities only include derivative contracts Generation enters into to hedge anticipated exposures related to its owned and contracted generation supply, but excludes its owned and contracted generating assets. (b) Total Gross Margin represents revenue, net of purchased power and fuel expense for Generation.
The following table provides detail on changes in Generation's mark-to-market net asset or liability balance sheet position from January 1, 2003 to September 30, 2003. It indicates the drivers behind changes in the balance sheet amounts. This table incorporates the mark-to-market activities that are recorded in earnings, as shown in the previous table, as well as the settlements from OCI to earnings and changes in fair value for the hedging activities that are recorded in Accumulated Other Comprehensive Income on the September 30, 2003 Consolidated Balance Sheet.
Normal Operations and Proprietary Hedging Activities Trading Total ------------------------------------------------------------------------------------------------------------------ Total mark-to-market energy contract net assets (liabilities) at January 1, 2003 $ (168) $ 5 $ (163) Total change in fair value for the nine months ended September 30, 2003 of contracts recorded in earnings 182 (1) 181 Reclassification to realized at settlement of contracts recorded in earnings (199) (3) (202) Reclassification to realized at settlement from OCI 271 -- 271 Effective portion of changes in fair value - recorded in OCI (205) -- (205) Purchase/sale of existing contracts or portfolios subject to mark-to-market -- -- -- ------------------------------------------------------------------------------------------------------------------ Total mark-to-market energy contract net assets (liabilities) at September 30, 2003 $ (119) $ 1 $ (118) ==================================================================================================================
160 The following table details the balance sheet classification of the mark-to-market energy contract net assets recorded as of September 30, 2003:
Normal Operations and Proprietary Hedging Activities Trading Total ------------------------------------------------------------------------------------------------------------------- Current assets $ 204 $ 1 $ 205 Noncurrent assets 79 -- 79 ------------------------------------------------------------------------------------------------------------------ Total mark-to-market energy contract assets 283 1 284 ------------------------------------------------------------------------------------------------------------------ Current liabilities (301) -- (301) Noncurrent liabilities (101) -- (101) ------------------------------------------------------------------------------------------------------------------ Total mark-to-market energy contract liabilities (402) -- (402) ------------------------------------------------------------------------------------------------------------------ Total mark-to-market energy contract net assets (liabilities) $ (119) $ 1 $ (118) ==================================================================================================================
The majority of Generation's contracts are non-exchange traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter, on-line exchanges. Prices reflect the average of the bid-ask midpoint prices obtained from all sources that Generation believes provide the most liquid market for the commodity. The terms for which such price information is available varies by commodity, by region and by product. The remainder of the assets represents contracts for which external valuations are not available, primarily option contracts. These contracts are valued using the Black model, an industry standard option valuation model. The fair values in each category reflect the level of forward prices and volatility factors as of September 30, 2003 and may change as a result of changes in these factors. Management uses its best estimates to determine the fair value of commodity and derivative contracts it holds and sells. These estimates consider various factors including closing exchange and over-the-counter price quotations, time value, volatility factors and credit exposure. It is possible, however, that future market prices could vary from those used in recording assets and liabilities from energy marketing and trading activities and such variations could be material. 161 The following table, which presents maturity and source of fair value of mark-to-market energy contract net assets, provides two fundamental pieces of information. First, the table provides the source of fair value used in determining the carrying amount of Generation's total mark-to-market asset or liability. Second, this table provides the maturity, by year, of Generation's net assets/liabilities, giving an indication of when these mark-to-market amounts will settle and generate or require cash.
Maturities within ----------------------------------------------------------- 2008 and Total Fair 2003 2004 2005 2006 2007 Beyond Value ------------------------------------------------------------------------------------------------------------------------ Normal Operations, qualifying cash flow hedge contracts (1): Prices provided by other external sources $(6) $ (98) $ (10) $ (6) $ -- $ -- $ (120) ------------------------------------------------------------------------------------------------------------------------ Total $(6) $ (98) $ (10) $ (6) $ -- $ -- $ (120) ------------------------------------------------------------------------------------------------------------------------ Normal Operations, other derivative contracts (2): Actively quoted prices $ -- $ 2 $ -- $ -- $ -- $ -- $ 2 Prices provided by other external sources 4 14 5 4 -- -- 27 Prices based on model or other valuation methods 4 (17) (3) (9) (3) -- (28) ------------------------------------------------------------------------------------------------------------------------ Total $ 8 $ (1) $ 2 $ (5) $ (3) $ -- $ 1 ------------------------------------------------------------------------------------------------------------------------ Proprietary Trading, other derivative contracts (3): Actively quoted prices $(2) $ 3 $ -- $ -- $ -- $ -- $ 1 Prices provided by other external sources 1 (4) 1 -- -- -- (2) Prices based on model or other valuation methods 1 1 -- -- -- -- 2 ------------------------------------------------------------------------------------------------------------------------ Total $-- $ -- $ 1 $ -- $ -- $ -- $ 1 ======================================================================================================================== Average tenor of proprietary trading portfolio (4) 1.75 years ======================================================================================================================== (1) Mark-to-market gains and losses on contracts that qualify as cash flow hedges are recorded in other comprehensive income. (2) Mark-to-market gains and losses on other non-trading derivative contracts that do not qualify as cash flow hedges are recorded in earnings. (3) Mark-to-market gains and losses on trading contracts are recorded in earnings. (4) Following the recommendations of the Committee of Chief Risk Officers, the average tenor of the proprietary trading portfolio measures the average time to collect value for that portfolio. Generation measures the tenor by separating positive and negative mark-to-market values in its proprietary trading portfolio, estimating the mid-point in years for each and then reporting the highest of the two mid-points calculated. In the event that this methodology resulted in significantly different absolute values of the positive and negative cash flow streams, Generation would use the mid-point of the portfolio with the largest cash flow stream as the tenor.
162 The table below provides details of effective cash flow hedges under SFAS No. 133 included in the balance sheet as of September 30, 2003. The data in the table gives an indication of the magnitude of SFAS No. 133 hedges Generation has in place, however, given that under SFAS No. 133 not all hedges are recorded in OCI, the table does not provide an all-encompassing picture of Generation's hedges. The table also includes a roll-forward of Accumulated Other Comprehensive Income on the Consolidated Balance Sheets related to cash flow hedges for the nine months ended September 30, 2003, providing insight into the drivers of the changes (new hedges entered into during the period and changes in the value of existing hedges). Information related to energy merchant activities is presented separately from interest rate hedging activities.
Total Cash Flow Hedge Other Comprehensive Income Activity, Net of Income Tax ------------------------------------------------------------------------------------------------------------------- Normal Operations and Interest Rate and Total Cash Hedging Activities Other Hedges (1) Flow Hedges ------------------------------------------------------------------------------------------------------------------- Accumulated OCI derivative loss at January 1, 2003 $ (114) $ (5) $ (119) Changes in fair value (124) (11) (135) Reclassifications from OCI to net income 165 -- 165 ------------------------------------------------------------------------------------------------------------------- Accumulated OCI derivative loss at September 30, 2003 $ (73) $ (16) $ (89) =================================================================================================================== (1) Includes interest rate hedges at Generation.
Generation uses a VaR model to assess the market risk associated with financial derivative instruments entered into for proprietary trading purposes. The measured VaR represents an estimate of the potential change in value of Generation's proprietary trading portfolio. The VaR estimate includes a number of assumptions about current market prices, estimates of volatility and correlations between market factors. These estimates, however, are not necessarily indicative of actual results, which may differ because actual market rate fluctuations may differ from forecasted fluctuations and because the portfolio may change over the holding period. Generation estimates VaR using a model based on the Monte Carlo simulation of commodity prices that captures the change in value of forward purchases and sales as well as option values. Parameters and values are back tested daily against daily changes in mark-to-market value for proprietary trading activity. VaR assumes that normal market conditions prevail and that there are no changes in positions. Generation uses a 95% confidence interval, one-day holding period, one-tailed statistical measure in calculating its VaR. This means that Generation may state that there is a one in 20 chance that if prices move against its portfolio positions, its pre-tax loss in liquidating its portfolio in a one-day holding period would exceed the calculated VaR. To account for unusual events and loss of liquidity, Generation uses stress tests and scenario analysis. For financial reporting purposes only, Generation calculates several other VaR estimates. The higher the confidence interval, the less likely the chance that the VaR estimate would be exceeded. A longer holding period considers the effect of liquidity in being able to actually liquidate the portfolio. A two-tailed test considers potential upside in the portfolio in addition to the potential downside in the portfolio 163 considered in the one-tailed test. The following table provides the VaR for all proprietary trading positions of Generation as of September 30, 2003.
Proprietary Trading VaR ------------------------------------------------------------------------------------------------------------------- 95% Confidence Level, One-Day Holding Period, One-Tailed Period end $ 0.1 Average for the period 0.1 High 0.2 Low 0.0 95% Confidence Level, Ten-Day Holding Period, Two-Tailed Period end $ 0.2 Average for the period 0.3 High 0.6 Low 0.1 99% Confidence Level, One-Day Holding Period, Two-Tailed Period end $ 0.1 Average for the period 0.1 High 0.2 Low 0.0 -------------------------------------------------------------------------------------------------------------------
Credit Risk Generation Generation has credit risk associated with counterparty performance on energy contracts which includes, but is not limited to, the risk of financial default or slow payment. Generation manages counterparty credit risk through established policies, including counterparty credit limits, and in some cases, requiring deposits and letters of credit to be posted by certain counterparties. Generation's counterparty credit limits are based on a scoring model that considers a variety of factors, including leverage, liquidity, profitability, credit ratings and risk management capabilities. Generation has entered into payment netting agreements or enabling agreements that allow for payment netting with the majority of its large counterparties, which reduce Generation's exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. The credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis. 164 The following tables provide information on Generation's credit exposure, net of collateral, as of September 30, 2003. They further delineate that exposure by the credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties and an indication of the maturity of a company's credit risk by credit rating of the counterparties. The tables below do not include sales to Generation's affiliates or exposure through Independent System Operators.
Total Number Of Net Exposure Of Exposure Counterparties Counterparties Before Credit Credit Net Greater than 10% Greater than 10% Rating Collateral Collateral Exposure of Net Exposure of Net Exposure -------------------------------------------------------------------------------------------------------------------------- Investment grade $ 208 $ -- $ 208 2 $ 81 Split rating -- -- -- -- -- Non-investment grade 14 6 8 -- -- No external ratings Internally rated - investment grade 26 4 22 3 10 Internally rated - non-investment grade 11 5 6 1 11 -------------------------------------------------------------------------------------------------------------------------- Total $ 259 $ 15 $ 244 6 $ 102 ==========================================================================================================================
Maturity of Credit Risk Exposure --------------------------------------------------------------- Exposure Total Exposure Less than Greater than Before Credit Rating 2 Years 2-5 Years 5 Years Collateral ------------------------------------------------------------------------------------------------------------------- Investment grade $ 194 $ 14 $ -- $ 208 Split rating -- -- -- -- Non-investment grade 14 -- -- 14 No external ratings Internally rated - investment grade 25 1 -- 26 Internally rated - non-investment grade 11 -- -- 11 ------------------------------------------------------------------------------------------------------------------- Total $ 244 $ 15 $ -- $ 259 ===================================================================================================================
Generation is a counterparty to Dynegy in various energy transactions. The credit ratings of Dynegy are considered below investment grade by two credit rating agencies. Generation has credit risk associated with Dynegy through Generation's equity investment in Sithe. Sithe is a 60% owner of the Independence generating station, a 1,040-MW gas-fired qualified facility that has an energy-only long-term tolling agreement with Dynegy with a related financial swap arrangement. As of September 30, 2003, Sithe had recognized an asset on its balance sheet related to the fair market value of the financial swap agreement with Dynegy that is marked-to-market under the provisions of SFAS No. 133. If Dynegy is unable to fulfill the terms of this agreement, Sithe would be required to impair this financial swap asset. Generation estimates, as a 49.9% owner of Sithe, that the impairment would result in an after-tax reduction of Generation's equity earnings of approximately $16 million. In addition to the impairment of the financial swap asset, if Dynegy were unable to fulfill its obligations under the financial swap agreement and the tolling agreement, Generation may incur a further impairment associated with Sithe's Independence station. 165 Additionally, the future economic value of AmerGen's purchased power arrangement with Illinois Power Company, a subsidiary of Dynegy, could be impacted by events related to Dynegy's financial condition. ComEd and Generation are parties to various transactions with Midwest Generation. Midwest Generation's credit ratings have been downgraded by certain credit rating agencies. Furthermore, the June 30, 2003 Form 10-Q filed by Edison Mission Energy (EME), an intermediate parent company of Edison Mission Midwest Holdings (EMMH) and Midwest Generation, indicates that EMMH is not expected to have sufficient cash to repay $911 million of debt when it matures on December 11, 2003; a failure to repay, extend, or refinance the EMMH obligation would likely result in a default under the senior secured notes and term loan of Mission Energy Holding Company, EME's parent company; and these events could make it necessary for EME to file a petition for reorganization under Chapter 11 of the United States Bankruptcy Code. Reorganization under Chapter 11 of the United States Bankruptcy Code does not assure non-performance under all contracts; however, the reorganization would increase the possibility of the obligations described in the following two paragraphs reverting to ComEd or Generation. In connection with ComEd's sale in December 1999 of fossil generating assets to Midwest Generation, ComEd entered into an agency agreement with EMMH and EME whereby EMMH assumed the benefits and liabilities of a long-term coal purchase contract and a railcar lease. EME guaranteed EMMH's performance. EMMH did not become a direct party to the obligations, and ComEd remained obligated and was not released. In connection with the Merger and subsequent restructuring, Generation assumed any contingent obligation on these contracts from ComEd. In the event of EMMH and EME's non-performance under the coal purchase contract, Generation would be required to fulfill the purchase commitments that extend through 2012. The contract requires the purchase of two million tons of coal annually or specifies a minimum payout. Based upon current market prices, Generation's contingent obligations for the minimum purchase obligation for the contract years 2003 to 2012 are estimated to be approximately $81 million (the net present value of the obligation approximates $51 million) related to this agreement. The railcar lease covers approximately 1,400 coal transport railcars through 2014. In the event of EMMH and EME's non-performance under the railcar lease, Generation would be required to fulfill the lease payments that extend through 2014. The remaining lease payments for the railcars approximate $65 million (the net present value of the obligation approximates $38 million). However, based on current prices for railcars in these particular markets, Generation believes it would be able to effectively sublease the railcars without incurring any exposure related to this obligation. Generation and ComEd have entered into other agreements with Midwest Generation and have other related exposures. In connection with ComEd's fossil generating asset sale to Midwest Generation, Midwest Generation and EME agreed to indemnify ComEd for various environmental exposures or penalties. Generation assumed any contingent obligations relating to generation-related environmental issues of ComEd in connection with the Merger and subsequent restructuring. Exelon cannot reasonably estimate the possible environmental exposures or penalties that could arise if Midwest Generation or EME do not honor their indemnity to ComEd or if the indemnity is discharged in bankruptcy. Midwest Generation also indemnified Generation and ComEd for approximately 50% of any post-acquisition asbestos claims relating to the plants sold to Midwest Generation. Generation assumed any contingent obligations of ComEd relating to these asbestos claims in connection with the Merger and subsequent restructuring. The bankruptcy of or non-performance of Midwest Generation of its obligations to Generation and ComEd for asbestos claims could result in contingent obligations to Generation and ComEd of up to an estimated $5 million. In addition, ComEd is exposed to risks associated with accounts receivable from transmission and station power services provided by ComEd to Midwest Generation. The bankruptcy of or non-performance of Midwest Generation of its obligations to ComEd for transmission and station power services provided by ComEd could result in ComEd recording a write-off of up to an estimated $3 million. Generation accounts for certain derivative financial instruments under the normal purchases and normal sales exemption of SFAS No. 133. As of September 30, 2003, Generation is a party to forward energy purchase and sale contracts with Midwest Generation, which are accounted for in that manner and, as such, are not marked-to-market. If Generation determines that the possibility of non-performance by Midwest Generation on these contracts becomes more than remote, these contracts will be required to be marked-to-market through earnings, which would be expected to result in a charge to Exelon and Generation's results of operations and such charge could be material. As part of the normal course of business, Exelon and Generation routinely enter into physical or financially settled contracts for the purchase and sale of capacity, energy, fuels and emissions allowances. These contracts either contain express provisions or otherwise permit Exelon, Generation and its counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if Exelon or Generation is downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is possible that a counterparty could attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance. Depending on Exelon or Generation's net position with a counterparty, the demand could be for the posting of collateral. In the absence of expressly agreed to provisions that specify the collateral that must be provided, the obligation to supply the collateral requested will be a function of the facts and circumstances of Exelon or Generation's situation at the time of the demand. If Exelon or Generation can reasonably claim that it is willing and financially able to perform its obligations, it may be possible to successfully argue that no collateral should be posted or that only an amount equal to two or three months of future payments should be sufficient. Interest Rate Risk ComEd ComEd uses a combination of fixed rate and variable rate debt to reduce interest rate exposure. Interest rate swaps may be used to adjust exposure when deemed appropriate based upon market conditions. ComEd also 166 utilizes forward-starting interest rate swaps and treasury rate locks to lock in interest rate levels in anticipation of future financing. These strategies are employed to maintain the lowest cost of capital. At September 30, 2003, ComEd has settled all of its interest rate swaps designated as cash flow hedges. ComEd has entered into fixed-to-floating interest rate swaps in order to maintain its targeted percentage of variable rate debt associated with fixed-rate debt issuances in the aggregate amount of $485 million. At September 30, 2003, these interest rate swaps, designated as fair value hedges, had an aggregate fair market value of $39 million based on the present value difference between the contract and market rates at September 30, 2003. If these derivative instruments had been terminated at September 30, 2003, this estimated fair value represents the amount that would be paid by the counterparties to ComEd. The aggregate fair value of the interest rate swaps, designated as fair value hedges, that would have resulted from a hypothetical 50 basis point decrease in the spot yield at September 30, 2003 is estimated to be $45 million in ComEd's favor. 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, 2003 is estimated to be $33 million in ComEd's favor. PECO In February 2003, PECO entered into forward-starting interest rate swaps in the aggregate amount of $360 million to lock in interest rate levels in anticipation of future financings. The debt issuances that these swaps were hedging were considered probable in February 2003 and closed in April 2003; therefore, PECO accounted for these interest rate swap transactions as hedges. In connection with PECO's April 28, 2003 issuance of $450 million in First and Refunding Mortgage Bonds, PECO settled the swaps for net proceeds of $1 million, which was recorded in other comprehensive income and is being amortized over the life of the debt issuance. PECO has entered into interest rate swaps to manage interest rate exposure associated with the floating rate series of transition bonds issued to securitize PECO's stranded cost recovery. At September 30, 2003, these interest rate swaps had an aggregate fair market value exposure of $11 million based on the present value difference between the contract and market rates at September 30, 2003. If these derivative instruments had been terminated at September 30, 2003, this estimated fair value represents the amount to be paid by PECO to the counterparties. The aggregate fair value exposure of the interest rate swaps that would have resulted from a hypothetical 50 basis point decrease in the spot yield at September 30, 2003 is estimated to be $12 million in the counterparties favor. The aggregate fair value exposure of the interest rate swaps that would have resulted from a hypothetical 50 basis point increase in the spot yield at September 30, 2003 is estimated to be $10 million in the counterparties favor. 167 PECO also has interest rate swaps in place to satisfy counterparty credit requirements in regards to the floating rate series of transition bonds which are mirror swaps of each other. These swaps are not designated as cash flow hedges; therefore, they are required to be marked-to-market if there is a difference in their values. Since these swaps offset each other, a mark-to-market adjustment is not expected to occur. Generation Generation uses a combination of fixed rate and variable rate debt to reduce interest rate exposure. Generation also uses interest rate swaps when deemed appropriate to adjust exposure based upon market conditions. These strategies are employed to achieve a lower cost of capital. As of September 30, 2003, a hypothetical 10% increase in the interest rates associated with variable rate debt would not have a material impact on pre-tax earnings for the three and nine months ended September 30, 2003. Under the terms of the EBG Facility, EBG is required to effectively fix the interest rate on 50% of borrowings under the facility through its maturity in 2007. As of September 30, 2003, EBG had entered into interest rate swap agreements that have effectively fixed the interest rate on $861 million of notional principal, or approximately 80% of borrowings outstanding under the EBG Facility at September 30, 2003. The fair market value exposure of these swaps, designated as cash flow hedges, is $91 million. If these derivative instruments had been terminated at September 30, 2003, this estimated fair value represents the amount to be paid by EBG to the counterparties. The aggregate fair value exposure of the interest rate swaps designated as cash flow hedges that would have resulted from a hypothetical 50 basis point decrease in the spot yield at September 30, 2003 is estimated to be $104 million in the counterparties favor. The aggregate fair value exposure of the interest rate swaps designated as cash flow hedges that would have resulted from a hypothetical 50 basis point increase in the spot yield at September 30, 2003 is estimated to be $78 million in the counterparties favor. In 2003, Generation entered into forward-starting interest rate swaps in the aggregate amount of $400 million to lock in interest rate levels in anticipation of future financings. The debt issuances that these swaps are hedging are considered probable; therefore, Generation has accounted for these interest rate swap transactions as hedges. At September 30, 2003, these interest rate swaps, designated as cash flow hedges, had an aggregate fair market value exposure of less than $1 million based on the present value of the difference between the contract and market rates at September 30, 2003. If these derivative instruments had been terminated at September 30, 2003, this estimated fair value represents the amount to be paid by Generation to the counterparties. The aggregate fair value exposure of the interest rate swaps designated as cash flow hedges that would have resulted from a hypothetical 50 basis point decrease in the spot yield at September 30, 2003 is estimated to be $17 million in the counterparties favor. 168 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, 2003 is estimated to be $16 million in Generation's favor. Equity Price Risk Generation Generation maintains trust funds, as required by the NRC, to fund certain costs of decommissioning its nuclear plants. As of September 30, 2003, decommissioning trust funds are reflected at fair value on Generation's Consolidated Balance Sheets. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to compensate for inflationary increases in decommissioning costs. However, the equity securities in the trust funds are exposed to price fluctuations in equity markets, and the value of fixed rate, fixed income securities are exposed to changes in interest rates. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocation in accordance with Generation's nuclear decommissioning trust fund investment policy. A hypothetical 10% increase in interest rates and decrease in equity prices would result in a $212 million reduction in the fair value of the trust assets. ITEM 4. CONTROLS AND PROCEDURES Exelon During the third quarter of 2003, Exelon's management, including the principal executive officer and principal financial officer, evaluated Exelon's disclosure controls and procedures related to the recording, processing, summarization and reporting of information in Exelon's periodic reports that it files with the SEC. These disclosure controls and procedures have been designed to ensure that (a) material information relating to Exelon, including its consolidated subsidiaries, is made known to Exelon's management, including these officers, by other employees of Exelon and its subsidiaries, and (b) this information is recorded, processed, summarized, evaluated and reported, as applicable, within the time periods specified in the SEC's rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people. Exelon's controls and procedures can only provide reasonable, not absolute, assurance that the above objectives have been met. Also, Exelon does not control or manage certain of its unconsolidated entities and as such, the disclosure controls and procedures with respect to such entities are more limited than those it maintains with respect to its consolidated subsidiaries. Accordingly, as of September 30, 2003, these officers (principal executive officer and principal financial officer) concluded that Exelon's disclosure controls and procedures were effective to accomplish their objectives. Exelon continually strives to improve its disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. 169 ComEd During the third quarter of 2003, ComEd's management, including the principal executive officer and principal financial officer, evaluated ComEd's disclosure controls and procedures related to the recording, processing, summarization and reporting of information in ComEd's periodic reports that it files with the SEC. These disclosure controls and procedures have been designed to ensure that (a) material information relating to ComEd, including its consolidated subsidiaries, is made known to ComEd's management, including these officers, by other employees of ComEd and its subsidiaries, and (b) this information is recorded, processed, summarized, evaluated and reported, as applicable, within the time periods specified in the SEC's rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people. ComEd's controls and procedures can only provide reasonable, not absolute, assurance that the above objectives have been met. Also, ComEd does not control or manage certain of its unconsolidated entities and as such, the disclosure controls and procedures with respect to such entities are more limited than those it maintains with respect to its consolidated subsidiaries. Accordingly, as of September 30, 2003, these officers (principal executive officer and principal financial officer) concluded that ComEd's disclosure controls and procedures were effective to accomplish their objectives. ComEd continually strives to improve its disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. PECO During the third quarter of 2003, PECO's management, including the principal executive officer and principal financial officer, evaluated PECO's disclosure controls and procedures related to the recording, processing, summarization and reporting of information in PECO's periodic reports that it files with the SEC. These disclosure controls and procedures have been designed to ensure that (a) material information relating to PECO, including its consolidated subsidiaries, is made known to PECO's management, including these officers, by other employees of PECO and its subsidiaries, and (b) this information is recorded, processed, summarized, evaluated and reported, as applicable, within the time periods specified in the SEC's rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people. PECO's controls and procedures can only provide reasonable, not absolute, assurance that the above objectives have been met. Also, PECO does not control or manage certain of its unconsolidated entities and as such, the disclosure controls and procedures with respect to such entities are more limited than those it maintains with respect to its consolidated subsidiaries. Accordingly, as of September 30, 2003, these officers (principal executive officer and principal financial officer) concluded that PECO's disclosure controls and procedures were effective to accomplish their 170 objectives. PECO continually strives to improve its disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. Generation During the third quarter of 2003, Generation's management, including the principal executive officer and principal financial officer, evaluated Generation's disclosure controls and procedures related to the recording, processing, summarization and reporting of information in Generation's periodic reports that it files with the SEC. These disclosure controls and procedures have been designed to ensure that (a) material information relating to Generation, including its consolidated subsidiaries, is made known to Generation's management, including these officers, by other employees of Generation and its subsidiaries, and (b) this information is recorded, processed, summarized, evaluated and reported, as applicable, within the time periods specified in the SEC's rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people. Generation's controls and procedures can only provide reasonable, not absolute, assurance that the above objectives have been met. Also, Generation does not control or manage certain of its unconsolidated entities and as such, the disclosure controls and procedures with respect to such entities are more limited than those it maintains with respect to its consolidated subsidiaries. Accordingly, as of September 30, 2003, these officers (principal executive officer and principal financial officer) concluded that Generation's disclosure controls and procedures were effective to accomplish their objectives. Generation continually strives to improve its disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. 171 PART II - OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS ComEd As previously reported in the 2002 Form 10-K and the June 2003 Form 10-Q, three of ComEd's wholesale municipal customers had filed a complaint and request for refund with the FERC alleging that ComEd failed to properly adjust its rates pursuant to the terms of the respective electric service contracts. In July 2003 ComEd and the municipal customers executed a settlement agreement ending the litigation. Pursuant to the settlement, ComEd paid approximately $3 million, in total, to the three municipalities. Generation As previously reported in the 2002 Form 10-K and the June 2003 Form 10-Q, Generation and Raytheon are involved in various litigation matters in connection with EBG. On August 29, 2003, Raytheon filed a new action against two subsidiaries of EBG (Project Companies) and BNP Paribas in the Superior Court of the Commonwealth of Massachusetts. Raytheon alleged that the Project Companies and BNP Paribas failed to provide adequate assurance that Raytheon would be paid the remaining amounts due under the Fore River and Mystic construction contracts. Raytheon sought: (1) an injunction preventing the Project Companies and BNP Paribas from drawing upon certain letters of credit guaranteeing Raytheon's performance; (2) the right to terminate the construction contracts; and (3) an order allowing Raytheon to seize project funds totaling approximately $40 million. Raytheon subsequently dismissed BNP Paribas from the litigation. On October 9, 2003, the court issued a preliminary injunction preserving the status quo and preventing the Project Companies from drawing upon the letters of credit until such time as the court decides Raytheon's pending motion for partial summary judgment. The court has heard argument on Raytheon's motion for partial summary judgment but has not announced any decision. On October 2, 2003, Mitsubishi Heavy Industries, LTD (MHI) and Mitsubishi Heavy Industries of America (MHIA) filed a New York state court action against Exelon Mystic Development, LLC and Exelon Fore River Development, LLC seeking to enjoin these indirect subsidiaries of Generation from drawing upon letters of credit posted to guarantee MHI's performance under certain gas turbine contracts. MHI and MHIA also seek $34 million from these entities in connection with work performed on these contracts. Generation believes that Exelon Mystic's and Exelon Fore River's contracts with MHI and MHIA have been assigned to Raytheon Corporation and that the claims against the Exelon entities are without merit. ITEM 3. DEFAULTS UPON SENIOR SECURITIES Generation EBG has approximately $1.1 billion of debt outstanding under the EBG Facility. The EBG Facility, which is non-recourse to Generation, was entered into primarily to finance the construction of Mystic 8 and 9 and Fore River and required that all of the projects achieve Project Completion by June 12, 2003. EBG negotiated an extension of the required 172 completion date to July 11, 2003. Project Completion was not achieved by July 12, 2003, resulting in an event of default under the EBG Facility. Although the generating units are in commercial operation, Project Completion has not been achieved to date. The event of default under the EBG Facility does not constitute an event of default under any other debt instruments of Exelon or its subsidiaries. EBG does not know which, if any, remedies the lenders will exercise. ITEM 5. OTHER INFORMATION ComEd As previously reported in the 2002 Form 10-K, in July 2002, the FERC conditionally approved ComEd's decision to join PJM. On April 1, 2003, ComEd received approval from the FERC to transfer control of ComEd's transmission assets to PJM. The FERC also accepted for filing the PJM tariff as amended to reflect the inclusion of ComEd and other new members, subject to a compliance filing, which was made on May 1, 2003, and to hearing on certain issues. On June 2, 2003, ComEd began receiving electric transmission reservation services from PJM and transferred control of its Open Access Same Time Information System to PJM. On September 11, 2003, the August 14, 2003 blackout caused PJM to delay ComEd's integration until spring of 2004. PJM wants to integrate any lessons learned from the blackout probes into ComEd's transition plan. On August 21, 2003, ComEd set a new record for highest daily peak load experienced to date of 22,054 MWs. PECO As previously reported in the 2002 Form 10-K, the PUC's Final Electric Restructuring Order established MSTs to promote competition. On May 1, 2003, the PUC approved the residential customer plan filed by PECO in February 2003. Under the plan and subsequent auction in September 2003, an aggregate of 267,000 residential customers will be transferred to alternative electric generation suppliers during December 2003. Any customer transferred has the right to return to PECO at any time. 173 ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits: 10.1 - Retirement and Separation between Exelon Corporation, PECO Energy Company and Kenneth G. Lawrence, dated as of May 11, 2003. Filed on behalf of PECO. 10.2 - Purchase and Sale Agreement dated as of October 10, 2003 between British Energy Investment Ltd. and Exelon Generation Company, LLC relating to the sale and purchase of 100% of the shares of British Energy US Holdings Inc. Filed on behalf of Exelon and Generation. Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2003 filed by the following officers for the following companies: - -------------------------------------------------------------------------------- 31-1 - Filed by John W. Rowe for Exelon Corporation 31-2 - Filed by Robert S. Shapard for Exelon Corporation 31-3 - Filed by Michael B. Bemis for Commonwealth Edison Company 31-4 - Filed by Robert S. Shapard for Commonwealth Edison Company 31-5 - Filed by Michael B. Bemis for PECO Energy Company 31-6 - Filed by Robert S. Shapard for PECO Energy Company 31-7 - Filed by Oliver D. Kingsley Jr. for Exelon Generation Company, LLC 31-8 - Filed by Robert S. Shapard for Exelon Generation Company, LLC - -------------------------------------------------------------------------------- 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, 2003 filed by the following officers for the following companies: - -------------------------------------------------------------------------------- 32-1 - Filed by John W. Rowe for Exelon Corporation 32-2 - Filed by Robert S. Shapard for Exelon Corporation 32-3 - Filed by Michael B. Bemis for Commonwealth Edison Company 32-4 - Filed by Robert S. Shapard for Commonwealth Edison Company 32-5 - Filed by Michael B. Bemis for PECO Energy Company 32-6 - Filed by Robert S. Shapard for PECO Energy Company 32-7 - Filed by Oliver D. Kingsley Jr. for Exelon Generation Company, LLC 32-8 - Filed by Robert S. Shapard for Exelon Generation Company, LLC - -------------------------------------------------------------------------------- (b) Reports on Form 8-K: Exelon, ComEd, PECO and/or Generation filed Current Reports on Form 8-K during the three months ended September 30, 2003 regarding the following items: Date of Earliest Event Reported Description of Item Reported - -------------------------------------------------------------------------------- July 3, 2003 "ITEM 5. OTHER EVENTS" filed for Exelon and Generation regarding the fact that EBG did not anticipate that the construction of the Mystic 8 and 9 and Fore River generating stations would achieve Project Completion as defined in EBG's credit facility by July 11, 2003. 174 July 29, 2003 "ITEM 5. OTHER EVENTS" filed for Exelon and Generation announcing that Exelon commenced the process of an orderly transition out of the ownership of EBG and the projects. August 6, 2003 "ITEM 5. OTHER EVENTS" filed for Exelon, ComEd, PECO and Generation reaffirming Exelon's 2003 earnings guidance and announcing workforce reductions related to The Exelon Way. August 13, 2003 "ITEM 5. OTHER EVENTS" filed for Exelon and Generation regarding a note to Exelon's financial community announcing an agreement with entities controlled by Reservoir to sell 50% of Sithe, after closing on a call transaction announced in May 2003. In a separate transaction, Sithe has entered into an agreement with Resevoir to sell entities holding six U.S. generating facilities and an entity holding Sithe's Canadian assets. August 25, 2003 "ITEM 5. OTHER EVENTS" filed for ComEd regarding ComEd's sale of $250 million of First Mortgage Bonds. "ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS" including exhibits to ComEd's Form S-3, Registration No. 333-99363. August 29, 2003 "ITEM 5. OTHER EVENTS" filed for Exelon and Generation regarding the fact that the period during which the lenders were precluded from exercising any remedies resulting from the failure of the EBG projects to achieve Project Completion had expired. Exelon was continuing discussions with the lenders regarding the orderly transition of the projects. Exelon has informed the lenders that Generation will not provide additional funding to the projects beyond its existing contractual obligations. September 12, 2003 "ITEM 5. OTHER EVENTS" filed for Exelon and ComEd regarding a filing with the Federal Energy Regulatory Commission to seek an adjustment in transmission rates. The exhibit includes the press release announcing the filing. September 24, 2003 "ITEM 5. OTHER EVENTS" filed for Exelon announcing that it had finalized the sale of InfraSource, Inc. September 26, 2003 "ITEM 5. OTHER EVENTS" filed for Exelon and ComEd announcing that Exelon is exploring the possibility of acquiring Illinois Power Company from Dynegy Inc. - -------------------------------------------------------------------------------- 175 SIGNATURES - -------------------------------------------------------------------------------- Pursuant to requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. EXELON CORPORATION /s/ John W. Rowe /s/ Robert S. Shapard ----------------- ---------------------- JOHN W. ROWE ROBERT S. SHAPARD Chairman and Executive Vice President and Chief Chief Executive Officer Financial Officer (Principal Executive Officer) (Principal Financial Officer) /s/ Matthew F. Hilzinger ------------------------ MATTHEW F. HILZINGER Vice President and Corporate Controller (Principal Accounting Officer) October 29, 2003 Pursuant to requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. COMMONWEALTH EDISON COMPANY /s/ Michael B. Bemis /s/ Robert S. Shapard -------------------- ---------------------- MICHAEL B. BEMIS ROBERT S. SHAPARD President, Exelon Energy Delivery Executive Vice President and Chief (Principal Executive Officer) Financial Officer, Exelon (Principal Financial Officer) /s/ Duane M. DesParte /s/ Frank M. Clark --------------------- ------------------ DUANE M. DESPARTE FRANK M. CLARK Vice President and Controller, President, ComEd Exelon Energy Delivery (Principal Accounting Officer) October 29, 2003 176 - -------------------------------------------------------------------------------- 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/ Michael B. Bemis /s/ Robert S. Shapard -------------------- ---------------------- MICHAEL B. BEMIS ROBERT S. SHAPARD President, Exelon Energy Delivery Executive Vice President and Chief (Principal Executive Officer) Financial Officer, Exelon (Principal Financial Officer) /s/ Duane M. DesParte /s/ Denis P. O'Brien --------------------- -------------------- DUANE M. DESPARTE DENIS P. O'BRIEN Vice President and Controller, President, PECO Exelon Energy Delivery (Principal Accounting Officer) October 29, 2003 - -------------------------------------------------------------------------------- Pursuant to requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. EXELON GENERATION COMPANY, LLC /s/ Oliver D. Kingsley Jr. /s/ Robert S. Shapard -------------------------- --------------------- OLIVER D. KINGSLEY JR. ROBERT S. SHAPARD Chief Executive Officer and Executive Vice President and Chief President Financial Officer, Exelon (Principal Executive Officer) (Principal Financial Officer) /s/ Thomas Weir III ------------------------------ THOMAS WEIR III Vice President and Controller (Principal Accounting Officer) October 29, 2003 177
                    (Filed on Behalf of PECO Energy Company)


                       RETIREMENT AND SEPARATION AGREEMENT

                  THIS RETIREMENT AND SEPARATION AGREEMENT (this "Agreement") is
entered into as of May 11, 2003 between Exelon Corporation ("Exelon"), PECO
Energy Company ("PECO", and, collectively with Exelon, the "Company") and
Kenneth G. Lawrence (the "Executive").

                              W I T N E S S E T H:

                  WHEREAS, the Executive has transitioned from his former
positions to the positions of Senior Vice President of Exelon and Chairman of
PECO; and

                  WHEREAS, the Company and the Executive desire to set forth
herein their mutual agreement with respect to all matters relating to the
Executive's retirement, resignation and separation from the Company and its
affiliates;

                  NOW, THEREFORE, in consideration of the mutual promises and
agreements contained herein, the adequacy and sufficiency of which are hereby
acknowledged, the Company and the Executive agree as follows:

                  1. Retirement; Resignation; Termination of Employment /
Continued Employment Until Employment Termination Date.

                  (a) Retirement; Resignation; Termination of Employment. The
Executive hereby resigns, effective as of October 31, 2003 (the "Employment
Termination Date"), as Senior Vice President of Exelon, Chairman of PECO and
from all other positions as an officer or director of the Company and its
subsidiaries and affiliates. The Executive shall continue to be employed by PECO
until (and including) the Employment Termination Date, at which time the
Executive shall cease to be an employee of, or have any other position with,
PECO, Exelon and their respective subsidiaries and affiliates.

                  (b) Continued Employment Until Employment Termination Date.
During the period beginning on the date of this Agreement and ending on the
Employment Termination Date (the "Employment Period"), the Executive shall be
available to provide advice and counsel to the Company's senior executive
management, assist and cooperate in good faith with the orderly transition of
his duties, and perform such other services reasonably consistent with his
position as may be requested by the Company. During the Employment Period, the
Executive shall use his best efforts and act at all times in the best interests
of the Company in performing his duties. The Executive may (i) serve on
corporate, civic or charitable boards or committees, (ii) deliver lectures,
fulfill speaking engagements or teach at educational institutions and (iii)
manage personal investments, so long as such activities do not significantly
interfere with the performance of the Executive's duties, but shall not engage
in other employment. The Executive's current annual base salary shall remain in
effect during the Employment Period.




                                       1


                  2. Payment of Accrued Amounts. The Company shall pay to the
Executive not later than the second payroll date after the Employment
Termination Date the following amounts:

                  (a) the portion of his annual salary that has accrued but is
unpaid as of the Employment Termination Date;

                  (b) $214,882, representing the Executive's target annual
incentive award for 2003 prorated to the Employment Termination Date; and

                  (c) an additional amount representing the Executive's accrued
but unused vacation days as of the Employment Termination Date.

                  3. Severance Payments. Subject to the Executive's execution,
not earlier than the Employment Termination Date and not later than twenty-one
days after the Employment Termination Date, of the waiver and release attached
hereto as Exhibit I and made a part hereof (the "Waiver and Release"), the
Company shall pay to the Executive cash severance payments in an aggregate
amount equal to $2,374,650, representing the product of three times the sum of
(i) $430,000 (the Executive's current annual base salary), plus (ii) $361,550,
(the average of the annual incentive awards paid to the Executive for calendar
years 2001 and 2002). Provided that the Executive has not revoked the Waiver and
Release, payment shall commence no later than the second payroll date occurring
in the month following the Employment Termination Date (or eight days after the
date the Executive signs the Waiver and Release, if later), in regular periodic
payments for a period of twenty-four months at a monthly rate equal to
$65,962.50, followed by a final payment in the twenty-fifth month following the
Employment Termination Date equal to $791,550. The Executive's deferral
elections with respect to base salary and annual incentive awards under the
Company's deferred compensation plan shall be applied to the respective portions
of his severance pay representing base salary and annual incentive awards.

                  4. Tax Withholding. The Company shall deduct from the amounts
payable to the Executive pursuant to this Agreement the amount of all required
federal, state and local withholding taxes in accordance with the Executive's
Form W-4 on file with the Company (as such form may be modified by the Executive
from time to time) and all applicable social security and Medicare taxes. The
Company shall be entitled to withhold from the shares of common stock of the
Company to be delivered to the Executive pursuant to Sections 6(b) and 6(c) a
number of shares of common stock of the Company having a value (based upon the
closing price of a share of the Company's common stock as reported on the New
York Stock Exchange on the Employment Termination Date) equal to the minimum
amount of all required federal, state and local withholding taxes and all
applicable social security and Medicare taxes with respect to the lapse of
forfeiture conditions applicable to shares of restricted stock and the vesting
of performance shares.

                  5. Outplacement Assistance / Financial Counseling / Tax
Preparation / Estate Planning. The Company shall reimburse the Executive for all
fees incurred for services rendered to the Executive by a professional
outplacement organization selected by the Executive to provide individual
outplacement services during the twelve-month period following the Employment
Termination Date, subject to an aggregate reimbursement limit of $30,000. In
addition, during the three-year period following the Employment Termination
Date, the Executive shall be entitled to reimbursement of reasonable expenses





                                       2


for personal financial counseling, income tax preparation and estate planning,
consistent with Exelon's programs or policies applicable to senior executives.

                  6. Stock Awards.

                  (a) Each of the Executive's options to purchase common stock
of Exelon Corporation granted pursuant to the Exelon Corporation Long Term
Incentive Plan or the PECO Energy Company Long Term Incentive Plan shall (A) to
the extent exercisable on the Employment Termination Date, remain exercisable
until the expiration date of such option as specified in the grant agreement or
plan (as applicable) relating thereto and (B) to the extent not fully
exercisable as of the Employment Termination Date, immediately become fully
exercisable and thereafter remain exercisable until the expiration date of such
option as specified in the grant agreement or plan (as applicable) relating
thereto; provided, however, that any stock option granted on or after January 1,
2002 shall remain exercisable until the earlier of the expiration date of such
option or the fifth anniversary of the Employment Termination Date.

                  (b) All forfeiture conditions applicable to the 10,000
restricted shares of Exelon Corporation common stock awarded to the Executive
under the PECO Long Term Incentive Plan on September 26, 2000 shall lapse as of
September 26, 2003. All forfeiture conditions which as of the Employment
Termination Date are applicable to the 35,000 restricted shares of Exelon
Corporation common stock awarded to the Executive under the Exelon Corporation
Long Term Incentive Plan on January 1, 2002 shall lapse as of the Employment
Termination Date with respect to 17,500 restricted shares, and the remaining
17,500 restricted shares shall be immediately forfeited.

                  (c) As of the Employment Termination Date, the Executive shall
become fully vested in 13,384 shares of common stock of Exelon Corporation,
representing grants of performance shares pursuant to Exelon Corporation's Long
Term Performance Share Award Program.

                  7. Supplemental Executive Retirement Benefits. The Executive
shall receive a retirement benefit under the PECO Energy Company Supplemental
Pension Benefit Plan (the "SERP") determined in accordance with the terms of the
SERP except that, in determining such benefit, the Executive shall be credited
with an additional three years of service (for purposes of determining the
amount, but not the timing of commencement, of his SERP benefit), will be
treated as though he had attained age 58, and will be treated as though he
received the severance benefits specified in Section 3 as regular salary and
incentive pay over a three-year period ending on the third anniversary of the
Employment Termination Date. The parties acknowledge that the Executive
previously elected to defer payment of his SERP benefit pursuant to the
Company's deferred compensation plan, and that such benefit shall be paid
pursuant to the Executive's payment election under, and in accordance with the
other terms and conditions of, such plan as provided in Section 8(c).

                  8. Employee and Other Benefits.

                  (a) Until the third anniversary of the Employment Termination
Date, (i) the Executive (and his family) shall be eligible to participate in,
and shall receive benefits under Exelon's welfare benefit plans (including





                                       3


medical, dental, vision and hearing) in which the Executive (and his family)
were participating immediately prior to the Employment Termination Date, and
(ii) the Executive shall be eligible to participate in the basic and executive
life insurance programs in which he was a participant immediately prior to the
Employment Termination, in each case on the same basis as if the Executive had
remained actively employed until the end of such three-year period.

                  (b) On and after the third anniversary of the Employment
Termination Date, (i) the Executive and his spouse shall be eligible for
Post-Retirement Health Care Coverage (defined below) in accordance with the
terms and conditions of the applicable plans under which Post-Retirement Health
Care Coverage is provided. Such coverage shall not duplicate any benefits that
may then be available to the Executive and his spouse under Section 8(a) and
shall be secondary to any coverage provided by any other employer or Medicare.
For purposes of this Section 8(b), "Post-Retirement Health Care Coverage" means
the medical, dental and vision care coverage provided by the Company from time
to time to its retired senior executives. After the third anniversary of the
Employment Termination Date, the Company shall transfer to the Executive a
fully-paid executive life insurance policy with a death benefit in an amount
equal to one times the sum of the Executive's base salary and target annual
incentive award as of the Employment Termination Date.

                  (c) Following the third anniversary of the Employment
Termination Date, the Company shall pay to the Executive, in the time and manner
specified in the terms of such plan and any elections by the Executive
thereunder, his account balance in the Company's deferred compensation plan,
subject to applicable earnings and losses on such account balance.

                  (d) The Executive shall be entitled to purchase from the
leasing company any automobile leased by the Company for his use, subject to the
terms and conditions of such lease, and shall be entitled to purchase the
computer furnished by the Company for his use. The Executive shall be
responsible for payment of expenses incurred on and after the Employment
Termination Date with respect to the Company-owned cellular phone furnished for
his use.

                  (e) If the Executive is entitled to any benefit that is vested
and accrued on the Employment Termination Date under any employee benefit plan
(excluding any severance benefit plan) of the Company or any of its subsidiaries
and that is not expressly referred to in this Agreement, such benefit shall be
provided to the Executive in accordance with the terms of such employee benefit
plan.

                  (f) Notwithstanding Section 8(e) or anything else contained in
this Agreement to the contrary, the Executive acknowledges and agrees that he is
not and shall not be entitled to benefits under any severance or change in
control plan, program, agreement or arrangement, including but not limited to
the Exelon Corporation Key Management Severance Plan, as in effect from time to
time (the "Key Management Severance Plan"), and his Exelon Corporation Change in
Control Employment Agreement dated as of October 22, 2001 (the "Change in
Control Agreement"), and that the benefits provided under this Agreement shall
be the sole and exclusive benefits to which the Executive may become entitled
upon his retirement and termination of employment. In the event that the
Executive resigns his employment or is terminated for "cause" (as defined in the
Key Management Severance Plan) prior to the Employment Termination Date, he
shall not be entitled to any further compensation or benefits under this
Agreement (other than the retiree welfare benefits described in Section 8(b)).





                                       4


In the event the Executive dies prior to executing the Waiver and Release
attached hereto, neither he, his estate, nor any other person shall be entitled
to any further compensation or benefits under this Agreement, unless and until
the executor of the Executive's estate (and/or such other heirs or
representatives as may be requested by the Company) executes and does not revoke
such a Waiver and Release.

                  9. Restrictive Covenants. The Executive acknowledges and
agrees that he is bound by, and subject to, the Restrictive Covenants contained
in Article IX of his Change in Control Agreement, including the remedies stated
in said Article IX (including Section 9.6 of the Change in Control Agreement,
except that the reference in Section 9.6(d) of the Change in Control Agreement
to "severance or benefits" under the Change in Control Agreement shall be deemed
to be a reference to severance or benefits under this Agreement). The Executive
shall comply with, and observe, those Restrictive Covenants including, without
limitation, the confidential information, non-competition, non-solicitation and
intellectual property provisions and related covenants contained, respectively,
in Sections 9.1, 9.2, 9.3, 9.4 and 9.5 of the Change in Control Agreement, all
of which are hereby incorporated by reference.

                  10. Excise Taxes. If it is determined by Exelon's independent
auditors that any payment or benefit to the Executive pursuant to this Agreement
is or will become subject to any excise tax under Section 4999 of the Internal
Revenue Code of 1986, as amended, or any similar tax payable under any United
States federal, state, local, foreign or other law ("Excise Taxes"), then Exelon
shall, subject to any and all limitations described under Section 5.2 of the
Change in Control Agreement, as well as any and all obligations of the Executive
(including but not limited to notice and cooperation obligations) and rights and
remedies of Exelon described in Sections 5.4 and 5.5 of the Change in Control
Agreement, which limitations, obligations, rights and remedies are hereby
incorporated by reference, pay or cause to be paid a tax gross-up payment
("Gross-Up Payment"), with respect to all such Excise Taxes and other taxes on
the Gross-Up Payment. The amount of any such Gross-Up Payment shall be
determined in accordance with subparagraphs (a) and (b) of Section 5.1 and, if
applicable, Section 5.3, of the Change in Control Agreement.

                  11. Director and Officer Liability Insurance. For a period of
six years after the Employment Termination Date, the Company shall provide to
the Executive coverage under a directors' and officers' liability insurance
policy in an amount no less than, and on terms no less favorable than, those
provided to senior executive officers and directors of the Company.

                  12. Nondisparagement. The Executive shall not (a) make any
written or oral statement that brings the Company or any of its affiliates or
the employees, officers, directors or agents of the Company or any of its
affiliates into disrepute, or tarnishes any of their images or reputations or
(b) publish, comment upon or disseminate any statements suggesting or accusing
the Company or any of its affiliates or any employees, officers, directors or
agents of the Company or any of its affiliates of any misconduct or unlawful
behavior. The Company will use its best efforts to ensure that no officer,
director or spokesperson of the Company shall (x) make or cause to be made any
written or oral statement that brings the Executive into disrepute or tarnishes
his image or reputation, or (y) publish, comment upon or disseminate any
statements suggesting or accusing the Executive of any misconduct or unlawful
behavior. The provisions of this Section 10 shall not apply to testimony as a
witness, compliance with other legal obligations, assertion of or defense





                                       5


against any claim of breach of this Agreement, or any activity that otherwise
may be required by the lawful order of a court or agency of competent
jurisdiction, and shall not require the Company or any subsidiary or affiliate
thereof or the Executive to make false statements or disclosures.

                  13. Other Employment; Other Plans. The Executive shall not be
obligated to seek other employment or take any other action by way of mitigation
of the amounts payable to the Executive under any provision of this Agreement.
The amounts payable hereunder shall not be reduced by any payments received by
the Executive from any other employer; provided, however, that any continued
welfare benefits provided for by Section 8(a) shall not duplicate any benefits
that are provided to the Executive and his family by such other employer and
shall be secondary to any coverage provided by such other employer. The
provisions of this Section 13 will not limit the entitlement of the Executive to
any other benefits available to the Executive under any benefit plan or
practice, policy or program that is maintained by the Company or any Company
Affiliate in which the Executive participates.

                  14. Cooperation by the Executive. For the period commencing on
the Employment Termination Date and ending on the third anniversary of the
Employment Termination Date, the Executive shall be reasonably available to
Exelon and PECO and each of their respective subsidiaries and affiliates to
respond to reasonable requests by them for information pertaining to or relating
to Exelon, PECO and their respective subsidiaries and affiliates which may be
within the knowledge of the Executive. The Executive will cooperate fully with
Exelon and PECO in connection with any and all existing or future litigation
brought by or against Exelon, the Company or any of their respective
subsidiaries or affiliates, to the extent Exelon reasonably deems the
Executive's cooperation necessary. Exelon shall reimburse the Executive for any
reasonable out-of-pocket expenses incurred as a result of such cooperation and,
following the third anniversary of the Employment Termination Date, shall
compensate the Executive at the rate of $250 per documented hour for time spent
on such cooperation. The Executive shall be fully responsible for any taxes
payable as a result of the receipt of any such compensation.

                  15. Consent to Jurisdiction. The Executive agrees to submit
himself, and the Company agrees to submit itself, to the jurisdiction of the
courts of the State of Illinois in any action by the other to enforce an
arbitration award or to obtain injunctive or other relief.

                  16. Arbitration. Except as provided in Section 9, any dispute
or controversy between the Company and the Executive, whether arising out of or
relating to this Agreement or the Waiver and Release, the breach of this
Agreement or the Waiver and Release, or otherwise, shall be settled by
arbitration in the State of Illinois, administered by the American Arbitration
Association, with any such dispute or controversy arising under this Agreement
or the Waiver and Release being so administered in accordance with its employee
benefit rules then in effect, and judgment on the award rendered by the
arbitrator may be entered in any court having jurisdiction thereof. The
arbitrator shall have the authority to award any remedy or relief that a court
of competent jurisdiction could order or grant, including, without limitation,
the issuance of an injunction. However, either party may, without inconsistency
with this arbitration provision, apply to any court having jurisdiction over
such dispute or controversy and seek interim provisional, injunctive or other
equitable relief until the arbitration award is rendered or the controversy is
otherwise resolved. Except as necessary in court proceedings to enforce this





                                       6


arbitration provision or an award rendered hereunder, or to obtain interim
relief, neither a party nor an arbitrator may disclose the existence, content or
results of any arbitration hereunder without the prior written consent of the
Company and the Executive. The Company and the Executive acknowledge that this
Agreement evidences a transaction involving interstate commerce. Notwithstanding
any choice of law provision included in this Agreement, the United States
Federal Arbitration Act shall govern the interpretation and enforcement of this
arbitration provision.

                  17. Successors; Binding Agreement. This Agreement shall inure
to the benefit of and be enforceable by the Company and its successors and by
the Executive, his spouse, his personal or legal representatives, executors,
administrators, successors, heirs, distributees, devisees and legatees.

                  18. Governing Law; Validity. The interpretation, construction
and performance of this Agreement shall be governed by and construed and
enforced in accordance with the internal laws of the State of Illinois without
regard to the principle of conflicts of laws.

                  19. Entire Agreement. This Agreement, the Waiver and Release,
and the provisions of the agreements referenced herein, constitute the entire
agreement and understanding between the parties with respect to the subject
matter hereof and supersede and preempt any prior understandings, agreements or
representations by or between the parties, written or oral, which may have
related in any manner to the subject matter hereof, including but not limited to
the provisions of the Change in Control Agreement other than Article IX thereof.

                  20. Counterparts. This Agreement may be executed in two
counterparts, each of which shall be deemed to be an original and both of which
together shall constitute one and the same instrument.

                  21. Miscellaneous. No provision of this Agreement may be
modified or waived unless such modification or waiver is agreed to in writing
and executed by the Executive and by a duly authorized officer of the Company.
No waiver by either party hereto at any time of any breach by the other party
hereto of, or compliance with, any condition or provision of this Agreement to
be performed by such other party shall be deemed a waiver of similar or
dissimilar provisions or conditions at the same or at any prior or subsequent
time. Failure by the Executive or the Company to insist upon strict compliance
with any provision of this Agreement or to assert any right which the Executive
or the Company may have hereunder shall not be deemed to be a waiver of such
provision or right or any other provision or right of this Agreement.

                  22. Beneficiary. If the Executive dies prior to receiving all
of the amounts payable hereunder but after executing the Waiver and Release,
such amounts shall be paid, except as may be otherwise expressly provided herein
or in the applicable plans, in a lump-sum payment to the beneficiary
("Beneficiary") designated with respect to this Agreement by the Executive in
writing to the Company during his lifetime, which the Executive may change from
time to time by new designation filed in like manner without the consent of any
Beneficiary; or if no such Beneficiary is designated, to his estate.

                  23. Nonalienation of Benefits. Benefits payable under this
Agreement shall not be subject in any manner to anticipation, alienation, sale,
transfer, assignment, pledge, encumbrance, charge, garnishment, execution or





                                       7


levy of any kind, either voluntary or involuntary, prior to actually being
received by the Executive, and any such attempt to dispose of any right to
benefits payable hereunder shall be void.

                  24. Severability. If all or any part of this Agreement is
declared by any court or governmental authority to be unlawful or invalid, such
unlawfulness or invalidity shall not serve to invalidate any portion of this
Agreement not declared to be unlawful or invalid. Any paragraph or part of a
paragraph so declared to be unlawful or invalid shall, if possible, be construed
in a manner which will give effect to the terms of such paragraph or part of a
paragraph to the fullest extent possible while remaining lawful and valid.

                  25. Communications. Nothing in this Agreement, including
Sections 9 and 12, shall be construed to prohibit the parties from communicating
with, including testifying in any administrative proceeding before, the Nuclear
Regulatory Commission, the United States Department of Labor, the Securities
Exchange Commission or from otherwise addressing issues related to nuclear
safety with any party or taking any other action protected under Section 211 of
the Energy Reorganization Act and no such communication or action shall
constitute a breach of Section 12 or any other provision of this Agreement;
provided, however, that if the Executive is entitled under Section 211 of the
Energy Reorganization Act to pursue a claim, complaint or charge seeking
damages, costs or fees, the Executive agrees that the consideration provided to
the Executive pursuant to this Agreement shall be fully inclusive of all such
damages, costs and fees that could have been awarded to the Executive, that such
consideration is being paid in full and that the Executive under no
circumstances shall be entitled to compensation of any kind from the Company or
any of the other Company Released Parties not expressly provided for pursuant to
this Agreement.

                  26. Sections. Except where otherwise indicated by the context,
any reference to a "Section" shall be to a Section of this Agreement.















                                       8


                  IN WITNESS WHEREOF, Exelon and PECO have caused this Agreement
to be executed by their duly authorized officers and the Executive has executed
this Agreement as of the day and year first above written.

                                        EXELON CORPORATION


                                        By:_________________________________

                                        Title:_______________________________




                                        PECO ENERGY COMPANY


                                        By:_________________________________

                                        Title:_______________________________





                                        ___________________________________
                                                   KENNETH G. LAWRENCE







                                       9



                                                                       EXHIBIT I

                               WAIVER AND RELEASE

                                      UNDER

                       RETIREMENT AND SEPARATION AGREEMENT



                  In consideration for the Executive's receiving benefits and
severance pay under the Section 3 of the Retirement and Separation Agreement by
and between Exelon Corporation, PECO Energy Company (collectively, the
"Company") and Kenneth G. Lawrence (the "Executive") dated as of May 11, 2003,
(the "Retirement and Separation Agreement"), and in consideration of the
representations, covenants, and mutual promises set forth therein, the Executive
hereby agrees as follows:

         1. Release. Except with respect to the Company's obligations under the
Retirement and Separation Agreement, the Executive, on behalf of himself and his
heirs, executors, assigns, agents, legal representatives and personal
representatives, hereby releases, acquits and forever discharges the Company,
its agents, subsidiaries, affiliates, and their respective officers, directors,
agents, servants, employees, attorneys, shareholders, successors, assigns and
affiliates, of and from any and all claims, liabilities, demands, causes of
action, costs, expenses, attorneys fees, damages, indemnities and obligations of
every kind and nature, in law, equity, or otherwise, known and unknown, foreseen
or unforeseen, disclosed and undisclosed, suspected and unsuspected, arising out
of or in any way related to agreements, events, acts or conduct at any time
prior to the day of execution of this Waiver and Release, including but not
limited to any and all such claims and demands directly or indirectly arising
out of or in any way connected with the Executive's employment or other service
with the Company, or any of its Subsidiaries or affiliates; the Executive's
termination of employment and other service with the Company or any of its
subsidiaries or affiliates; claims or demands related to salary, bonuses,
commissions, stock, stock options, restricted stock or any other ownership
interests in the Company or any of its subsidiaries and affiliates, vacation
pay, fringe benefits, expense reimbursements, sabbatical benefits, severance,
change in control or other separation benefits, or any other form of
compensation or equity; and claims pursuant to any federal, state, local law,
statute, ordinance, common law or other cause of action including but not
limited to, the federal Civil Rights Act of 1964, as amended; the federal Age
Discrimination in Employment Act of 1967, as amended; the federal Americans with
Disabilities Act of 1990; tort law; contract law; wrongful discharge;
discrimination; fraud; defamation; harassment; emotional distress; or breach of
the covenant of good faith and fair dealing. This Waiver and Release does not
apply to the payment of any benefits to which the Executive may be entitled
under a Company-sponsored tax qualified retirement or savings plan.

         2. No Inducement. The Executive agrees that no promise or inducement to
enter into this Waiver or Release has been offered or made except as set forth
in this Waiver and Release and the Retirement and Separation Agreement, that the
Executive is entering into this Waiver and Release without any threat or
coercion and without reliance on any statement or representation made on behalf





                                       1


of the Company or any of its subsidiaries or affiliates, or by any person
employed by or representing the Company or any of its subsidiaries or
affiliates, except for the written provisions and promises contained in this
Waiver and Release and the Retirement and Separation Agreement.

         3. Advice of Counsel; Time to Consider; Revocation. The Executive
acknowledges the following:

                  (a) The Executive has read this Waiver and Release, and
                  understands its legal and binding effect, including that by
                  signing and not revoking this Waiver and Release the Executive
                  waives and releases any and all claims under the Age
                  Discrimination in Employment Act of 1967, as amended,
                  including but not limited to the Older Workers Benefits
                  Protection Act. The Executive is acting voluntarily and of the
                  Executive's own free will in executing this Waiver and
                  Release.

                  (b) The Executive has been advised to seek and has had the
                  opportunity to seek legal counsel in connection with this
                  Waiver and Release.

                  (c) The Executive was given at least twenty-one (21) days to
                  consider the terms of this Waiver and Release before signing
                  it.

         The Executive understands that, if the Executive signs the Waiver and
         Release, the Executive may revoke it within seven (7) days after
         signing it. The Executive understands that this Waiver and Release will
         not be effective until after the seven-day period has expired and no
         consideration will be due the Executive.

         4. Severability. If all or any part of this Waiver and Release is
declared by any court or governmental authority to be unlawful or invalid, such
unlawfulness or invalidity shall not invalidate any other portion of this Waiver
and Release. Any section or a part of a section declared to be unlawful or
invalid shall, if possible, be construed in a manner which will give effect to
the terms of the section to the fullest extent possible while remaining lawful
and valid.

         5. Amendment. This Waiver and Release shall not be altered, amended, or
modified except by written instrument executed by the Company and the Executive.
A waiver of any portion of this Waiver and Release shall not be deemed a waiver
of any other portion of this Waiver and Release.

         6. Headings. The headings of this Waiver and Release are not part of
the provisions hereof and shall not have any force or effect.

         7. Applicable Law. The provisions of this Waiver and Release shall be
interpreted and construed in accordance with the laws of the State of Illinois
without regard to its choice of law principles.




                                       2


                  IN WITNESS WHEREOF, the Executive has executed this Waiver and
Release as of the date specified below.

                                          KENNETH G. LAWRENCE



                                          _______________________________

                                          DATE:  ________________________





































                                       3


   (Filed on behalf of Exelon Corporation and Exelon Generation Company, LLC)


                                                                 EXECUTION COPY


                           PURCHASE AND SALE AGREEMENT
                                   dated as of
                                October 10, 2003
                                     between
                         BRITISH ENERGY INVESTMENT LTD.
                                       and
                         EXELON GENERATION COMPANY, LLC
                        relating to the sale and purchase
                                       of
              100% of the shares of British Energy US Holdings Inc.





                                TABLE OF CONTENTS

                                                                            Page

ARTICLE 1 DEFINITIONS..........................................................1
        SECTION 1.1   DEFINITIONS..............................................1
        SECTION 1.2   ACCOUNTING TERMS........................................15

ARTICLE 2 PURCHASE AND SALE...................................................15
        SECTION 2.1   PURCHASE AND SALE OF THE BEUSH SHARES FROM
                        BRITISH ENERGY........................................15
        SECTION 2.2   ADJUSTMENT TO PURCHASE PRICE............................15
        SECTION 2.3   CLOSING.................................................17
        SECTION 2.4   DELIVERIES BY BRITISH ENERGY AT CLOSING.................18
        SECTION 2.5   DELIVERIES BY BUYER AT CLOSING..........................19

ARTICLE 3 REPRESENTATIONS AND WARRANTIES OF SELLER............................19
        SECTION 3.1   CORPORATE EXISTENCE AND POWER OF SELLER AND THE
                        MEMBERS OF THE COMPANY GROUP..........................20
        SECTION 3.2   AUTHORIZATION, EXECUTION AND ENFORCEABILITY
                        OF TRANSACTIONS.......................................20
        SECTION 3.3   NON-CONTRAVENTION.......................................20
        SECTION 3.4   CONSENTS AND APPROVALS..................................20
        SECTION 3.5   FINANCIAL STATEMENTS....................................21
        SECTION 3.6   NO OTHER LIABILITIES....................................21
        SECTION 3.7   OWNERSHIP OF BEUSH SHARES...............................21
        SECTION 3.8   CAPITALIZATION OF BEUSH.................................21
        SECTION 3.9   OWNERSHIP OF INTERESTS IN THE COMPANY...................21
        SECTION 3.10   BEUSH OPERATIONS.......................................22
        SECTION 3.11   BRITISH ENERGY LP OPERATIONS...........................22
        SECTION 3.12   BRITISH ENERGY US INVESTMENTS LLC OPERATIONS...........22
        SECTION 3.13   ABSENCE OF CERTAIN CHANGES.............................23
        SECTION 3.14   LITIGATION.............................................23
        SECTION 3.15   MATERIAL CONTRACTS.....................................23
        SECTION 3.16   QUALIFIED DECOMMISSIONING FUNDS........................24
        SECTION 3.17   NONQUALIFIED DECOMMISSIONING FUNDS.....................25
        SECTION 3.18   INSURANCE..............................................26
        SECTION 3.19   COMPLIANCE WITH LAWS...................................26
        SECTION 3.20   ENVIRONMENTAL MATTERS..................................26
        SECTION 3.21   EMPLOYEES..............................................28
        SECTION 3.22   EMPLOYEES BENEFIT PLANS................................28
        SECTION 3.23   TAXES..................................................30
        SECTION 3.24   CONDEMNATION...........................................31
        SECTION 3.25   REAL PROPERTY..........................................31
        SECTION 3.26   PERMITS................................................31
        SECTION 3.27   PLANT AND EQUIPMENT; PERSONAL PROPERTY.................32

                                       ii


        SECTION 3.28   BANK ACCOUNTS..........................................32
        SECTION 3.29   INTELLECTUAL PROPERTY..................................32
        SECTION 3.30   SUBSIDIARIES...........................................32
        SECTION 3.31   UTILITIES..............................................32
        SECTION 3.32   BOOKS AND RECORDS......................................33
        SECTION 3.33   AFFILIATE TRANSACTIONS.................................33
        SECTION 3.34   BANKRUPTCY; SOLVENCY...................................33
        SECTION 3.35   FINDERS' OR BROKERS' FEES..............................33
        SECTION 3.36   DOE STANDARD SPENT FUEL CONTRACTS AND PAYMENT OF
                        DEFERRED ONE-TIME FEES................................33
        SECTION 3.37   PRICES AND TERMS FOR PURCHASE BY EXELON OF POWER
                        FROM THE FACILITIES...................................33
        SECTION 3.38   DISCLOSURE.............................................34
        SECTION 3.39   INQUIRIES BY SELLER....................................34
        SECTION 3.40   LIMITATION OF REPRESENTATIONS AND WARRANTIES...........34

ARTICLE 4 REPRESENTATIONS AND WARRANTIES OF BUYER.............................34
        SECTION 4.1   EXISTENCE AND POWER OF BUYER............................34
        SECTION 4.2   AUTHORIZATION...........................................35
        SECTION 4.3   NON-CONTRAVENTION.......................................35
        SECTION 4.4   CONSENTS AND APPROVALS..................................35
        SECTION 4.5   FINDERS' OR BROKERS' FEES...............................35
        SECTION 4.6   AVAILABILITY OF FUNDS...................................35
        SECTION 4.7   LITIGATION..............................................36
        SECTION 4.8   DUE DILIGENCE...........................................36
        SECTION 4.9   ABSENCE OF CERTAIN EVENTS...............................36
        SECTION 4.10   NO KNOWLEDGE OF BREACH.................................36
        SECTION 4.11   INQUIRIES BY BUYER.....................................36

ARTICLE 5 COVENANTS...........................................................36
        SECTION 5.1   GENERAL.................................................36
        SECTION 5.2   NOTICES, CONSENTS AND APPROVALS.........................36
        SECTION 5.3   OPERATION OF BUSINESS OF COMPANY GROUP DURING
                        INTERIM PERIOD........................................38
        SECTION 5.4   ACCESS AND INVESTIGATIONS DURING INTERIM PERIOD.........41
        SECTION 5.5   CERTAIN NOTICES.........................................42
        SECTION 5.6   FURTHER ASSURANCES; POST-CLOSING COOPERATION............43
        SECTION 5.7   GUARANTEES..............................................44
        SECTION 5.8   CONFIDENTIALITY.........................................44
        SECTION 5.9   PUBLIC ANNOUNCEMENTS....................................44
        SECTION 5.10   TAX MATTERS............................................45
        SECTION 5.11   INTERCOMPANY LOANS.....................................47
        SECTION 5.12   CORPORATE NAMES........................................47
        SECTION 5.13   ISRA CLEARANCE.........................................48
        SECTION 5.14   REIMBURSEMENT OF NONQUALIFIED DECOMMISSIONING FUNDS....48

                                      iii



        SECTION 5.15   DOCUMENTS RELATING TO LIABILITY FOR PAYMENT OF
                         ONE-TIME FEE FOR SPENT FUEL DISPOSAL.................48
        SECTION 5.16   PROHIBITED TRANSACTIONS................................49
        SECTION 5.17   FINANCIAL STATEMENTS...................................49
        SECTION 5.18   TRANSMISSION...........................................50
        SECTION 5.19   RISK OF LOSS...........................................50

ARTICLE 6 CONDITIONS TO CLOSING...............................................51
        SECTION 6.1   CONDITIONS TO OBLIGATIONS OF BUYER AND BRITISH
                        ENERGY................................................51
        SECTION 6.2   CONDITION TO OBLIGATION OF BUYER........................52
        SECTION 6.3   CONDITIONS TO OBLIGATION OF BRITISH ENERGY..............53

ARTICLE 7 INDEMNIFICATION.....................................................54
        SECTION 7.1   INDEMNIFICATION BY SELLER...............................54
        SECTION 7.2   INDEMNIFICATION BY BUYER................................54
        SECTION 7.3   LIMITATIONS ON INDEMNITY................................54
        SECTION 7.4   INDEMNITY PROCEDURES....................................55
        SECTION 7.5   PROCEDURAL REQUIREMENTS FOR ENVIRONMENTAL
                        CLAIMS BY BUYER.......................................56
        SECTION 7.6   SURVIVAL AND TIME LIMITATION............................57
        SECTION 7.7   SPECIFIC INDEMNITY BY SELLER............................57
        SECTION 7.8   FURTHER INDEMNITY LIMITATIONS...........................58
        SECTION 7.9   SOLE AND EXCLUSIVE REMEDY...............................58

ARTICLE 8 TERMINATION.........................................................58
        SECTION 8.1   TERMINATION.............................................58
        SECTION 8.2   EFFECT OF TERMINATION...................................59
        SECTION 8.3   REMEDIES................................................59

ARTICLE 9 MISCELLANEOUS.......................................................61
        SECTION 9.1   NOTICES.................................................61
        SECTION 9.2   AMENDMENTS; NO WAIVERS..................................62
        SECTION 9.3   EXPENSES................................................62
        SECTION 9.4   SUCCESSORS AND ASSIGNS..................................62
        SECTION 9.5   GOVERNING LAW...........................................62
        SECTION 9.6   COUNTERPARTS; EFFECTIVENESS.............................62
        SECTION 9.7   ENTIRE AGREEMENT........................................62
        SECTION 9.8   CAPTIONS................................................63
        SECTION 9.9   THIRD PARTY BENEFICIARIES...............................63
        SECTION 9.10   SEVERABILITY...........................................63
        SECTION 9.11   CONSTRUCTION...........................................63
        SECTION 9.12   CONSENT TO JURISDICTION................................63
        SECTION 9.13   WAIVER OF PUNITIVE AND OTHER DAMAGES AND JURY TRIAL....64
        SECTION 9.14   GOOD FAITH COVENANT....................................64
        SECTION 9.15   BUYER OBLIGATIONS......................................64

                                       iv



        SECTION 9.16   DISPUTE RESOLUTION.....................................64
        SECTION 9.17   CHANGE IN LAW..........................................65
        SECTION 9.18   TIME IS OF THE ESSENCE; ACTION ON A BUSINESS DAY.......65

                                       v



                                                            Exhibits & Schedules


Exhibit A(i)       Form British Energy Scottish Counsel Opinion
Exhibit A(ii)      Form British Energy U.S. Counsel Opinion
Exhibit B          [Intentionally Deleted]
Exhibit C          FIRPTA Affidavit
Exhibit D          Form of Seller Guaranty
Exhibit E          [Intentionally Deleted]
Schedule 1.1(a)    Seller Knowledge Group
Schedule 1.1(b)    Buyer Knowledge Group
Schedule 2.2       Working Capital Target
Schedule 2.2(d)    Capital Expenses Plan
Schedule 3.2       Authorization, Execution and Enforceability of Transactions
Schedule 3.3       Seller Non-Contravention
Schedule 3.4       Consents and Approvals
Schedule 3.5       Financial Statements
Schedule 3.6       Other Liabilities
Schedule 3.8       BEUSH Options, Warrants and Purchase Rights
Schedule 3.10      BEUSH Operations Exceptions
Schedule 3.11      British Energy, LP Operations Exceptions
Schedule 3.12      BEUILLC Operations Exceptions
Schedule 3.13      Absence of Certain Changes
Schedule 3.14      Litigation
Schedule 3.15      Material Contracts
Schedule 3.16      Qualified Decommissioning Funds
Schedule 3.17      Nonqualified Decommissioning Funds
Schedule 3.18      Insurance
Schedule 3.19      Compliance with Laws
Schedule 3.20      Environmental Matters
Schedule 3.21      Collective Bargaining Agreements; Employee Matters
Schedule 3.22      Employee Benefit Plans
Schedule 3.23      Taxes
Schedule 3.24      Condemnation
Schedule 3.25      Real Property
Schedule 3.26      Permits
Schedule 3.27      Plant and Equipment; Personal Property
Schedule 3.28      Bank Accounts
Schedule 3.30      Subsidiaries
Schedule 3.33      Affiliate Transactions
Schedule 3.37      Prices and Terms for Purchase by Exelon Power from the
                   Facilities
Schedule 4.3       Buyer Non-Contravention
Schedule 4.4       Consents and Approvals
Schedule 5.3(a)    Operation of Business of Company Group During Interim Period
Schedule 5.7       Guarantees
Schedule 5.11      Intercompany Loans

                                       vi



Schedule 5.17      Financial Statements During Interim Period
Schedule 6.2(d)    Buyer Regulatory Approvals
Schedule 6.3(d)    British Energy Regulatory Approvals

                                      vii

                                                                  EXECUTION COPY


                           PURCHASE AND SALE AGREEMENT

         PURCHASE AND SALE AGREEMENT (this "Agreement") dated as of October 10,
2003 between British Energy Investment Ltd., a Scottish company limited by
shares ("British Energy" or "Seller"), and Exelon Generation Company, LLC, a
Pennsylvania limited liability company ("Buyer"). British Energy and Buyer are
referred to herein individually as a "Party" and collectively as the "Parties".

         WHEREAS, British Energy owns all of the issued and outstanding capital
stock (the "BEUSH Shares") of British Energy US Holdings Inc., a Delaware
corporation ("BEUSH"), and BEUSH holds indirectly through its one hundred
percent (100%) owned subsidiary British Energy LP, a Delaware limited
partnership, fifty percent (50%) of the ownership interests in AmerGen Energy
Company, LLC, a Delaware limited liability company (the "Company"); and

         WHEREAS, pursuant to a notice from Buyer, dated October 3, 2003, Buyer
has elected, pursuant to the requirements of, and in accordance with, the
Limited Liability Company Agreement (as defined below), to exercise its right of
first refusal to purchase the BEUSH Shares;

         NOW, THEREFORE, in consideration of the mutual covenants and
undertakings contained herein, and on the terms and subject to the conditions
set forth herein, the Parties hereto agree as follows:

                                   ARTICLE 1

                                   Definitions

         SECTION 1.1 Definitions.

         The following terms, as used herein, have the following meanings:

         "Acceptance Notice" is defined in Section 7.4(a).

         "Action" means any action, suit, proceeding, condemnation,
investigation or audit by or before any court or other Governmental Authority,
or any arbitration proceeding.

         "Adjusted Purchase Price" is defined in Section 2.2(a).

         "Adjustment Amount" is defined in Section 2.2(f).

         "Adjustment Statement" is defined in Section 2.2(f).

         "Affiliate" means, with respect to any Person, any other Person
controlling, controlled by, or under common control with such Person. The
concept of control, controlling or controlled as used with respect to any Person
means the possession, directly or indirectly, of the power to direct or cause
the direction of the management and policies of such Person, whether through the
ownership of voting securities, by contract or otherwise.

         "Agreement" is defined in the Introduction.



         "Application" or "Applications" means all necessary or appropriate
actions to request NRC or FERC approval of a transfer of the BEUSH Shares,
indirect transfers of the Facilities' NRC licenses, or any amendment to the
Facilities' NRC licenses and such other matters as may be necessary or
appropriate with respect to the NRC or FERC in connection with the transactions
contemplated hereunder.

         "Assets" means, individually or in the aggregate, the assets and
properties of the Company, including, without limitation, the Facilities.

         "Atomic Energy Act" means the Atomic Energy Act of 1954, as amended, 42
U.S.C. Section 2011 et seq., or any successor statute.

         "BEUILLC" means British Energy US Investments, LLC, a Delaware limited
liability company.

         "BEUSH" means British Energy US Holdings, Inc., a Delaware corporation.

         "BEUSH Working Capital" means the Working Capital of the Company Group
(excluding the Company Working Capital).

         "BEUSH Working Capital Target" is defined in Section 2.1.

         "BEUSH Shares" is defined in the Recitals.

         "British Energy" means British Energy Investment Ltd., a Scottish
company limited by shares.

         `British Energy LP" means British Energy LP, a Delaware limited
partnership.

         "British Energy Regulatory Approvals" is defined in Section 6.3(d).

         "Business" means the business and operations of the Company Group.

         "Business Day" shall mean any day other than Saturday, Sunday and any
day on which banking institutions in the State of New York are authorized by law
or other governmental action to close.

         "Buyer" is defined in the Introduction.

         "Buyer Indemnified Party" and "Buyer Indemnified Parties" are defined
in Section 7.1.

         "Buyer Regulatory Approvals" is defined in Section 6.2(d).

                                       2


         "Capital Projects" means capital projects of the Company included in
the Company's budget for fiscal year 2003 except for Major Capital Projects.

         "Clinton" means the Clinton Nuclear Power Station located in Harp
Township, Illinois and identified in NRC Operating License No. NPF-62, Docket
No. 50-461, and the facilities, equipment, supplies and improvements relating
exclusively thereto.

         "Clinton FSAR" means the report, as updated, that is required to be
maintained for Clinton in accordance with the requirements of 10 CFR Section
50.71(e).

         "Clinton Technical Specifications" means the technical specifications
included in the NRC license for Clinton in accordance with the requirements of
10 CFR Section 50.36.

         "Closing" is defined in Section 2.3.

         "Closing Date" means the date of the Closing.

         "Code" means the Internal Revenue Code of 1986, as amended.

         "Collective Bargaining Agreements" is defined in Section 3.21.

         "Commercially Reasonable Efforts" means efforts which are reasonably
within the contemplation of the Parties on the date hereof, which are designed
to enable a Party, directly or indirectly, to satisfy a condition to, or
otherwise assist in the consummation of, the transactions contemplated by this
Agreement and which do not require the performing Party to expend any funds or
assume liabilities other than expenditures and liabilities which are reasonable
in nature and amount in the context of the transactions contemplated by this
Agreement; provided that, with respect to Buyer's obligations under Sections
5.1, 5.2 and 5.6, such term shall include any sale or other disposal of electric
generation facilities or uncommitted electric generation capacity required to
obtain the approval of FERC or any other Governmental Authority.

         "Company" means AmerGen Energy Company, LLC, a Delaware limited
liability company.

         "Company Group" means BEUSH, BEUILLC, British Energy LP, the Company
and their respective Subsidiaries.

         "Company Working Capital" means the Working Capital of the Company.

         "Company Working Capital Target" is defined in Section 2.1.

         "Confidentiality Agreement" means the confidentiality letter agreement
dated March 26, 2003, by and among Citigroup Global Markets Inc. on behalf of
Seller, and FPL.

         "Contested Proceeding" means a proceeding at NRC or FERC considering an
Application which becomes subject to hearing or other extraordinary procedure by
NRC or FERC.

         "Contested Taxes" is defined in Section 5.10(g).

                                       3



         "Credit Facility Agreement" means the Credit Facility Agreement dated
September 26, 2002, among the Secretary of State for Trade and Industry, British
Energy plc and others, as extended by the Extension and Amendment Agreement,
dated November 28, 2002 and the Further Extension and Amendment Agreement, dated
March 7, 2003.

         "Decommissioning Trust Agreement" means the Amended and Restated
Nuclear Decommissioning Master Trust Agreement effective October 16, 2001 among
the Company and Mellon Bank, N.A., as trustee.

         "Decommissioning Trusts" means the revocable trusts created pursuant to
the Decommissioning Trust Agreement, consisting of assets held as Qualified
Decommissioning Funds and Nonqualified Decommissioning Funds.

         "DOE" means the U.S. Department of Energy or any successor thereto.

         "Employee Benefit Plan" means any (a) nonqualified deferred
compensation or retirement plan or arrangement which is an Employee Pension
Benefit Plan, (b) qualified defined contribution retirement plan or arrangement
which is an Employee Pension Benefit Plan, (c) qualified defined benefit
retirement plan or arrangement which is an Employee Pension Benefit Plan, (d)
Employee Welfare Benefit Plan or material fringe benefit plan, program or
arrangement or (e) profit sharing, bonus, stock option, stock purchase equity,
stock appreciation, deferred compensation, incentive, severance plan or other
benefit plan.

         "Employee Pension Benefit Plan" has the meaning set forth in ERISA
Section 3 Subsection (2).

         "Employee Welfare Benefit Plan" has the meaning set forth in ERISA
Section 3 Subsection (1).

         "Energy Reorganization Act" means the Energy Reorganization Act of
1974, as amended.

         "Environment" means soil, land surface or subsurface strata, real
property, surface waters (including navigable waters, ocean waters, streams,
ponds, drainage basins and wetlands), groundwater, water body sediments,
drinking water supply, stream sediments, ambient air (including indoor air),
plant and animal life (including fish and all other aquatic life) and any other
environmental medium or natural resource.

         "Environmental Claim" means a claim by any Person based upon a breach
of Environmental Law or an Environmental Liability alleging loss of life, injury
to persons, property or business, damage to natural resources or trespass to
property.

         "Environmental Clean-Up Site" means any location which is listed or
formally proposed for listing on the National Priorities List, the Comprehensive
Environmental Response, Compensation and Liability Information System, or on any
similar state list of sites requiring investigation or cleanup, or which is the
subject of any action, suit, proceeding or investigation for any alleged
violation of any Environmental Laws.

                                       4



         "Environmental Laws" means all Laws including any binding
administrative or judicial interpretation thereof in effect as of or prior to
the date hereof relating to: (a) the regulation, protection and use of the
Environment; (b) the conservation, management, development, control and/or use
of land with respect to natural resources and wildlife; or (c) the management,
manufacture, possession, use, generation, transportation, treatment, storage,
disposal, Release, abatement, removal, remediation, or handling of or exposure
to, any Hazardous Substances; and includes, without limitation, the following
federal statutes (and their implementing regulations): the Comprehensive
Environmental Response, Compensation and Liability Act of 1980, as amended, 42
U.S.C.ss.9601 et seq.; the Hazardous Materials Transportation Act, 49
U.S.C.ss.1801 et seq.; the Solid Waste Disposal Act, 42 U.S.C.ss.6901 et seq.;
the Federal Water Pollution Control Act of 1972, as amended, 33 U.S.C.ss.1251 et
seq.; the Clean Air Act of 1966, as amended, 42 U.S. C.ss.7401 et seq.; the
Toxic Substances Control Act of 1976, as amended, 15 U.S.C.ss.2601 et seq.; the
Oil Pollution Act of 1990, as amended, 33 U.S.C.ss.2701 et seq.; the Emergency
Planning and Community Right-to-Know Act, 42 U.S.C.ss.11001 et seq.; the
Occupational Safety and Health Act, 29 U.S.C.ss.651 et seq., to the extent
involving handling of or exposure to Hazardous Substances; the Federal
Insecticide, Fungicide and Rodenticide Act, as amended, 7 U.S.C.ss.136 et seq.;
the Coastal Zone Management Act of 1972, as amended, 16 U.S.C.ss.1451 et seq.;
the Rivers and Harbors Act of 1899, as amended, 33 U.S.C.ss.401 et seq.; the
Endangered Species Act of 1973, as amended, 16 U.S.C.ss. 1531 et seq.; the Safe
Drinking Water Act of 1974, as amended, 42 U.S.C.ss.300(f) et seq.; all
analogous or comparable state statutes and regulations; and any common law
doctrine, including negligence, negligence per se, nuisance, trespass, personal
injury or property damage relating to or arising out of the Release of or
exposure to Hazardous Substances; provided, however, that in no event shall
"Environmental Laws" include any Nuclear Laws.

         "Environmental Liability" means any Liability of the Company which: (i)
arises under any Environmental Laws, as a result of (a) any violation or alleged
violation of Environmental Laws, with respect to the ownership, operation or use
of the Assets; (b) loss of life, injury to persons, property or business or
damage to natural resources caused (or allegedly caused) by the presence or
Release of Hazardous Substances at, on, in, under, above, adjacent to or
migrating from the Assets, including, but not limited to, Hazardous Substances
contained in building materials at the Assets or in the atmosphere, soil,
surface water, sediments, groundwater, landfill cells or in other environmental
media at or adjacent to the Assets; (c) the Remediation of Hazardous Substances
that are present or have been Released at, on, in, under, above, adjacent to or
migrating from the Assets, including, but not limited to, Hazardous Substances
contained in building materials at the Assets or in the atmosphere, soil,
surface water, sediments, groundwater, landfill cells or in other environmental
media at or adjacent to the Assets; (d) loss of life, injury to persons,
property or business or damage to natural resources caused (or allegedly caused)
by the offsite disposal, storage, transportation, discharge, Release or
recycling, or the arrangement for such activities, of Hazardous Substances, in
connection with the ownership or operation of the Assets; and (e) the
Remediation of Hazardous Substances that are disposed, stored, transported,
discharged, Released, recycled, or the arrangement of such activities, in
connection with the ownership or operation of the Assets, and (ii) is
attributable to the Company's conduct during the Seller Ownership Period,
provided, however, that in no event shall "Environmental Liability" include
Nuclear Liability.

         "ERISA" means the Employee Retirement Income Security Act of 1974, as
amended, and any successor statute thereto, and the rules and regulations
promulgated thereunder.

                                       5



         "ERISA Affiliate" of any entity means any other entity which, together
with such entity, would be treated as a single employer under Section 414 of the
Code.

         "Event of Loss" is defined in Section 5.19.

         "Exelon" means Exelon Generation Company, LLC. "Facilities" means
         Clinton, TMI-l and Oyster Creek, collectively.

         "Facility" means each of Clinton, TMI-1 and Oyster Creek.

         "FERC" means the Federal Energy Regulatory Commission, or its
regulatory successor, as applicable.

         "Federal Power Act" means the Federal Power Act, 16 U.S.C. Section 792,
et seq., as amended, or any successor statute.

         "Final Safety Analysis Reports" or "FSARs" means collectively, the
Clinton FSAR, the TMI-l FSAR and the Oyster Creek FSAR, as required in
accordance with 10 C.F.R. Section 50.71(e).

         "Financial Statements" is defined in Section 3.5.

         "FIRPTA Affidavit" means the Foreign Investment in Real Property Tax
Act Certification and Affidavit, substantially in the form of Exhibit C hereto.

         "FPL" is defined in Section 8.1(b).

         "GAAP" means generally accepted accounting principles in the United
States.

         "Good Utility Practices" means any of the practices, methods and
activities engaged in and approved by a significant portion of the electric
utility industry in the United States as good practices applicable to nuclear
generating facilities of similar design, size and capacity during the relevant
time period or any of the practices, methods or activities which, in the
exercise of reasonable judgment by a prudent nuclear operator in light of the
facts known at the time the decision was made, could have been expected to
accomplish the desired result at a reasonable cost consistent with good business
practices, reliability, safety and applicable Law. Good Utility Practices are
not intended to be limited to the optimal practices, methods or acts to the
exclusion of all others, but rather to be practices, methods or acts generally
accepted in the United States utility industry applicable to nuclear generating
facilities.

         "Governmental Authority" means (a) any governmental, regulatory or
administrative agency, commission, department, board or other governmental
subdivision of (i) the United States of America, or (ii) any state, county,
municipality or other governmental subdivision within the United States of
America, and (b) any court, tribunal or arbitral body of the United States of
America or of any state, county, municipality or other governmental subdivision
within the United States of America.

         "Guarantees" is defined in Section 5.7.

                                       6



         "Hazardous Substance" means (a) any petrochemical or petroleum
products, oil or coal ash, radioactive materials, radon gas, asbestos or
asbestos-containing material, polychlorinated biphenyls, lead based paint or
urea formaldehyde foam insulation, (b) any chemicals, materials, substances or
wastes which are currently defined or regulated as "hazardous substances,"
"hazardous materials," "hazardous constituents," "extremely hazardous
substances," "hazardous wastes," "restricted hazardous materials," "toxic
substances," "toxic pollutants," "toxic air pollutants," "pollutants" or
"contaminants" or words of similar meaning and regulatory effect under any
Environmental Law, and (c) any other chemicals, materials, wastes or substances,
the exposure to or treatment, storage, transportation, disposal or Release of
which is prohibited, limited or regulated by any Environmental Law; provided,
however, that "Hazardous Substances" shall specifically exclude any "Nuclear
Material," as defined in this Agreement, to the extent regulated under any
Nuclear Laws.

         "High Level Waste" means (a) Spent Nuclear Fuel, (b) liquid wastes
resulting from the operation of the first cycle solvent extraction system, or
its equivalent, and the concentrated wastes from subsequent extraction cycles,
or their equivalent, in a facility for reprocessing irradiated reactor fuel, or
(c) solids into which such liquid wastes have been converted, or (d) any other
material containing radionuclides in concentration or quantities that exceed NRC
requirements for classification as Low Level Waste.

         "HSR Act" means the Hart-Scott-Rodino Antitrust Improvements Act of
1976, as amended, and the applicable rules and regulations promulgated
thereunder.

         "ICC" means the Illinois Commerce Commission and any successor agency
thereto.

         "Indemnified Claim" is defined in Section 7.4(c).

         "Indemnified Party" is defined in Section 7.4(a).

         "Indemnifying Party" is defined in Section 7.4(a).

         "Independent Accounting Firm" means a nationally-recognized independent
accounting firm in the United States mutually appointed by British Energy and
Buyer.

         "Intercompany Loans" is defined in Section 5.11.

         "Interim Period" means that period of time commencing on the date
hereof and ending on the Closing Date.

         "Inventory" means those items listed in the Company's Passport System
with respect to Clinton and PIMS with respect to Oyster Creek and TMI-1.

         "Inventory Target Amount" is defined in Section 2.1.

         "ISRA" is defined in Section 5.13.

         "Knowledge" means (a) with respect to Seller, the actual knowledge of
the individuals listed on Schedule 1.1(a), based on a reasonable inquiry of
appropriate employees of the Company (including without limitation seconded
employees of Seller) and (b), with respect to Buyer, the actual knowledge of the

                                       7



individuals listed on Schedule 1.1(b), based on a reasonable inquiry of
appropriate employees of the Buyer.

         "Law" means any applicable statute, law, code, ordinance, regulation,
rule, ruling, order, restriction, requirement, writ, injunction, judgment,
charge, license, interpretation, constitution, decree, common law, treaty or
other official act or restriction of or by any Governmental Authority.

         "Leased Real Property" is defined in Section 3.25(b).

         "Liability" means any liability or obligation, whether known or
unknown, asserted or unasserted, absolute or contingent, accrued or unaccrued,
liquidated or unliquidated, or incurred or consequential, and whether due or to
become due.

         "Lien" means, with respect to any asset, any mortgage, lien, pledge,
charge, security interest, encumbrance, option, warrant, purchase right, lease
or other encumbrance, or adverse claim of any kind in respect of such asset
except for any of the foregoing contained in or granted pursuant to Section 7.3
of the LLC Agreement. For the purposes of this Agreement, a Person shall be
deemed to own subject to a Lien any asset which it has acquired or holds subject
to the interest of a vendor or lessor under any conditional sale agreement,
capital lease or other title retention agreement relating to such asset.

         "Limited Liability Company Agreement" or "LLC Agreement" means the
Amended and Restated Limited Liability Company Agreement of the Company dated as
of August 1, 2000, and amended on December 21, 2001 and May 1, 2002.

         "Losses" (and, with correlative meaning, "Loss") means any and all
claims, Liabilities, losses, damages, causes of action, fines, penalties,
litigation, lawsuits, administrative proceedings, administrative investigations
and costs and expenses, including reasonable attorneys' fees, court costs and
other costs of suit; provided, however, that with respect to any of the
foregoing suffered or incurred by the Company, "Losses" for purposes of this
Agreement shall in no event exceed 50% of the Company's Losses.

         "Low Level Waste" means waste material which contains radioactive
nuclides emitting either primarily beta or gamma radiation, or both, in
concentrations or quantities which exceed applicable federal or state standards
for unrestricted release; provided that Low Level Waste shall not include any
waste containing more than ten (10) nanocuries of transuranic contaminants per
gram of material, Spent Nuclear Fuel, or material classified as either High
Level Waste or waste which is unsuited for disposal by near-surface burial under
any applicable federal regulations.

         "Major Capital Projects" means those capital projects of the Company
involving expenditures in excess of $500,000, each of which is identified on
Schedule 2.2(d) and such other capital projects as may be agreed upon by the
Parties after the date hereof.

         "Major Loss" is defined in Section 5.19(b).

         "Material Adverse Effect" means when used in connection with any
Person, any change, effect, event, occurrence or state of facts (a) that is, or
would likely be, materially adverse to the business, assets, properties,
financial condition or results of operations of such Person and its Subsidiaries

                                       8



taken as a whole, or (b) that prevents, or can reasonably be expected to
prevent, such Person from performing any of its material obligations under this
Agreement or consummation of the transactions contemplated hereby; provided,
however, that Material Adverse Effect shall not include any change (or changes
taken together) generally affecting the international, national, regional or
local wholesale or retail electric industry as a whole or nuclear generating
facilities or their operations or operators as a whole which does not affect the
Assets or the Parties in any manner or degree significantly different than the
industry as a whole, including but not limited to (i) changes in markets for
electric power, nuclear generation or fuel used in connection with the Assets,
(ii) changes resulting from or associated with acts of war or terrorism or
changes imposed by a Governmental Authority to address the events of September
11, 2001, or (iii) changes (individually or taken together) in the North
American, national, regional or local electric transmission systems or
operations thereof; and provided, further, that any loss, claim, occurrence,
change or effect that is cured prior to the Closing Date (at Seller's expense),
or that is a result of a change in general economic, regulatory or political
conditions, shall not be considered a Material Adverse Effect.

         "Material Contract" is defined in Section 3.15.

         "Multiemployer Plan" means each Employee Benefit Plan that is a
multiemployer plan, as defined in Section 3(37) of ERISA.

         "NJBPU" means the New Jersey Board of Public Utilities and any
successor agency thereto.

         "Nonqualified Decommissioning Fund(s)" means one or more of the
external trust funds that do not meet the requirements of Code Section 468A or
Treas. Reg. Section 1.468A-5, maintained by the Company pursuant to the
Decommissioning Trust Agreements, as further defined in Section 3.17(a).

         "NQDF Tax Reimbursement" means the distribution from the Non-Qualified
Decommissioning Funds for administrative costs and other incidental expenses for
periods prior to the Closing Date.

         "NQDF Tax Reimbursement Share" means an amount equal to fifty percent
(50%) of any NQDF Tax Reimbursement received by the Company up to a maximum
amount of $12,500,000.

         "NRC" means the United States Nuclear Regulatory Commission, as
established by Section 201 of the Energy Reorganization Act of 1974, as amended,
42 U.S.C. Section 5841, or any successor commission, agency or officer.

         "NRC Staff" means the regulatory staff of the NRC.

         "Nuclear Fuel" means all nuclear fuel assemblies in the Facilities'
reactors on the Closing Date and any irradiated nuclear fuel assemblies that
have been temporarily removed from the Facilities' reactors as of the Closing
Date and all nuclear unirradiated fuel assemblies awaiting insertion into the
Facilities' reactors, as well as all nuclear fuel constituents in any stage of
the fuel cycle which are in the process of production, conversion, enrichment or
fabrication for use in the Facilities or which have been or will be purchased
for the Facilities.

                                       9



         "Nuclear Fuel Amount" is defined in Section 2.1.

         "Nuclear Laws" means all applicable Federal, state, local, provincial,
foreign and international civil and criminal Laws, regulations, rules,
ordinances, codes, decrees, judgments, directives, or judicial or administrative
orders relating to the regulation of nuclear power plants, source material,
byproduct material and special nuclear materials (as defined in the Atomic
Energy Act); the regulation of Low Level Waste and High Level Waste; the
transportation and storage of Nuclear Materials; the regulation of safeguards
information; the regulation of nuclear fuel; the enrichment of uranium; the
disposal and storage of High Level Waste and Spent Nuclear Fuel; contracts for
any payments into the Nuclear Waste Fund; and as applicable, the antitrust laws
and the Federal Trade Commission Act to specified activities or proposed
activities of certain licenses of commercial nuclear reactors, but shall not
include Environmental Laws. "Nuclear Laws" include the Atomic Energy Act of
1954, as amended (42 U.S.C. Section 2011 et seq.); the Price-Anderson Act
(Section 170 of the Atomic Energy Act of 1954, as amended); the Energy
Reorganization Act of 1974 (42 U.S.C. Section 5801 et seq.); Convention on the
Physical Protection of Nuclear Material Implementation Act of 1982 (Public Law
97-351; 96 Stat. 1663); the Foreign Assistance Act of 1961 (22 U.S.C. Section
2429 et seq.); the Nuclear Non-Proliferation Act of 1978 (22 U.S.C. Section
3201); the Low-Level Radioactive Waste Policy Act (42 U.S.C. Section 202lb et
seq.); the Nuclear Waste Policy Act, (42 U.S.C. Section 10101 et seq., as
amended); the Low-Level Radioactive Waste Policy Amendments Act of 1985 (42
U.S.C. Section 2021d, 471); the Energy Policy Act of 1992 (4 U.S.C. Section
13201 et seq.); and any applicable state or local Laws analogous to the
foregoing.

         "Nuclear Liability" means any Liability arising out of or resulting
from the hazardous or radioactive properties of (a) Nuclear Material or any
other fissionable isotope and (b) any fission product resulting from the fission
process.

         "Nuclear Material" means any source, special nuclear or byproduct
material, as defined in the Atomic Energy Act of 1954, as amended.

         "Nuclear Waste Fund" means the fund established pursuant to Section
302(c) of the Nuclear Waste Policy Act of 1982, as amended.

         "OCIP" is defined in Section 3.18.

         "Offsite Hazardous Substance Facility" means a location, or transport
vehicle or vessel, which accepts or accepted Hazardous Substances for treatment,
storage or disposal, other than a Facility.

         "Owned Real Property" is defined in Section 3.25(a).

         "Oyster Creek" means the Oyster Creek Nuclear Generating Station
located in Lacey Township, New Jersey and identified in NRC Operating License
No. DPR-16, Docket No. 50-219, and the facilities, equipment, supplies and
improvements relating exclusively thereto.

         "Oyster Creek FSAR" means the report, as updated, that is required to
be maintained for Oyster Creek in accordance with the requirements of 10 C.F.R.
Section 50.7 1(e).

                                       10



         "Oyster Creek Technical Specifications" means the technical
specifications included in the NRC License for Oyster Creek in accordance with
the requirements of 10 C.F.R. Section 50.36.

         "PaPUC" means the Pennsylvania Public Utility Commission and any
successor agency thereto.

         "Party" means either Buyer or Seller.

         "Parties" means Buyer and Seller collectively.

         "Permits" means all certificates, licenses, permits, approvals,
consents, orders,
exemptions, decisions and other actions of a Governmental Authority to the
extent pertaining to the ownership or operation of the Company, the Assets or
the Facilities.

         "Permitted Encumbrances" means and includes: (a) Liens for Taxes or
other charges or assessments by any Governmental Authority to the extent that
the payment thereof is not in arrears or otherwise due or is being contested in
good faith; (b) encumbrances in the nature of zoning restrictions, building and
land use Laws, ordinances, orders, decrees, restrictions or any other conditions
imposed by or pursuant to any agreement with any Governmental Authority;
provided, however, that the same do not materially detract from operation or use
of such property; (c) easements granted or reserved by an instrument executed in
connection with this Agreement or the transactions contemplated hereby or
thereby, but excluding such encumbrances that secure indebtedness; (d) deposits
or pledges made in connection with or to secure payment of workers'
compensation, unemployment insurance, pension programs mandated under applicable
Laws or other social security regulations; (e) statutory or common law liens in
favor of carriers, warehousemen, mechanics and materialmen, statutory or common
law liens to secure claims for labor, materials or supplies and other like
liens, which secure obligations to the extent that payment thereof is not in
arrears or otherwise due; (f) any Lien or title imperfection with respect to the
Assets created by or resulting from any act or omission of the Buyer; and (g)
Liens arising under purchase money obligations to finance the purchase of, and
limited to, equipment and other personal property.

         "Person" means an individual, corporation, partnership, limited
partnership, association, trust, limited liability company, joint venture or
other entity or organization, including a government or political subdivision or
an agency or instrumentality thereof.

         "Plant Material Adverse Effect" means any event, circumstance, claim,
occurrence, change or effect related to any Facility which could reasonably be
expected to cause a Loss by the Buyer within one year following the Initial
Closing Date in excess of $2,000,000 individually, or in excess of $10,000,000
in the aggregate; provided, however, that Plant Material Adverse Effect shall
not include any change (or changes taken together) generally affecting the
international, national, regional or local wholesale or retail electric industry
as a whole or nuclear generating facilities or their operations or operators as
a whole which does not affect the Assets or the Parties in any manner or degree
significantly different than the industry as a whole, including but not limited
to (a) changes in markets for electric power or fuel used in connection with the
Assets, (b) changes resulting from or associated with acts of war or terrorism
or changes imposed by a Governmental Authority to address the events of
September 11, 2001, or (c) changes (individually or taken together) in the North
American, national, regional or local electric transmission systems or

                                       11



operations thereof; and provided, further, that any event, circumstance, claim,
occurrence, change or effect that is cured prior to the Closing Date, at the
Seller's expense, or that is a result of general economic, regulatory or
political conditions, shall not be considered a Plant Material Adverse Effect.

         "Pledge Agreement" means the Pledge Agreement, dated September 27, 2002
and amended as of November 28, 2002, between the Secretary of State for Trade
and Industry and BEUSH.

         "Pre-Closing ERISA Liability" shall mean any Liability or obligation of
BEUSH, BEUILLC or British Energy LP as a result of such member of the Company
Group being considered at any time prior to the Closing Date a single company
with any other Person pursuant to ERISA Section 4001 or Section 414 of the Code.

         "Prime Rate" means the prime lending rate as reported in The Wall
Street Journal from time to time as the base rate on loans to creditworthy
corporate borrowers.

         "Prohibited Transactions" are defined in Section 5.16.

         "Property Tax Agreement" means agreements with a taxing authority
having jurisdiction and powers to impose real property Tax, personal property
Tax or other Taxes on the Assets.

         "Purchase Price" is defined in Section 2.1.

         "Qualified Decommissioning Funds" means the external trust funds that
meet the requirements of Code Section 468A and Treas. Reg. Section 1.468A-5
maintained by the Company pursuant to the Decommissioning Trust Agreements, as
further defined in Section 3.16(a).

         "Real Property Leases" is defined in Section 3.25(b).

         "Release" means any actual, threatened or alleged spilling, leaking,
pumping, pouring, emitting, dispersing, emptying, discharging, injecting,
escaping, leaching, migrating, dumping, or disposing of any Hazardous Substance
into the Environment that may cause an Environmental Liability (including the
disposal or abandonment of barrels, containers, tanks or other receptacles
containing or previously containing any Hazardous Substance). The term
"Released" has a comparable meaning.

         "Remediation" means any and all of the following activities to the
extent required under applicable Environmental Law to address the presence or
Release of Hazardous Substances: (a) monitoring, investigation, assessment,
treatment, cleanup, containment, removal, mitigation, response or restoration
work as well as obtaining any permits, consents, approvals or authorizations of
any Governmental Authority necessary to conduct such activities; (b) preparing
and implementing any plans or studies for any such activities; (c) obtaining a
written notice from a Governmental Authority with competent jurisdiction under
Environmental Laws that no material additional work in connection with such
activities is required; and (d) any other related activities required under
Environmental Laws.

                                       12



         "Representative" means, with respect to any Person, any of such
Person's Affiliates and its or their agents (including, without limitation,
accountants, counsel, directors, officers, employees, consultants, advisors or
investment bankers).

         "Required Expenditure" is defined in Section 5.3(a).

         "Required Nuclear Expenditure" means a capital expenditure that is (a)
required in order to satisfy an order from the NRC or other applicable legal
requirement, (b) required in order to preclude, forestall or satisfy any form of
NRC enforcement action (including, without limiting the generality of the
foregoing, a so-called "confirmatory action letter"), or (c) necessary in order
to cause a Facility to meet NRC regulations.

         "Schedule" means a schedule to this Agreement.

         "Seller" is defined in the Introduction.

         "Seller Indemnified Party" and "Seller Indemnified Parties" are defined
in Section 7.2.

         "Seller Ownership Period" means, with respect to each Facility or
Asset, the period of time beginning on the date on which the Company first
acquired any direct or indirect ownership or leasehold interest in any Facility
or Asset and ending on the Closing Date.

         "Seller Ownership Period Environmental Liability" shall mean any
Liability under applicable Environmental Law in effect on or prior to the
Closing Date, to the extent relating to (i) the disposal, storage,
transportation, discharge, release, recycling or arrangement for such activities
of Hazardous Substances at or from a Facility, at any Offsite Hazardous
Substance Facility, or at a location other than the Facility to the extent
caused by the Company Group, or by or on behalf of any member of the Company
Group, where the initial disposal, storage, transportation, discharge, release
or recycling of such Hazardous Substances occurred during the Seller Ownership
Period, (ii) the failure during the Seller Ownership Period of any operations of
any member of the Company Group to be in compliance with any applicable
Environmental Laws, and (iii) any other act or failure to act (where there is a
duty to act under Law) occurring during the Seller Ownership Period with respect
to any Assets of the Company or its Subsidiaries or a Facility which gives rise
to any Environmental Liability. By way of example, but not in limitation, civil
or criminal claims and/or penalties arising from the 2002 fish kill incident
involving Oyster Creek constitutes a Seller Ownership Period Environmental
Liability.

         "Solvent" means, as to any Person, that such Person is able to pay its
debts as they mature and owns property having a fair market value greater than
the amount required to pay its debts.

         "Spent Nuclear Fuel" means fuel and other radioactive materials
associated with nuclear fuel assemblies that have been withdrawn from a nuclear
reactor following irradiation, and have not been chemically separated into its
constituent elements by reprocessing.

         "Subsidiary" when used in reference to any Person means any entity of
which securities or other ownership interests having ordinary voting power to
elect a majority of the board of directors or other persons performing similar
functions are at the time directly or indirectly owned by such Person.

                                       13



         "Taking" is defined in Section 5.19.

         "Tax Basis" means the adjusted tax basis determined for federal income
tax purposes under Code Section 1011(a).

         "Taxes" (and, with correlative meaning, "Tax") means any taxes, duties,
assessments, fees, levies, or similar governmental charges, together with any
interest, penalties and additions to tax, imposed by any Taxing Authority
,including without limitation all net income, gross income, gross receipts, net
receipts, sales, use, transfer, franchise, privilege, profits, social security,
disability, withholding, payroll, unemployment, employment, excise, severance,
property, windfall profits, value added, ad valorem, occupation, license,
business enterprise, stamp, premium, environmental (including Taxes under
Section 59 of the Code), capital stock, recordation, registration, estimated or
other Tax or similar governmental charge or imposition of any kind or nature.

         "Taxing Authority" means any taxing authority, wherever located (i.e.,
whether federal, state, local, municipal or foreign).

         "Tax Return" means any return, report, information return, declaration,
claim for refund or other document (including any schedule or related or
supporting information) required to be supplied to any taxing authority with
respect to Taxes including amendments thereto.

         "Technical Specifications" means, collectively, the Clinton Technical
Specifications the TMI-1 Technical Specifications and the Oyster Creek Technical
Specifications.

         "TMI-l" means Three Mile Island Unit 1 Nuclear Generating Facility
located near Middletown, Pennsylvania and identified in NRC Operating License
No. DPR-50, Docket No. 50-289, and the facilities, equipment, supplies and
improvements relating exclusively thereto.

         "TMI-1 FSAR" means the report, as updated, that is required to be
maintained for TMI-l in accordance with the requirements of 10 C.F.R. Section
50.71(e).

         "TMI-1 Technical Specifications" means the technical specifications
included in the NRC license for TMI-1 in accordance with the requirements of 10
C.F.R. Section 50.36.

         "Transition Executive Committee" is defined in Section 5.3(b).

         "Working Capital" means the excess of current assets over current
liabilities, determined in accordance with GAAP, consistently applied; provided,
however, that for purposes of this computation, if any Tax Return is filed with
respect to any member of the Company Group after June 30, 2003, and if such Tax
Return reflects a higher initial Tax Basis for the assets of the Company than
reported in prior Tax Returns as a result of a redetermination of the initial
purchase price of such assets attributable to the nonqualified decommissioning
liability, the excess, if any, of (a) the Taxes which would have been reported
on such Tax Return had such Tax Return been filed without reflecting such higher
Tax Basis, over (b) the Taxes reported on such Tax Return, shall be treated as a
current liability, but only to the extent that such excess (whether in the form
of a receivable, a Tax refund or a reduction in Tax liability) has otherwise
been taken into account in determining Working Capital; provided further, that

                                       14



any distribution directly or indirectly from the Nonqualified Decommissioning
Funds to any member of the Company Group in excess of (i) $25 million in the
case of the Company, or (ii) the NQDF Tax Reimbursement Share in the case of any
member of the Company Group other than the Company, shall be excluded from
Working Capital.

         SECTION 1.2 Accounting Terms. Any accounting terms used in this
Agreement shall, unless otherwise specifically provided, have the meanings
customarily given them in accordance with GAAP, and all financial computations
hereunder or thereunder shall, unless otherwise specifically provided, be
computed in accordance with GAAP consistently applied.

                                   ARTICLE 2

                                Purchase and Sale

         SECTION 2.1 Purchase and Sale of the BEUSH Shares from British Energy.
Upon the terms and subject to the conditions of this Agreement, at the Closing,
British Energy agrees to sell to Buyer, and Buyer agrees to purchase from
British Energy, the BEUSH Shares. The aggregate purchase price for the BEUSH
Shares will be $276,500,000 in cash (the "Purchase Price"), which shall be paid
as provided in Section 2.5(f) and shall be subject to adjustment as provided in
Section 2.2. The Purchase Price includes an allowance of (i) negative
$26,800,000 for the Working Capital of the Company (the "Company Working Capital
Target"), (ii) negative $6,375,167 for the Working Capital of BEUSH (the "BEUSH
Working Capital Target"), (iii) $31,100,000 for the book value of Inventory (the
"Inventory Target Amount"), and (iv) $206,500,000 for the net book value of
Nuclear Fuel (the "Nuclear Fuel Amount").

         SECTION 2.2 Adjustment to Purchase Price. The "Adjusted Purchase Price"
shall be the Purchase Price, less the amounts payable pursuant to Section
2.5(g), as increased or decreased, as follows:

                  (a) There shall be an adjustment for Working Capital equal to
(i) fifty percent (50%) of the sum of the Company Working Capital as of the
Closing Date minus the Company Working Capital Target, plus (ii) the sum of the
BEUSH Working Capital minus the BEUSH Working Capital Target. The statement of
the Company Working Capital as of the Closing Date shall be prepared by British
Energy within sixty (60) days of the Closing Date using the same GAAP, policies
and methods as the Company has historically used in connection with the
calculation of the items reflected in the Company Working Capital Target set
forth on Schedule 2.2. The statement of BEUSH Working Capital as of the Closing
Date shall be prepared by British Energy within sixty (60) days of the Closing
Date using the same GAAP, policies and methods as BEUSH has historically used in
connection with the calculation of the items reflected in the BEUSH Working
Capital Target set forth on Schedule 2.2. Buyer and British Energy each agree to
cooperate in connection with the preparation of the statement of the Company
Working Capital and the statement of BEUSH Working Capital as of the Closing
Date and related information, and each shall provide to the other such books,
records and information as may be reasonably requested from time to time.

                  (b) There shall be an adjustment for Inventory equal to fifty
percent (50%) of the sum of the book value of the Inventory (including
reductions for missing, unusable or obsolete Inventory on a basis consistent
with the Company's past practices) as of the Closing Date minus the Inventory

                                       15



Target Amount. The statement of the book value of the Inventory as of the
Closing Date shall be prepared by British Energy within sixty (60) days of the
Closing Date using the same GAAP, policies and methods as the Company has
historically used in connection with the calculation of the book value of
Inventory (including reductions for missing, unusable or obsolete Inventory on a
basis consistent with the Company's past practices). Buyer and British Energy
each agree to cooperate in connection with the preparation of the statement of
the book value of Inventory as of the Closing Date and related information, and
each shall provide to the other such books, records and information as may be
reasonably requested from time to time.

                  (c) There shall be an adjustment for Nuclear Fuel equal to
fifty percent (50%) of the sum of the net book value of the Nuclear Fuel as of
the Closing Date minus the Nuclear Fuel Amount. The statement of the net book
value of the Nuclear Fuel as of the Closing Date shall be prepared by British
Energy within sixty (60) days of the Closing Date using the same GAAP, policies
and methods as the Company has historically used in connection with the
calculation of the net book value of Nuclear Fuel. Buyer and British Energy each
agree to cooperate in connection with the preparation of the net book value of
Nuclear Fuel as of the Closing Date and related information, and each shall
provide to the other such books, records and information as may be reasonably
requested from time to time.

                  (d) There shall be a downward adjustment for capital
expenditures equal to (i) fifty percent (50%) of the excess, if any, of the
budget for Capital Projects over the actual expenditures by the Company for such
Capital Projects as of December 31, 2003, in the aggregate, plus (ii) fifty
percent (50%) of the total projected costs to complete Major Capital Projects
that the Company failed to complete on or prior to the Closing Date but were
scheduled to be completed on or prior to such date, on a project by project
basis, plus (iii) fifty percent (50%) of the Company's total expected costs as
of the Closing Date to complete any unfinished Major Capital Projects that were
not scheduled to be completed on or prior to such date in excess, if any, of the
budget for such Major Capital Projects, on a project by project basis. The
statement of the actual expenditures by the Company for Capital Projects and
Major Capital Projects and the Company's projected costs to complete any
unfinished Major Capital Projects shall be prepared by British Energy within
sixty (60) days of the Closing Date using the same GAAP, policies and methods as
the Company has historically used in connection with preparation of the budget
set forth on Schedule 2.2(d). Buyer and British Energy each agree to cooperate
in connection with the preparation of the actual expenditures by the Company for
Major Capital Projects and the Company's projected costs to complete any
unfinished Major Capital Projects as of the Closing Date and related
information, and each shall provide to the other such books, records and
information as may be reasonably requested from time to time.

                  (e) In addition to the adjustments pursuant to Sections 2.2(a)
through (d) hereof, to the extent that prior to the Closing Date the Company has
not disposed of all of its Low Level Waste, whether located at a Facility or at
any other location, and the cost of such disposal is in excess of Five Hundred
Thousand Dollars ($500,000) (in 2003 dollars), the Purchase Price shall be
decreased by an amount equal to fifty percent (50%) of the excess of such amount
(the cost of such disposal to be determined based on the Company's cost to
dispose of such Low Level Waste under the terms of any existing contract
pursuant to which such Low Level Waste may be disposed or, if no such contract
exists, based on the prevailing industry costs as of a date as close to the
Closing Date as practicable). The statement of the cost of disposal of Low Level
Waste at each facility as of the Closing Date shall be prepared by British
Energy within sixty (60) days of the Closing Date using the same GAAP, policies
and methods as the Company has historically used in connection of such costs.

                                       16



Buyer and British Energy each agree to cooperate in connection with the
preparation of the costs of disposal of Low Level Waste as of the Closing Date
and related information, and each shall provide to the other such books, records
and information as may be reasonably requested from time to time.

                  (f) British Energy shall prepare an adjustment statement which
reflects the Purchase Price as increased or decreased by each of the adjustments
set forth in Sections 2.2(a) through (e) herein (in aggregate, the "Adjustment
Amount", such statement being referred to herein as the "Adjustment Statement").
If the Adjustment Amount for the Company Group is positive, within ten (10)
Business Days after Buyer's receipt of the Adjustment Statement, Buyer shall pay
to British Energy an amount equal to Adjustment Amount. If the Adjustment Amount
for the Company Group is negative, within ten (10) Business Days after Buyer's
receipt of the Adjustment Statement, British Energy shall pay to Buyer an amount
equal to the Adjustment Amount. If there is a dispute with respect to any amount
on the Adjustment Statement, any undisputed amounts shall be paid within ten
(10) Business Days after Buyer's receipt of the Adjustment Statement. All
payments made pursuant to this Section 2.2 shall be paid together with interest
thereon for the period commencing on the Closing Date through the date of
payment, calculated at an annual rate equal to the Prime Rate, in cash by wire
transfer of immediately available funds.

                  (g) Buyer may dispute the Adjustment Amount; provided,
however, that Buyer shall notify British Energy in writing of the disputed
amount, and the basis of such dispute, within thirty (30) days of Buyer's
receipt of the Adjustment Statement. In the event of a dispute with respect to
the Adjustment Amount, Buyer and British Energy shall attempt to reconcile their
differences and any resolution by them as to any disputed amounts shall be
final, binding and conclusive on Buyer and British Energy. If Buyer and British
Energy are unable to reach a resolution of such differences within thirty (30)
days of receipt of Buyer's written notice of dispute to British Energy, Buyer
and British Energy shall submit the amounts remaining in dispute for
determination and resolution to the Independent Accounting Firm, which shall be
instructed to determine and report to Buyer and British Energy, within thirty
(30) days after such submission, upon such remaining disputed amounts, and such
report shall be final, binding and conclusive on Buyer and British Energy with
respect to the amounts disputed. The fees and disbursements of the Independent
Accounting Firm shall be allocated between Buyer and British Energy so that
Buyer's share of such fees and disbursements shall be in the same proportion
that the aggregate amount of such remaining disputed amounts so submitted by
Buyer to the Independent Accounting Firm that is unsuccessfully disputed by
Buyer (as finally determined by the Independent Accounting Firm) bears to the
total amount of such remaining disputed amounts so submitted by Buyer to the
Independent Accounting Firm. Payment of the disputed amount shall be made by the
appropriate Party within five (5) days of the final report of the Independent
Accounting Firm together with interest thereon for the period commencing on the
Closing Date through the date of payment, calculated at an annual rate equal to
the Prime Rate, in cash by wire transfer of immediately available funds.

         SECTION 2.3 Closing. The closing (the "Closing") of the purchase and
sale of the BEUSH Shares hereunder shall take place at the offices of Simpson
Thacher & Bartlett, 425 Lexington Avenue, New York, New York, at 10:00 a.m.
(Eastern time), or another mutually acceptable time and location, on the date
that is ten (10) Business Days following the date on which the last of the
conditions precedent to Closing set forth in Article 6 of this Agreement has

                                       17



been either satisfied or waived by the Party for whose benefit such conditions
precedent exist; provided, however, that if such date falls during the
continuance of a scheduled outage at any of the Facilities, then the Closing
shall occur on the earlier of (a) the second Business Day after the conclusion
of such scheduled outage, and (b) the date that is thirty (30) days after
satisfaction or waiver of the conditions precedent set forth in Sections 6.2(d)
and 6.3(d) hereof Subject to the foregoing, the parties shall use their
Commercially Reasonable Efforts to cause the Closing to occur, to the extent
practicable and within the respective time periods set forth in the immediately
preceding sentence, on the first Business Day of a calendar month and, in the
event the Closing does not occur on the first Business Day of a calendar month,
shall cooperate in good faith to determine and allocate any applicable costs and
expenses of the Company among Seller and Buyer on a prorated basis for the month
in which the Closing occurs. The Closing shall be effective for all purposes as
of 12:01 a.m. (Eastern time) on the Closing Date.

         SECTION 2.4 Deliveries by British Energy at Closing. British Energy
shall deliver or cause to be delivered the following at Closing:

                  (a) certificates confirming (i) British Energy's due and valid
incorporation from the Registrar of companies in Scotland, and (ii) the good
standing of the members of the Company Group from the Secretary of the State of
the jurisdiction in which they are incorporated or organized, each dated within
three (3) Business days of the Closing Date;

                  (b) the certificates for the BEUSH Shares free and clear of
all Liens, duly endorsed or accompanied by stock powers duly endorsed in blank,
with any required transfer stamps affixed thereto;

                  (c) the certificates representing BEUSH' s partnership and
membership interests in British Energy, LP and BEUILLC, free and clear of all
Liens;

                  (d) the certificate representing British Energy, LP' s
membership interest in the Company, free and clear of all Liens;

                  (e) resignations or terminations of the executive officers,
directors and managers of each member of the Company Group appointed or
designated by Seller or its Affiliates to such positions, effective as of the
Closing Date;

                  (f) the officer's certificates required of British Energy by
Sections 6.2(a) and 6.2(b);

                  (g) each of the legal opinions and documents required by
Section 6.2(f);

                  (h) evidence of the receipt of British Energy Regulatory
Approvals;

                  (i) the consents and approvals listed on Items 1 and 2 of
Schedule 3.2;

                  (j) proof of repayment in full of the loans identified on
Schedule 5.11;

                  (k) a duly executed FIRPTA Affidavit;

                                       18



                  (1) a guaranty, in the form of Exhibit D hereto, executed by
British Energy plc in favor of Buyer, guaranteeing the obligations of British
Energy under this Agreement (or a substitute guaranty or other credit support
that guarantees the obligations of British Energy under this Agreement in form
and substance reasonably acceptable to Buyer, has been executed); and

                  (m) such other agreements, consents, documents, instruments
and writings as are reasonably required to be delivered by British Energy at or
prior to the Closing Date pursuant to this Agreement or otherwise reasonably
required in connection herewith, including all such other instruments as Buyer
or its counsel may reasonably request in connection with the purchase of the
BEUSH Shares contemplated hereby.

         SECTION 2.5 Deliveries by Buyer at Closing. Buyer shall deliver or
cause to be delivered the following at Closing:

                  (a) a certificate confirming the good standing of Buyer from
Secretary of State of the Commonwealth of Pennsylvania, dated within three (3)
Business days of the Closing Date;

                  (b) the officer's certificates required of Buyer by Sections
6.3(a) and 6.3(b);

                  (c) [Intentionally Omitted];

                  (d) evidence of the receipt of the Buyer Regulatory Approvals;

                  (e) the third party consents listed on Schedule 4.4;

                  (f) the Purchase Price (less any amounts loaned to British
Energy LP pursuant to Section 2.5(g) hereof) in immediately available funds by
wire transfer to an account of British Energy designated by British Energy by
notice to Buyer not later than three (3) Business Days prior to the Closing
Date;

                  (g) evidence of a loan by Buyer (or on Buyer's behalf) to
British Energy LP of an amount in immediately available funds sufficient to pay
in full to British Energy or its affiliates the net amount of all Intercompany
Loans (including any unpaid, accrued interest and other fees as of the Closing
Date) to BEUSH and its Subsidiaries in accordance with Section 5.11; and

                  (h) such other agreements, consents, documents, instruments
and writings as are reasonably required to be delivered by Buyer at or prior to
the Closing Date pursuant to this Agreement or otherwise reasonably required in
connection herewith, including all such other instruments as British Energy or
its counsel may reasonably request in connection with the purchase of the BEUSH
Shares contemplated hereby.

                                   ARTICLE 3

                    Representations and Warranties of Seller

         Seller hereby makes the following representations and warranties to
Buyer as of the date hereof:

                                       19




         SECTION 3.1 Corporate Existence and Power of Seller and the Members of
the Company Group. Each of the Seller and the members of the Company Group is a
limited liability company, corporation or limited partnership, as appropriate,
duly organized, validly existing and in good standing under the laws of the
jurisdiction in which it is organized. True and correct copies of the
organizational documents of Seller and the members of the Company Group, each as
amended to date, have been delivered or made available to Buyer Each of the
Seller and the members of the Company Group (i) has all requisite powers and
authority required to carry on its business as now conducted, and (ii) is duly
qualified or licensed to do business and is in good standing in each
jurisdiction in which the property owned, leased or operated by it or the nature
of its business make such qualification necessary, except where the failure to
be so qualified, licensed and in good standing would not have a Material Adverse
Effect on the Company.

         SECTION 3.2 Authorization, Execution and Enforceability of
Transactions. British Energy has the full power and authority to execute and
deliver this Agreement and, subject to receipt of the British Energy Regulatory
Approvals or as disclosed on Schedule 3.2, to perform its obligations hereunder.
Except as disclosed on Schedule 3.2, all necessary actions or proceedings to be
taken by or on the part of British Energy to authorize and permit the due
execution and valid delivery by British Energy of this Agreement, the
performance by British Energy of its obligations hereunder, and the consummation
by British Energy of the transactions contemplated herein, have been duly and
properly taken (and true and valid evidence thereof has been provided to Buyer).
This Agreement has been duly executed and validly delivered by British Energy,
and, assuming due execution and delivery by Buyer and receipt of the British
Energy Regulatory Approvals, or as disclosed on Schedule 3.2, constitutes the
valid and legally binding obligation of British Energy, enforceable in
accordance with its terms and conditions, subject to applicable bankruptcy,
insolvency, moratorium and other Laws affecting the rights of creditors
generally and the application of general principles of equity (regardless of
whether such enforceability is sought in equity or at law).

         SECTION 3.3 Non-contravention. Subject to British Energy obtaining the
British Energy Regulatory Approvals, neither the execution and delivery of this
Agreement, nor the consummation of the transactions contemplated hereby and
thereby, will (i) violate any Law to which British Energy or any of its property
is subject or any provision of the charter or by-laws of British Energy, or (ii)
conflict with, result in a breach of, constitute a forfeiture of, constitute a
default under, result in the acceleration of, create in any Person the right to
accelerate, terminate, modify, revoke, suspend or cancel, or require any notice
under any agreement, contract, lease, Permit, license, instrument or other
arrangement to which British Energy is bound or to which any of its assets is
subject (or result in the imposition of any Lien upon any of the Assets), except
for matters that, (x) in the aggregate, would not be likely to have a Material
Adverse Effect on British Energy or its ability to perform its obligations under
this Agreement and the Related Agreements or for which a consent or waiver shall
have been obtained, (y) are disclosed on Schedule 3.3, or (z) arise in relation
to any non-assigned rights under Permits, Material Contracts, or other
agreements.

         SECTION 3.4 Consents and Approvals. Except as disclosed on Schedule
3.4, and except for British Energy Regulatory Approvals, no declaration, filing
or registration with, or notice to, or authorization, consent or approval of any

                                       20



Governmental Authority is necessary for the execution and delivery of this
Agreement by British Energy, or the consummation of the transactions
contemplated hereby.

         SECTION 3.5 Financial Statements. Set forth on Schedule 3.5 are (i) the
audited consolidated balance sheets of the Company and the unaudited
consolidated balance sheets of BEUSH in each case as of December 31, 2002 and
the related audited (in the case of the Company) and unaudited (in the case of
BEUSH) consolidated statements of income and cash flows for the year ended
December 31, 2002, and (ii) the unaudited interim consolidated balance sheet of
each such member of the Company Group for the three months ended March 31, 2003
and the related unaudited interim consolidated statements of income and cash
flows for the three months ended March 31, 2003 (collectively, the "Financial
Statements"). The Financial Statements fairly present, in conformity with GAAP,
applied on a consistent basis (except as may be indicated in the notes thereto),
the consolidated financial position of such member of the Company Group as of
the dates thereof and its consolidated results of operations and cash flows for
the periods then ended (subject in the case of any unaudited interim financial
statements to routine and recurring year-end adjustments which have not been and
are not expected to be material in amount).

         SECTION 3.6 No Other Liabilities. None of the Company, BEUSH, BEUILLC
or British Energy, LP has any liabilities other than (i) liabilities reflected
on its balance sheets as disclosed on Schedule 3.5, (ii) liabilities which have
arisen since March 31, 2003 in the ordinary course of business, (iii)
liabilities described on Schedule 3.6, and (iv) liabilities that would not,
individually or in the aggregate, have a Material Adverse Effect.

         SECTION 3.7 Ownership of BEUSH Shares. British Energy is and will be at
the Closing the record and beneficial owner of the BEUSH Shares, free and clear
of any Lien and free of any other limitation or restriction (including any
restriction on the right to vote, sell or otherwise dispose of such Shares)
(other than those created by this Agreement, the LLC Agreement and restrictions
on sales of stock under applicable securities laws and, prior to the Closing,
other than any Lien or other limitation or restriction under the Credit Facility
Agreement or the Pledge Agreement), and will transfer and deliver to Buyer at
the Closing valid, good and marketable title to such BEUSH Shares free and clear
of any such Lien and free and clear of any such limitation or restriction.

         SECTION 3.8 Capitalization of BEUSH. The BEUSH Shares constitute all of
the outstanding equity interests in BEUSH. The BEUSH Shares have been duly
authorized and are validly issued, fully paid and nonassessable and were not
issued in violation of the preemptive rights of any Person. Except as shown on
Schedule 3.8, BEUSH has no outstanding convertible security, call, preemptive
right, option, warrant, purchase right or other contract or commitment that
would, directly or indirectly, require BEUSH to sell, issue or otherwise dispose
of any equity interest in BEUSH.

         SECTION 3.9 Ownership of Interests in the Company. BEUSH is and will be
at the Closing the beneficial indirect owner of fifty percent (50%) of the
ownership interests in the Company, free and clear of any Lien and free of any
other limitation or restriction (including any restriction on the right to vote,
sell or otherwise dispose of such ownership interests) (other than those created

                                       21



by this Agreement, the LLC Agreement and restrictions on sales of stock under
applicable securities laws and, prior to the Closing, other than any Lien or
other limitation or restriction under the Credit Facility Agreement or the
Pledge Agreement).

         SECTION 3.10 BEUSH Operations. Except as disclosed on Schedule 3.10,
(a) the business of BEUSH is and, since its formation, has been restricted
solely to directly holding ninety-nine percent (99%) of the ownership interests
in British Energy, LP and one hundred percent (100%) of the ownership interests
in BEUILLC, and indirectly holding fifty percent (50%) of the ownership
interests in the Company, and doing things necessary or incidental in connection
with those activities; (b) BEUSH does not and, since its formation, has not,
owned any assets, incurred any liabilities or engaged participated or invested
in any business other than as described in clause (a) of this Section 3.10; (c)
BEUSH does not and, since its formation, has not, had any employees, except to
the extent it might be deemed to have, or have had, employees as a result of the
employment by the Company of seconded employees from Affiliates of British
Energy LP; (d) BEUSH does not have and, since its organization, has not had any
outstanding debt obligations (other than the Intercompany Loans); (e) BEUSH is
not a party to any contracts or agreements (other than the limited partnership
agreement of British Energy LP); (f) BEUSH has no assets other than its
ownership interests in British Energy LP and British Energy US Investments LLC;
and (g) BEUSH has not incurred any other liabilities that remain outstanding.

         SECTION 3.11 British Energy LP Operations. Except as disclosed on
Schedule 3.11, (a) the business of British Energy LP is and, since its
formation, has been restricted solely to directly holding fifty percent (50%) of
the ownership interests in the Company and doing things necessary or incidental
in connection with that activity; (b) British Energy LP does not and, since its
formation, has not, owned any assets, incurred any liabilities or engaged,
participated or invested in any business other than as described in clause (a)
of this Section 3.11; (c) British Energy LP does not and, since its formation,
has not, had any employees, except to the extent it might be deemed to have, or
have had, employees as a result of the employment by the Company of seconded
employees from Affiliates of British Energy LP; (d) British Energy LP does not
have and, since its organization, has not had any outstanding debt obligations
(other than the Intercompany Loans); (e) other than the LLC Agreement, British
Energy LP is not a party to any contracts or agreements; (f) British Energy LP
has no assets other than its ownership interests in the Company; and (g) British
Energy LP has not incurred any other liabilities that remain outstanding.

         SECTION 3.12 British Energy US Investments LLC Operations. Except as
disclosed on Schedule 3.12, (a) the business of BEUILLC is, and since its
formation, has been, restricted solely to directly holding one percent (100%) of
the ownership interests in British Energy LP and doing things necessary or
incidental in connection with that activity; (b) BEUILLC does not and, since its
formation, has not, owned any assets, incurred any liabilities or engaged,
participated or invested in any business other than as described in clause (a)
of this Section 3.12; (c) BEUILLC does not and, since its formation, has not,
had any employees, except to the extent it might be deemed to have, or have had,
employees as a result of the employment by the Company of seconded employees
from Affiliates of British Energy LP; (d) BEUILLC does not have and, since its
organization, has not had any outstanding debt obligations (other than the
Intercompany Loans); (e) BEUILLC is not a party to any contracts or agreements
(other than the limited partnership agreement of British Energy LP); (f) BEUILLC

                                       22



has no assets other than its ownership interests in British Energy LP; and (g)
BEUILLC has not incurred any other liabilities that remain outstanding.

         SECTION 3.13 Absence of Certain Changes. Since December 31, 2002,
except as disclosed on Schedule 3.13, as of the date hereof, there has not
occurred (i) any Material Adverse Effect with respect to the Company Group, or
(ii) any Plant Material Adverse Effect.

         SECTION 3.14 Litigation. Except as set forth on Schedule 3.14, (i)
there are no claims or Actions, pending, or to Seller's Knowledge threatened,
which, individually or in the aggregate, would be likely to have a Plant
Material Adverse Effect or a Material Adverse Effect on the Company, that
challenge the validity of this Agreement or of any action taken or to be taken
pursuant to or in connection with the provisions of this Agreement, or which,
individually or in the aggregate, would be likely to have a Material Adverse
Effect as to any member of the Company Group; (ii) no member of the Company
Group is subject to any outstanding judgment, rule, order, citation, fine,
penalty, writ, injunction or decree of any court, arbitrator or Governmental
Authority which, individually or in the aggregate, would be likely to have a
Material Adverse Effect; and (iii) no member of the Company Group has received
any written notification that it is in violation of any Laws or Permits with
respect to the Assets, except for notifications of violations which would not,
individually or in the aggregate, be likely to have a Material Adverse Effect.

         SECTION 3.15 Material Contracts. Set forth in Part I of Schedule 3.15
is a list of all agreements and contracts to which any member of the Company
Group is a party or by which any member of the Company Group is bound (except
for Collective Bargaining Agreements and Employee Benefit Plans disclosed in
other schedules to this Agreement) (i) involving an aggregate consideration, per
contract, in excess of $150,000, or (ii) constituting a swap, exchange,
commodity option or hedging agreement (the contracts referred to in the
foregoing clauses (i) and (ii), the "Material Contracts").

                  Except as set forth in Part II of Schedule 3.15, no member of
the Company Group is, in any material respect, in breach of or in default under,
and no event has occurred and is continuing that would constitute a material
default by a member of the Company Group under, any provision of any Material
Contract, and no member of the Company Group has received written notice from
any other party to any Material Contract that a member of the Company Group is
in breach of such Material Contract, which breach has not been remedied, and, to
Seller's Knowledge, no such other party is, in any material respect, in breach
of or default under any provision of any such Material Contract. Except as set
forth on Part II of Schedule 3.15, each Material Contract is in full force and
effect and (except for those contracts which, pursuant to their terms, are to be
and will be fully performed prior to the Closing Date) will remain in full force
and effect upon consummation of the transactions contemplated hereby and is a
valid agreement, arrangement or commitment of the member of the Company Group
which is a party thereto, enforceable against such member of the Company Group
in accordance with its terms and, to the knowledge of Seller, is a valid
agreement, arrangement or commitment of each other party thereto, enforceable
against such party in accordance with its terms, except in each case where
enforceability may be limited by bankruptcy, insolvency or other similar laws
affecting creditors' rights generally and except where enforceability is subject
to the application of equitable principles or remedies. True, correct and
complete copies of the Material Contracts have been made available to Buyer.

                                       23




         SECTION 3.16 Qualified Decommissioning Funds.

                  (a) Except as disclosed on Schedule 3.16, the Company is the
sole owner of the AmerGen Clinton-l Qualified Fund, AmerGen Three Mile Island-l
Qualified Fund and AmerGen Oyster Creek Qualified Fund (collectively, the
Qualified Decommissioning Funds), each of which is, and since its inception has
been, treated as a nuclear decommissioning reserve fund in accordance with Code
Section 468A and is therefore treated as a corporation in accordance with Code
Section 468A(e)(2)(D). Each of the Company's Qualified Decommissioning Funds is
a trust, validly existing and in good standing under the laws of the
jurisdiction of its formation with all requisite authority to conduct its
affairs as it now does. Seller has heretofore made available to Buyer a copy of
the Decommissioning Trust Agreement provided by the Company as in effect on the
date of this Agreement. Seller agrees to furnish Buyer with copies of all
amendments to the Decommissioning Trust Agreement adopted after the date of this
Agreement promptly after each such amendment has been adopted and provided by
the Company to Seller. Each of the Company's Qualified Decommissioning Funds
satisfies the requirements necessary for such fund to be treated as a "Nuclear
Decommissioning Reserve Fund" within the meaning of Code section 468A(a) and as
a "nuclear decommissioning fund" and a "qualified nuclear decommissioning fund"
within the meaning of Treas. Reg. Section 1.468A- I (b)(3). Each such fund is in
compliance in all material respects with all applicable rules and regulations of
any Governmental Authority having jurisdiction (including, without limitation,
the NRC, the PaPUC, the NJBPU, the FERC and the ICC). Except as set forth in
Schedule 3.16, none of the Company's Qualified Decommissioning Funds has engaged
in any acts of "self-dealing" as defined in Treas. Reg. Section 1.468A-5(b)(2).
No "excess contribution," as defined in Treas. Reg. Section 1.468A-5(c)(2)(ii),
has been made to the Company's Qualified Decommissioning Funds which has not
been withdrawn within the period provided under Treas. Reg. Section
1.468A-5(c)(2)(i) for withdrawals of excess contributions to be made without
resulting in a disqualification of the funds under Treas. Reg. Section
1.468A-5(c)(l).

                  (b) The Company and/or the trustee of each of the Qualified
Decommissioning Funds have filed or caused to be filed with the NRC, the IRS and
any state or local Governmental Authority all material forms, statements,
reports, documents (including all exhibits, amendments and supplements thereto)
required to be filed by any of them. As of the Closing, the Company has not
requested a revised schedule of ruling amounts and has not contributed any
amounts to the Qualified Decommissioning Funds during the period that the
Company has held such Qualified Decommissioning Funds.

                  (c) Seller has made available to Buyer the trustee statements
provided by the Company for each of the Qualified Decommissioning Funds as of
December 31, 2002, and they present fairly as of such date the financial
position of each of the Qualified Decommissioning Funds. Seller has made or will
make available, or has caused or will cause to be made available, to Buyer
information from which Buyer can determine the Tax Basis of all assets in the
Qualified Decommissioning Funds as of December 31, 2002. There are no
Liabilities, including any acts of "self-dealing" as defined in Treas. Reg.
Section 1.468A-5(b)(2) or agency or other legal proceedings that may materially
affect the financial position of each of the Qualified Decommissioning Funds
other than those, if any, that are disclosed on Schedule 3.16.

                                       24



                  (d) Seller has made available to Buyer all contracts and
agreements provided by the Company to which the trustee of each of the Qualified
Decommissioning Funds, in its capacity as such, is a party.

                  (e) Each of the Qualified Decommissioning Funds has filed all
material Tax Returns required to be filed and all material Taxes, whether or not
shown to be due on such Tax Returns, have been paid in full. Except as disclosed
on Schedule 3.16, no notice of deficiency or assessment has been received from
any Taxing Authority with respect to Liability for Taxes of each of the
Qualified Decommissioning Funds which have not been fully paid or finally
settled, and any such deficiency shown in such Schedule 3.16 is being contested
in good faith through appropriate proceedings. Except as disclosed on Schedule
3.16, to Seller's Knowledge there are no outstanding agreements or waivers
extending the applicable statutory periods of limitations for Taxes associated
with each of the Qualified Decommissioning Funds for any period.

         SECTION 3.17 Nonqualified Decommissioning Funds.

                 (a) Except as disclosed on Schedule 3.17, the Company is the
sole owner of AmerGen Clinton Non-Qualified Fund, AmerGen Three Mile Island-l
Non-Qualified Fund and AmerGen Oyster Creek Non-Qualified Fund (collectively,
the Nonqualified Decommissioning Funds), each of which is, and since its
inception has been, treated as a grantor trust for federal income tax purposes
in accordance with Code Section 671. Each of the Company's Nonqualified
Decommissioning Funds is a trust validly existing and in good standing under the
laws of the jurisdiction of its formation with all requisite authority to
conduct its affairs as it now does. Each of the Company's Nonqualified
Decommissioning Funds is in full compliance with all applicable rules and
regulations of any Governmental Authority having jurisdiction (including,
without limitation the NRC the PaPUC, the NJBPU, the FERC and the ICC).

                  (b) The Company and/or the trustee of the Nonqualified
Decommissioning Funds have filed or caused to be filed with the NRC and any
state or local Governmental Authority all material forms, statements, reports,
and documents (including all exhibits, amendments and supplements thereto)
required to be filed by either of them.

                  (c) Seller has made available to Buyer the trustee statements
provided by the Company for each of the Nonqualified Decommissioning Funds as of
December 31, 2002 and they present fairly as of such date the financial position
of the Nonqualified Decommissioning Funds. Seller has made or caused to be made
available to Buyer, and will make or cause to be made available to Buyer,
information from which Buyer can determine the Tax Basis of all assets of the
Nonqualified Decommissioning Funds (other than cash) as of December 31, 2002.
There are no liabilities (whether absolute, accrued, contingent or otherwise and
whether due or to become due) including agency or other legal proceedings, that
may materially affect the financial position of the Nonqualified Decommissioning
Funds other than those, if any, that are disclosed on Schedule 3.17.

                   (d) Seller has made available to Buyer all contracts and
agreements provided by the Company to which the trustee of each of the
Nonqualified Decommissioning Funds, in its capacity as such, is a party.

                   (e) Each of the Nonqualified Decommissioning Funds has filed
all material Tax Returns required to be filed and all material Taxes, whether or
not shown to be due on such Tax Returns, have been paid in full. Except as

                                       25



disclosed on Schedule 3.17, no notice of deficiency or assessment has been
received from any Taxing Authority with respect to Liability for Taxes of any of
the Nonqualified Decommissioning Funds which have not been fully paid or finally
settled, and any such deficiency shown in such Schedule 3.17 is being contested
in good faith through appropriate proceedings. Except as disclosed on Schedule
3.17, to Seller's Knowledge there are no outstanding agreements or waivers
extending the applicable statutory periods of limitations for Taxes associated
with any of the Nonqualified Decommissioning Funds for any period.

         SECTION 3.18 Insurance. Seller has made available to Buyer a list
provided by the Company of all material insurance policies maintained by the
Company and its affiliates covering the Assets, business, equipment, properties,
operations, employees, officers and directors of the Company. There is no claim,
suit or other matter pending under any of such policies as to which coverage has
been denied or disputed by the underwriters of such policies. All premiums due
and payable under all such policies have been paid and the Company has otherwise
complied fully with the terms and conditions of all such policies. Except as
disclosed on Schedule 3.18, there is no threatened termination or cancellation
of any such policies as a result of the transactions contemplated hereby or
otherwise, and as of the date of this Agreement, neither British Energy nor the
Company has received any written notice of termination or cancellation as to any
such policies. The Company is approved for self-insurance of the workers
compensation in Pennsylvania and Illinois. Schedule 3.18 includes the list of
surety bonds required for self-insurance of workers compensation, environmental
issues and the letters of credit required to support the Owner Controlled
Insurance Program ("OCIP").

         SECTION 3.19 Compliance with Laws. Except as set forth on Schedule
3.19, no uncured material violation of any applicable Law by any member of the
Company Group exists, nor has there been any material violation of any
applicable Law by any member of the Company Group during the Seller Ownership
Period. Except as shown on Schedule 3.19, no member of the Company Group other
than the Company has (and to Seller's Knowledge the Company has not) received
written notice from any Governmental Authority of any material violation of
applicable Law with respect to the Company Group, the Business or the Assets.
Except as set forth on Schedule 3.19, no written notice has been received by any
member of the Company Group (other than the Company) or, to Seller's Knowledge,
by the Company, during the Seller Ownership Period to the effect that any member
of the Company Group or the Assets are not in compliance in any material respect
with any applicable Laws. Except as set forth on Schedule 3.19, during the
Seller Ownership Period, no internal investigation has been conducted by Seller
or by any member of the Company Group in connection with which any of them has
retained or sought advice from outside legal counsel with respect to any actual,
potential or alleged material violation of any applicable Law by any member of
the Company Group or any of their employees, officers, directors or agents.
Seller is not making any representations or warranties in this Section 3.19 with
respect to any Environmental Law or any applicable Law relating to Taxes, and
such matters are addressed in Sections 3.20 and 3.23.

         SECTION 3.20 Environmental Matters. Except as set forth on Schedule
3.20:

                   (a) the Company Group and the Assets comply in all material
respects with all applicable Environmental Laws, and neither Seller nor any
member of the Company Group has received during the Seller Ownership Period, any

                                       26



written notice from any Governmental Authority alleging that any member of the
Company Group or any Asset is in material violation of any Environmental Law;

                  (b) no Lien has been imposed on any Asset by any Governmental
Authority in connection with any material violation of or material noncompliance
with Environmental Laws and to Seller's Knowledge there are no facts,
circumstances or conditions that are reasonably likely or expected to restrict,
encumber or result in the imposition of special conditions under any
Environmental Law (other than ISRA and any successor statutes or regulations)
with respect to the ownership, occupancy, development, use or transferability of
the Assets, except those facts, circumstances or conditions relating to the
status of the Facilities as nuclear facilities;

                  (c) all material Permits required under applicable
Environmental Laws for the ownership and operation of the Assets as they are
currently operated have been obtained, each such Permit is in full force and
effect, the Company is in material compliance with all of its obligations
thereunder, there are no proceedings pending or threatened that would reasonably
be expected to result in the revocation, termination, modification or amendment
of any such Permit, and the Company has not failed to make in a timely fashion
any application or other filing required for the renewal of any such Permit
which failure would reasonably be expected to result in such Permit terminating
or being revoked, terminated, suspended or adversely modified;

                  (d) (i) neither any member of the Company Group nor any Asset
is subject to any outstanding consent decree, compliance order or administrative
order pursuant to an Environmental Law, and (ii) the Company Group has not
received, during the Seller Ownership Period, any written notice of intent to
sue under the citizen suit provision of any Environmental Law, or of any written
notice, complaint or claim seeking to impose an Environmental Liability against
the Company;

                  (e) there has been and is no Release of a Hazardous Substance
initially occurring during the Seller Ownership Period, at, from, on, under or
to any Asset that would reasonably be expected to result in any material
Environmental Liabilities to any member of the Company Group;

                  (f) there are no environmental investigation reports with
respect to any violation of any applicable Environmental Law by the Company
Group or any Asset, or any Environmental Liability of the Company Group, in the
custody or possession of the Seller or the Company Group, that have not been
made available to Buyer and to Seller's Knowledge, there exists no state of
facts which would reasonably be expected to result in any material Environmental
Liability with respect to any member of the Company Group or any Asset;

                  (g) during the Seller Ownership Period, neither Seller nor any
member of the Company Group have performed, or arranged for, the transportation,
storage, handling, disposal or treatment of any Hazardous Substance from any
Asset to or at any off-site location that is an Environmental Clean-Up Site;

                  (h) the Assets are not Environmental Clean-Up Sites; and

                  (i) to Seller's Knowledge, there are no underground storage
tanks, active or abandoned, or polychlorinated biphenyl-containing equipment
located at any of the Assets.

                                       27



Except for the applicability of Sections 3.18 or 3.38 to this Section 3.20, this
Section 3.20 contains the only representations and warranties of Seller
regarding Environmental Laws or the presence, Remediation or Release of
Hazardous Substances in this Agreement, and no other provision in this Agreement
shall be construed to contain any such representation or warranty.

         SECTION 3.21 Employees. Schedule 3.21 contains a list of all collective
bargaining agreements that relate to the employees of the Company or the Assets
(the "Collective Bargaining Agreements"), true and correct copies of which have
heretofore been made available to Buyer. Except as described in Schedule 3.21,
during the Seller Ownership Period: (a) there has been no work stoppage due to
labor disagreements experienced by any member of the Company Group; (b) no
written notice has been received from any Governmental Authority of any unfair
labor practice charge or complaint against any member of the Company Group
pending or threatened before the National Labor Relations Board or any other
Governmental Authority with respect to the Company's employees; (c) no
arbitration proceeding arising out of or under any Collective Bargaining
Agreement with respect to the Facilities and/or the Assets other than
proceedings arising in connection with individual employee grievance procedures
is pending against any member of the Company Group, and (d) there is no labor
strike, slowdown or stoppage actually pending or threatened by any authorized
representative of any union or other representative of employees of the Company
Group related to the Facilities and/or the Assets against or affecting any
member of the Company Group, except in any such case set forth in clauses (a)
through (d) above as would not, individually or in the aggregate, have a
Material Adverse Effect on such member of the Company Group.

         SECTION 3.22 Employees Benefit Plans.

                  (a) Schedule 3.22 contains a true and complete list of any
Employee Benefit Plans maintained or contributed to or required to be
contributed to by the Company for the benefit of any employee or former employee
of the Company or any of its ERISA Affiliates (the "Plans"). No member of the
Company Group (other than the Company) maintains or contributes to or is
required to contribute to any Employee Benefit Plan for the benefit of any
employee or former employee of the Company Group or any of their ERISA
Affiliates. Schedule 3.22 identifies each of the Plans that is an Employee
Welfare Benefit Plan, or Employee Pension Benefit Plan (such plans being
hereinafter referred to collectively as the "ERISA Plans").

                  (b) With respect to each of the Plans, Seller has heretofore
delivered or made available to the Buyer true and complete copies of each of the
following documents: (i) a copy of the Plan documents (including all amendments
thereto) for each written Plan; (ii) a copy of the annual report or Internal
Revenue Service Form 5500 Series, if required under ERISA, with respect to each
such Plan for the last Plan year ending prior to the date of this Agreement for
which such a report was filed; (iii) a copy of the actuarial report, if required
under ERISA, with respect to each such Plan for the last Plan year ending prior
to the date of this Agreement; (iv) a copy of the most recent Summary Plan
Description ("SPD"), together with all summaries of material modification issued
subsequent to the date of such SPD, required under ERISA with respect to such
Plan; and (v) the most recent determination letter received from the IRS with
respect to each Plan that is intended to be qualified under Section 401(a) of
the Code.

                                       28



                  (c) The PBGC has not instituted proceedings pursuant to
Section 4042 of ERISA to terminate any of the ERISA Plans subject to Title IV of
ERISA and no condition exists that presents a material risk that such
proceedings will be instituted by the PBGC.

                  (d) None of the ERISA Plans or any trust established
thereunder has incurred any "accumulated funding deficiency" (as defined in
Section 302 of ERISA and Section 412 of the Code), whether or not waived, as of
the last day of the most recent fiscal year of each of the ERISA Plans ended
prior to the date of this Agreement and no Lien has been imposed under Section
412(n) of the Code or Section 302(f) of ERISA on the assets of the Company or
any of its ERISA Affiliates.

                  (e) Neither the Company Group nor any of their respective
ERISA Affiliates maintains or has an obligation to contribute to a Multiemployer
Plan.

                  (f) Except as set forth in Schedule 3.22, (i) each of the
ERISA Plans that is intended to be "qualified" within the meaning of Section
401(a) of the Code has received a determination letter from the IRS stating that
it is so qualified and (ii) any trust established under an ERISA Plan that is
intended to satisfy the requirements of Section 501(c)(9) of the Code has
received a determination letter from the IRS stating that it has so satisfied
such requirements.

                  (g) Except as set forth in Schedule 3.22, neither the Company
Group nor any of their respective ERISA Affiliates has announced any formal plan
or commitment to create any additional Plan or make any material modifications
or changes to any existing Plan.

                  (h) No material liability under Title IV of ERISA or Section
412 of the Code has been incurred by the Company Group or any of their
respective ERISA Affiliates that has not been satisfied in full, and no
condition exists that presents a material risk to the Company Group or any of
their respective ERISA Affiliates of incurring a material liability under such
Title, other than liability for contributions to any such ERISA Plans or
premiums due the Pension Benefit Guaranty Corporation ("PBGC"), which payments
have been made when due with respect to any ERISA Plan.

                  (i) Neither the Company Group, any of their respective ERISA
Affiliates, any of the ERISA Plans, any trust created thereunder nor any
trustee, or administrator thereof has engaged in a transaction or has taken or
failed to take any action in connection with which the Company Group or any of
their respective ERISA Affiliates would reasonably be expected to be subject to
any material liability for either a civil penalty assessed pursuant to Section
409 or 502(i) of ERISA or a tax imposed pursuant to Section 4975(a) or (b), 4976
or 4980B of the Code.

                  (j) Except as set forth in Schedule 3.22, each of the Plans
has been operated and administered in all material respects in accordance with
applicable Laws, including but not limited to ERISA and the Code.

                  (k) Except as set forth in Schedule 3.22, the consummation of
the transactions contemplated by this Agreement will not (A) entitle any current
or former employee or officer of the Company Group to severance pay,
unemployment compensation or any other similar termination payment or (B)
accelerate the time of payment or vesting, or increase the amount of
compensation due any such employee or officer.

                                       29



                  (1) There are no pending or, to Seller's Knowledge, threatened
claims by or on behalf of any Plan, by any employee or beneficiary covered under
any such Plan, or otherwise involving any such Plan (other than routine claims
for benefits) that could reasonably be expected to result in material liability.

         SECTION 3.23 Taxes. Except as set forth in Schedule 3.23:

                  (i) all material Tax Returns required to be filed by or with
respect to each member of the Company Group have been or will be timely filed
with the appropriate Taxing Authorities in all jurisdictions in which such Tax
Returns are required to be filed;

                  (ii) such Tax Returns are or will be true and correct in all
material respects, and all Taxes, whether or not reported on such Tax Returns,
have been or will be timely paid;

                  (iii) to Seller's knowledge, no member of the Company Group
has, and Seller has not with respect to the Company Group, extended or waived
the application of any statute of limitations of any jurisdiction regarding the
assessment or collection of any Tax;

                  (iv) to Seller's knowledge, there is no audit or other
proceeding presently pending or threatened with regard to any Tax of the Company
Group and neither British Energy nor any member of the Company Group has
received a written ruling from a Taxing Authority relating to any Tax or entered
into a written agreement with any Taxing Authority;

                  (v) there are no Liens for Taxes upon the assets of any member
of the Company Group, except for Liens for Taxes not yet due or being contested
in good faith;

                  (vi) none of the assets of any member of the Company Group,
directly or indirectly, secures any debt the interest on which is tax exempt
under Section 103(a) of the Code;

                  (vii) the Company is, and has been since its inception,
classified as a partnership for federal Tax purposes under Treas. Reg. Sections
30 1.7701-2 and -3 and any comparable provision of applicable Law of state and
local jurisdictions that permits such treatment;

                  (viii) true and correct copies of all material Tax Returns
filed by or with respect to each member of the Company Group for all periods
ending on and after December 31, 1999 have been provided to the Buyer;

                  (ix) British Energy LP is and has been since its inception
treated as a corporation for federal Tax purposes under Treas. Reg. Section
301.7701-3;

                  (x) BEUILLC is and has been since its inception treated as a
disregarded entity for federal tax purposes under Treas. Reg. Section
301.7701-3;

                  (xi) BEUSH has not been a United States real property holding
corporation within the meaning of Section 897(c)(2) of the Code at any time
during the shorter of the period during which Seller held the stock of BEUSH (or
any predecessor thereof) and five (5) years preceding the Closing Date; and

                                       30



                  (xii) each member of the Company Group has complied in all
material respects with all applicable Laws, rules and regulations relating to
withholding Taxes, and has, within the time periods and in the manner prescribed
by Law, withheld from employee wages and paid to the proper Governmental
Authority or Taxing Authority all amounts required to have been so withheld and
paid.

         SECTION 3.24 Condemnation. Except as disclosed on Schedule 3.24,
neither Seller nor any member of the Company Group has received any written
notice from any Governmental Authority of any pending proceeding to condemn or
take by power of eminent domain or otherwise, by any Governmental Authority, all
or any part of the Assets that would be likely to have a Material Adverse Effect
on the Company.

         SECTION 3.25 Real Property. (a) To Seller's Knowledge, Schedule 3.25(a)
lists all real property owned by the Company (such property, the "Owned Real
Property"). To Seller's Knowledge, the Company has fee simple title to each
parcel of Owned Real Property free and clear of all Liens, except: (A) as set
forth on Schedule 3.25(a); (B) matters that are disclosed in the title policy
and survey for the burdened Owned Real Property, none of which individually or
in the aggregate materially and adversely affects the operation of any of the
Assets as currently operated; (C) Permitted Encumbrances; and (D) zoning,
planning and other limitations and restrictions of record, none of which
individually or in the aggregate materially and adversely affects the operation
of a Facility as currently operated. True and correct copies of each deed and
lease pursuant to which the Company acquired the Owned Real Property, together
with copies of the title insurance policies and surveys related thereto to which
Seller has access have been made available to Buyer.

                  (b) To Seller's Knowledge, Schedule 3.25(b) sets forth a list
of all leases of real property under which the Company is lessee and all
amendments thereto and assignments thereof (the "Real Property Leases"). The
real property subject to the Real Property Leases is hereinafter referred to as
the "Leased Real Property". To Seller's Knowledge, the Company has a valid
leasehold in and enjoys quiet and undisturbed possession of the Leased Real
Property. True and correct copies of the Real Property Leases have been made
available to Buyer prior to the date hereof. To Seller's Knowledge, (A) the
Company is not in default in any material respect under any Real Property Lease,
and (B) no lessor is in default in any material respect under any Real Property
Lease.

                  (c) To Seller's Knowledge, the Owned Real Property and the
Leased Real Property constitute all the real property required by the Company
Group for the conduct of the Business as currently conducted. Except as
disclosed on Schedule 3.25(c), there are no leases, subleases, licenses,
occupancy agreements, options, rights, concessions or other agreements or
arrangements, written or oral, granting to any Person the right to purchase the
Owned Real Property, or the right to use or occupy any of the Owned Real
Property or Leased Real Property.

                  (d) No member of the Company Group other than the Company has
title to or leases any real property.

         SECTION 3.26 Permits. Except as set forth on Schedule 3.26, the Company
Group has all material Permits required to conduct the Business as currently
conducted. Each material Permit is in full force and effect and the applicable
member of the Company Group is in compliance in all material respects with all

                                       31



its obligations with respect thereto. There are no proceedings pending or to
Seller's Knowledge threatened which might reasonably be expected to result in
the revocation, termination or material adverse modification of any material
Permit of the Company Group. Except as set forth on Schedule 3.26, all required
filings with respect to such material Permits have been timely made and all
required applications for renewal thereof have been timely filed, except for
such failure to do any of the foregoing as would not lead to the revocation,
cancellation, suspension or adverse modification of any such Permit. To Seller's
Knowledge, no such Permit will terminate or be subject to termination or
revocation as a result of the transactions contemplated by this Agreement.
Seller is not making any representation or warranty in this Section 3.26 with
respect to Permits required under any Environmental Law, which Permits are
instead addressed in Section 3.20.

         SECTION 3.27 Plant and Equipment; Personal Property.

                  (a) Except as disclosed in Schedule 3.27, the Facilities
conform in all material respects to the applicable Technical Specifications and
Final Safety Analysis Reports and are being operated in all respects in
conformance with applicable requirements under the Atomic Energy Act, the Energy
Reorganization Act and the rules, regulations, orders and licenses issued
thereunder. The Assets constitute all of the material assets necessary for the
operation of the Business, and, except as disclosed on Schedule 3.27, the Assets
are currently in a condition adequate and sufficient to operate the Facilities
at full licensed thermal load in accordance with Good Utility Practice.

                  (b) The personal property of the Company Group is not subject
to or encumbered by any Liens, except (i) as disclosed on Schedule 3.27, and
(ii) Permitted Encumbrances.

         SECTION 3.28 Bank Accounts. Schedule 3.28 sets forth a complete list of
all bank accounts of the Company Group.

         SECTION 3.29 Intellectual Property. The Company or another member of
the Company Group owns or has licensed or otherwise possesses sufficient legally
enforceable rights to use all material patents, copyrights, trademarks, service
marks, technology, know-how, computer software programs and applications and
databases that are currently used in the Business. To Seller's Knowledge, the
Business is not operated in a manner that infringes upon any patents,
copyrights, trademarks or other intellectual property rights of any third
parties and, to the Seller's Knowledge no third party is infringing on any
patents, copyrights, trademarks or other intellectual property rights of the
Company Group.

         SECTION 3.30 Subsidiaries. Schedule 3.30 sets forth a list of each
Subsidiary of the members of the Company Group and the ownership thereof. Except
as set forth on Schedule 3.30, no member of the Company Group owns or holds,
directly or indirectly, any equity or other ownership interest in any
corporations, limited liability companies, partnerships, joint ventures or other
entities.

         SECTION 3.31 Utilities. To Seller's Knowledge, there are utility lines
to the Owned Real Property and the Leased Real Property which currently supply
all such services on such real property necessary to operate the Business in a
manner and to an extent consistent with past practices.

                                       32




         SECTION 3.32 Books and Records. The books, accounts, ledgers and files
of each member of the Company Group other than the Company (and, to Seller's
Knowledge, of the Company) are true and complete in all material respects and
have been maintained in accordance with GAAP on a consistent basis (except, with
respect to members of the Company Group other than the Company, for any
inconsistencies that may result from the reconciliation of such books, accounts,
ledgers and files to GAAP prior to the date hereof) and bookkeeping practices in
all material respects. The minute books and other similar records of each member
of the Company Group are true and complete in all material respects.

         SECTION 3.33 Affiliate Transactions. Except as set forth on Schedule
3.33, (i) neither Seller, any Affiliate of Seller (other than a member of the
Company Group), officer, manager, or director of Seller or any Affiliate of
Seller (including members of the Company Group), (ii) no individual related by
blood, marriage or adoption to any person described in clause (i), and (iii) no
entity in which any of the foregoing persons described in clause (i) or clause
(ii) owns individually or in the aggregate a greater than ten percent (10%)
beneficial interest is, or at any time during the past three (3) years has been
a party to any agreement, contract, commitment or transaction with any member of
the Company Group or has a material interest in any material property used by
any member of the Company Group at any time during the past three (3) years.

         SECTION 3.34 Bankruptcy; Solvency. There are no bankruptcy,
reorganization or arrangement proceedings pending against or, to the Knowledge
of Seller, threatened against the Seller or any member of the Company Group. The
Seller and each member of the Company Group are Solvent.

         SECTION 3.35 Finders' or Brokers' Fees. Other than Citigroup Global
Markets Inc., Lazard Freres & Co. LLC and Lazard & Co. Limited, each of whose
fees shall be paid by Seller, there is no investment banker, broker, finder or
other intermediary that has been retained by or is authorized to act on behalf
of any member of Company Group which might be entitled to any fee or commission
from Buyer in connection with the transactions contemplated by this Agreement.

         SECTION 3.36 DOE Standard Spent Fuel Contracts and Payment of Deferred
One-Time Fees. The Company holds a DOE Standard Spent Fuel Contract for each of
the Facilities. The liability to DOE for payment of a one-time fee for spent
fuel discharged from TMI-1 and Oyster Creek prior to the execution of the DOE
Standard Spent Fuel Contracts for those Facilities was deferred, as permitted by
the DOE Standard Spent Fuel Contracts, and remains a liability to DOE with
accumulated interest until payment. The previous owners of TMI-1 and Oyster
Creek retained the liability for the payment of the deferred one-time fee for
spent fuel discharged from TMI-1 and Oyster Creek.

         SECTION 3.37 Prices and Terms for Purchase by Exelon of Power from the
Facilities. Pursuant to the LLC Agreement, all output from the Facilities, other
than the output sold to the former owners as a condition of the sale, shall be
sold to Exelon Generation's Power Team at the price and for the period of time
which the Company used in its evaluation of the acquisition of each Facility.

                                       33



Schedule 3.37 sets forth the price of the output and period of time that Exelon
Generation's Power Team is obligated to purchase the output, which the Company
used in its evaluation of the acquisition of TMI-1, Oyster Creek and Clinton.
The Company and Exelon are bound by the prices and term for each Facility set
forth in Schedule 3.37.

         SECTION 3.38 Disclosure. No representation or warranty made herein or
in any document delivered hereunder contains any untrue statements of material
fact nor does it omit to state a material fact which is known to either Seller
or their Affiliates to be necessary in order to make the statements made, in
light of the circumstances under which they were made, not misleading. There is
no fact known to Seller or its Affiliates that Seller or their Affiliates have
not disclosed to Buyer in writing on or before the Closing Date which would
reasonably be expected to have a Material Adverse Effect on the Company Group or
the Facilities.

         SECTION 3.39 Inquiries by Seller. The individuals listed on Schedule
1.1(a) constitute all Persons currently employed by British Energy or its
Affiliates (including employees seconded to the Company) who might have direct
knowledge of the information that is the subject of the representations and
warranties contained in Article 3.

         SECTION 3.40 Limitation of Representations and Warranties. BUYER
ACKNOWLEDGES THAT EXCEPT AS SET FORTH IN THIS AGREEMENT, SELLER MAKES NO
REPRESENTATIONS OR WARRANTIES, EITHER EXPRESS OR IMPLIED, OF ANY NATURE
WHATSOEVER RELATING TO THE BUSINESS, ASSETS AND LIABILITIES OF THE COMPANY
GROUP, INCLUDING ANY IMPLIED WARRANTY OF MERCHANTABILITY OR FITNESS FOR A
PARTICULAR PURPOSE. WITHOUT LIMITING THE GENERALITY OF THE FOREGOING, SELLER
MAKES NO REPRESENTATION OR WARRANTY WITH RESPECT TO ANY PROJECTIONS, ESTIMATES
OR BUDGETS DELIVERED TO OR MADE AVAILABLE TO BUYER RELATING TO FUTURE FINANCIAL
RESERVES, FUTURE REVENUES, FUTURE RESULTS OF OPERATIONS (OR ANY COMPONENT
THEREOF), FUTURE CASH FLOWS OR FUTURE FINANCIAL CONDITION (OR ANY COMPONENT
THEREOF) OF THE COMPANY OR THE FUTURE BUSINESS AND OPERATIONS OF THE COMPANY.

                                   ARTICLE 4

                     Representations and Warranties of Buyer

         Buyer hereby makes the following representations and warranties to
British Energy as of the date hereof:

         SECTION 4.1 Existence and Power of Buyer.. Buyer is a limited liability
company duly incorporated, validly existing and in good standing under the laws
of Pennsylvania, and has all requisite power and all certificates, licenses,
permits, approvals, consents, orders, exemptions, decisions and other actions of
a Governmental Authority to the extent required to carry on its business as now
conducted, except where the failure to have such powers, certificates, licenses,
permits, approvals, consents, orders, exemptions, decisions or actions would not
have a Material Adverse Effect on Buyer.

                                       34



         SECTION 4.2 Authorization. Execution and Enforceability of
Transactions. Buyer has the full power and authority to execute and deliver this
Agreement and, subject to receipt of Buyer Regulatory Approvals, to perform its
obligations hereunder. All necessary actions or proceedings to be taken by or on
the part of Buyer to authorize and permit the due execution and valid delivery
by Buyer of this Agreement, the performance by Buyer of its obligations
hereunder, and the consummation by Buyer of the transactions contemplated
herein, have been duly and properly taken (and true and valid evidence thereof
has been provided to Seller). This Agreement has been duly executed and validly
delivered by Buyer, and assuming due execution and delivery by British Energy
and receipt of Buyer Regulatory Approvals, constitutes the valid and legally
binding obligation of Buyer, enforceable in accordance with its terms and
conditions, subject to applicable bankruptcy, insolvency, moratorium and other
Laws affecting the rights of creditors generally and the application of general
principles of equity (regardless of whether such enforceability is sought in
equity or at law).

         SECTION 4.3 Non-contravention. Subject to Buyer's obtaining its Buyer
Regulatory Approvals, and except as disclosed on Schedule 4.3, the execution,
delivery and performance of this Agreement by Buyer do not and will not (a)
contravene or conflict with the articles of organization or formation or limited
liability company agreement of Buyer, (b) contravene or conflict with or
constitute a violation of any provision of any Law binding upon or applicable to
Buyer, (c) require any consent, approval or other action by any Person or
constitute a default under or give rise to any right of termination,
cancellation or acceleration of any right or obligation of Buyer or to a loss of
any benefit to which Buyer is entitled under any provision of any material
agreement, contract, indenture, lease or other instrument binding upon Buyer or
any license, franchise, permit or other similar authorization held by Buyer, or
(d) result in the creation or imposition of any Lien on any asset of Buyer,
except in any such case set forth in clauses (b) through (d) above as would not,
individually or in the aggregate, have a Material Adverse Effect on Buyer.

         SECTION 4.4 Consents and Approvals. Except as disclosed on Schedule
4.4, and except for Buyer Regulatory Approvals, no declaration, filing or
registration with, or notice to, or authorization, consent or approval of any
Governmental Authority is necessary for the execution and delivery of this
Agreement by Buyer, or the consummation of the transactions contemplated hereby.

         SECTION 4.5 Finders' or Brokers' Fees. Other than Dresdner Kleinwort
Wasserstein, whose fees will be paid by the Buyer, there is no investment
banker, broker, finder or other intermediary which has been retained by or is
authorized to act on behalf of Buyer that might be entitled to any fee or
commission from Seller in connection with the transactions contemplated by this
Agreement.

         SECTION 4.6 Availability of Funds. Buyer has sufficient funds available
to it or has received binding written commitments from third parties (copies of
which have been provided to British Energy) to provide sufficient funds on the
Closing Date to pay the Purchase Price as contemplated hereby and to enable
Buyer timely to perform all of its obligations under this Agreement, including
sufficient funds available or binding written commitments from third parties

                                       35



that are adequate to ensure the release of the obligations of certain guarantors
as provided in Section 5.7 and the repayment of all loans as provided in Section
5.11.

         SECTION 4.7 Litigation. There is no claim or Action pending against, or
to Buyer's Knowledge, threatened against or affecting, Buyer which in any manner
challenges or seeks to prevent, enjoin, alter or materially delay the
transactions contemplated by this Agreement.

         SECTION 4.8 Due Diligence. Buyer acknowledges that, prior to its
execution of this Agreement, (i) it has been afforded access to and the
opportunity to inspect the Assets, the Material Contracts (or copies thereof)
and all other due diligence items made available by Seller with respect to the
Company Group and the Business, and (ii) it is relying upon only those
representations and warranties that are expressly contained herein, as well as
upon its own inspections and investigation, in order to satisfy itself as to the
condition and suitability of the Assets and the Business. Buyer (A) is not
relying upon any representations, warranties, statements, advice, documents,
projections or other information of any type provided by Seller other than those
representations and warranties expressly set forth in this Agreement; (B) is
entering into this Agreement as principal (and not as advisor, agent, broker or
in any other capacity, fiduciary or otherwise); (C) has entered into this
Agreement with a full understanding of the material terms and risks of the same;
and (D) has made its purchase decision (including regarding the suitability
thereof) based upon its own judgment and any advice from such advisors as it has
deemed necessary and not in reliance upon any view expressed by Seller.

         SECTION 4.9 Absence of Certain Events. Since December 31, 2002, to
Buyer's Knowledge, there has not been any event which would be likely to have a
Material Adverse Effect on Buyer's ability to perform under this Agreement.

         SECTION 4.10 No Knowledge of Breach. Buyer does not know of any breach
of warranty or any misrepresentation by British Energy hereunder or of any
condition or circumstance that would excuse Buyer from performance of its
obligations under this Agreement.

         SECTION 4.11 Inquiries by Buyer. The individuals listed on Schedule
1.1(b) constitute Persons currently employed by Buyer or its Affiliates who have
direct knowledge of the information that is the subject of the representations
and warranties contained in Article 4.

                                   ARTICLE 5

                                    Covenants

         SECTION 5.1 General. Without limiting the rights of any Party to
exercise its rights hereunder, each Party will use Commercially Reasonable
Efforts to take all actions and to do all things necessary, proper or advisable
in order to consummate and make effective the transactions contemplated by this
Agreement pursuant to this Agreement, prior to the date which is six (6) months
from the date hereof, subject to any extension of the six (6) month period
pursuant to Section 8.1(b) (including satisfaction of the Closing conditions set
forth in Article 6).

         SECTION 5.2 Notices, Consents and Approvals.

                                       36




                  (a) Hart-Scott-Rodino. British Energy and Buyer shall, if
required, file or cause to be filed with the Federal Trade Commission and the
United States Department of Justice any notifications required to be filed under
the HSR Act and the rules and regulations promulgated thereunder with respect to
the transactions contemplated hereby. British Energy and Buyer shall cooperate
with one another and use Commercially Reasonable Efforts to make such filings as
promptly as possible after the date hereof and to respond promptly to any
requests for additional information made by either of such agencies. Buyer will
pay all filing fees under the HSR Act, but British Energy and Buyer each will
bear its own costs for the preparation of any filing. British Energy and Buyer
shall use Commercially Reasonable Efforts to cause any waiting period under the
HSR Act with respect to the transactions contemplated by this Agreement to
expire or terminate at the earliest possible time.

                   (b) Nuclear Regulatory Commission Approval.

                           (i) Application. As promptly after the date hereof as
may be feasible (and in any event, within forty-five (45) calendar days of the
date of this Agreement), British Energy and Buyer shall jointly prepare one or
more Applications to be filed with the NRC for approval of the indirect transfer
of the NRC licenses for each Facility and any conforming amendment of the NRC
licenses to reflect such indirect transfer. Thereafter, British Energy and Buyer
shall cooperate with one another to facilitate review of the Application(s) by
the NRC Staff, including but not limited to promptly providing the NRC Staff
with any and all documents or information that the NRC Staff may reasonably
request or require any of the Parties to provide or generate. British Energy
shall use Commercially Reasonable Efforts to obtain the cooperation of the
Company in filing such Application(s) jointly with Buyer and in responding to
requests for information from the NRC staff.

                           (ii) Prosecution of Application. The Application(s)
shall identify British Energy and Buyer as separate parties to the
Application(s), but Buyer shall direct and control the prosecution of the
Application(s). In the event the processing of such Application(s) by the NRC
becomes a Contested Proceeding, until such Contested Proceeding becomes final
and nonappealable, British Energy and Buyer shall separately appear therein by
their own counsel, and shall continue to cooperate with each other to facilitate
a favorable result. British Energy shall use Commercially Reasonable Efforts to
obtain the cooperation of the Company in prosecuting such Application(s).

                           (iii) Costs of Application and Prosecution. British
Energy and Buyer will bear their own costs of the preparation, submission and
processing of the Application, including any Contested Proceeding that may occur
in respect thereof provided, however, that Buyer shall bear the costs of all NRC
Staff fees payable in connection with the Application. In the event that British
Energy and Buyer agree upon the use of common counsel, they shall share equally
the fees and expenses of such counsel. British Energy shall be responsible for
any costs, fees and expenses of the Company.

                  (c) FERC Approval.

                           (i) Application. As promptly after the date hereof as
may be feasible (and in any event, within forty-five (45) calendar days of the
date of this Agreement), British Energy and Buyer shall jointly prepare and file
with FERC an Application.

                                       37



                           (ii) Prosecution of Application. Buyer shall direct
and control the prosecution of the Application. In the event the processing of
such Application by the FERC becomes a Contested Proceeding, until such
Contested Proceeding becomes final, British Energy and Buyer shall separately
appear therein by their own counsel, and shall continue to cooperate with each
other to facilitate a favorable result.

                           (iii) Costs of Application and Prosecution. British
Energy and Buyer will bear their own costs of the preparation, submission and
processing of the Application, including any Contested Proceeding that may occur
in respect thereof. In the event that British Energy and Buyer agree upon the
use of common counsel, they shall share equally the fees and expenses of such
counsel. British Energy shall use Commercially Reasonable Efforts to obtain the
cooperation of the Company in all filings and any proceedings in connection with
obtaining FERC approval, and British Energy shall be responsible for any costs,
fees or expenses of the Company in connection with obtaining FERC approval.

                  (d) Consents and Approvals.

                           (i) British Energy and Buyer each shall cooperate and
use Commercially Reasonable Efforts with respect to their respective obligations
to (A) promptly prepare and file all necessary documentation, (B) effect all
necessary applications, notices, petitions and filings and execute all
agreements and documents, (C) obtain the transfer, issuance or reissuance, if
necessary, to the Buyer of all necessary Permits, (D) facilitate the
substitution, if necessary, of Buyer for British Energy where appropriate on
pending Permits, and (F) obtain all necessary consents, waivers, approvals and
authorizations of all other parties necessary or advisable to consummate the
transactions contemplated by this Agreement (including British Energy Regulatory
Approvals and Buyer Regulatory Approvals) or approvals required by the terms of
any note, bond, mortgage, indenture, deed of trust, license, franchise, Permit,
concession, contract, lease, warranty or other instrument to which either
British Energy or Buyer is a party or by which any of them is bound. Without
limiting the generality of the foregoing, British Energy and Buyer shall, as
promptly as practicable after the date hereof and in any event by no later than
forty-five (45) calendar days after the date hereof, make the necessary filings
and pursue receipt of those British Energy Regulatory Approvals and Buyer
Regulatory Approvals for which British Energy or Buyer has responsibility.

                           (ii) British Energy and Buyer each shall have the
right to review and comment in advance on all filings relating to the
transactions contemplated by this Agreement made by the other Party in
connection with the transactions contemplated hereby. British Energy and Buyer
shall in good faith consider such comments before making any such filings.
Neither Party shall intervene in opposition to a filing made by the other Party
in connection herewith unless the approval or other action to be taken in
response to such filing would have a material adverse effect on the opposing
Party or the filing is otherwise not in good faith. British Energy shall use
Commercially Reasonable Efforts to obtain the cooperation of the Company in all
filings and any proceedings in connection with obtaining British Energy
Regulatory Approvals and Buyer Regulatory Approvals.

         SECTION 5.3 Operation of Business of Company Group During Interim
Period.

                  (a) During the Interim Period, British Energy shall cause each
member of the Company Group (other than the Company), and, subject to Good
Utility Practices and to the extent within its rights, authority and powers as a

                                       38



"Member" of the Company under the Limited Liability Company Agreement, use
Commercially Reasonable Efforts to cause the Company, to (except as required to
comply with Sections 2.4(j) and 2.5(g) of this Agreement):

                           (i) conduct its Business in the ordinary course
(including making budgeted capital expenditures), not make any material change
in the conduct of the Business and preserve intact its goodwill and maintain
satisfactory relationships with those Persons having business relationships with
it, except as contemplated by the matters described on Schedule 5.3(a);

                           (ii) except in the ordinary course of business and
consistent with past practices or Good Utility Practices, or except as otherwise
approved in writing by the Buyer, not enter into, assign, terminate or amend, in
any material respect, any Material Contract or Permit or release or relinquish
any material rights thereunder;

                           (iii) except as set forth in Schedule 5.3(a), not
sell, lease (as lessor), transfer or otherwise dispose of, any material Assets,
other than as used, consumed or replaced in the ordinary course of business
consistent with Good Utility Practices, or encumber, pledge, mortgage or suffer
to be imposed on any of the Assets any encumbrance other than Permitted
Encumbrances, and not incur any indebtedness for borrowed money, other than in
the ordinary course of business, or guarantee any such indebtedness or make any
loans, advances or capital contributions to, or investments in, any other
Person;

                           (iv) not make any material change in the level of
inventories customarily maintained by the Company with respect to the Assets,
except for such changes as are consistent with Good Utility Practices;

                           (v) not enter into, amend, make any waivers under or
otherwise modify any real or personal Property Tax Agreement, treaty or
settlement or make any new, or change any current, election with respect to
Taxes, or file any amended Tax Return (except for, or as a result of the filing
of, any amended Tax Return with respect to the Company);

                           (vi) not engage in any practice, take any action,
fail to take any action, or enter into any transaction that will result in any
misrepresentation or breach of warranty under Article 3 as of the Closing Date;

                           (vii) not amend in any material respect, or cancel,
any property, liability or casualty insurance policies related thereto, or fail
to maintain by self insurance, or with financially responsible insurance
companies, insurance in such amounts and against such risks and losses as are
consistent with past practice;

                           (viii) not change, in any material respect, its
accounting methods or practices, credit practices or collection policies;

                           (ix) not fail to take any actions required to be
taken in order to ensure that the Assets are being operated and maintained in
all material respects in a manner that is in compliance with Good Utility
Practice and all applicable Laws or Permits;

                           (x) not to take reasonably appropriate steps to
pursue currently pending regulatory approvals relating to the Facilities;

                                       39



                           (xi) not hire any employees (other than to replace
any employees who have resigned or been terminated) or increase the compensation
or benefits payable to any employees, except as required under the Collective
Bargaining Agreements or other agreements as in existence on the date hereof or
consistent with the Company's past practices

                           (xii) not participate as an adverse party to the
Buyer or to British Energy in any proceeding before the NRC or any other
Governmental Authority relating to the sale of BEUSH Shares, or the transfer of
any Permit, or the issuance of any Buyer Regulatory Approvals or British Energy
Regulatory Approvals;

                           (xiii) except in accordance with Section 5.14 of this
Agreement, not declare or pay any dividends or make any distributions in respect
of or issue any of its equity securities or securities convertible into its
equity securities, or repurchase, redeem or otherwise acquire any such
securities or make or propose to make any other change in its capitalization;

                           (xiv) not merge into or with or consolidate with any
other Person or acquire all or substantially all of the business or assets of
any Person;

                           (xv) not make any material change in its certificate
of incorporation, certificate of formation, the LLC Agreement, limited liability
company agreement, operating agreement, partnership agreement or similar charter
or organizational documents;

                           (xvi) not purchase any securities of any Person,
except in accordance with the Company's treasury management policy;

                           (xvii) not take any action or enter into any
commitment with respect to or in contemplation of any liquidation, dissolution,
recapitalization, reorganization or other winding up of its business or
operations;

                           (xviii) not enter into an agreement in writing or
otherwise or otherwise resolve to take, any of the foregoing actions; and

                           (xix) not assign or consent to any assignment of any
rights or obligations of any party under the LLC Agreement to any third party.

Notwithstanding anything in this Section 5.3 to the contrary, the Parties agree
that (i) the Company may, in its sole discretion, make or incur an obligation to
the extent relating to Required Nuclear Expenditures or any repairs or
modifications to any Facility reasonably required in the normal course of
business and in accordance with Good Utility Practices (a "Required
Expenditure"), and (ii) the Company shall retain exclusive control over all
aspects of the operation, maintenance, refueling, shutdown or other matters
relating to the operation of the Facilities and to the Company during the
Interim Period, all in accordance with Good Utility Practices.

                  (b) During the Interim Period, in the interest of facilitating
an orderly transition of the upstream ownership of the Company and permitting
informed action by the Buyer regarding its rights under Section 5.3(a), the
Parties shall, as promptly as is practicable after the date hereof, establish a
committee comprised of at least five (5) persons, two (2) persons to be

                                       40



designated by the Seller and two persons to be designated by the Buyer, and such
additional persons as may be appointed by the persons originally appointed to
such committee (the "Transition Executive Committee"). From time to time, the
Transition Executive Committee shall report to the senior management of Seller
and Buyer. The Transition Executive Committee shall meet periodically and shall
oversee and manage the transition process during the Interim Period. The Seller
shall consult with Buyer's representatives on the Transition Executive
Committee, on a regular and timely basis, with respect to the refueling
outage(s) occurring during the Interim Period, to any repairs to the Facilities
and to the Required Nuclear Expenditures and Required Expenditures. The
Transition Executive Committee shall have no authority to bind or make
agreements on behalf of Seller or the Buyer or to issue instructions to or
direct or exercise authority over Seller or Buyer or any of their respective
officers, employees, advisors or agents or to waive or modify any provision
thereof. Seller shall refrain from voting on any material matter presented at
Company Management Committee meetings (as defined in the LLC Agreement) and
finance committee meetings that was not set forth on the agenda delivered to
Buyer prior to such meeting, and shall consult with Buyer prior to voting on any
such matter.

         SECTION 5.4 Access and Investigations During Interim Period. During the
Interim Period, British Energy will permit, and will use Commercially Reasonable
Efforts to cause the Company to permit, Buyer to have reasonable access to each
Facility, subject to any restrictions and procedures set forth in this Section
5.4 or otherwise reasonably imposed by the Company, to conduct environmental
studies and inspections (such as the review of existing environmental records
and related material but, for the avoidance of doubt, not including any
environmental testing of soil samples or other invasive procedures with respect
to any Facility), and to observe and inspect all premises, properties,
management, personnel, books, records, (including tax records), and other
information, including without limitation all information necessary to enable
Buyer to verify the representations and warranties as set forth in Article 3 and
to confirm that British Energy has complied with the covenants set forth herein,
and any other information or documents associated with or pertaining to the
Assets. All access and inspections by Buyer are subject to the following
provisions:

                  (a) Costs. All costs of such investigations and observations,
including the compensation paid to the Persons involved and their expenses, and
other discrete incremental costs incurred by the Company or British Energy in
connection with such investigation and observation, shall be borne by Buyer.

                  (b) Escorted Physical Access to Facilities. The Buyer shall,
with respect to each Person designated by the Buyer to have escorted access to
the Facilities for purposes of this Section 5.4, provide the following
information for each such Person to the contact designated by British Energy for
the Facility (or his designee) no later than twenty-four (24) hours prior to the
proposed time of access by such Person: name, date of birth social security
number and the name of each nuclear power plant at which such Person has a
current badge for access. British Energy shall be permitted where necessary in
its sole discretion to limit the number of Persons to whom escorted access is
provided at any one time on account of reasonable logistical considerations.

                  Subject to the immediately succeeding sentence, the Buyer
shall, with respect to each Person designated by the Buyer to have escorted
access to the Facilities, provide reasonable notice to the contact designated by
British Energy for the Facilities (or his designee), so as not to interfere with
the normal business operations of the Facilities, and such Person shall comply

                                       41



with all existing requirements of the Facility and NRC for escorted access,
including, but not limited to, background investigation, training requirements,
fitness-for-duty requirements, a psychological assessment and behavioral
observation.

                  The Buyer may request that any Person subject to the
fitness-for-duty program of the Buyer be excused from compliance with the
fitness-for-duty program of the Company for up to ninety (90) days, in which
event the provisions of 10 C.F.R. Section 26.23 shall be applicable to such
Person designated by the Buyer to have access to the Facilities.

                  (c) Access to Records and Information. (i) Under no
circumstances shall the Company be required by British Energy to provide access
to any documents or information constituting or containing "Classified National
Security Information" or "Restricted Data", as defined in 10 C.F.R. Part 73. The
Company shall not be required by British Energy to provide access to any
documents or information constituting or containing "Safeguards Information", as
defined in 10 C.F.R. Part 73, except to any Person designated by Buyer to have
access to such information and Buyer shall have first obtained authorization or
concurrence from the NRC for the disclosure of such information to such Person.

                  (ii) Except as provided in clause (i) above, the Buyer shall
have the right to receive copies of all documentary information and records
associated with the Assets, subject to the provisions of Section 5.8.

                  (d) Limitations. Notwithstanding anything to the contrary in
this Section 5.4, British Energy shall not be required to assist Buyer in
obtaining from the Company: (i) access to confidential personnel records and
medical records except as allowed by applicable Laws, (ii) any information that
British Energy, the Company or the Company's or British Energy's counsel
reasonably believes constitutes or could reasonably be deemed to constitute a
waiver of the attorney-client privilege, or (iii) any information that British
Energy or the Company is under a legal obligation not to supply; provided that
British Energy shall use Commercially Reasonable Efforts to obtain the consent
to disclose all material information otherwise described in this Section 5.4.

                  (e) Contact with Company Related Persons. Prior to the Closing
Date, Buyer shall not contact any vendors, suppliers, contractors, customers or
employees of British Energy regarding the Facilities, the Assets or the
transactions contemplated in this Agreement without prior written consent of
British Energy, which shall not be unreasonably withheld or delayed, and any
such permitted contacts shall be conducted in a manner which will not materially
adversely interfere with the operations or business relationships of the Company
or British Energy with such Persons.

         SECTION 5.5 Certain Notices.

                  (a) British Energy shall notify Buyer of the existence of any
information or matter that becomes known to British Energy, which if in
existence on the date hereof or the Closing Date, would cause or would have a
reasonable likelihood of causing any of the representations or warranties in
Article 3 to be materially untrue or incorrect. In particular, but without
limitation, British Energy shall notify Buyer of (i) information regarding any
actual or asserted Nuclear Liability, Environmental Liability or Environmental
Claim, or (ii) communications from the NRC or any other Governmental Authority
regarding any Permit, Nuclear Law or Environmental Law, in each case with

                                       42



respect to the Company Group or the Assets. Unless Buyer terminates this
Agreement pursuant to Section 8.1(f), the written notice pursuant to this
Section 5.5(a) shall be deemed to amend the original Schedule or Schedules as of
the date hereof and the Closing Date, to have qualified the representations and
warranties contained in Article 3 as of the date hereof and the Closing Date and
to have cured any misrepresentation or breach of warranty that otherwise might
have existed hereunder by reason of the existence of such matter.

                   (b) Buyer shall notify British Energy of the existence of any
matter that becomes known to Buyer, which if in existence on the date hereof or
the Closing Date, would cause or would have a reasonable likelihood of causing
any of the representations or warranties in Article 4 to be untrue or incorrect.
Unless British Energy terminates this Agreement pursuant to Section 8.1(g), the
written notice pursuant to this Section 5.5(b) shall be deemed to amend the
original Schedule or Schedules as of the date hereof and the Closing Date, to
have qualified the representations and warranties contained in Article 4 as of
the date hereof and the Closing Date and to have cured any misrepresentation or
breach of warranty that otherwise might have existed hereunder by reason of the
existence of such matter.

                  (c) Buyer shall notify British Energy if any information or
matter comes to its attention which would cause or would have a reasonable
likelihood of causing any of the representations or warranties of British Energy
in Article 3 above to be materially untrue or incorrect. British Energy shall
then comply with Section 5.5(a) with respect to such information.

                  (d) British Energy shall notify the Buyer if any information
or matter comes to its attention which would cause or would have a reasonable
likelihood of causing any of the representations and warranties of Buyer in
Article 4 above to be materially untrue or incorrect. Buyer shall then comply
with Section 5.5(b) with respect to such information.

         SECTION 5.6 Further Assurances; Post-Closing Cooperation.

                  (a) Subject to the terms and conditions of this Agreement,
each of the Parties will use Commercially Reasonable Efforts to take, or cause
to be taken, all action, and to do, or cause to be done, all things necessary,
proper or advisable under applicable Laws to consummate the transactions
contemplated by this Agreement, including using Commercially Reasonable Efforts
to ensure satisfaction of the conditions precedent to each Party's obligations
hereunder. Notwithstanding anything in the previous sentence to the contrary,
British Energy and Buyer shall use Commercially Reasonable Efforts to obtain all
Permits necessary for Buyer to acquire the BEUSH Shares.

                  (b) From time to time after the Closing Date, without further
consideration, British Energy will, at its own expense, execute and deliver such
documents to Buyer as Buyer may reasonably request in order to more effectively
consummate the transactions contemplated by this Agreement. From time to time
after the Closing Date, without further consideration, Buyer will, at its own
expense, execute and deliver such documents to British Energy as British Energy
may reasonably request in order to more effectively consummate the transactions
contemplated by this Agreement.

                  (c) After the Closing Date, each Party shall have reasonable
access to the employees of the other Party, for purposes of consultation or
otherwise, to the extent that such access may reasonably be required in

                                       43



connection with matters relating to or affected by the operations of the Seller
or the Company Group prior to the Closing Date. The Parties agree to cooperate
in connection with any audit, investigation, hearing or inquiry by any
Governmental Authority, litigation or regulatory or other proceeding which may
arise following the Closing Date and which relates to the ownership of the
Company Group or operation of the Assets by the Seller or the Company Group
prior to the Closing Date. Notwithstanding any other provision of this Agreement
to the contrary, each Party shall bear its own expenses, including fees of
attorneys or other representatives, in connection with any such matter described
in this Section 5.6(c) in which the Seller and the Buyer are subjects or parties
or in which they have a material interest.

         SECTION 5.7 Guarantees. Schedule 5.7 identifies each financial or
performance guarantee by British Energy, and by any of its Affiliates, of any
obligations of or related to BEUSH and its Subsidiaries (including without
limitation, the Company) (the "Guarantees"). Buyer shall use commercially
reasonable efforts to obtain promptly the release of the obligations of any
guarantor, or Buyer's substitution for such guarantor, with respect to all
Guarantees identified on Schedule 5.7. Buyer agrees to indemnify, defend and
hold harmless British Energy and its Affiliates, and their respective
Representatives, from and against any and all losses, costs, damages,
obligations, claims, liabilities, expenses and causes of action relating to
resulting from, or arising out of any Guarantee with respect to acts, omissions
or occurrences arising on or after the Closing Date.

         SECTION 5.8 Confidentiality. Notwithstanding anything herein to the
contrary, British Energy and Buyer agree that prior to the Closing Date and
after any termination of this Agreement, each will observe the confidentiality
requirements of Section 6.7 of the LLC Agreement; provided, however, that any
party to this Agreement (and any employee, representative, or other agent of any
party to this Agreement) may disclose to any and all persons, without limitation
of any kind, the tax treatment and tax structure of the transactions
contemplated by this Agreement and all materials of any kind (including opinions
or other tax analyses) that are provided to it relating to such tax treatment
and tax structure; provided, however, that neither party (nor any employee,
representative or other agent thereof) shall disclose (A) any information that
is not relevant to an understanding of the tax treatment of the

transactions contemplated by this Agreement, including the identity of any Party
to this Agreement (or its employees, representatives or agents) or other
information that could lead any person to determine such identity or (B) any
information to the extent such disclosure could result in a violation of any
federal or state securities laws.

         SECTION 5.9 Public Announcements. Prior to the Closing Date, the
Parties shall consult with each other before issuing any public announcement,
statement or other disclosure with respect to this Agreement or the transactions
contemplated hereby and shall not issue any such public announcement, statement
or other disclosure prior to such consultation and the approval of the other
Party, except as may be required by Law or stock exchange rules. For the
avoidance of doubt, this Section 5.9 shall not restrict Seller from making
private disclosures with respect to this Agreement and the transactions
contemplated hereby to members, officials and instrumentalities of the
government of the United Kingdom or to Exelon pursuant to the LLC Agreement.

                                       44



         SECTION 5.10 Tax Matters.

                  (a) Preparation. The following provisions shall govern the
allocation of responsibility as between Buyer and Seller for certain Tax matters
following the Closing Date:

                  (i) Tax Periods Ending on or Before the Closing Date. Seller
shall prepare or cause to be prepared and file or cause to be filed all Tax
Returns for all members of the Company Group other than the Company for all
periods ending on or prior to the Closing Date that are due after the Closing
Date. Seller shall permit Buyer to review and comment on such Tax Returns prior
to filing. If Seller fails to file such Tax Returns prior to the date on which
such Tax Returns are due, Buyer shall be required to file such Tax Returns on
behalf of the Company Group. Seller shall pay or cause to be paid the Taxes of
all members of the Company Group other than the Company with respect to such
periods except to the extent such Taxes are included as current liabilities in
Working Capital, which Buyer shall pay.

                   (ii) Tax Periods Beginning Before and Ending After the
Closing Date. Buyer shall prepare or cause to be prepared and file or cause to
be filed any Tax Returns of all members of the Company Group other than the
Company for Tax periods which begin before the Closing Date and end after the
Closing Date. Buyer shall permit Seller to review and comment on such Tax
Returns prior to filing and shall consider in good faith any changes reasonably
suggested by Seller. Buyer shall pay or cause to be paid the Taxes of all
members of the Company Group other than the Company with respect to such
periods. Seller shall pay to Buyer within fifteen (15) days after the date on
which Taxes are paid with respect to such periods an amount equal to the portion
of such Taxes that relates to the portion of such Tax period ending on the
Closing Date except to the extent such Taxes are included as current liabilities
in Working Capital, which Buyer shall pay. In the case of Taxes that are payable
with respect to a taxable period that begins before the Closing Date and ends
after the Closing Date, the portion of any such Tax that is allocable to the
portion of the period ending on the Closing Date shall be (A) in the case of
Taxes that are based upon or related to income or gross receipts or sales or use
Tax, determined based on an interim closing of the books as of the close of
business on the day immediately prior to the Closing Date (and for such
purposes, the taxable period of any member of the Company Group other than the
Company shall be deemed to terminate at such time); and (B) in the case of any
Taxes other than gross receipts, sale or use Tax and Taxes based upon or related
to income, deemed to be the amount of such Taxes for the entire period,
multiplied by a fraction the numerator of which is the number of calendar days
in the period ending on the day immediately prior to the Closing Date and the
denominator of which is the number of calendar days in the entire period.

                 (iii) Allocation of Items from Company. The allocation of
British Energy LP's share of all items of the Company's income gain, loss,
deduction or credit for the Company's taxable year which includes the Closing
Date between (x) the portion of the taxable year of BEUSH ending on the day
immediately prior to the Closing Date, and (y) the portion of the taxable year
of BEUSH beginning on the Closing Date, shall be made as if the Company's
taxable year ended on the day immediately prior to the Closing Date.

                 (b) Adjustment for Indemnity Payments. The Parties agree to
treat any indemnity payment made pursuant to this Agreement as an adjustment to
the Purchase Price, unless otherwise required pursuant to a "determination"
within the meaning of Section 1313(a) of the Code.

                                       45



                   (c) Transfer Taxes. Buyer shall pay fifty percent (50%) and
Seller shall pay fifty percent (50%) of all transfer Taxes resulting from the
transactions contemplated by this Agreement. Buyer shall prepare and timely file
all Tax Returns or other documentation relating to such transfer Taxes;
provided, however, that to the extent required by Applicable Law, Seller will
join in the execution of any such Tax Returns or other documents relating to
such Taxes. Buyer shall provide Seller with copies of each such Tax Return or
other document at least thirty (30) days prior to the date on which such Tax
Return or other document is required to be filed.

                  (d) Tax Sharing Agreements. On or before the Closing Date,
Seller shall ensure that no Tax indemnity agreement, Tax allocation agreement or
Tax sharing agreement with respect to the Company Group (other than with respect
to the Company or including only members of the Company Group) is in force or
effect and that no member of the Company Group other than the Company shall have
any Liability after the Closing Date under any such agreement.

                   (e) Assistance and Cooperation. Seller and Buyer shall
reasonably cooperate, and shall cause their respective Affiliates, employees and
agents reasonably to cooperate, in preparing and filing all Tax Returns,
including maintaining and making available to each other all records that are
necessary for the preparation of any Tax Returns that each Party is required to
file under this Section 5.10, and in resolving all disputes and audits with
respect to such Tax Returns.

                  (f) Tax Indemnity. Notwithstanding any other provisions of
this Agreement, Sections 5.10(f), 5.10(g) and 7.6 hereof set forth the sole
remedy of Buyer with respect to Losses of the nature described in this Section
5.10(f). Seller shall indemnify and hold the Company Group (other than the
Company) and Buyer harmless from and against (i) any income Taxes imposed on
Seller resulting from the sale of the BEUSH Shares to Buyer and any other
transaction herein contemplated, and (ii) any Liability for Taxes for any period
or portion thereof that ends on or prior to the Closing Date which is imposed on
any member of the Company Group (other than the Company) under Treas. Reg.
Section 1.1502-6 (or under any comparable provision of state or local law
imposing several liability upon members of a consolidated, combined, affiliated
or unitary group).

                  (g) Tax Indemnity Claims. Buyer shall notify Seller within
thirty (30) days of receipt of written notice of any pending or threatened Tax
examination, audit or other administrative or judicial proceeding relating to
any member of the Company Group that could reasonably be expected to result in
an indemnification obligation of Seller arising under Section 5.10(f) or under
Section 7.1 as a result of the breach of any representation or warranty
contained in Sections 3.16, 3.17 or 3.23 ("Contested Taxes"). If Buyer fails to
provide such notice to Seller, Buyer shall not be entitled to indemnification
for such Contested Taxes if the failure shall preclude Seller from contesting
the Tax. Seller shall, at its own expense, control the defense and settlement of
such Tax contest. Buyer shall have the right to participate in the conduct of
any Tax contest relating to the Contested Taxes at its own expense, including
through its own counsel and other professional experts and shall be entitled to
control such Tax contest in the event that Seller fails to do so. Seller shall
consult with Buyer prior to the settlement of any such Tax contest and Seller
shall not settle any such Tax contest if the settlement would have an adverse
tax effect in a taxable period ending after the Closing Date without the consent
of Buyer, which shall not be unreasonably withheld; provided however, that
Seller shall not settle any Tax contest without the consent of Buyer relating to

                                       46



a determination that the initial Tax Basis of the assets of the Company should
not be increased by the amount of the nonqualified decommissioning liability.

                   (h) Refunds. Seller shall be entitled to all refunds of Taxes
with respect to the Company Group (other than the Company) relating to taxable
periods or portions thereof ending on or before the Closing Date except to the
extent included in the Working Capital adjustment pursuant to Section 2.2 or
attributable to an increase in the initial Tax Basis of the assets of the
Company as a result of a redetermination of the initial purchase price of such
assets attributable to the nonqualified decommissioning liability. Buyer shall,
upon receipt of any refund by Buyer or the Company Group (other than the
Company), pay over to the Seller any such refund or the amount of any such
benefit within five (5) Business Days of the earlier of receipt or entitlement
thereto. Buyer shall, if Seller so requests and at Seller's expense, cause the
relevant entity to file for and obtain any refunds or equivalent amounts to
which Seller is entitled under this Section 5.10(h). Buyer shall permit Seller
to control (at Seller's expense) the prosecution of any such refund claimed and
shall cause the relevant entity to authorize by appropriate power of attorney
such persons as the Seller shall designate to represent such entity with respect
to such refund claimed.

         SECTION 5.11 Intercompany Loans. Schedule 5.11 identifies all loans
between BEUSH and its Subsidiaries (other than the Company) and British Energy
or its affiliates (other than BEUSH and its Subsidiaries) as of the date of this
Agreement (the "Intercompany Loans"). On or prior to the Closing Date, (i) Buyer
shall loan, or caused to be loaned to British Energy LP an amount sufficient to
repay in full to British Energy or its affiliates, and (ii) British Energy LP
shall repay, or cause to be repaid, in full to British Energy or its affiliates,
the net amount of all Intercompany Loans (including any unpaid, accrued interest
and other fees as of the Closing Date) to BEUSH and its Subsidiaries as
identified on Schedule 5.11; provided that, in determining the net amount of
Intercompany Loans to be repaid under this Section 5.11, Buyer may discharge its
obligation to loan or caused to be loaned an amount sufficient to repay or cause
repayment of any Intercompany Loan to British Energy and its affiliates (other
than BEUSH and its Subsidiaries) through netting the amount of any Intercompany
Loans due from British Energy and its affiliates (other than BEUSH and its
Subsidiaries). British Energy shall deliver or make available to Buyer proof of
repayment in full of Intercompany Loans at the Closing.

         SECTION 5.12 Corporate Names.

                   (a) As soon as reasonably practicable after the Closing Date,
but in any event no later than thirty (30) days from the Closing Date, Buyer
shall cause BEUSH and each of its Subsidiaries to remove or cover the name
"British Energy" and any trademarks, trade names brandmarks, brand names, trade
dress or logos relating to such name from all signs, telephone listings, labels,
stationery, office forms, packaging or other materials of BEUSH or its
Subsidiaries. Thereafter, the Buyer shall neither use nor permit any of BEUSH or
its Subsidiaries to use such names or any trademark, trade name, brandmark,
brand name, trade dress or logo relating or confusingly similar to such names in
connection with the businesses of BEUSH or its Subsidiaries or otherwise. As
soon as reasonably practicable after the Closing, but in any event no later than
ninety (90) days thereafter, the Buyer shall cause each of BEUSH and its
Subsidiaries to amend its certificate of incorporation, partnership agreement,
LLC Agreement, limited liability company agreement and other applicable
documents, subject to any required consent or approval of any other partner or

                                       47



member, which Buyer shall use its reasonable efforts to obtain, so as to delete
any reference to "British Energy" in its legal name and, within such ninety (90)
day period, to make all required filings with Governmental Authorities to effect
such amendments.

                  (b) Each of the Parties hereto acknowledges and agrees that
the remedy at Law for any breach of the requirements of this Section 5.12 would
be inadequate, and agrees and consents that without intending to limit any
additional remedies that may be available, temporary and permanent injunctive
and other equitable relief may be granted without proof of actual damage or
inadequacy of legal remedy in any proceeding which may be brought to enforce any
of the provisions of this Section 5.12.

         SECTION 5.13 ISRA Clearance. Seller shall obtain at its sole expense
(and deliver a copy to Buyer), pursuant to the New Jersey Industrial Site
Recovery Act, N.J.S.A. 13: lK-6 et seq. and the regulations promulgated
thereunder ("ISRA"), one of the following as required to consummate the
transactions contemplated by this Agreement: (i) a letter of non-applicability
of ISRA from the New Jersey Department of Environmental Protection ("NJDEP");
(ii) a no further action letter under ISRA; (iii) a remediation agreement
pursuant to ISRA reasonably acceptable to Buyer and Seller, under which the
Buyer will perform or cause to be performed such remediation, subject to any
indemnification from Seller available hereunder with respect to environmental
matters and in connection with which Buyer shall provide or cause to be provided
all necessary financial assurance required by NJDEP (except to the extent NJDEP
affirmatively requires that Seller (x) be so designated as the party responsible
for performance of such remediation and/or (y) provide such financial
assurance); (iv) approval of an application for one of the following exemptions
from ISRA: (A) a "de minimis quantity" exemption, (B) an underground storage
tank exemption, (C) a minimal environmental concern exemption, (D) a
"remediation in progress waiver"; or (v) any other approval or authorization of
the NJDEP reasonably acceptable to Buyer and Seller.

         SECTION 5.14 Reimbursement of Nonqualified Decommissioning Funds. The
NQDF Tax Reimbursement Share of any payments made to the Company for NQDF Tax
Reimbursement shall be for the account of Seller, provided that (i) on or prior
to the Closing Date, Seller shall be permitted to distribute to itself any or
all of the NQDF Tax Reimbursement Share distributed to British Energy LP
(provided that Exelon shall have received an equal distribution to the amount
distributed to British Energy LP), and (ii) with respect to any NQDF Tax
Reimbursement Share not distributed to Seller in accordance with subsection (i)
of this Section 5.14 or received after the Closing Date, and to the extent not
included as an asset in either the Company's Working Capital Adjustment
Statement or BEUSH's Working Capital Adjustment Statement, Buyer shall pay to
Seller an amount equal to such NQDF Tax Reimbursement Share in immediately
available funds, within sixty (60) days of receipt of such payments by the
Company.

         SECTION 5.15 Documents Relating to Liability for Payment of One-Time
Fee for Spent Fuel Disposal. Prior to Closing, Seller shall use Commercially
Reasonable Efforts to obtain all documents from the files of the Company Group
and their counsel that relate to the retained liability of the previous owners
of TMI-1 and Oyster Creek for the payment to DOE of the deferred one-time fee
for spent fuel discharged from TMI-1 and Oyster Creek pursuant to the DOE
Standard Spent Fuel Contracts for those Facilities, including, but not limited

                                       48



to, the relevant documents from the Company's and its counsel's files from the
negotiations leading to the purchase and sale agreements for the acquisition of
TMI-1 and Oyster Creek and any correspondence with DOE relating to the payment
of the deferred one-time fee for TMI-1 and Oyster Creek. Seller shall promptly
provide Buyer with a copy of any documents obtained pursuant to the immediately
preceding sentence, provided that Seller shall not be required to provide Buyer
with documents or portions of documents containing: (i) any information that the
Company or the Company's counsel reasonably believes constitutes or could
reasonably be deemed to constitute a waiver of the attorney-client privilege as
to the Company, or (ii) any information that Seller or the Company is under a
legal obligation not to disclose to third parties. Notwithstanding the
foregoing, to the extent that documents are withheld from Buyer as a result of
asserting (x) attorney-client privilege or (y) nondisclosure contractual
obligations, Seller shall provide Buyer with a list of such documents citing the
basis upon which each document is withheld (except to the extent such disclosure
itself would violate such privilege or obligations) and, if the basis for
withholding is attorney-client privilege, the name of the party asserting the
privilege; provided that, the assertion of the privilege by the Company or a
third party, including Exelon or its affiliates, shall in no event be deemed to
constitute a breach by Seller of its obligations under this Section 5.15. In
addition, Seller shall use Commercially Reasonable Efforts to seek waiver of any
attorney-client privilege and to protect against, or cause to be protected
against, such documents from being destroyed or lost during the Interim Period.

         SECTION 5.16 Prohibited Transactions. From and after the date hereof,
none of the Seller nor any member of the Company Group, nor their respective
officers, directors, employees, affiliates, stockholders, representatives or
agents, nor anyone acting on behalf of any of them, shall, directly or
indirectly, encourage, solicit, engage in discussions or negotiations with, or
provide any non-public information to, any person or entity (other than Buyer
and its representatives) concerning any sale of BEUSH Shares or similar
transaction involving the Company or the Assets (collectively "Prohibited
Transactions") unless this Agreement is terminated pursuant to and in accordance
with Article 8 hereof; provided that, Seller may provide FPL with a copy of this
Agreement, the Waiver Letter, dated as of the date of this Agreement, from Buyer
to Seller relating to the Agreement, and the notice from Buyer referred to in
the Recitals, subject to the requirements of the Confidentiality Agreement.

         SECTION 5.17 Financial Statements. (a) Within thirty (30) days after
the end of each calendar month during the Interim Period, the Seller shall
provide to the Buyer consolidated financial statements of the Company Group,
including a consolidated balance sheet as of the end of such calendar month and
income and cash-flow statements for the one-month period then ending. Except as
set forth on Schedule 5.17, such financial statements shall (a) be in accordance
with the books and records of the Company Group, (b) be prepared in accordance
with GAAP consistently applied throughout the periods covered thereby (except
for the absence of footnotes and normal year-end adjustments), and (c) present
fairly and accurately in accordance with GAAP the assets, liabilities
(including, without limitation, all reserves) and financial condition of the
Company Group as of the respective dates thereof and the results of operations
for the periods covered thereby.

                  (b) Seller shall deliver to Buyer, as soon as practicable
after they become available to Seller, the audited consolidated balance sheets
of each of BEUSH, BEUILLC and British Energy, LP, in each case as of December

                                       49



31, 2002 and the related audited consolidated statements of income and cash
flows for the year ended December 31, 2002.

         SECTION 5.18 Transmission. During the Interim Period, Seller shall use
Commercially Reasonable Efforts to cause the Company to obtain and/or maintain
any and all necessary transmission rights and services required in order to
deliver the energy and capacity output of the Facilities to the purchasers of
such output.

         SECTION 5.19 Risk of Loss. Except as otherwise provided in this Section
5.19 and Article 7, during the Interim Period all risk of loss or damage to the
property included in the Assets shall be borne by the Seller. If during the
Interim Period the Assets are damaged by fire or other casualty (each such
event, an "Event of Loss") or are taken by a Governmental Authority by exercise
of the power of eminent domain (each, a "Taking"), the following provisions
shall apply:

                  (a) Upon the occurrence of (i) any one or more Events of Loss,
as a result of which the aggregate costs to restore, repair or replace, less any
insurance proceeds received or payable to the Company in connection with such
Event or Events of Loss (provided that any insurance proceeds received or
payable in connection with the Event or Events of Loss are either used to
restore, repair or replace such Event or Events of Loss) are reasonably
estimated to be equal to or less than $10,000,000, and/or (ii) any one or more
Takings, as a result of which the aggregate condemnation proceeds equal an
amount reasonably estimated to be equal to or less than $10,000,000, shall have
no effect on the transactions contemplated hereby; provided that any
condemnation proceeds received or payable in connection with the Taking or
Takings shall be excluded from the calculation of Company Working Capital at
Closing;

                  (b) Upon the occurrence of (i) any one or more Events of Loss,
as a result of which the aggregate costs to restore, repair or replace, less any
insurance proceeds received or payable to the Company in connection with such
Event or Events of Loss (provided that any insurance proceeds received or
payable in connection with the Event or Events of Loss are used to restore,
repair or replace such Event or Events of Loss) are reasonably estimated to be
greater than $10,000,000, and/or (ii) any one or more Takings, as a result of
which the aggregate condemnation proceeds are reasonably estimated to be greater
than $10,000,000 (a "Major Loss"), Seller shall have, in the case of a Major
Loss relating to one or more Events of Loss, the option, exercised by notice to
the Buyer, to cause the Company to restore, repair or replace the affected
Assets. If the Seller elects not to cause the Company to restore, repair or
replace the Assets affected by a Major Loss, or such Major Loss is the result of
one or more Takings, the provisions of Section 5.19(c) will apply;

                 (c) In the event that the Seller elects not to cause the
Company to restore, repair or replace a Major Loss, or in the event that the
Seller, having elected to cause the Company to repair, replace or restore the
Major Loss, fails to cause the Company to complete such repair, replacement or
restoration prior to the Closing Date, or in the event that a Major Loss is the
result of one or more Takings, then the Parties shall, within thirty (30) days
following the Seller's election not to cause the Company to restore, repair or
replace, failure to complete, or the occurrence of such Takings, as the case may
be, negotiate in good faith an equitable adjustment in the Purchase Price to
reflect the impact of the Major Loss, as mitigated by any repair, replacement or
restoration work actually completed by the Company, on the Assets, and proceed

                                       50



to the Closing at a Purchase Price so adjusted. To assist the Buyer in its
evaluation of any and all Events of Loss, the Seller shall provide the Buyer
such access to the Assets and such information as the Buyer may reasonably
request in connection therewith; and

                  (d) In the event that the Parties fail to reach agreement on
an equitable adjustment of the Purchase Price within the thirty (30) days
provided in Section 5.19(c), then the Buyer shall have the right to elect,
exercisable by notice to the Seller within fifteen (15) days immediately
following the expiration of the thirty (30) day period, to (i) proceed with the
consummation of the transaction at the Closing, with a reduction in the Purchase
Price, consistent with the Seller's last offer of equitable adjustment thereto
as contemplated by the penultimate sentence of Section 5.19(c) communicated to
the Buyer, in which event the Seller shall assign over or deliver to the Buyer
at the Closing all condemnation proceeds or insurance proceeds that the Seller
receives, or to which the Seller become entitled by virtue of the Event of Loss
or Taking with respect to the Assets, less any costs and expenses reasonably
incurred by the Seller in connection with such Events of Loss or Taking or in
obtaining such condemnation proceeds or insurance proceeds, and less the
reduction in the Purchase Price made pursuant to this clause (i), or (ii) submit
the matter to dispute resolution pursuant to Section 9.16 to determine the
adjustment, if any, in the Purchase Price, which determination shall be binding
on all Parties. If the Buyer fails to make the election within the fifteen (15)
day period described in the preceding sentence, the Buyer will be deemed to have
made the election to proceed with the Closing under clause (i) hereof.

                  (e) For the avoidance of doubt, any Event of Loss which has
been repaired, replaced or restored by Seller pursuant to Section 5.19(b) or any
Taking or Event of Loss which has been the subject of a purchase price reduction
pursuant to Section 5.19(c) or 5.19(d) shall be disregarded for purposes of
determining whether Seller has breached any representation or warranty
hereunder, including for purposes of Section 6.2(a) and Section 7.1(i).

                                   ARTICLE 6

                              Conditions to Closing

         SECTION 6.1 Conditions to Obligations of Buyer and British Energy. The
obligations of Buyer and British Energy to consummate the Closing are subject to
the satisfaction of the following conditions:


                  (a) The waiting period applicable to the consummation of the
transactions contemplated hereby under the HSR Act and any other material
waiting periods under applicable foreign laws (if any) shall have expired or
been terminated, or the Parties shall have determined to their mutual
satisfaction that the transactions contemplated hereby are exempt from the HSR
Act or other applicable foreign laws. No action by the Federal Trade Commission,
Department of Justice or any foreign Governmental Entity challenging or seeking
to enjoin the consummation of the transactions contemplated hereby shall have
been instituted and be pending.

                   (b) No temporary restraining order, preliminary or permanent
injunction or other order issued by any court of competent jurisdiction or other
legal or regulatory restraint or prohibition shall have been issued and be in
effect restraining or prohibiting the consummation of the transactions

                                       51



contemplated hereby nor shall any action have been taken or any statute, rule,
regulation or order have been enacted, entered or enforced or be deemed
applicable to the transactions contemplated hereby which makes the consummation
of the transactions contemplated hereby illegal or prevents or prohibits the
sale of the BEUSH Shares.

         SECTION 6.2 Condition to Obligation of Buyer. The obligation of Buyer
to consummate the Closing is subject to the satisfaction or waiver of each of
the following conditions:


                   (a) Representations, Warranties and Covenants. The
representations and warranties in Article 3 shall be true and correct in all
material respects on and as of the Closing Date, as if such representations and
warranties were made on and as of the Closing Date (except to the extent that
any such representations and warranties were made as of a specified date, which
representations and warranties shall continue on the Closing Date to be true in
all material respects as of such specified date), and the covenants and
agreements of Seller to be performed on or before the Closing Date shall have
been duly performed in all material respects in accordance with this Agreement,
except where the failure of such representations and warranties to be so true,
correct and complete or failure to perform a covenant or agreement shall not
have, individually or in the aggregate, resulted in a Material Adverse Effect on
any member of the Company Group. The Seller shall have delivered an officer's
certificate dated as of the Closing, to such effect.

                   (b) Closing Documents. On or prior to the Closing Date,
Seller shall have delivered all agreements, instruments and documents required
to be delivered by Seller pursuant to Section 2.4. The Seller shall have
delivered an officer's certificate, dated as of the Closing, to such effect.

                   (c) No Action. Except for any NRC Proceeding initiated by a
party other than a member of the Company Group which may be pending after the
NRC has approved the Application, on the Closing Date, no claim or Action
(excluding any such matter initiated by Buyer or any of its Affiliates) shall be
pending or threatened seeking to enjoin or restrain the consummation of the
Closing or the transactions contemplated by this Agreement, or seeking to
recover substantial damages from Buyer or any Affiliate of Buyer resulting
therefrom.

                  (d) Buyer's Regulatory Approvals. Buyer shall have obtained or
made each of the approvals listed on Schedule 6.2(d) (the "Buyer Regulatory
Approvals"), each such approval to be in form and substance reasonably
acceptable to Buyer.

                  (e) Seller Approvals and Consents. Seller shall have obtained
or made each of the British Energy Regulatory Approvals, each such approval
shall be in form and substance reasonably acceptable to Buyer.

                  (f) Legal Opinions. Buyer shall have received opinions of
counsel of British Energy, such in the form of Exhibit A(i) and Exhibit A(ii).


                  (g) No Material Adverse Effect. No Material Adverse Effect as
to any member of the Company Group shall have occurred and be continuing.

                                       52



                  (h) ISRA Clearance. Seller shall have obtained an ISRA
clearance satisfying the requirements of Section 5.13.

                  (i) No Permanent Shutdown of Facilities. None of the
Facilities shall have been permanently shut down as a result of actions taken by
the NRC or other Governmental Authority.

                  (j) No Reduction of Licensed Thermal Output. Neither the NRC
nor any other Governmental Authority shall have reduced the licensed thermal
output of any Facility by an amount that exceeds five percent (5%) of the
licensed thermal output of all Facilities on an aggregate basis.

                   (k) Guarantee of British Energy plc. British Energy shall
deliver or cause to be delivered (i) a guaranty, in the form of Exhibit D
hereto, executed by British Energy plc in favor of Buyer, guaranteeing the
obligations of British Energy under this Agreement or (ii) an executed
substitute guaranty or other credit support that guarantees the obligations of
British Energy under this Agreement, in form and substance reasonably acceptable
to Buyer.

                  (1) Tax Matter. (i) The Company has received from the Internal
Revenue Service, and delivered to Buyer, a private letter ruling under Treas.
Reg. Section 301.9100 that the transfer in 2001 of the fifty percent (50%)
ownership interest in the Company from PECO Energy Company to Exelon had the tax
consequences set forth in Treas. Reg. Section 1.468A-6(c); or (ii) Buyer has
received a "will" opinion to the foregoing effect, dated as of the Closing Date,
from counsel to Seller, addressed and in form satisfactory to Buyer in Buyer's
sole and absolute discretion.

                  (m) Any Liens associated with the Credit Facility Agreement or
the Pledge Agreement shall have been released in the reasonable satisfaction of
Buyer.

         SECTION 6.3 Conditions to Obligation of British Energy. The obligation
of British Energy to consummate the Closing is subject to the satisfaction or
waiver of each of the following conditions:

                  (a) Representations, Warranties and Covenants. The
representations and warranties of Buyer contained in Article 4 shall be true and
correct in all material respects on and as of the Closing Date, as if such
representations and warranties were made on and as of the Closing Date (except
to the extent that any such representations and warranties were made as of a
specified date, which representations and warranties shall continue on the
Closing Date to be true in all material respects as of such specified date), and
the covenants and agreements of Seller to be performed on or before the Closing
Date shall have been duly performed in all material respects in accordance with
this Agreement, except where the failure of such representations and warranties
to be so true, correct and complete or failure to perform a covenant or
agreement shall not have, individually or in the aggregate, resulted in a
Material Adverse Effect on Buyer. The Buyer shall have delivered an officer's
certificate, dated as of the Closing, to such effect.

                  (b) Closing Documents. On or prior to the Closing Date, Buyer
shall have delivered all agreements, instruments and documents required to be
delivered by Buyer pursuant to Section 2.5. The Buyer shall have delivered an
officer's certificate, dated as of the Closing, to such effect.

                                       53



                   (c) No Action. Except for any NRC Proceeding which may be
pending after the NRC has approved the Application, on the Closing Date, no
claim or Action (excluding any such matter initiated by Seller or any of its
Affiliates) shall be pending or threatened seeking to enjoin or restrain the
consummation of the Closing or the transactions contemplated by this Agreement,
or seeking to recover substantial damages from Seller or any Affiliate of Seller
resulting therefrom.

                  (d) British Energy Approvals. British Energy shall have
obtained or made each of the approvals listed on Schedule 6.3(d) (the "British
Energy Regulatory Approvals"), each such approval to be in form and substance
reasonably acceptable to British Energy. The approvals listed in Items 1 and 2
of Schedule 3.2 shall have been obtained.

                  (e) [Intentionally Omitted.]

                  (f) ISRA Clearance. Seller shall have obtained an ISRA
clearance meeting the requirements set forth in Section 5.13.

                                   ARTICLE 7

                                 Indemnification

         SECTION 7.1 Indemnification by Seller. From and after the Closing,
subject to the other terms and limitations set forth in this Agreement, Seller
shall, indemnify, defend, reimburse and hold harmless Buyer, its Affiliates
(including the Company Group) and their respective directors, officers, partners
and employees (each such Person, a "Buyer Indemnified Party" and, collectively,
the "Buyer Indemnified Parties"), from and against any and all Losses actually
incurred by any Buyer Indemnified Party (i) for any breach of the
representations and warranties contained in Article 3 or in any certificate
delivered by Seller at the Closing with respect to such representations and
warranties, (ii) for any breach of the covenants or obligations of Seller under
this Agreement, (iii) for any Seller Ownership Period Environmental Liability,
or (iv) for any Pre-Closing ERISA Liability.

         SECTION 7.2 Indemnification by Buyer. From and after the Closing,
subject to the other terms and limitations set forth in this Agreement, Buyer
shall indemnify, defend, reimburse and hold harmless Seller, its Affiliates and
their respective directors, officers, partners and employees (each such Person,
a "Seller Indemnified Party" and, collectively, the "Seller Indemnified
Parties"), from and against any and all Losses actually incurred by any Seller
Indemnified Party (i) for any breach of Buyer's representations or warranties
made in this Agreement or in any certificate delivered by Buyer at the Closing
with respect to such representations and warranties, or (ii) for any breach of
the covenants or obligations of Buyer under this Agreement.

         SECTION 7.3 Limitations on Indemnity.

                  (a) Except for the specific indemnity provided in Section 7.7
of this Agreement, anything in this Agreement to the contrary notwithstanding,
in no event shall Seller ever be required to indemnify any Buyer Indemnified

                                       54



Party for Losses pursuant to Section 7.1 or any of the other provisions of this
Agreement, including Section 5.10 (or to pay any other amount in connection with
or with respect to this Agreement or the transactions contemplated by this
Agreement) (i) until the aggregate amount of all such Losses shall have exceeded
$5 million (the "Deductible"), whereupon only Losses in excess of the Deductible
shall be subject to indemnification hereunder; provided, however, that any
individual Loss of less than $100,000 that is otherwise subject to
indemnification hereunder shall be disregarded in determining whether any Buyer
Indemnified Party has incurred Losses up to or exceeding the Deductible, or (ii)
in an amount exceeding, in the aggregate, 75% of the Adjusted Purchase Price.

                  (b) Notwithstanding anything to the contrary contained in this
Agreement, Seller and Buyer agree that the recovery by any Indemnified Party of
any damages suffered or incurred by such Indemnified Party as a result of any
breach by another Party of any of its obligations under this Agreement shall be
limited to the actual damages suffered or incurred by an Indemnified Party as a
result of the breach by the breaching Party of its obligations hereunder, and in
no event shall the breaching Party be liable to an Indemnified Party for any
indirect, consequential, special, exemplary or punitive damages (including any
damages on account of lost profits or opportunities or lost or delayed
generation) suffered or incurred by an Indemnified Party as a result of the
breach by the breaching Party of any of its obligations hereunder.

         SECTION 7.4 Indemnity Procedures.

                  (a) If a claim by a third party is made against a Seller
Indemnified Party or a Buyer Indemnified Party (any such person, an "Indemnified
Party") or an Indemnified Party shall otherwise learn of an assertion or of a
potential claim, and if such Indemnified Party intends to seek indemnity with
respect thereto under this Article 7 (other than with respect to an indemnity
arising out of the breach of any representation or warranty contained in
Sections 3.16, 3.17 or 3.23, which shall be governed by Section 5.10(g)), such
Indemnified Party shall promptly furnish written notice of such claim (in
reasonable detail and including the factual basis for such claim and, to the
extent known, the amount thereof) to the Party against whom indemnity is sought
(such Party, in such capacity, the "Indemnifying Party"). Thereafter, the
Indemnified Party will deliver to the Indemnifying Party, promptly after the
Indemnified Party's receipt thereof, copies of all material notices and
documents (including court papers) received or transmitted by the Indemnified
Party relating to such claim. The failure of the Indemnified Party to deliver
prompt written notice of a claim shall not affect the indemnity obligations of
the Indemnifying Party hereunder, except to the extent the Indemnifying Party
was actually disadvantaged by such delay in delivery of notice of such claim.
The Indemnifying Party shall have thirty (30) days after receipt of such notice
to provide written notice to the Indemnified Party acknowledging unconditionally
its obligations to indemnify the Indemnified Party with respect to such claim
(an "Acceptance Notice") and if it delivers an Acceptance Notice, to elect to
undertake, conduct and control (through counsel of its own choosing and at its
own expense), the settlement or defense of such claim, and the Indemnified Party
shall cooperate with it in connection therewith. If the Indemnifying Party does
not assume the conduct and control of such settlement and defense, it shall have
the right to participate in the settlement or defense of such claim, and the
Indemnified Party shall cooperate with it in connection therewith. If the
Indemnifying Party elects to undertake, conduct and control the settlement or
defense of such claim, the Indemnifying Party shall permit the Indemnified Party
to participate in such settlement or defense through counsel chosen by such
Indemnified Party (but the fees and expenses of such counsel shall be borne by
such Indemnified Party). So long as the Indemnifying Party, at the Indemnifying
Party's cost and expense, (i) has undertaken the defense of, and assumed full

                                       55



responsibility for all indemnified liabilities with respect to, such claim, (ii)
is reasonably contesting such claim in good faith through appropriate
proceedings, and (iii) has taken such action (including the posting of a bond,
deposit or other security) as may be necessary to prevent any action to
foreclose a lien against or attachment of the property of the Indemnified Party
for payment of such claim, the Indemnified Party shall not pay or settle any
such claim; provided, however, that, the Indemnified Party shall have the right
to pay or settle any such claim if it has waived in writing any right to
indemnity by the Indemnifying Party for such claim; and, provided, further,
that, if within thirty (30) days after the receipt of the Indemnified Party's
notice of a claim of indemnity under this Section 7.4(a), the Indemnifying Party
does not notify the Indemnified Party that it elects (at the Indemnifying
Party's cost and expense) to undertake the defense thereof and assume full
responsibility for all indemnified liabilities with respect thereto, or gives
such notice and thereafter fails to contest such claim in good faith or to
prevent action to foreclose a lien against or attachment of the Indemnified
Party's property as contemplated above, the Indemnified Party shall have the
right to contest, settle or compromise such claim and the Indemnified Party
shall not thereby waive any right to indemnity for such claim under this
Agreement.

                  (b) Any claim on account of Losses for which indemnification
is provided under this Agreement which does not involve a claim of a third party
will be asserted by prompt written notice (setting forth in reasonable detail
the facts or circumstances that allegedly give rise to such claim and, to the
extent known, the amount thereof) given by the Indemnified Party to the
Indemnifying Party from whom such indemnification is sought. The failure or
delay by any Indemnified Party to so notify the Indemnifying Party will not
relieve the Indemnifying Party from any liability which it may have to such
Indemnified Party under this Agreement, except to the extent that the
Indemnifying Party is actually disadvantaged by such delay in delivery of notice
of such claim.

                 (c) In the event of payment in full by an Indemnifying Party to
any Indemnified Party in connection with any claim (an "Indemnified Claim"),
such Indemnifying Party will be subrogated to and will stand in the place of
such Indemnified Party as to any events or circumstances in respect of which
such Indemnified Party may have any right or claim relating to such Indemnified
Claim against any claimant or plaintiff asserting such Indemnified Claim or
against any other Person. Such Indemnified Party will cooperate with such
Indemnifying Party in a reasonable manner, and at the cost and expense of such
Indemnifying Party, in prosecuting any subrogated right or claim.

         SECTION 7.5 Procedural Requirements for Environmental Claims by Buyer.
The provisions of this Section 7.5 are in addition to, and not in limitation of,
the procedures set forth in Section 7.4 (which shall be deemed superseded to the
extent inconsistent with this Section 7.5). Buyer will provide Seller with
prompt notice describing in reasonable detail any condition or claim in respect
of which Losses arising out of a breach of the representations and warranties in
Section 3.20 or any Seller Ownership Period Environmental Liability are or may
be incurred by any Buyer Indemnified Party; provided, however, that if such
notice is not given within a sufficient period of time or in sufficient detail
to apprise Seller of the nature of any such condition or claim (in each instance
taking into account the facts and circumstances with respect thereto), the costs
and expenses incurred by such Buyer Indemnified Party in connection with such
condition or claim shall not constitute Losses to the extent that Seller's
position is actually prejudiced as a result thereof. Seller will have the option
to participate, at their own expense, in the resolution of any such conditions

                                       56



or claims (and, in any event, Buyer will consult in good faith with Seller in
respect of the resolution of any such conditions or claims). Buyer will keep
Seller apprised of the status of and any action by or on behalf of Buyer or any
member of the Company Group or their respective Affiliates with respect to all
such conditions or claims. If Seller is not given, within a sufficient period of
time or in sufficient detail, information necessary to reasonably apprise Seller
of the status of and any action by or on behalf of Buyer, any member of the
Company Group or their respective Affiliates with respect to any such conditions
or claims (in each instance taking into account the facts and circumstances with
respect thereto), the costs and expenses incurred by Buyer or any member of the
Company Group in connection with such condition or claim shall not constitute
Losses to the extent that Seller's position is actually prejudiced as a result
thereof.

         SECTION 7.6 Survival and Time Limitation. The terms and provisions of
this Agreement shall survive the Closing of the transactions contemplated
hereunder. Notwithstanding the foregoing, after Closing, any claim by any Buyer
Indemnified Party that Seller is liable to such Buyer Indemnified Party under
the terms of this Agreement for breach of any representations and warranties of
Seller must be given to Seller on or prior to the date that is twelve (12)
months after the Closing Date, except for (i) any claims for breach of the
representations and warranties of Seller in Sections 3.1, 3.2, 3.3, 3.10, 3.11,
3.12, 3.16, 3.17 and 3.23, and any claims made by Buyer pursuant to Section
5.10, which must be given to Seller (or not at all) on or prior to the date that
is ninety (90) days after the expiration of all applicable statutes of
limitations with respect to the matters covered thereby, (ii) any claim for
breach of the representations and warranties of Seller in Sections 3.7, 3.8, 3.9
and 3.36, which shall survive indefinitely, (iii) except as described in clause
(iv) of this Section 7.6, any claim for breach of the representations and
warranties of Seller in Section 3.20, which must be given to Seller on or prior
to the date that is twenty-four (24) months after the Closing Date, (iv) any
claim for breach of Section 3.20 relating to the matters described in Section
7.7 hereof, which shall survive until the later of the complete and conclusive
resolution of any such matters with any applicable Governmental Authority or the
payment in full of any amounts owed to each Buyer Indemnified Party under
Section 7.7, and (v) any claim for breach of Section 3.37, which shall survive
for the initial license term of each respective Facility. Notwithstanding the
initial sentence of this Section 7.6, after Closing, any claim by any Seller
Indemnified Party that Buyer is liable to such Seller Indemnified Party for a
breach of any representations and warranties of Buyer must be given to Buyer on
or prior to the date that is twelve (12) months after the Closing Date. All
covenants and other agreements of Seller and Buyer contained in this Agreement
that by their terms are to be performed after the Closing shall survive until
the expiration of all applicable statutes of limitations with respect to the
matters covered thereby.

         SECTION 7.7 Specific Indemnity by Seller. Notwithstanding the
foregoing, from and after the Closing, Seller shall indemnify, defend, reimburse
and hold harmless each Buyer Indemnified Party from and against any and all
Losses actually incurred by any Buyer Indemnified Party that were incurred by
such Buyer Indemnified Party as a result of the "Fish Kill" described in
Schedule 3.20 hereof (including without limitation any and all Losses actually
incurred in connection with the allegations set forth in Schwartz v. AmerGen
Energy Company, Exelon Generation Company, British Energy Company et al.,
Superior Court of New Jersey, Docket L-2075-03 as filed on July 25, 2003, and
any subsequent amendments to the allegations related to the "Fish Kill", as

                                       57



described in Schedule 3.20 hereof). In connection with making an Indemnified
Claim, the Parties shall follow the Indemnification Procedures described in
Sections 7.4 and 7.5 above.

         SECTION 7.8 Further Indemnity Limitations. The amount of any
indemnifiable Loss shall be reduced (i) to the extent any Indemnified Party
actually receives any insurance proceeds with respect to such Loss, (ii) to take
into account any net Tax benefit arising from the recognition of the Loss, (iii)
to take into account any payment actually received by an Indemnified Party from
a third party with respect to such Loss, and (iv) to the extent of any Loss that
is attributable to a determination that the initial Tax Basis of the assets of
the Company should not be increased by the amount of the nonqualified
decommissioning liability.

         SECTION 7.9 Sole and Exclusive Remedy. From and after the Closing,
except as provided in Section 5.10 of this Agreement for any claim in respect of
Taxes, the indemnification provisions of this Article 7 shall be the sole and
exclusive post-Closing remedy of each Party (including the Seller Indemnified
Parties and the Buyer Indemnified Parties) (i) for any breach of any Party's
representations, warranties, covenants or agreements contained in this
Agreement, or (ii) otherwise with respect to this Agreement or the transactions
contemplated hereby. In furtherance of the foregoing, each Party hereby waives,
to the fullest extent permitted under applicable Law, any and all other rights,
claims and causes of action it or any of its Affiliates may have against another
Party hereunder with respect thereto.

                                    ARTICLE 8

                                     Termination

         SECTION 8.1 Termination. This Agreement may be terminated at any time
prior to the Closing:

                  (a) by mutual written agreement of British Energy and Buyer;

                  (b) by British Energy or Buyer if the Closing shall not have
been consummated on or before the day that is six (6) months after the date
hereof, unless the reason that the Closing has not occurred shall be the failure
of the Party seeking to terminate this Agreement to fulfill its obligations
hereunder; provided, however, (i) that if the reason the Closing has not
occurred is because Buyer Regulatory Approvals or British Energy Regulatory
Approvals have not been obtained and Commercially Reasonable Efforts are being
undertaken to obtain such regulatory approvals by the Party responsible for
obtaining such regulatory approvals, the reference to "the day that is six (6)
months after the date hereof' in this Section 8.1(b) shall be extended for an
additional six (6) months and neither British Energy nor Buyer may terminate
this Agreement during such extended period so long as such Commercially
Reasonable Efforts continue, or (ii) that if the reason the Closing has not
occurred is because FPL Energy Nuclear Mid-Atlantic, LLC or its Affiliates
(collectively "FPL") is attempting to prevent the transfer of the Seller's
indirect interest in the Company and Seller has timely commenced arbitration
proceedings or other legal action with FPL regarding FPL's action or inaction
with respect to such transfer, the reference to "the day that is six (6) months
after the date hereof" in this Section 8.1(b) shall be extended for an

                                       58



additional six (6) months and neither British Energy nor Buyer may terminate
this Agreement during such extended period;

                  (c) by British Energy or Buyer if consummation of the
transactions contemplated hereby would violate any nonappealable final order,
decree or judgment of any court or governmental body having competent
jurisdiction;

                  (d) by Buyer if any Buyer Regulatory Approvals shall have been
denied (and a petition for rehearing, a petition for review or refiling of an
application initially denied without prejudice shall also have been denied) or
shall have been granted subject to terms and conditions that would likely have a
Material Adverse Effect, and all appeals of any such actions shall have been
taken and been unsuccessful;

                  (e) by British Energy if any British Energy Regulatory
Approvals shall have been denied (and a petition for rehearing, a petition for
review or refiling of an application initially denied without prejudice shall
also have been denied) or shall have been granted subject to terms and
conditions that would likely have a Material Adverse Effect, and all appeals of
any such actions shall have been taken and been unsuccessful;

                  (f) by Buyer if there has been a material violation or breach
by British Energy of any covenant, representation or warranty contained in this
Agreement and such violation or breach is not cured by the earlier of the
Closing Date or the date thirty (30) days after receipt by British Energy of
written notice specifying particularly such violation or breach, and such
violation or breach has not been waived by Buyer;

                  (g) by British Energy if there has been a material violation
or breach by Buyer of any covenant, representation or warranty contained in this
Agreement and such violation or breach is not cured by the earlier of the
Closing Date or the date thirty (30) days after receipt by Buyer of written
notice specifying particularly such violation or breach, and such violation or
breach has not been waived by British Energy;

         The Party desiring to terminate this Agreement shall give notice of
such termination to the other Party in the manner set forth in Section 8.2.

         SECTION 8.2 Effect of Termination. In the event of termination of this
Agreement by Seller or Buyer pursuant to Section 8.1, written notice thereof
shall promptly be given by the terminating Party to the other Parties, and this
Agreement shall thereupon terminate provided, however, the termination of this
Agreement shall not release any party from liability for any breach of any
representation, warranty or covenant contained herein prior to the date of
termination. Following any such termination, Buyer and Seller will continue to
be bound by the obligations set forth in Sections 5.8 and 5.9 and Article 7. If
this Agreement is terminated as provided herein, all filings, applications and
other submissions made to any Governmental Authority shall, to the extent
practicable, be withdrawn from the Governmental Authority to which they were
made.

         SECTION 8.3 Remedies.

                  (a) Seller's Remedies. (i) Notwithstanding anything herein to
the contrary, upon the failure by Buyer to fulfill any undertaking or commitment
provided for herein on the part of Buyer that is required to be fulfilled on or

                                       59



prior to the Closing Date, Seller, at its sole option, may enforce specific
performance of this Agreement or pursue any rights or remedies available at law
or in equity.

                  (b) Seller's Remedy for Termination Pursuant to Section
8.1(b), 8.l(c), 8.1(d) or 8.1(e). In the event that (i) this Agreement is
terminated pursuant to any of Section 8.1(b) through 8.1(e), (ii) such
termination resulted from a failure to obtain applicable regulatory approvals,
and (iii) such failure is attributable to the announcement or consummation after
the date hereof of any transaction pursuant to which Buyer or any of its
Affiliates would acquire any electric generation facilities or uncommitted
electric generating capacity, Buyer shall pay to Seller, no later than five (5)
days after any such termination, by wire transfer of immediately available funds
to an account designated in writing by Seller, an amount equal to $8,295,000.

                  (c) Buyer's Remedies. Except as set forth in Section 8.3(d)
hereof, notwithstanding anything herein provided to the contrary, upon failure
of Seller to fulfill any undertaking or commitment provided for herein on the
part of Seller that is required to be fulfilled on or prior to the Closing Date,
Buyer, at its sole option, may enforce specific performance of this Agreement or
pursue any rights or remedies available at law or in equity.

                  (d) Buyer's Remedy for Termination Pursuant to Section 8.1(b).
In the event that this Agreement is terminated by Buyer or Seller pursuant to
Section 8.1(b) and the Closing shall not have been consummated as a result of
FPL's material interference with the transactions contemplated hereby, Buyer's
sole and exclusive remedy for such termination shall be a termination payment in
the amount of $8,295,000 (the "Break Up Fee"), payable by Seller to Buyer by
wire transfer no later than five (5) days after the consummation of any sale of
the BEUSH Shares which directly or indirectly transfers the Company Group's
ownership interest in the Company to FPL or an Affiliate thereof; provided that,
in the event that, following such a termination of this Agreement, Seller has
not consummated such a sale of its direct or indirect ownership interests in the
Company within one (1) year of the date of this Agreement, Seller shall make a
payment to Buyer, within three (3) Business Days after the first anniversary of
the date hereof, in the amount of $1,000,000, such amount to be deducted from
any payment of the Break Up Fee upon consummation of such a sale within three
(3) years from the date of this Agreement. In the event such a sale of Seller's
direct or indirect ownership interests in the Company is not consummated within
three (3) years from the date of this Agreement, Seller shall have no further
liability to Buyer for termination pursuant to Section 8.1(b). The Parties agree
that Buyer's actual damages as a result of such termination would be extremely
difficult to calculate, and that such payment constitutes liquidated damages for
the consequences of such termination and is not a penalty.

                   (e) Election of Remedies. (i) Except as set forth in Section
8.3(d) hereof, if any Party elects to pursue singularly any right or remedy
available to it under this Section 8.3, then such Party may at any time
thereafter cease pursuing that right or remedy and elect to pursue any other
right or remedy available to it under this Section 8.3. All rights and remedies
hereunder (except those set forth in Section 8.3(d)) shall be cumulative. Except
as otherwise provided by Applicable Law, no delay or forbearance by a Party in
the exercise or enforcement of any right or remedy hereunder shall be deemed a
waiver by such party of its right hereunder to exercise or enforce such right or
remedy.

                                       60



                                   ARTICLE 9

                                  Miscellaneous

         SECTION 9.1 Notices. All notices, requests and other communications to
either Party hereunder shall be in writing. All notices, request, demands,
waivers and other communications required or permitted to be given under this
Agreement shall be in writing and shall be deemed to have been duly given if (i)
delivered personally, (ii) sent by next-day or overnight mail or delivery, or
(iii) sent by facsimile addressed as follows:

         If to Buyer, to:

                  Exelon Generation Company, LLC
                  4300 Winfield Road
                  Warrenville, IL 60555
                  Attn:  Chief Executive Officer and Chief Nuclear Officer
                  Telecopy: (630) 657-4300

         with a copy to:

                  Exelon Corporation
                  10 South Dearborn Street
                  Chicago, IL 60603
                  Attn:  Executive Vice President and General Counsel
                  Telecopy:   (312) 394-2900

         If to British Energy, to:

                  3 Redwood Crescent
                  Peel Park
                  East Kilbride, G74 SPR, Scotland
                  Attn:  Company Secretary
                  Telecopy: 011-44-13552-62563

         with a copy to:

                  Simpson Thacher & Bartlett
                  425 Lexington Avenue
                  New York, New York 10017-3954
                  Attn:   Mario A. Ponce, Esq.
                  Telecopy: (212) 455-3442

         All such notices, requests, demands, waivers and other communications
shall be deemed to have been received (w) if by personal delivery, on the day
after such delivery, (x) if by certified or registered mail, on the seventh
business day after the mailing thereof, (y) if by next-day or overnight mail or
delivery, on the day delivered, or (z) if by fax or telegram, on the next
business day following the day on which such fax or telegram was sent, provided,
however, that a copy is also sent by certified or registered mail.

                                       61



         SECTION 9.2 Amendments; No Waivers.

                  (a) Any provisions of this Agreement may be amended or waived
prior to the Closing Date if, and only if, such amendment or waiver is in
writing and signed, in the case of an amendment, by Buyer and British Energy or
in the case of a waiver, by the Party against whom the waiver is to be
effective.

                   (b) No failure or delay by either Party in exercising any
right, power or privilege hereunder shall operate as a waiver thereof nor shall
any single or partial exercise thereof preclude any other or further exercise
thereof or the exercise of any other right, power or privilege. The rights and
remedies herein provided shall be cumulative and not exclusive of any rights or
remedies provided by law.

         SECTION 9.3 Expenses. Except as expressly provided in this Agreement,
all costs and expenses incurred in connection with the execution, delivery and
performance of this Agreement, including fees and expenses of counsel, financial
advisors and accountants, shall be paid by the Party incurring such cost or
expense (or in the case of any fees or expenses incurred by any member of the
Company Group, by Seller), whether or not the Closing shall have occurred.

         SECTION 9.4 Successors and Assigns. The rights and obligations of the
Parties shall not be assigned or delegated by either Seller, on the one hand, or
Buyer, on the other hand, without the written consent of Buyer (in the case of
an assignment or delegation by Seller) or Seller (in the case of an assignment
or delegation by Buyer), which consent shall not be unreasonably withheld or
delayed. No assignment of this Agreement will relieve the assigning Party of its
obligations hereunder. Subject to the two preceding sentences, this Agreement
shall be binding upon and inure to the benefit of the Parties hereto and their
respective successors and permitted assigns.

         SECTION 9.5 Governing Law. This Agreement shall be governed by and
construed in accordance with the domestic laws of the State of New York without
giving effect to any choice or conflict of law provision or rule (whether of the
State of New York or any other jurisdiction) that would cause the application of
the laws of any jurisdiction other than the State of New York.

         SECTION 9.6 Counterparts; Effectiveness. This Agreement may be signed
in any number of counterparts, each of which shall be an original, with the same
effect as if the signatures thereto and hereto were upon the same instrument.
This Agreement shall become effective when each Party hereto shall have received
a counterpart hereof signed by the other Party hereto. Facsimile transmission of
any signed original document and/or retransmission of any signed facsimile
transmission will be deemed the same as delivery of an original. At the request
of any Party, the Parties will confirm facsimile transmission by signing a
duplicate original document.

         SECTION 9.7 Entire Agreement. This Agreement and, to the extent
applicable, the LLC Agreement constitute the entire agreement between the
Parties with respect to the subject matter hereof and supersede all prior
agreements, understandings and negotiations, both written and oral, between the

                                       62



Parties with respect to the subject matter of this Agreement. Neither this
Agreement nor any provision hereof is intended to confer upon any Person other
than the Parties hereto any rights or remedies hereunder.

         SECTION 9.8 Captions. The captions herein are included for convenience
of reference only and shall not affect in any way the meaning or interpretation
hereof.

         SECTION 9.9 Third Party Beneficiaries. Except as provided in Sections
5.8, 5.12 and 7.2, no provision of this Agreement is intended to confer any
rights, benefits, remedies, obligations or liabilities hereunder upon any Person
other than the Parties and their respective successors and permitted assigns.

         SECTION 9.10 Severability. If any term, provision, covenant or
restriction of this Agreement is held by a court of competent jurisdiction or
other authority to be invalid, void or unenforceable, the remainder of the
terms, provisions, covenants and restrictions of this Agreement shall remain in
full force and effect and shall in no way be affected, impaired or invalidated
so long as the economic or legal substance of the transactions contemplated
hereby is not affected in any manner materially adverse to any Party. Upon such
a determination, the Parties shall negotiate in good faith to modify this
Agreement so as to effect the original intent of the Parties as closely as
possible in an acceptable manner in order that the transactions contemplated
hereby be consummated as originally contemplated to the fullest extent possible.

         SECTION 9.11 Construction. Unless the context of this Agreement clearly
requires otherwise, (a) references to the plural include the singular, the
singular the plural, the part the whole, (b) references to any gender include
all genders, (c) "or" has the inclusive meaning frequently identified with the
phrase "and/or", (d) "including" has the inclusive meaning frequently identified
with the phrase "but not limited to", (e) references to "hereunder" or "herein"
relate to this Agreement and (f) section, subsection, schedule and exhibit
references are to this Agreement unless otherwise specified.

         SECTION 9.12 Consent to Jurisdiction.

                  (a) Each of the Parties hereby irrevocably and unconditionally
submits, for itself and its property, to the exclusive jurisdiction of any court
of the State of New York sitting in New York County or any Federal court of the
United States of America sitting in the State of New York and any appellate
court from any thereof, in any action or proceeding arising out of or relating
to this Agreement or any transaction contemplated by this Agreement or for
recognition or enforcement of any judgment relating to the transactions
contemplated by this Agreement, and each of the Parties hereby irrevocably and
unconditionally agrees that all claims in respect of any such action or
proceeding may be heard and determined in such court of the State of New York
or, to the extent permitted by Law, in such Federal court. Each of the Parties
agree that a final judgment in any such action or proceeding shall be conclusive
and may be enforced in other jurisdictions by suit on the judgment or in any
other manner provided by Law.

                  (b) Each of the Parties hereby irrevocably and unconditionally
waives, to the fullest extent it may legally and effectively do so, any
objection which may now or hereafter have to the laying of venue of any suit,
action or proceeding arising out of or relating to this Agreement or the
transactions contemplated by this Agreement in any court of the State of New

                                       63



York sitting in New York County or any Federal court of the United States of
America sitting in the State of New York. Each of the Parties hereby irrevocably
waives, to the fullest extent permitted by Law, the defense of an inconvenient
forum to the maintenance of such action or proceeding in any such court.

         SECTION 9.13 Waiver of Punitive and Other Damages and Jury Trial.

                  (a) THE PARTIES TO THIS AGREEMENT EXPRESSLY WAIVE AND FOREGO
ANY RIGHT TO RECOVER PUNITIVE, EXEMPLARY, LOST PROFITS, CONSEQUENTIAL OR SIMILAR
DAMAGES IN ANY ARBITRATION, LAWSUIT, LITIGATION OR PROCEEDING ARISING OUT OF OR
RESULTING FROM ANY CONTROVERSY OR CLAIM ARISING OUT OF OR RELATING TO THIS
AGREEMENT OR THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT.

                  (b) EACH PARTY ACKNOWLEDGES AND AGREES THAT ANY CONTROVERSY
WHICH MAY ARISE UNDER THIS AGREEMENT IS LIKELY TO INVOLVE COMPLICATED AND
DIFFICULT ISSUES, AND THEREFORE IT HEREBY IRREVOCABLY AND UNCONDITIONALLY WAIVES
ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN RESPECT TO ANY LITIGATION DIRECTLY
OR INDIRECTLY ARISING OUT OF OR RELATING TO THIS AGREEMENT OR THE TRANSACTIONS
CONTEMPLATED BY THIS AGREEMENT.

                  (c) EACH PARTY CERTIFIES AND ACKNOWLEDGES THAT (i) NO
REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY
OR OTHERWISE, THAT SUCH OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK
TO ENFORCE EITHER OF THE FOREGOING WAIVERS, (ii) IT UNDERSTANDS AND HAS
CONSIDERED THE IMPLICATIONS OF SUCH WAIVERS, (iii) IT MAKES SUCH WAIVERS
VOLUNTARILY, AND (iv) IT HAS BEEN INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG
OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION 9.13.

         SECTION 9.14 Good Faith Covenant. The Parties agree that their actions
and dealings with each other pursuant to this Agreement shall be subject to an
express covenant of good faith and fair dealing.

         SECTION 9.15 Buyer Obligations. Any obligations of the Buyer under this
Agreement may be satisfied or performed by an Affiliate of the Buyer.

         SECTION 9.16 Dispute Resolution. Prior to instituting any litigation or
other dispute resolution in connection with this Agreement, the Parties will
attempt in good faith to resolve any dispute or claim by referring any such
matter, within ten (10) days of written notice of any such dispute or claim, to
one of their respective executive officers for resolution. The executive
officers of the Parties shall attempt to resolve the dispute or claim within
thirty (30) days thereafter.

                                       64



         SECTION 9.17 Change in Law. If and to the extent that any Laws or
regulations that govern any aspect of this Agreement shall change, so as to make
any aspect of this transaction unlawful or unpracticable, then the Parties shall
endeavor, to the extent reasonably possible, to enter into such amendments to
this Agreement as may be reasonably necessary for this Agreement to accommodate
any such legal or regulatory changes, without materially changing the overall
benefits or consideration expected hereunder by either Party.

         SECTION 9.18 Time is of the Essence; Action on a Business Day. Time is
of the essence under this Agreement. If the date specified in this Agreement for
the giving of any notice or the taking of any action is not a Business Day (or
if the period during which any notice is required to be given or any action
taken expires on a date which is not a Business Day), then the date for giving
such notice or taking such action (and the expiration date of such period during
which notice is required to be given or action taken) shall be the next day
which is a Business Day.

                           [intentionally left blank]


                                       65



         IN WITNESS WHEREOF, the Parties hereto have duly executed this
Agreement or have caused this Agreement to be duly executed by their respective
authorized officers as of the day and year first above written.

                                   BUYER

                                   EXELON GENERATION COMPANY, LLC


                                   By:
                                      ------------------------------------------
                                   Name:
                                   Title:

                                   SELLER

                                   BRITISH ENERGY INVESTMENT LTD.


                                   By:
                                      ------------------------------------------
                                   Name:
                                   Title:






                                       66

Exhibit 31-1

            CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) 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 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
     report;

3.   Based on my knowledge, the financial statements, and other financial
     information included in this 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 report;

4.   The registrant's other certifying officer and I are responsible for
     establishing and maintaining disclosure controls and procedures (as defined
     in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

     (a)  Designed  such  disclosure  controls  and  procedures,  or caused such
          disclosure   controls  and   procedures  to  be  designed   under  our
          supervision,  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 report is being prepared;

     (b)  Evaluated the  effectiveness of the registrant's  disclosure  controls
          and procedures and presented in this report our conclusions  about the
          effectiveness of the disclosure controls and procedures, as of the end
          of the period covered by this report based on such evaluation; and

     (c)  Disclosed  in this  report  any  change in the  registrant's  internal
          control over financial reporting that occurred during the registrant's
          most  recent  fiscal  quarter  that  has  materially  affected,  or is
          reasonably  likely to materially  affect,  the  registrant's  internal
          control over financial reporting; and

5.   The registrant's other certifying officer and I have disclosed, based on
     our most recent evaluation of internal control over financial reporting, to
     the registrant's auditors and the audit committee of the registrant's board
     of directors (or persons performing the equivalent functions):

     (a)  All significant  deficiencies and material weaknesses in the design or
          operation  of internal  control  over  financial  reporting  which are
          reasonably  likely to  adversely  affect the  registrant's  ability to
          record, process, summarize and report financial information; and

     (b)  Any fraud, whether or not material,  that involves management or other
          employees who have a  significant  role in the  registrant's  internal
          control over financial reporting.

     Date:        October 29, 2003          /s/ John W. Rowe
                                            ---------------------------
                                            Chairman and Chief Executive Officer
                                            (Principal Executive Officer)




Exhibit 31-2

            CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF
                     THE SECURITIES AND EXCHANGE ACT OF 1934

I, Robert S. Shapard, certify that:

1.   I have reviewed this report on Form 10-Q of Exelon Corporation;

2.   Based on my knowledge, this 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
     report;

3.   Based on my knowledge, the financial statements, and other financial
     information included in this 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 report;

4.   The registrant's other certifying officer and I are responsible for
     establishing and maintaining disclosure controls and procedures (as defined
     in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

     (a)  Designed  such  disclosure  controls  and  procedures,  or caused such
          disclosure   controls  and   procedures  to  be  designed   under  our
          supervision,  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 report is being prepared;

     (b)  Evaluated the  effectiveness of the registrant's  disclosure  controls
          and procedures and presented in this report our conclusions  about the
          effectiveness of the disclosure controls and procedures, as of the end
          of the period covered by this report based on such evaluation; and

     (c)  Disclosed  in this  report  any  change in the  registrant's  internal
          control over financial reporting that occurred during the registrant's
          most  recent  fiscal  quarter  that  has  materially  affected,  or is
          reasonably  likely to materially  affect,  the  registrant's  internal
          control over financial reporting; and

5.   The registrant's other certifying officer and I have disclosed, based on
     our most recent evaluation of internal control over financial reporting, to
     the registrant's auditors and the audit committee of the registrant's board
     of directors (or persons performing the equivalent functions):

     (a)  All significant  deficiencies and material weaknesses in the design or
          operation  of internal  control  over  financial  reporting  which are
          reasonably  likely to  adversely  affect the  registrant's  ability to
          record, process, summarize and report financial information; and

     (b)  Any fraud, whether or not material,  that involves management or other
          employees who have a  significant  role in the  registrant's  internal
          control over financial reporting.


     Date: October 29, 2003       /s/ Robert S. Shapard
                                  -----------------------------------
                                  Executive Vice President and
                                  Chief Financial Officer
                                  (Principal Financial Officer)


Exhibit 31-3

            CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF
                     THE SECURITIES AND EXCHANGE ACT OF 1934

I, Michael B. Bemis, certify that:

1.   I have reviewed this quarterly report on Form 10-Q of Commonwealth Edison
     Company;

2.   Based on my knowledge, this 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
     report;

3.   Based on my knowledge, the financial statements, and other financial
     information included in this 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 report;

4.   The registrant's other certifying officer and I are responsible for
     establishing and maintaining disclosure controls and procedures (as defined
     in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

     (a)  Designed  such  disclosure  controls  and  procedures,  or caused such
          disclosure   controls  and   procedures  to  be  designed   under  our
          supervision,  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 report is being prepared;

     (b)  Evaluated the  effectiveness of the registrant's  disclosure  controls
          and procedures and presented in this report our conclusions  about the
          effectiveness of the disclosure controls and procedures, as of the end
          of the period covered by this report based on such evaluation; and

     (c)  Disclosed  in this  report  any  change in the  registrant's  internal
          control over financial reporting that occurred during the registrant's
          most  recent  fiscal  quarter  that  has  materially  affected,  or is
          reasonably  likely to materially  affect,  the  registrant's  internal
          control over financial reporting; and

5.   The registrant's other certifying officer and I have disclosed, based on
     our most recent evaluation of internal control over financial reporting, to
     the registrant's auditors and the audit committee of the registrant's board
     of directors (or persons performing the equivalent functions):

     (a)  All significant  deficiencies and material weaknesses in the design or
          operation  of internal  control  over  financial  reporting  which are
          reasonably  likely to  adversely  affect the  registrant's  ability to
          record, process, summarize and report financial information; and

     (b)  Any fraud, whether or not material,  that involves management or other
          employees who have a  significant  role in the  registrant's  internal
          control over financial reporting.

     Date:  October 29, 2003          /s/ Michael B. Bemis
                                      ------------------------------------
                                      President, Exelon Energy Delivery
                                      (Principal Executive Officer)

Exhibit 31-4

            CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF
                     THE SECURITIES AND EXCHANGE ACT OF 1934

I, Robert S. Shapard, certify that:

1.   I have reviewed this quarterly  report on Form 10-Q of Commonwealth  Edison
     Company;

2.   Based on my knowledge, this 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
     report;

3.   Based on my knowledge, the financial statements, and other financial
     information included in this 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 report;

4.   The registrant's other certifying officer and I are responsible for
     establishing and maintaining disclosure controls and procedures (as defined
     in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

     (a)  Designed  such  disclosure  controls  and  procedures,  or caused such
          disclosure   controls  and   procedures  to  be  designed   under  our
          supervision,  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 report is being prepared;

     (b)  Evaluated the  effectiveness of the registrant's  disclosure  controls
          and procedures and presented in this report our conclusions  about the
          effectiveness of the disclosure controls and procedures, as of the end
          of the period covered by this report based on such evaluation; and

     (c)  Disclosed  in this  report  any  change in the  registrant's  internal
          control over financial reporting that occurred during the registrant's
          most  recent  fiscal  quarter  that  has  materially  affected,  or is
          reasonably  likely to materially  affect,  the  registrant's  internal
          control over financial reporting; and

5.   The registrant's other certifying officer and I have disclosed, based on
     our most recent evaluation of internal control over financial reporting, to
     the registrant's auditors and the audit committee of the registrant's board
     of directors (or persons performing the equivalent functions):

     (a)  All significant  deficiencies and material weaknesses in the design or
          operation  of internal  control  over  financial  reporting  which are
          reasonably  likely to  adversely  affect the  registrant's  ability to
          record, process, summarize and report financial information; and

     (b)  Any fraud, whether or not material,  that involves management or other
          employees who have a  significant  role in the  registrant's  internal
          control over financial reporting.

     Date: October 29, 2003         /s/ Robert S. Shapard
                                    -----------------------------------
                                    Executive Vice President and
                                    Chief Financial Officer, Exelon
                                    (Principal Financial Officer)


Exhibit 31-5

            CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF
                     THE SECURITIES AND EXCHANGE ACT OF 1934

I, Michael B. Bemis, certify that:

1.   I have reviewed this quarterly report on Form 10-Q of PECO Energy Company;

2.   Based on my knowledge, this 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
     report;

3.   Based on my knowledge, the financial statements, and other financial
     information included in this 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 report;

4.   The registrant's other certifying officer and I are responsible for
     establishing and maintaining disclosure controls and procedures (as defined
     in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

     (a)  Designed  such  disclosure  controls  and  procedures,  or caused such
          disclosure   controls  and   procedures  to  be  designed   under  our
          supervision,  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 report is being prepared;

     (b)  Evaluated the  effectiveness of the registrant's  disclosure  controls
          and procedures and presented in this report our conclusions  about the
          effectiveness of the disclosure controls and procedures, as of the end
          of the period covered by this report based on such evaluation; and

     (c)  Disclosed  in this  report  any  change in the  registrant's  internal
          control over financial reporting that occurred during the registrant's
          most  recent  fiscal  quarter  that  has  materially  affected,  or is
          reasonably  likely to materially  affect,  the  registrant's  internal
          control over financial reporting; and

5.   The registrant's other certifying officer and I have disclosed, based on
     our most recent evaluation of internal control over financial reporting, to
     the registrant's auditors and the audit committee of the registrant's board
     of directors (or persons performing the equivalent functions):

     (a)  All significant  deficiencies and material weaknesses in the design or
          operation  of internal  control  over  financial  reporting  which are
          reasonably  likely to  adversely  affect the  registrant's  ability to
          record, process, summarize and report financial information; and

     (b) Any fraud, whether or not material, that involves management or other
         employees who have a significant role in the registrant's internal
         control over financial reporting.

     Date: October 29, 2003                 /s/ Michael B. Bemis
                                            -----------------------------------
                                            President, Exelon Energy Delivery
                                            (Principal Executive Officer)

Exhibit 31-6

            CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF
                     THE SECURITIES AND EXCHANGE ACT OF 1934

I, Robert S. Shapard, certify that:

1.   I have reviewed this quarterly report on Form 10-Q of PECO Energy Company;

2.   Based on my knowledge, this 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
     report;

3.   Based on my knowledge, the financial statements, and other financial
     information included in this 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 report;

4.   The registrant's other certifying officer and I are responsible for
     establishing and maintaining disclosure controls and procedures (as defined
     in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

     (a)  Designed  such  disclosure  controls  and  procedures,  or caused such
          disclosure   controls  and   procedures  to  be  designed   under  our
          supervision,  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 report is being prepared;

     (b)  Evaluated the  effectiveness of the registrant's  disclosure  controls
          and procedures and presented in this report our conclusions  about the
          effectiveness of the disclosure controls and procedures, as of the end
          of the period covered by this report based on such evaluation; and

     (c)  Disclosed  in this  report  any  change in the  registrant's  internal
          control over financial reporting that occurred during the registrant's
          most  recent  fiscal  quarter  that  has  materially  affected,  or is
          reasonably  likely to materially  affect,  the  registrant's  internal
          control over financial reporting; and

5.   The registrant's other certifying officer and I have disclosed, based on
     our most recent evaluation of internal control over financial reporting, to
     the registrant's auditors and the audit committee of the registrant's board
     of directors (or persons performing the equivalent functions):

     (a)  All significant  deficiencies and material weaknesses in the design or
          operation  of internal  control  over  financial  reporting  which are
          reasonably  likely to  adversely  affect the  registrant's  ability to
          record, process, summarize and report financial information; and

     (b)  Any fraud, whether or not material,  that involves management or other
          employees who have a  significant  role in the  registrant's  internal
          control over financial reporting.

     Date: October 29, 2003         /s/ Robert S. Shapard
                                    -----------------------------------
                                    Executive Vice President and
                                    Chief Financial Officer, Exelon
                                    (Principal Financial Officer)



Exhibit 31-7

  CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) 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 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
     report;

3.   Based on my knowledge, the financial statements, and other financial
     information included in this 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 report;

4.   The registrant's other certifying officer and I are responsible for
     establishing and maintaining disclosure controls and procedures (as defined
     in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

     (a)  Designed  such  disclosure  controls  and  procedures,  or caused such
          disclosure   controls  and   procedures  to  be  designed   under  our
          supervision,  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 report is being prepared;

     (b)  Evaluated the  effectiveness of the registrant's  disclosure  controls
          and procedures and presented in this report our conclusions  about the
          effectiveness of the disclosure controls and procedures, as of the end
          of the period covered by this report based on such evaluation; and

     (c)  Disclosed  in this  report  any  change in the  registrant's  internal
          control over financial reporting that occurred during the registrant's
          most  recent  fiscal  quarter  that  has  materially  affected,  or is
          reasonably  likely to materially  affect,  the  registrant's  internal
          control over financial reporting; and

5.   The registrant's other certifying officer and I have disclosed, based on
     our most recent evaluation of internal control over financial reporting, to
     the registrant's auditors and the audit committee of the registrant's board
     of directors (or persons performing the equivalent functions):

     (a)  All significant  deficiencies and material weaknesses in the design or
          operation  of internal  control  over  financial  reporting  which are
          reasonably  likely to  adversely  affect the  registrant's  ability to
          record, process, summarize and report financial information; and

     (b)  Any fraud, whether or not material,  that involves management or other
          employees who have a  significant  role in the  registrant's  internal
          control over financial reporting.

     Date:  October 29, 2003              /s/ Oliver D. Kingsley Jr.
                                          ---------------------------
                                          Chief Executive Officer and President
                                          (Principal Executive Officer)

Exhibit 31-8

            CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF
                     THE SECURITIES AND EXCHANGE ACT OF 1934

I, Robert S. Shapard, certify that:

1.   I have reviewed this quarterly report on Form 10-Q of Exelon Generation
     Company, LLC;

2.   Based on my knowledge, this 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
     report;

3.   Based on my knowledge, the financial statements, and other financial
     information included in this 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 report;

4.   The registrant's other certifying officer and I are responsible for
     establishing and maintaining disclosure controls and procedures (as defined
     in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

     (a)  Designed  such  disclosure  controls  and  procedures,  or caused such
          disclosure   controls  and   procedures  to  be  designed   under  our
          supervision,  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 report is being prepared;

     (b)  Evaluated the  effectiveness of the registrant's  disclosure  controls
          and procedures and presented in this report our conclusions  about the
          effectiveness of the disclosure controls and procedures, as of the end
          of the period covered by this report based on such evaluation; and

     (c)  Disclosed  in this  report  any  change in the  registrant's  internal
          control over financial reporting that occurred during the registrant's
          most  recent  fiscal  quarter  that  has  materially  affected,  or is
          reasonably  likely to materially  affect,  the  registrant's  internal
          control over financial reporting; and

5.   The registrant's other certifying officer and I have disclosed, based on
     our most recent evaluation of internal control over financial reporting, to
     the registrant's auditors and the audit committee of the registrant's board
     of directors (or persons performing the equivalent functions):

     (a)  All significant  deficiencies and material weaknesses in the design or
          operation  of internal  control  over  financial  reporting  which are
          reasonably  likely to  adversely  affect the  registrant's  ability to
          record, process, summarize and report financial information; and

     (b)  Any fraud, whether or not material,  that involves management or other
          employees who have a  significant  role in the  registrant's  internal
          control over financial reporting.

     Date: October 29, 2003         /s/ Robert S. Shapard
                                    -----------------------------------
                                    Executive Vice President and
                                    Chief Financial Officer, Exelon
                                    (Principal Financial Officer)




Exhibit 32-1

              Certificate Pursuant to Section 1350 of Chapter 63 of
                          Title 18 United States Code

         The undersigned officer hereby certifies, as to the Quarterly Report on
     Form 10-Q of Exelon Corporation for the quarterly period ended September
     30, 2003, that (i) the report fully complies with the requirements of
     section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the
     information contained in the report fairly presents, in all material
     respects, the financial condition and results of operations of Exelon
     Corporation.


     Date:  October 29, 2003              /s/ John W. Rowe
                                          ----------------
                                          John W. Rowe
                                          Chairman and Chief Executive Officer

     Exhibit 32-2


              Certificate Pursuant to Section 1350 of Chapter 63 of
                          Title 18 United States Code

         The undersigned officer hereby certifies, as to the Quarterly Report on
     Form 10-Q of Exelon Corporation for the quarterly period ended September
     30, 2003, that (i) the report fully complies with the requirements of
     section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the
     information contained in the report fairly presents, in all material
     respects, the financial condition and results of operations of Exelon
     Corporation.


     Date:  October 29, 2003                  /s/ Robert S. Shapard
                                              ---------------------
                                              Robert S. Shapard
                                              Executive Vice President and
                                              Chief Financial Officer

     Exhibit 32-3

              Certificate Pursuant to Section 1350 of Chapter 63 of
                          Title 18 United States Code

         The undersigned officer hereby certifies, as to the Quarterly Report on
     Form 10-Q of Commonwealth Edison Company for the quarterly period ended
     September 30, 2003, that (i) the report fully complies with the
     requirements of section 13(a) or 15(d) of the Securities Exchange Act of
     1934, and (ii) the information contained in the report fairly presents, in
     all material respects, the financial condition and results of operations of
     Commonwealth Edison Company.


     Date:  October 29, 2003                  /s/ Michael B. Bemis
                                              --------------------
                                              Michael B. Bemis
                                              President
                                              Exelon Energy Delivery

     Exhibit 32-4

              Certificate Pursuant to Section 1350 of Chapter 63 of
                          Title 18 United States Code

         The undersigned officer hereby certifies, as to the Quarterly Report on
     Form 10-Q of Commonwealth Edison Company for the quarterly period ended
     September 30, 2003, that (i) the report fully complies with the
     requirements of section 13(a) or 15(d) of the Securities Exchange Act of
     1934, and (ii) the information contained in the report fairly presents, in
     all material respects, the financial condition and results of operations of
     Commonwealth Edison Company.


     Date:  October 29, 2003                  /s/ Robert S. Shapard
                                              ---------------------
                                              Robert S. Shapard
                                              Executive Vice President and
                                              Chief Financial Officer
                                              Exelon Corporation

     Exhibit 32-5

              Certificate Pursuant to Section 1350 of Chapter 63 of
                          Title 18 United States Code

         The undersigned officer hereby certifies, as to the Quarterly Report on
     Form 10-Q of PECO Energy Company for the quarterly period ended September
     30, 2003, that (i) the report fully complies with the requirements of
     section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the
     information contained in the report fairly presents, in all material
     respects, the financial condition and results of operations of PECO Energy
     Company.


     Date:  October 29, 2003                  /s/ Michael B. Bemis
                                              --------------------
                                              Michael B. Bemis
                                              President
                                              Exelon Energy Delivery

     Exhibit 32-6

              Certificate Pursuant to Section 1350 of Chapter 63 of
                          Title 18 United States Code

         The undersigned officer hereby certifies, as to the Quarterly Report on
     Form 10-Q of PECO Energy Company for the quarterly period ended September
     30, 2003, that (i) the report fully complies with the requirements of
     section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the
     information contained in the report fairly presents, in all material
     respects, the financial condition and results of operations of PECO Energy
     Company.


     Date:  October 29, 2003                  /s/ Robert S. Shapard
                                              ---------------------
                                              Robert S. Shapard
                                              Executive Vice President and
                                              Chief Financial Officer
                                              Exelon Corporation





     Exhibit 32-7

              Certificate Pursuant to Section 1350 of Chapter 63 of
                          Title 18 United States Code

         The undersigned officer hereby certifies, as to the Quarterly Report on
     Form 10-Q of Exelon Generation Company, LLC for the quarterly period ended
     September 30, 2003, that (i) the report fully complies with the
     requirements of section 13(a) or 15(d) of the Securities Exchange Act of
     1934, and (ii) the information contained in the report fairly presents, in
     all material respects, the financial condition and results of operations of
     Exelon Generation Company, LLC.


     Date:  October 29, 2003                  /s/ Oliver D. Kingsley Jr.
                                              --------------------------
                                              Oliver D. Kingsley Jr.
                                              Chief Executive Officer and
                                              President

     Exhibit 32-8

              Certificate Pursuant to Section 1350 of Chapter 63 of
                          Title 18 United States Code

         The undersigned officer hereby certifies, as to the Quarterly Report on
     Form 10-Q of Exelon Generation Company, LLC for the quarterly period ended
     September 30, 2003, that (i) the report fully complies with the
     requirements of section 13(a) or 15(d) of the Securities Exchange Act of
     1934, and (ii) the information contained in the report fairly presents, in
     all material respects, the financial condition and results of operations of
     Exelon Generation Company, LLC.


     Date:  October 29, 2003                  /s/ Robert S. Shapard
                                              ---------------------
                                              Robert S. Shapard
                                              Executive Vice President and
                                              Chief Financial Officer
                                              Exelon Corporation