10-Q 1 exelon10q.txt UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Quarterly Period Ended June 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 June 30, 2003 was: Exelon Corporation Common Stock, without par value 325,848,491 Commonwealth Edison Company Common Stock, $12.50 par value 127,016,429 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 61 Exelon Corporation 61 Commonwealth Edison Company 90 PECO Energy Company 105 Exelon Generation Company, LLC 120 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK 135 ITEM 4. CONTROLS AND PROCEDURES 147 PART II. OTHER INFORMATION 150 ITEM 1. LEGAL PROCEEDINGS 150 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 150 ITEM 5. OTHER INFORMATION 152 ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K 153 SIGNATURES 156
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 Corporation's website at www.exeloncorp.com. 3 PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS 4
EXELON CORPORATION ------------------ EXELON CORPORATION AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (Unaudited) Three Months Ended June 30, Six Months Ended June 30, --------------------------- ------------------------- (in millions, except per share data) 2003 2002 2003 2002 ------------------------------------------------------------------------------------------------------------------------- OPERATING REVENUES $ 3,721 $ 3,519 $ 7,795 $ 6,876 OPERATING EXPENSES Purchased power 746 699 1,586 1,311 Purchased power from unconsolidated affiliate 110 60 177 116 Fuel 531 364 1,356 860 Operating and maintenance 1,100 1,070 2,212 2,137 Depreciation and amortization 275 332 549 667 Taxes other than income 159 181 358 367 ------------------------------------------------------------------------------------------------------------------------- Total operating expenses 2,921 2,706 6,238 5,458 ------------------------------------------------------------------------------------------------------------------------- OPERATING INCOME 800 813 1,557 1,418 ------------------------------------------------------------------------------------------------------------------------- OTHER INCOME AND DEDUCTIONS Interest expense (220) (241) (443) (490) Distributions on preferred securities of subsidiaries (10) (11) (22) (23) Equity in earnings of unconsolidated affiliates 15 9 33 22 Other, net 9 194 (134) 222 ------------------------------------------------------------------------------------------------------------------------- Total other income and deductions (206) (49) (566) (269) ------------------------------------------------------------------------------------------------------------------------- INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES 594 764 991 1,149 INCOME TAXES 222 279 370 427 ------------------------------------------------------------------------------------------------------------------------- INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES 372 485 621 722 CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES (net of income taxes of $69 and $(90) for the six months ended June 30, 2003 and 2002, respectively) -- -- 112 (230) ------------------------------------------------------------------------------------------------------------------------- NET INCOME 372 485 733 492 ------------------------------------------------------------------------------------------------------------------------- OTHER COMPREHENSIVE INCOME (LOSS) (net of income taxes) Cash flow hedge adjustment 62 (16) (84) (68) Foreign currency translation adjustment 1 -- 2 -- Unrealized gain (loss) on marketable securities 3 (72) (2) (87) SFAS No. 143 transition adjustment -- -- 168 -- Interest in other comprehensive income (loss) of unconsolidated affiliates 17 (7) 8 (1) ------------------------------------------------------------------------------------------------------------------------- Total other comprehensive income (loss) 83 (95) 92 (156) ------------------------------------------------------------------------------------------------------------------------- TOTAL COMPREHENSIVE INCOME $ 455 $ 390 $ 825 $ 336 ========================================================================================================================= AVERAGE SHARES OF COMMON STOCK OUTSTANDING - Basic 325 322 324 322 ========================================================================================================================= AVERAGE SHARES OF COMMON STOCK OUTSTANDING - Diluted 327 324 327 324 ========================================================================================================================= EARNINGS PER AVERAGE COMMON SHARE: BASIC: Income before cumulative effect of changes in accounting principles $ 1.14 $ 1.50 $ 1.92 $ 2.24 Cumulative effect of changes in accounting principles -- -- 0.34 (0.71) ------------------------------------------------------------------------------------------------------------------------- Net income $ 1.14 $ 1.50 $ 2.26 $ 1.53 ------------------------------------------------------------------------------------------------------------------------- DILUTED: Income before cumulative effect of changes in accounting principles $ 1.14 $ 1.50 $ 1.90 $ 2.23 Cumulative effect of changes in accounting principles -- -- 0.34 (0.71) ------------------------------------------------------------------------------------------------------------------------- Net income $ 1.14 $ 1.50 $ 2.24 $ 1.52 ========================================================================================================================= DIVIDENDS PER COMMON SHARE $ 0.46 $ 0.44 $ 0.92 $ 0.88 =========================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements 5
EXELON CORPORATION AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Six Months Ended June 30, ------------------------- (in millions) 2003 2002 ----------------------------------------------------------------------------------------------------------------------- CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 733 $ 492 Adjustments to reconcile net income to net cash flows provided by operating activities: Depreciation, amortization and accretion, including nuclear fuel 846 848 Cumulative effect of changes in accounting principles (net of income taxes) (112) 230 Gain on sale of investments -- (199) Provision for uncollectible accounts 43 67 Deferred income taxes (100) (10) Equity in earnings of unconsolidated affiliates (33) (22) Impairment of investments 238 38 Impairment of goodwill and long-lived assets 53 -- Net realized (gains) losses on nuclear decommissioning trust funds (12) 21 Other operating activities 12 40 Changes in assets and liabilities: Accounts receivable 66 (281) Inventories (16) (3) Accounts payable, accrued expenses and other current liabilities (62) 364 Changes in payables and receivables from unconsolidated affiliates 19 12 Other current assets (214) (143) Deferred energy costs (24) 49 Pension and non-pension postretirement benefits obligations (146) 10 Other noncurrent assets and liabilities 1 125 ----------------------------------------------------------------------------------------------------------------------- Net cash flows provided by operating activities 1,292 1,638 ----------------------------------------------------------------------------------------------------------------------- CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures (1,019) (1,028) Proceeds from liquidated damages 86 -- Proceeds from nuclear decommissioning trust funds 1,262 889 Investment in nuclear decommissioning trust funds (1,368) (943) Note receivable from unconsolidated affiliate 35 (75) Proceeds from sale of investment 6 285 Acquisition of generating plants -- (443) Other investing activities 11 47 ----------------------------------------------------------------------------------------------------------------------- Net cash flows used in investing activities (987) (1,268) ----------------------------------------------------------------------------------------------------------------------- CASH FLOWS FROM FINANCING ACTIVITIES Issuance of long-term debt 1,813 701 Retirement of long-term debt (1,479) (697) Change in short-term debt (100) 110 Issuance of preferred securities of subsidiaries 300 -- Retirement of preferred securities of subsidiaries (300) -- Dividends paid on common stock (285) (280) Payment on acquisition note payable to Sithe Energies, Inc. (210) -- Proceeds from employee stock plans 91 60 Change in restricted cash (29) (26) Other financing activities (85) (10) ----------------------------------------------------------------------------------------------------------------------- Net cash flows used in financing activities (284) (142) ----------------------------------------------------------------------------------------------------------------------- INCREASE IN CASH AND CASH EQUIVALENTS 21 228 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 469 485 ----------------------------------------------------------------------------------------------------------------------- CASH AND CASH EQUIVALENTS INCLUDING CASH CLASSIFIED AS HELD FOR SALE 490 713 CASH CLASSIFIED AS HELD FOR SALE ON THE CONSOLIDATED BALANCE SHEET (26) -- ----------------------------------------------------------------------------------------------------------------------- CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 464 $ 713 ----------------------------------------------------------------------------------------------------------------------- See Condensed Combined Notes to Consolidated Financial Statements 6
EXELON CORPORATION AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (Unaudited) June 30, December 31, (in millions) 2003 2002 ----------------------------------------------------------------------------------------------------------------------- ASSETS CURRENT ASSETS Cash and cash equivalents $ 464 $ 469 Restricted cash 425 396 Accounts receivable, net Customer 1,903 2,076 Other 246 284 Receivable from unconsolidated affiliate -- 39 Inventories, at average cost Fossil fuel 172 175 Materials and supplies 309 306 Other 579 380 Assets held for sale 352 -- ----------------------------------------------------------------------------------------------------------------------- Total current assets 4,450 4,125 ----------------------------------------------------------------------------------------------------------------------- PROPERTY, PLANT AND EQUIPMENT, NET 20,323 17,126 DEFERRED DEBITS AND OTHER ASSETS Regulatory assets 5,414 5,993 Nuclear decommissioning trust funds 3,316 3,053 Investments 1,189 1,403 Goodwill 4,735 4,992 Other 861 793 ----------------------------------------------------------------------------------------------------------------------- Total deferred debits and other assets 15,515 16,234 ----------------------------------------------------------------------------------------------------------------------- TOTAL ASSETS $ 40,288 $ 37,485 =======================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements 7 EXELON CORPORATION AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (Unaudited)
June 30, December 31, (in millions) 2003 2002 ----------------------------------------------------------------------------------------------------------------------- LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES Notes payable $ 581 $ 681 Note payable to unconsolidated affiliate 326 534 Long-term debt due within one year 2,391 1,402 Accounts payable 1,762 1,607 Accrued expenses 1,205 1,354 Other 283 296 Liabilities held for sale 81 -- ----------------------------------------------------------------------------------------------------------------------- Total current liabilities 6,629 5,874 ----------------------------------------------------------------------------------------------------------------------- LONG-TERM DEBT 12,480 13,127 MANDATORILY REDEEMABLE PREFERRED SECURITIES 100 -- DEFERRED CREDITS AND OTHER LIABILITIES Deferred income taxes 3,973 3,702 Unamortized investment tax credits 295 301 Nuclear decommissioning liability for retired plants -- 1,395 Asset retirement obligation 2,444 -- Pension obligation 1,747 1,959 Non-pension postretirement benefits obligation 943 877 Spent nuclear fuel obligation 863 858 Regulatory liabilities 810 -- Other 1,037 978 ----------------------------------------------------------------------------------------------------------------------- Total deferred credits and other liabilities 12,112 10,070 ----------------------------------------------------------------------------------------------------------------------- COMMITMENTS AND CONTINGENCIES MINORITY INTEREST OF CONSOLIDATED SUBSIDIARIES 79 77 PREFERRED SECURITIES OF SUBSIDIARIES 510 595 SHAREHOLDERS' EQUITY Common stock 7,169 7,059 Deferred compensation -- (1) Retained earnings 2,475 2,042 Accumulated other comprehensive income (loss) (1,266) (1,358) ----------------------------------------------------------------------------------------------------------------------- Total shareholders' equity 8,378 7,742 ----------------------------------------------------------------------------------------------------------------------- TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 40,288 $ 37,485 ======================================================================================================================= See Condensed Combined Notes to Consolidated Financial Statements
8 COMMONWEALTH EDISON COMPANY ---------------------------
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (Unaudited) Three Months Ended June 30, Six Months Ended June 30, -------------------------- ------------------------- (in millions) 2003 2002 2003 2002 --------------------------------------------------------------------------------------------------------------------------- OPERATING REVENUES Operating revenues $ 1,345 $ 1,469 $ 2,756 $ 2,773 Operating revenues from affiliates 16 12 29 23 --------------------------------------------------------------------------------------------------------------------------- Total operating revenues 1,361 1,481 2,785 2,796 --------------------------------------------------------------------------------------------------------------------------- OPERATING EXPENSES Purchased power 5 6 11 12 Purchased power from affiliate 528 547 1,099 1,079 Operating and maintenance 193 191 425 386 Operating and maintenance from affiliates 28 29 58 71 Depreciation and amortization 96 133 190 268 Taxes other than income 68 73 148 146 --------------------------------------------------------------------------------------------------------------------------- Total operating expenses 918 979 1,931 1,962 --------------------------------------------------------------------------------------------------------------------------- OPERATING INCOME 443 502 854 834 --------------------------------------------------------------------------------------------------------------------------- OTHER INCOME AND DEDUCTIONS Interest expense (106) (127) (215) (252) Distributions on mandatorily redeemable preferred securities (6) (7) (14) (15) Interest income from affiliates 7 8 13 16 Other, net 5 6 21 13 --------------------------------------------------------------------------------------------------------------------------- Total other income and deductions (100) (120) (195) (238) --------------------------------------------------------------------------------------------------------------------------- INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE 343 382 659 596 INCOME TAXES 138 151 263 236 --------------------------------------------------------------------------------------------------------------------------- INCOME BEFORE CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE 205 231 396 360 CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE (net of income taxes of $0) -- -- 5 -- --------------------------------------------------------------------------------------------------------------------------- NET INCOME 205 231 401 360 --------------------------------------------------------------------------------------------------------------------------- OTHER COMPREHENSIVE INCOME (LOSS) (net of income taxes) Cash flow hedge adjustment (3) (9) 28 (6) Unrealized gain (loss) on marketable securities 1 (2) 1 (2) Foreign currency translation adjustment 1 -- 2 -- --------------------------------------------------------------------------------------------------------------------------- Total other comprehensive income (loss) (1) (11) 31 (8) --------------------------------------------------------------------------------------------------------------------------- TOTAL COMPREHENSIVE INCOME $ 204 $ 220 $ 432 $ 352 =========================================================================================================================== See Condensed Combined Notes to Consolidated Financial Statements 9 COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Six Months Ended June 30, ------------------------- (in millions) 2003 2002 ------------------------------------------------------------------------------------------------------------------------- CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 401 $ 360 Adjustments to reconcile net income to net cash flows provided by operating activities: Depreciation and amortization 190 268 Cumulative effect of a change in accounting principle (net of income taxes) (5) -- Provision for uncollectible accounts 20 11 Deferred income taxes 60 75 Other operating activities 25 29 Changes in assets and liabilities: Accounts receivable 9 (158) Inventories 2 -- Accounts payable, accrued expenses and other current liabilities (115) 51 Changes in receivables and payables to affiliates (94) 63 Other current assets (2) (1) Pension and non-pension postretirement benefits obligations (72) 15 Other noncurrent assets and liabilities 11 27 ------------------------------------------------------------------------------------------------------------------------- Net cash flows provided by operating activities 430 740 ------------------------------------------------------------------------------------------------------------------------- CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures (355) (372) Notes receivable from affiliates (165) 13 Other investing activities 14 7 ------------------------------------------------------------------------------------------------------------------------- Net cash flows used in investing activities (506) (352) ------------------------------------------------------------------------------------------------------------------------- CASH FLOWS FROM FINANCING ACTIVITIES Issuance of long-term debt 1,135 701 Retirement of long-term debt (662) (481) Issuance of mandatorily redeemable preferred securities 200 -- Retirement of mandatorily redeemable preferred securities (200) -- Change in short-term debt (71) -- Dividends paid on common stock (211) (235) Change in restricted cash (18) (32) Settlement of cash flow hedges (51) (10) Other financing activities (28) -- ------------------------------------------------------------------------------------------------------------------------- Net cash flows provided by (used in) financing activities 94 (57) --------------------------------------------------------------------------------------------------------------------------- INCREASE IN CASH AND CASH EQUIVALENTS 18 331 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 16 23 ------------------------------------------------------------------------------------------------------------------------- CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 34 $ 354 ========================================================================================================================= 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
10
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (Unaudited) June 30, December 31, (in millions) 2003 2002 ------------------------------------------------------------------------------------------------------------------------- ASSETS CURRENT ASSETS Cash and cash equivalents $ 34 $ 16 Restricted cash 83 65 Accounts receivable, net Customer 747 782 Other 78 72 Inventories, at average cost 63 65 Deferred income taxes 19 20 Receivables from affiliates 177 15 Other 16 14 ------------------------------------------------------------------------------------------------------------------------- Total current assets 1,217 1,049 ------------------------------------------------------------------------------------------------------------------------- PROPERTY, PLANT AND EQUIPMENT, NET 7,944 7,756 DEFERRED DEBITS AND OTHER ASSETS Regulatory assets -- 447 Investments 35 42 Goodwill 4,711 4,916 Receivables from affiliates 2,397 1,300 Other 373 320 ------------------------------------------------------------------------------------------------------------------------- Total deferred debits and other assets 7,516 7,025 ------------------------------------------------------------------------------------------------------------------------- TOTAL ASSETS $ 16,677 $ 15,830 =========================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements 11
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (Unaudited) June 30, December 31, (in millions) 2003 2002 ------------------------------------------------------------------------------------------------------------------------- LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES Notes payable $ -- $ 71 Long-term debt due within one year 869 698 Accounts payable 158 201 Accrued expenses 456 538 Payables to affiliates 209 416 Customer deposits 79 81 Other 19 18 ------------------------------------------------------------------------------------------------------------------------- Total current liabilities 1,790 2,023 ------------------------------------------------------------------------------------------------------------------------- LONG-TERM DEBT 5,584 5,268 DEFERRED CREDITS AND OTHER LIABILITIES Deferred income taxes 1,741 1,650 Unamortized investment tax credits 50 51 Pension obligation 1 91 Non-pension postretirement benefits obligation 156 138 Payables to affiliates 26 224 Regulatory liabilities 810 -- Other 345 297 ------------------------------------------------------------------------------------------------------------------------- Total deferred credits and other liabilities 3,129 2,451 ------------------------------------------------------------------------------------------------------------------------- COMMITMENTS AND CONTINGENCIES MANDATORILY REDEEMABLE PREFERRED SECURITIES 344 330 SHAREHOLDERS' EQUITY Common stock 1,588 1,588 Preference stock 7 7 Other paid in capital 4,029 4,239 Receivable from parent (554) (615) Retained earnings 767 577 Accumulated other comprehensive income (loss) (7) (38) ------------------------------------------------------------------------------------------------------------------------- Total shareholders' equity 5,830 5,758 ------------------------------------------------------------------------------------------------------------------------- TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 16,677 $ 15,830 =========================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements 12
PECO ENERGY COMPANY ------------------- PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (Unaudited) Three Months Ended June 30, Six Months Ended June 30, --------------------------- ------------------------ (in millions) 2003 2002 2003 2002 ----------------------------------------------------------------------------------------------------------------------- OPERATING REVENUES Operating revenues $ 958 $ 992 $ 2,173 $ 2,008 Operating revenues from affiliates 3 3 5 7 ----------------------------------------------------------------------------------------------------------------------- Total operating revenues 961 995 2,178 2,015 ----------------------------------------------------------------------------------------------------------------------- OPERATING EXPENSES Purchased power 62 59 127 107 Purchased power from affiliate 324 346 681 649 Fuel 67 53 257 188 Operating and maintenance 110 114 236 225 Operating and maintenance from affiliates 11 17 25 42 Depreciation and amortization 116 109 236 221 Taxes other than income 47 63 110 122 ----------------------------------------------------------------------------------------------------------------------- Total operating expenses 737 761 1,672 1,554 ----------------------------------------------------------------------------------------------------------------------- OPERATING INCOME 224 234 506 461 ----------------------------------------------------------------------------------------------------------------------- OTHER INCOME AND DEDUCTIONS Interest expense (83) (92) (168) (187) Distributions on mandatorily redeemable preferred securities (2) (2) (5) (5) Other, net 1 2 10 2 ----------------------------------------------------------------------------------------------------------------------- Total other income and deductions (84) (92) (163) (190) ----------------------------------------------------------------------------------------------------------------------- INCOME BEFORE INCOME TAXES 140 142 343 271 INCOME TAXES 52 49 119 90 ----------------------------------------------------------------------------------------------------------------------- NET INCOME 88 93 224 181 Preferred stock dividends (2) (2) (3) (4) ----------------------------------------------------------------------------------------------------------------------- NET INCOME ON COMMON STOCK $ 86 $ 91 $ 221 $ 177 ======================================================================================================================= OTHER COMPREHENSIVE INCOME (LOSS) (net of income taxes) Net income $ 88 $ 93 $ 224 $ 181 Other comprehensive income (loss) (net of income taxes): Cash flow hedge adjustment -- (6) -- (4) ----------------------------------------------------------------------------------------------------------------------- Total other comprehensive income (loss) -- (6) -- (4) ----------------------------------------------------------------------------------------------------------------------- TOTAL COMPREHENSIVE INCOME $ 88 $ 87 $ 224 $ 177 ======================================================================================================================= See Condensed Combined Notes to Consolidated Financial Statements
13
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Six Months Ended June 30, ------------------------- (in millions) 2003 2002 ----------------------------------------------------------------------------------------------------------------------- CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 224 $ 181 Adjustments to reconcile net income to net cash flows provided by operating activities: Depreciation and amortization 236 221 Provision for uncollectible accounts 21 32 Deferred income taxes (28) (19) Other operating activities 5 -- Changes in assets and liabilities: Accounts receivable 48 (4) Changes in receivables and payables to affiliates 27 34 Inventories (1) 14 Accounts payable, accrued expenses and other current liabilities 11 44 Prepaid taxes (91) (98) Deferred energy costs (24) 49 Other current assets (4) (3) Pension and non-pension postretirement benefits obligations 16 8 Other noncurrent assets and liabilities (15) 9 ----------------------------------------------------------------------------------------------------------------------- Net cash flows provided by operating activities 425 468 ----------------------------------------------------------------------------------------------------------------------- CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures (132) (132) Other investing activities 6 10 ----------------------------------------------------------------------------------------------------------------------- Net cash flows used in investing activities (126) (122) ----------------------------------------------------------------------------------------------------------------------- CASH FLOWS FROM FINANCING ACTIVITIES Issuance of long-term debt 450 -- Issuance of mandatorily redeemable preferred securities 100 -- Retirement of long-term debt (592) (207) Retirement of mandatorily redeemable preferred securities (50) -- Retirement of preferred stock (50) -- Change in short-term debt (30) 74 Dividends paid on preferred and common stock (168) (174) Contribution from parent 17 -- Change in restricted cash 28 1 Other financing activities (6) -- ----------------------------------------------------------------------------------------------------------------------- Net cash flows used in financing activities (301) (306) ----------------------------------------------------------------------------------------------------------------------- INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (2) 40 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 63 32 ----------------------------------------------------------------------------------------------------------------------- CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 61 $ 72 ======================================================================================================================= See Condensed Combined Notes to Consolidated Financial Statements
14
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (Unaudited) June 30, December 31, (in millions) 2003 2002 ----------------------------------------------------------------------------------------------------------------------- ASSETS CURRENT ASSETS Cash and cash equivalents $ 61 $ 63 Restricted cash 303 331 Accounts receivable, net Customer 300 379 Other 51 39 Inventories, at average cost Fossil fuel 67 67 Materials and supplies 9 8 Deferred energy costs 55 31 Prepaid taxes 92 1 Other 10 8 ----------------------------------------------------------------------------------------------------------------------- Total current assets 948 927 ----------------------------------------------------------------------------------------------------------------------- PROPERTY, PLANT AND EQUIPMENT, NET 4,213 4,159 DEFERRED DEBITS AND OTHER ASSETS Regulatory assets 5,414 5,546 Investments 19 19 Prepaid pension asset 56 41 Other 22 28 ----------------------------------------------------------------------------------------------------------------------- Total deferred debits and other assets 5,511 5,634 ----------------------------------------------------------------------------------------------------------------------- TOTAL ASSETS $ 10,672 $ 10,720 ======================================================================================================================= See Condensed Combined Notes to Consolidated Financial Statements
15
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (Unaudited) June 30, December 31, (in millions) 2003 2002 ----------------------------------------------------------------------------------------------------------------------- LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES Notes payable $ 170 $ 200 Payables to affiliates 137 170 Long-term debt due within one year 264 689 Accounts payable 70 87 Accrued expenses 361 332 Deferred income taxes 27 27 Other 32 33 ----------------------------------------------------------------------------------------------------------------------- Total current liabilities 1,061 1,538 ----------------------------------------------------------------------------------------------------------------------- LONG-TERM DEBT 5,230 4,951 MANDATORILY REDEEMABLE PREFERRED SECURITIES 100 -- DEFERRED CREDITS AND OTHER LIABILITIES Deferred income taxes 2,891 2,903 Unamortized investment tax credits 23 24 Non-pension postretirement benefits obligation 282 251 Payable to affiliate 16 -- Other 149 164 ----------------------------------------------------------------------------------------------------------------------- Total deferred credits and other liabilities 3,361 3,342 ----------------------------------------------------------------------------------------------------------------------- COMMITMENTS AND CONTINGENCIES MANDATORILY REDEEMABLE PREFERRED SECURITIES 78 128 SHAREHOLDERS' EQUITY Common stock 1,993 1,976 Receivable from parent (1,698) (1,758) Preferred stock 87 137 Retained earnings 455 401 Accumulated other comprehensive income 5 5 ----------------------------------------------------------------------------------------------------------------------- Total shareholders' equity 842 761 ----------------------------------------------------------------------------------------------------------------------- TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 10,672 $ 10,720 =======================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements 16
EXELON GENERATION COMPANY, LLC ------------------------------ EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (Unaudited) Three Months Ended June 30, Six Months Ended June 30, --------------------------- -------------------------- (in millions) 2003 2002 2003 2002 ------------------------------------------------------------------------------------------------------------------------ OPERATING REVENUES Operating revenues $ 990 $ 606 $ 1,876 $ 1,175 Operating revenues from affiliates 896 953 1,889 1,845 ------------------------------------------------------------------------------------------------------------------------ Total operating revenues 1,886 1,559 3,765 3,020 ------------------------------------------------------------------------------------------------------------------------ OPERATING EXPENSES Purchased power 675 634 1,436 1,186 Purchased power from affiliates 125 71 206 137 Fuel 348 224 706 433 Operating and maintenance 411 374 861 750 Operating and maintenance from affiliates 40 37 82 94 Depreciation and amortization 46 65 91 128 Taxes other than income 40 41 88 90 ------------------------------------------------------------------------------------------------------------------------ Total operating expenses 1,685 1,446 3,470 2,818 ------------------------------------------------------------------------------------------------------------------------ OPERATING INCOME 201 113 295 202 ------------------------------------------------------------------------------------------------------------------------ OTHER INCOME AND DEDUCTIONS Interest expense (16) (10) (30) (27) Interest expense - affiliates (4) (1) (8) (1) Equity in earnings of unconsolidated affiliates 18 9 37 32 Other, net 34 24 (134) 40 ------------------------------------------------------------------------------------------------------------------------ Total other income and deductions 32 22 (135) 44 ------------------------------------------------------------------------------------------------------------------------ INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES 233 135 160 246 INCOME TAXES 91 51 71 96 ------------------------------------------------------------------------------------------------------------------------ INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES 142 84 89 150 CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES (net of income taxes of $70 and $9 for the six months ended June 30, 2003 and 2002, respectively) -- -- 108 13 ------------------------------------------------------------------------------------------------------------------------ NET INCOME 142 84 197 163 ------------------------------------------------------------------------------------------------------------------------ OTHER COMPREHENSIVE INCOME (LOSS) (net of income taxes) Unrealized gain (loss) on marketable securities 2 (74) (3) (83) SFAS No. 143 transition adjustment -- -- 168 -- Cash flow hedge adjustment 64 6 (116) (67) Interest in other comprehensive income (loss) of unconsolidated affiliates 17 (7) 8 (1) ------------------------------------------------------------------------------------------------------------------------ Total other comprehensive income (loss) 83 (75) 57 (151) ------------------------------------------------------------------------------------------------------------------------ TOTAL COMPREHENSIVE INCOME $ 225 $ 9 $ 254 $ 12 ======================================================================================================================== See Condensed Combined Notes to Consolidated Financial Statements
17
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Six Months Ended June 30, ------------------------- (in millions) 2003 2002 ------------------------------------------------------------------------------------------------------------------------ CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 197 $ 163 Adjustments to reconcile net income to net cash flows provided by operating activities: Depreciation, amortization and accretion, including nuclear fuel 388 312 Cumulative effect of changes in accounting principles (net of income taxes) (108) (13) Provision for uncollectible accounts 1 17 Deferred income taxes (107) (4) Equity in earnings of unconsolidated affiliates (37) (32) Impairment of investment 200 -- Impairment of long-lived assets 5 -- Net realized (gains) losses on nuclear decommissioning trust funds (12) 21 Other operating activities (39) 53 Changes in assets and liabilities: Accounts receivable (116) (136) Changes in receivables and payables to affiliates, net 238 (93) Inventories (19) (15) Accounts payable, accrued expenses and other current liabilities 91 307 Other current assets (104) (87) Pension and non-pension postretirement benefits obligations (59) (4) Other noncurrent assets and liabilities 20 30 ------------------------------------------------------------------------------------------------------------------------ Net cash flows provided by operating activities 539 519 ------------------------------------------------------------------------------------------------------------------------ CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures (510) (475) Proceeds from liquidated damages 86 -- Proceeds from nuclear decommissioning trust funds 1,262 889 Investment in nuclear decommissioning trust funds (1,368) (943) Note receivable from unconsolidated affiliate 35 (75) Acquisition of generating plants -- (443) Other investing activities (1) (1) ------------------------------------------------------------------------------------------------------------------------ Net cash flows used in investing activities (496) (1,048) ------------------------------------------------------------------------------------------------------------------------ CASH FLOWS FROM FINANCING ACTIVITIES Issuance of long-term debt 211 -- Retirement of long-term debt (3) (2) Payment on acquisition note payable to Sithe Energies, Inc. (210) -- Change in payables to affiliates 58 331 Distribution to member (45) -- Change in restricted cash (38) -- ------------------------------------------------------------------------------------------------------------------------ Net cash flows (used in) provided by financing activities (27) 329 ------------------------------------------------------------------------------------------------------------------------ INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 16 (200) CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 58 224 ------------------------------------------------------------------------------------------------------------------------ CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 74 $ 24 ======================================================================================================================== 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) June 30, December 31, (in millions) 2003 2002 ------------------------------------------------------------------------------------------------------------------------ ASSETS CURRENT ASSETS Cash and cash equivalents $ 74 $ 58 Restricted cash 38 -- Accounts receivable, net Customer 656 587 Other 83 57 Receivables from affiliates 334 594 Inventories, at average cost Fossil fuel 96 97 Materials and supplies 235 217 Deferred income taxes 7 7 Other 288 188 ------------------------------------------------------------------------------------------------------------------------ Total current assets 1,811 1,805 ------------------------------------------------------------------------------------------------------------------------ PROPERTY, PLANT AND EQUIPMENT, NET 7,884 4,800 DEFERRED DEBITS AND OTHER ASSETS Nuclear decommissioning trust funds 3,316 3,053 Investments 484 657 Receivable from affiliate 35 220 Deferred income taxes 102 271 Prepaid pension asset 55 -- Other 226 201 ------------------------------------------------------------------------------------------------------------------------ Total deferred debits and other assets 4,218 4,402 ------------------------------------------------------------------------------------------------------------------------ TOTAL ASSETS $ 13,913 $ 11,007 ========================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements 19
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (Unaudited) June 30, December 31, (in millions) 2003 2002 ------------------------------------------------------------------------------------------------------------------------ LIABILITIES AND MEMBER'S EQUITY CURRENT LIABILITIES Long-term debt due within one year $ 1,252 $ 5 Accounts payable 1,408 1,126 Payables to affiliates 45 10 Notes payable to affiliates 717 863 Accrued expenses 431 482 Other 93 108 ------------------------------------------------------------------------------------------------------------------------ Total current liabilities 3,946 2,594 ------------------------------------------------------------------------------------------------------------------------ LONG-TERM DEBT 1,111 2,132 DEFERRED CREDITS AND OTHER LIABILITIES Unamortized investment tax credits 222 226 Nuclear decommissioning liability for retired plants -- 1,395 Asset retirement obligation 2,440 -- Pension obligation -- 37 Non-pension postretirement benefits obligation 443 410 Spent nuclear fuel obligation 863 858 Payable to affiliate 1,094 -- Other 438 402 ------------------------------------------------------------------------------------------------------------------------ Total deferred credits and other liabilities 5,500 3,328 ------------------------------------------------------------------------------------------------------------------------ COMMITMENTS AND CONTINGENCIES MINORITY INTEREST OF CONSOLIDATED SUBSIDIARY 54 54 MEMBER'S EQUITY Membership interest 2,489 2,296 Undistributed earnings 1,077 924 Accumulated other comprehensive income (loss) (264) (321) ------------------------------------------------------------------------------------------------------------------------ Total member's equity 3,302 2,899 ------------------------------------------------------------------------------------------------------------------------ TOTAL LIABILITIES AND MEMBER'S EQUITY $ 13,913 $ 11,007 ========================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements 20 EXELON CORPORATION AND SUBSIDIARY COMPANIES COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES CONDENSED COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in millions, except per share data, unless otherwise noted) 1. BASIS OF PRESENTATION (Exelon, ComEd, PECO and Generation) The accompanying consolidated financial statements as of June 30, 2003 and for the three and six months then ended are unaudited, but in the opinion of management of Exelon Corporation (Exelon), Commonwealth Edison Company (ComEd), PECO Energy Company (PECO) and Exelon Generation Company, LLC (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 Report 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 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 lives projected to be from 2029 through 2056. These nuclear plants 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 of $3,316 million and $3,053 million as of June 30, 2003 and December 31, 2002, respectively, in trust accounts. Exelon and Generation anticipate that all trust fund assets will ultimately be used to decommission Generation's nuclear plants. 21 After considering interpretations of the transitional guidance included in SFAS No. 143, Exelon recorded income of $112 million (after income taxes) as a cumulative effect of a change in accounting principle in connection with its adoption of this standard in the first quarter of 2003. The components of the cumulative effect of a change in accounting principle, after income taxes, are 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. Accretion expense for the three months and six months ended June 30, 2003 for Exelon was $39 million and $78 million, respectively. Accretion expense for the three months and six months ended June 30, 2003 for Generation was $38 million and $77 million, respectively. The following table provides a reconciliation of the AROs reflected on the balance sheet at December 31, 2002 and June 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 ------------------------------------------------------------------------------- Decommissioning obligation at January 1, 2003 2,363 2,366 Accretion expense for six months ended June 30, 2003 77 78 ------------------------------------------------------------------------------- Asset retirement obligation at June 30, 2003 $2,440 $2,444 ================================================================================ 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 Exelon's decommissioning obligation at the time of adoption of SFAS No. 143. 22 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 six months ended June 30, 2002 adjusted as if SFAS No. 143 had been applied effective January 1, 2002.
Three Months Ended Six Months Ended June 30, 2002 June 30, 2002 --------------------------------------------------------------------------------------------------------------------------- Reported income before cumulative effect of changes in accounting principles $ 485 $ 722 Adjustment as if SFAS No. 143 had been applied effective January 1, 2002 10 20 --------------------------------------------------------------------------------------------------------------------------- Adjusted income before cumulative effect of changes in accounting principles $ 495 $ 742 =========================================================================================================================== Three Months Ended Six Months Ended June 30, 2002 June 30, 2002 --------------------------------------------------------------------------------------------------------------------------- Reported net income $ 485 $ 492 Adjustment as if SFAS No. 143 had been applied effective January 1, 2002: Adjustment to income before cumulative effect of changes in accounting principles 10 20 Cumulative effect of changes in accounting principles -- 132 --------------------------------------------------------------------------------------------------------------------------- Adjusted net income $ 495 $ 644 =========================================================================================================================== Three Months Ended June 30, 2002 -------------------------------- Basic earnings per common share: Reported Adjustment (1) Adjusted --------------------------------------------------------------------------------------------------------------------------- Income before cumulative effect of changes in accounting principles $ 1.50 $ 0.03 $ 1.53 Net income $ 1.50 $ 0.03 $ 1.53 --------------------------------------------------------------------------------------------------------------------------- Three Months Ended June 30, 2002 -------------------------------- Diluted earnings per common share: Reported Adjustment (1) Adjusted --------------------------------------------------------------------------------------------------------------------------- Income before cumulative effect of changes in accounting principles $ 1.50 $ 0.03 $ 1.53 Net income $ 1.50 $ 0.03 $ 1.53 --------------------------------------------------------------------------------------------------------------------------- (1) The adjustment represents the earnings impact as if SFAS No. 143 had been applied effective January 1, 2002. Six Months Ended June 30, 2002 ------------------------------ Basic earnings per common share: Reported Adjustment (1) Adjusted --------------------------------------------------------------------------------------------------------------------------- Income before cumulative effect of changes in accounting principles $ 2.24 $ 0.06 $ 2.30 Net income $ 1.53 $ 0.47 $ 2.00 --------------------------------------------------------------------------------------------------------------------------- 23 Six Months Ended June 30, 2002 ------------------------------ Diluted earnings per common share: Reported Adjustment (1) Adjusted --------------------------------------------------------------------------------------------------------------------------- Income before cumulative effect of changes in accounting principles $ 2.23 $ 0.06 $ 2.29 Net income $ 1.52 $ 0.47 $ 1.99 --------------------------------------------------------------------------------------------------------------------------- (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 June 30, 2003, the regulatory liability and corresponding receivable from Generation totaled $1,094 million. Exelon believes that all of the decommissioning assets, including up to $73 million of annual collections 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 June 30, 2003, the regulatory asset and corresponding payable to Generation totaled $16 million. Exelon believes that all of the decommissioning assets, including the $29 million of annual collections, 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. In accordance with regulatory accounting, the net plant balances of Exelon, ComEd and PECO include recoveries for removal costs, which are included as a component of accumulated depreciation. The adoption of SFAS No. 143 had no impact on the accounting for removal costs not associated with AROs. 24 Prior to the adoption of SFAS No. 143, Generation's accumulated depreciation included $2,845 million for decommissioning liabilities related to the active plants. This amount was reclassified to an ARO upon the adoption of SFAS No. 143. Additionally, Generation adjusted the total decommissioning liability for the ComEd plants to $1,575 million and for the PECO plants to $787 million. As described above, Generation recorded a payable to ComEd of $948 million and a receivable from PECO of $20 million. Generation also recorded an asset retirement cost asset (ARC) of $172 million related to the establishment of the PECO ARO in accordance with SFAS No. 143. The ARC will be amortized over the remaining lives of the plants. As discussed above, Exelon re-measured its 2001 decommissioning related balances associated with the Merger purchase price allocation at ComEd and the January 2001 corporate restructuring as if SFAS No. 143 had been in effect at the Merger Date. Exelon and ComEd concluded that had SFAS No. 143 been in effect, ComEd would not have recorded an impairment on its regulatory asset for decommissioning of its retired nuclear plants as a purchase price allocation adjustment in 2001 as a result of the December 2000 ICC order. Increased net assets would have been transferred to Generation by ComEd in the corporate restructuring. Accordingly, Exelon recorded a reduction of goodwill of approximately $210 million, with a corresponding reduction in its overall decommissioning obligation in connection with the implementation of SFAS No. 143 on January 1, 2003. Similarly, ComEd recorded a reduction of $210 million of goodwill and of shareholders' equity, and Generation recorded a $210 million increase in member's equity and a corresponding reduction of its decommissioning obligation. In addition, Exelon and ComEd recorded a cumulative effect of a change in accounting principle of $5 million to reverse goodwill amortization that had been recorded in 2001. Exelon and ComEd also reclassified a regulatory asset related to nuclear decommissioning costs for retired units of $248 million to regulatory liabilities. In accordance with the provisions of SFAS No. 143 and regulatory accounting guidance, Exelon and Generation recorded a SFAS No. 143 transition adjustment to accumulated other comprehensive income to reclassify $168 million of 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 six months ended June 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 Six Months Ended ComEd June 30, 2002 June 30, 2002 ------------------------------------------------------------------------------------------------------------- Reported net income $ 231 $ 360 Adjustment as if SFAS No. 143 had been applied effective January 1, 2002: Cumulative effect of changes in accounting principles -- 5 ------------------------------------------------------------------------------------------------------------- Adjusted net income $ 231 $ 365 ============================================================================================================= 25 Three Months Ended Six Months Ended Generation June 30, 2002 June 30, 2002 ------------------------------------------------------------------------------------------------------------ Reported income before cumulative effect of changes in accounting principles $ 84 $ 150 Adjustment as if SFAS No. 143 had been applied effective January 1, 2002 10 20 ------------------------------------------------------------------------------------------------------------ Adjusted income before cumulative effect of changes in accounting principles $ 94 $ 170 ============================================================================================================= Three Months Ended Six Months Ended Generation June 30, 2002 June 30, 2002 ------------------------------------------------------------------------------------------------------------ Reported net income $ 84 $ 163 Adjustment as if SFAS No. 143 had been applied effective January 1, 2002: Adjustment to income before cumulative effect of changes in accounting principles 10 20 Cumulative effect of changes in accounting principles -- 128 ------------------------------------------------------------------------------------------------------------ Adjusted net income $ 94 $ 311 =============================================================================================================
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 no earnings impact to Generation for as long as the trust assets exceed the decommissioning liabilities for the former ComEd plants. The above accounting practices are also applicable for former PECO plants owned by Generation. 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 of decommissioning costs, 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. 26 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 are 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 June 30, 2003, Exelon had goodwill of $4,735 million of which $4,711 million relates to ComEd and the remaining goodwill relates to Enterprises' reporting units. See Note 3 - Acquisitions, Dispositions and Retirements for a further discussion of Enterprises' goodwill. Consistent with SFAS No. 142, the remaining 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. The annual update impairment review during the fourth quarter of 2002 did not identify any goodwill impairment. 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 unaffected by the adoption SFAS No. 146. 27 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 six months ended June 30, 2003 are reflected in Note 8 - Commitments and Contingencies. 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 six months ended June 30, 2003 and 2002: 28
Exelon Three Months Ended June 30, --------------------------- 2003 2002 ------------------------------------------------------------------------------------------------------------ Net income - as reported $ 372 $ 485 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 $ 367 $ 477 ============================================================================================================ Earnings per share: Basic - as reported $ 1.14 $ 1.50 Basic - pro forma $ 1.13 $ 1.48 Diluted - as reported $ 1.14 $ 1.50 Diluted - pro forma $ 1.12 $ 1.47 ------------------------------------------------------------------------------------------------------------ Six Months Ended June 30, ------------------------- 2003 2002 ------------------------------------------------------------------------------------------------------------ Net income - as reported $ 733 $ 492 Deduct: Total stock-based compensation expense determined under fair value based method for all awards, net of income taxes (10) (17) ------------------------------------------------------------------------------------------------------------ Pro forma net income $ 723 $ 475 ============================================================================================================ Earnings per share: Basic - as reported $ 2.26 $ 1.53 Basic - pro forma $ 2.23 $ 1.48 Diluted - as reported $ 2.24 $ 1.52 Diluted - pro forma $ 2.21 $ 1.47 ------------------------------------------------------------------------------------------------------------ ComEd Three Months Ended June 30, ------------------------- 2003 2002 ------------------------------------------------------------------------------------------------------------ Net income - as reported $ 205 $ 231 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 $ 204 $ 228 ============================================================================================================ Six Months Ended June 30, ------------------------- 2003 2002 ------------------------------------------------------------------------------------------------------------ Net income - as reported $ 401 $ 360 Deduct: Total stock-based compensation expense determined under fair value based method for all awards, net of income taxes (2) (6) ------------------------------------------------------------------------------------------------------------ Pro forma net income $ 399 $ 354 ============================================================================================================
29
PECO Three Months Ended June 30, ------------------------- 2003 2002 ------------------------------------------------------------------------------------------------------------ Net income on common stock- as reported $ 86 $ 91 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 $ 85 $ 88 ============================================================================================================ Six Months Ended June 30, ------------------------- 2003 2002 ------------------------------------------------------------------------------------------------------------ Net income on common stock- as reported $ 221 $ 177 Deduct: Total stock-based compensation expense determined under fair value based method for all awards, net of income taxes (1) (7) ------------------------------------------------------------------------------------------------------------ Pro forma net income on common stock $ 220 $ 170 ============================================================================================================ Generation Three Months Ended June 30, ------------------------- 2003 2002 ------------------------------------------------------------------------------------------------------------ Net income - as reported $ 142 $ 84 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 $ 139 $ 80 ============================================================================================================ Six Months Ended June 30, ------------------------- 2003 2002 ------------------------------------------------------------------------------------------------------------ Net income - as reported $ 197 $ 163 Deduct: Total stock-based compensation expense determined under fair value based method for all awards, net of income taxes (5) (7) ------------------------------------------------------------------------------------------------------------ Pro forma net income $ 192 $ 156 ============================================================================================================
FIN No. 46 In January 2003, the FASB issued FIN No. 46, "Consolidation of Variable Interest Entities" (FIN No. 46). FIN No. 46 addresses consolidating certain variable interest entities and applies immediately to variable interest entities created after January 31, 2003. FIN No. 46 requires Exelon to consolidate pre-existing variable interest entities as of July 1, 2003. Based on management's interpretation of the provisions of FIN No. 46, it is reasonably possible that Generation will consolidate Sithe Energies, Inc. (Sithe) as of July 1, 2003. Generation is a 49.9% owner of Sithe and has accounted for this entity as an unconsolidated equity investment through June 30, 2003. Sithe owns and operates power generating facilities. Refer to Note 17 - Unconsolidated Equity Investments in Generation's Form 10-K for the year ended December 31, 2002 and Note 10 - Unconsolidated Investments for further information related to Generation's investment in Sithe. FIN No. 46 is a complex accounting standard and requires management to exercise judgment in analyzing entities with which Exelon and its 30 subsidiaries have business arrangements to determine if those entities are variable interest entities and, if so, whether consolidation is required. This accounting standard is the subject of continuing discussions by the FASB and others. The final determination of entities that may be considered variable interest entities will be completed in the third quarter of 2003. 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 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 is effective for contracts entered into or modified after June 30, 2003, except as stated below, and for hedging relationships designated after June 30, 2003. In addition, except as stated below, all provisions of SFAS No. 149 will be applied prospectively. The provisions of SFAS No. 149 that 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 will have 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. Most of the guidance in SFAS No. 150 is effective for all financial instruments entered into or modified after May 31, 2003, and otherwise is effective for Exelon as of July 1, 2003. During June 2003, PECO issued $100 million of trust preferred securities. These securities were recorded as liabilities (see Note 9 - Long-Term Debt and Preferred Securities). 31 Effective July 1, 2003, Exelon, ComEd and PECO will reclassify mandatorily redeemable shares that were issued prior to May 31, 2003 as liabilities on their respective balance sheets. The total amounts to be reclassified will be $422 million, $344 million and $78 million, respectively. The adoption of SFAS No. 150 will have no impact on Generation. Change in Accounting 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, after income taxes). As a result of the change, operating income for the three and six months ended June 30, 2003 increased approximately $24 million and $48 million, respectively ($14 million and $29 million, respectively, after income taxes) compared to the three and six months ended June 30, 2002. 3. ACQUISITIONS, DISPOSITIONS AND RETIREMENTS (Exelon and Generation) InfraSource Sale On June 18, 2003, Enterprises entered into an agreement to sell the electric construction and services, underground and telecom businesses of InfraSource, Incorporated (InfraSource). The net cash proceeds to Exelon from the sale are expected to be $211 million plus a $30 million subordinated note maturing with interest in 2011. The interest rate on the note is 8% annually if paid in cash and 10% if paid in kind. In connection with this transaction, Enterprises will enter into an agreement at closing 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. Enterprises anticipates incurring approximately $5 million in closing costs associated with the transaction. Closing of the transaction is subject to the satisfaction of a number of conditions, including regulatory approvals from state utility commissions in Pennsylvania, Delaware, New Jersey, Virginia, Maryland and Washington, D.C. and other conditions, the satisfaction of which cannot be assured. Early termination of the Hart Scott Rodino waiting period was granted effective July 17, 2003. If all closing conditions are satisfied, the transaction is expected to close in the third or fourth quarter of 2003. Exelon classified the assets and liabilities of InfraSource that are subject to the agreement of sale 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 June 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 June 30, 2003 consist of the following (in millions): 32 ------------------------------------------------------------------------------ Cash $ 26 Accounts receivable, net 82 Inventory 13 Property, plant and equipment, net 122 Deferred income taxes 62 Other assets 47 ------------------------------------------------------------------------------ Total assets classified as held for sale $ 352 ============================================================================== ------------------------------------------------------------------------------ Accounts payable $ 13 Accrued expenses and other current liabilities 53 Other liabilities 15 ------------------------------------------------------------------------------ Total liabilities classified as held for sale $ 81 ============================================================================== In connection with the sale, Exelon recorded an impairment charge of approximately $47 million (before income taxes) pursuant to SFAS No. 142 related to the goodwill recorded within the InfraSource reporting unit. Management of Exelon and Enterprises primarily considered the negotiated sales price of InfraSource in determining the amount of the goodwill impairment charge. This impairment charge was recorded as an operating and maintenance expense within the Consolidated Statements of Income and Comprehensive Income. 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 (after income taxes) on the $84 million investment in other income and deductions on 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. 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 (2) pay certain taxes, and/or (3) contribute to certain reserve funds. 33 EBG has a $1.25 billion credit facility (EBG Facility), which was entered into primarily to finance the construction of the Mystic 8 and 9 and Fore River generating units. The approximately $1.1 billion of debt outstanding under the credit facility at June 30, 2003 is reflected in Exelon and Generation's Consolidated Balance Sheets as a current liability due to certain events of default described below. Generation made a cash payment to Sithe of approximately $210 million during the second quarter of 2003 related to the note payable associated with the acquisition. See Note 9 - Long-Term Debt and Preferred Securities for additional information regarding this note. 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 ================================================================================ The EBG Facility requires 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 are 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 are in commercial operation, although construction has not progressed to the point of Project Completion. Construction of Fore River is substantially complete and the unit is currently undergoing testing. EBG does not anticipate that the projects will achieve Project Completion by August 29, 2003. The EBG Facility is non-recourse to Exelon and 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. As a result of Exelon's continuing evaluation of the projects and discussions with the lenders in July 2003, 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 Exelon's 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. Exelon expects Generation will incur an impairment of its EBG related assets, which, in aggregate, could reach approximately $550 million after income taxes. 34 Retirement of Power Plants Generation filed a request with the New England ISO to retire Exelon New England's Mystic 4, 5 and 6 and New Boston units based upon management's view of the ongoing financial viability of the units due to the start up of Mystic Units 8 and 9. Pursuant to SFAS No. 144, Generation performed a fair value analysis associated with the pending retirement of Mystic Units 4, 5, and 6 and New Boston. Based on a probability-weighted undiscounted cash flow model, Generation determined that the book value exceeded the fair value by $5 million for Mystic Units 4, 5 and 6. Therefore, an impairment charge of $5 million was recorded as operating and maintenance expense in Exelon and Generation's Consolidated Statements of Income and Comprehensive Income for the three months ended June 30, 2003. Acquisition of Generating Plants from TXU On April 25, 2002, Generation acquired two natural-gas and oil-fired plants from TXU Corp. (TXU) for an aggregate purchase price of $443 million. The purchase included the 893-MW Mountain Creek Steam Electric Station in Dallas, Texas and the 1,441-MW Handley Steam Electric Station in Fort Worth, Texas. The transaction included a purchased power agreement for TXU to purchase power during the months of May through September from 2002 through 2006. During the periods covered by the purchased power agreement, TXU has agreed to fixed capacity and variable expense payments, and to provide fuel to Exelon in return for exclusive rights to the energy and capacity of the generation plants. Substantially all of the purchase price was allocated to property, plant and equipment. 4. 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 purchased power agreement (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 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 35 was $29 million (before income taxes). In accordance with the Agreement, ComEd made payments of $17 million during the second quarter of 2003. 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, a total of 375,000 residential customers may be transferred to alternative electric generation suppliers in December 2003. Customers transferred will 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. 5. EARNINGS PER SHARE (Exelon) Diluted earnings per share are calculated by dividing net income by the weighted average number of shares of common stock outstanding, including shares issuable upon exercise of stock options outstanding under Exelon's stock option plans considered to be common stock equivalents. The following table shows the effect of these stock options on the weighted average number of shares outstanding used in calculating diluted earnings per share (in millions):
Three Months Ended June 30, Six Months Ended June 30, -------------------------- -------------------------- 2003 2002 2003 2002 ------------------------------------------------------------------------------------------------------------------------ Average Common Shares Outstanding 325 322 324 322 Assumed Exercise of Stock Options 2 2 3 2 ------------------------------------------------------------------------------------------------------------------------ Average Dilutive Common Shares Outstanding 327 324 327 324 ========================================================================================================================
The number of stock options not included in average common shares used in calculating diluted earnings per share due to their antidilutive effect were five million for the three and six months ended June 30, 2003 and three million for the three and six months ended June 30, 2002. 36 6. 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 six months ended June 30, 2003 and 2002 and at June 30, 2003 and December 31, 2002 is as follows: Three Months Ended June 30, 2003 and 2002
Corporate and Energy Intersegment Delivery Generation Enterprises Eliminations Consolidated ------------------------------------------------------------------------------------------------------------------------ Total Revenues (1): 2003 $ 2,322 $ 1,886 $ 443 $ (930) $ 3,721 2002 2,476 1,559 476 (992) 3,519 Intersegment Revenues: 2003 $ 19 $ 896 $ 16 $ (931) $ -- 2002 15 953 24 (992) -- Income (Loss) Before Income Taxes: 2003 $ 481 $ 233 $ (95) $ (25) $ 594 2002 522 135 142 (35) 764 Income Taxes: 2003 $ 190 $ 91 $ (34) $ (25) $ 222 2002 200 51 59 (31) 279 Net Income (Loss): 2003 $ 291 $ 142 $ (61) $ -- $ 372 2002 322 84 83 (4) 485 ------------------------------------------------------------------------------------------------------------------------
(1) $51 million and $57 million in utility taxes are included in the Revenues and Expenses for the three months ended June 30, 2003 and 2002, respectively, for ComEd. $47 million and $49 million in utility taxes are included in the Revenues and Expenses for the three months ended June 30, 2003 and 2002, respectively, for PECO. 37 Six Months Ended June 30, 2003 and 2002, June 30, 2003, and December 31, 2002
Corporate and Energy Intersegment Delivery Generation Enterprises Eliminations Consolidated ------------------------------------------------------------------------------------------------------------------------ Total Revenues (1): 2003 $ 4,964 $ 3,765 $ 1,022 $ (1,956) $ 7,795 2002 4,811 3,020 966 (1,921) 6,876 Intersegment Revenues: 2003 $ 35 $ 1,889 $ 35 $ (1,959) $ -- 2002 29 1,845 47 (1,921) -- Income (Loss) Before Income Taxes and the Cumulative Effect of Changes in Accounting Principles: 2003 $ 998 $ 160 $ (125) $ (42) $ 991 2002 864 246 95 (56) 1,149 Income Taxes: 2003 $ 382 $ 71 $ (47) $ (36) $ 370 2002 326 96 40 (35) 427 Cumulative Effect of Changes in Accounting Principles: 2003 $ 5 $ 108 $ (1) $ -- $ 112 2002 -- 13 (243) -- (230) Net Income (Loss): 2003 $ 621 $ 197 $ (79) $ (6) $ 733 2002 538 163 (188) (21) 492 Total Assets: June 30, 2003 $ 27,349 $ 13,913 $ 1,166 $ (2,140) $ 40,288 December 31, 2002 26,550 11,007 1,297 (1,369) 37,485 ------------------------------------------------------------------------------------------------------------------------
(1) $113 million and $114 million in utility taxes are included in the Revenues and Expenses for the six months ended June 30, 2003 and 2002, respectively, for ComEd. $98 million and $93 million in utility taxes are included in the Revenues and Expenses for the six months ended June 30, 2003 and 2002, respectively, for PECO. 7. FAIR VALUE OF FINANCIAL ASSETS AND LIABILITIES (Exelon, ComEd, PECO and Generation) During the three and six months ended June 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 June 30, 2003 $ (6) $ 2 $ 103 $ 3 $ 102 Three months ended June 30, 2002 (14) (6) 10 (3) (13) Six months ended June 30, 2003 (5) 5 (191) 7 (184) Six months ended June 30, 2002 (16) (1) (108) 14 (111) ------------------------------------------------------------------------------------------------------------------------
38 During the three and six months ended June 30, 2003 and 2002, Generation recognized net MTM gains on non-trading energy derivative contracts not designated as cash flow hedges, in purchased power as follows: 2003 2002 -------------------------------------------------------------------------------- Three months ended June 30, $ 32 $ 4 Six months ended June 30, 1 10 -------------------------------------------------------------------------------- During the three and six months ended June 30, 2003 and 2002, Generation recognized net MTM losses on proprietary trading contracts in operating revenues as follows: 2003 2002 -------------------------------------------------------------------------------- Three months ended June 30, $ (2) $ (9) Six months ended June 30, (4) (13) -------------------------------------------------------------------------------- During the three and six months ended June 30, 2003 and 2002, no amounts were reclassified to other income in the Consolidated Statements of Income and Comprehensive Income as a result of the discontinuance of cash flow hedges related to certain forecasted financing transactions that were no longer probable of occurring. During the three and six months ended June 30, 2003 and 2002, Generation did not reclassify any amounts from accumulated other comprehensive income into earnings as a result of forecasted energy commodity transactions no longer being probable. As of June 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 $ (281) $ 8 $ (262) ------------------------------------------------------------------------------------------------------------------
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 June 30, 2003, ComEd expects to amortize during the next twelve months $7 million of regulatory assets for settled cash flow swaps. During the three and six months ended June 30, 2003 and 2002, ComEd reclassified amounts from other comprehensive income to regulatory assets for cash flow swaps settled as follows:
2003 2002 ------------------------------------------------------------------------------------------------------ Three months ended June 30, (net of tax of $0 and $0, respectively) $ -- $ 1 Six months ended June 30, (net of tax of $21 and $4, respectively) 30 6 ------------------------------------------------------------------------------------------------------
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 will be recorded in 39 earnings. However, as long as the hedge remains effective, changes in the fair value of the swaps will be offset by changes in the fair value of the hedged liabilities. Any change in the fair value of the hedge as a result of ineffectiveness would be recorded immediately in earnings. As of June 30, 2003, these swaps had an aggregate fair market value of $46 million, which was classified as other deferred debits and other assets within the Consolidated Balance Sheets. 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 anticipated debt issuance. In connection with the 2003 issuances of certain First Mortgage Bonds, forward-starting interest rate swaps with an aggregate notional amount of $870 million were settled with net proceeds to counterparties of $51 million ($30 million, after income taxes) that has been deferred in regulatory assets and is being amortized over the life of the First Mortgage Bonds as an increase to interest expense. See Note 9 - Long-Term Debt and Preferred Securities for additional information regarding the issuance of the First Mortgage Bonds. On June 30, 2003, ComEd's remaining forward-starting swaps had an aggregate notional amount of $200 million and an aggregate fair market value of $6 million. 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 June 30, 2003, these interest rate swaps had an aggregate fair market value exposure of $17 million based on the present value difference between the contract and market rates at June 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 in 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 9 - 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 June 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 at June 30, 2003. The fair market value exposure of these swaps, designated as cash flow hedges, is $105 million. Generation has also entered into interest rate swaps with an aggregate notional amount of $200 million to manage interest rate exposures associated with an anticipated debt issuance. As of June 30, 2003, these swaps had an aggregate fair market value of $4 million based on the present value difference between the contract and market rates at June 30, 2003, which was classified as deferred debits and other assets within the Consolidated Balance Sheets. 40 Generation classifies investments in the trust accounts for decommissioning nuclear plants as available-for-sale. The following tables show the fair values, gross unrealized gains and losses and amortized cost bases for the securities held in these trust accounts.
June 30, 2003 ----------------------------------------------------------------------------------------------------------------------- Gross Gross Amortized Unrealized Unrealized Estimated Cost Gains Losses Fair Value ----------------------------------------------------------------------------------------------------------------------- Cash and cash equivalents $ 171 $ -- $ -- $ 171 Equity securities 1,909 124 (387) 1,646 Debt securities Government obligations 1,015 71 (2) 1,084 Other debt securities 410 32 (27) 415 ----------------------------------------------------------------------------------------------------------------------- Total debt securities 1,425 103 (29) 1,499 ----------------------------------------------------------------------------------------------------------------------- Total available-for-sale securities $ 3,505 $ 227 $ (416) $ 3,316 ======================================================================================================================= December 31, 2002 ----------------------------------------------------------------------------------------------------------------------- Gross Gross Amortized Unrealized Unrealized Estimated Cost Gains Losses Fair Value ----------------------------------------------------------------------------------------------------------------------- Cash and cash equivalents $ 184 $ -- $ -- $ 184 Equity securities 1,763 72 (482) 1,353 Debt securities Government obligations 938 62 -- 1,000 Other debt securities 514 32 (30) 516 ----------------------------------------------------------------------------------------------------------------------- Total debt securities 1,452 94 (30) 1,516 ----------------------------------------------------------------------------------------------------------------------- Total available-for-sale securities $ 3,399 $ 166 $ (512) $ 3,053 =======================================================================================================================
Net unrealized losses of $189 million were recognized in regulatory assets, regulatory liabilities or accumulated other comprehensive income in Exelon's Consolidated Balance Sheet at June 30, 2003. Net unrealized losses of $189 million were recognized in noncurrent affiliate payables, noncurrent affiliate receivables or accumulated other comprehensive income in Generation's Consolidated Balance Sheet as of June 30, 2003. Net unrealized losses of $346 million were recognized in accumulated depreciation and accumulated other comprehensive income in the Consolidated Balance Sheets of Exelon and Generation at December 31, 2002. During the three and six months ended June 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 June 30, Six Months Ended June 30, -------------------------- ------------------------- 2003 2002 2003 2002 -------------------------------------------------------------------------------------------------------- Proceeds from sales $ 690 $ 309 $ 1,262 $ 889 Gross realized gains 51 13 65 31 Gross realized losses (45) (24) (53) (56) --------------------------------------------------------------------------------------------------------
Net realized gains of $6 million and net realized losses of $11 million for the three months ended June 30, 2003 and 2002, respectively, were recorded in other income and deductions. Net realized gains of $12 million and net realized losses of $21 million for the six months ended June 30, 2003 and 2002, respectively, were recorded in other income and 41 deductions. Net realized losses of $4 million were recognized in accumulated depreciation at June 30, 2002. The available-for-sale securities held at June 30, 2003 have an average maturity of eight to ten years. The cost of these securities was determined on the basis of specific identification. 8. COMMITMENTS AND CONTINGENCIES (Exelon, ComEd, PECO and Generation) For information regarding capital commitments, nuclear decommissioning and spent fuel storage, see the Commitments and Contingencies and Nuclear Decommissioning and Spent Fuel Storage Notes in the Notes to Consolidated Financial Statements of Exelon, ComEd, PECO and Generation for the year ended December 31, 2002. See Note 2 - New Accounting Principles and Accounting Changes for further discussion of nuclear decommissioning commitments and contingencies. Environmental Liabilities As of June 30, 2003, Exelon had accrued $131 million for environmental investigation and remediation costs that currently can be reasonably estimated, including $108 million for manufactured gas plant (MGP) investigation and remediation. Exelon has identified 71 sites where former MGP activities have or may have resulted in actual site contamination. As of June 30, 2003, ComEd had accrued $86 million for environmental investigation and remediation costs that currently can be reasonably estimated. This reserve included $82 million (discounted) for MGP investigation and remediation. As of June 30, 2003, PECO had accrued $35 million (undiscounted) for environmental investigation and remediation costs that currently can be reasonably estimated, including $26 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 12 - Supplemental Financial Information). As of June 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. Energy Commitments Exelon and Generation had long-term commitments as of June 30, 2003 relating to the net purchase and sale of energy, capacity and transmission rights from unaffiliated utilities, 42 including Midwest Generation, LLC (Midwest Generation), and others, including AmerGen, as expressed in the following table:
Power Only Purchases from Net Capacity Power Only ------------------------- Transmission Rights Purchases (1) Non-Affiliate Sales AmerGen(2) Non-Affiliates Purchases (3) ------------------------------------------------------------------------------------------------------------------------------ 2003 $ 531 $2,012 $ 231 $1,306 $ 38 2004 822 1,708 492 1,066 103 2005 509 536 386 296 84 2006 476 169 398 223 3 2007 458 61 404 212 -- Thereafter 3,802 1 1,826 845 -- ------------------------------------------------------------------------------------------------------------------------------ Total $6,598 $4,487 $3,737 $3,948 $ 228 ==============================================================================================================================
(1) Net Capacity Purchases includes Midwest Generation commitments as of June 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. Net Capacity Purchases in 2004 include 3,474 MWs of optional capacity from Midwest Generation. Net Capacity Purchases also include capacity sales to TXU under the PPA entered into in connection with the purchase of two generating plants in April 2002, which states that TXU will purchase the plant output from May through September from 2002 through 2006. The combined capacity of the two plants is 2,334 MWs. (2) 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 Nuclear Power Station (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 has agreed to purchase all of the residual energy from Clinton Nuclear Power Station (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. (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. Prices for this energy vary depending upon the time of day and month of delivery. During 2005 and 2006, ComEd's PPA is a partial requirements agreement under which ComEd will purchase all of its required energy and capacity from Generation, up to the available capacity of the nuclear generating plants formerly owned by ComEd and transferred to Generation. Under the terms of the PPA, Generation is responsible for obtaining any required transmission service, 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, which could include Generation. The PPA for 2005 and 2006 may be extended to a full requirements contract as a result of the Agreement (see Note 4 - Regulatory Issues). In connection with the 2001 corporate restructuring, 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. 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 (Class Period). The complaints allege that Exelon violated Federal securities laws by issuing a series of materially false and misleading statements relating to its 2001 earnings expectations during the Class Period. The court consolidated the pending cases into one lawsuit and appointed two lead plaintiffs as well as lead counsel. On October 1, 2002, the plaintiffs filed a consolidated amended complaint, which contained allegations of new facts and several new theories of liability. On June 13, 2003, the court dismissed the amended complaint with prejudice. The plaintiffs have agreed not to appeal 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 Federal Energy Regulatory Commission (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. ComEd and the municipal customers have executed a settlement agreement ending the litigation. Under the settlement, ComEd will pay a total of approximately $3 million to the three municipalities. 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 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 44 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. 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. The Court preliminarily approved the settlement on June 23, 2003, and a final hearing is set for October 2, 2003. The settlement, when approved, will release ComEd from all claims arising from the 1999 power outages. A portion of any settlement or verdict may be covered by insurance. 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 total $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. Cotter intends to vigorously defend each case. On February 18, 2000, ComEd sold Cotter to an unaffiliated third party. As part of the 45 sale, ComEd agreed to indemnify Cotter for any liability incurred by Cotter as a result of these actions, as well as any liability arising in connection with the West Lake Landfill discussed in the next paragraph. In connection with Exelon's 2001 corporate restructuring, the responsibility to indemnify Cotter for any liability related to these matters was transferred by ComEd to Generation. The 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. Raytheon Arbitration. In March 2001, two subsidiaries of Sithe New England acquired in November 2002, brought an action in the New York Supreme Court against Raytheon Corporation (Raytheon) relating to its failure to honor its guaranty with respect to the performance of the Mystic and Fore River projects, as a result of the abandonment of the projects by the turnkey contractor. In a related proceeding, in May 2002, Raytheon submitted claims to the International Chamber of Commerce Court of Arbitration (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 contract. Hearings by the Arbitration Court with respect to damages are scheduled and a final decision is expected in September 2003. Generation believes that Sithe New England properly rejected Raytheon's request for a change order and that Raytheon's damages claims are inflated. In addition to its asserted claims, Raytheon has indicated that it will bring additional claims for damages. Exelon will continue to vigorously defend its position in the arbitration and contest any additional claims that may be asserted. 46 Clean Air Act. On June 1, 2001, the EPA issued to EBG a Notice of Violation (NOV) and Reporting Requirement pursuant to Sections 113 and 114 of the Clean Air Act, alleging numerous exceedances of opacity limits and violations of opacity-related monitoring, recording and reporting requirements at Mystic Station in Everett, Massachusetts. On January 8, 2002, the EPA indicated that it had decided to resolve the NOV through an administrative compliance order and a judicial civil penalty action. In March 2002, the EPA issued and Sithe Mystic LLC, a wholly owned subsidiary of EBG, voluntarily entered a Compliance Order and Reporting Requirement (Compliance Order) regarding Mystic Station, under which Mystic Station installed new ignition equipment on three of the four units at the plant. Mystic Station also undertook an extensive opacity monitoring and testing program for all four units at the plant to help determine if additional compliance measures were needed. Pursuant to the requirements of the Compliance Order, EBG switched three of the four units to a lower sulfur fuel oil by September 1, 2002. The Compliance Order does not address civil penalties. By a letter dated April 21, 2003, the United States Department of Justice notified EBG that, at the request of the EPA, it intended to bring a civil penalty action, but also offered the opportunity to resolve the matter through settlement discussions. EBG is pursuing settlement discussions with the EPA and the Department of Justice. Real Estate Tax Appeals. Generation is involved in tax appeals regarding a number of its nuclear facilities, Limerick Generating Station (Montgomery County, PA), Peach Bottom Atomic Power Station (York County, PA) and Quad Cities Station (Rock Island County, IL). Generation is also involved in the tax appeal for Three Mile Island (Dauphin County, PA) through AmerGen. Generation does not believe the outcome of these matters will have a material adverse effect on Generation's results of operations or financial condition. Exelon, ComEd, PECO and Generation Exelon, ComEd, PECO and Generation are involved in various other litigation matters. The ultimate outcome of such matters, as well as the matters discussed above, while uncertain, are not expected to have a material adverse effect on their respective financial condition or results of operations. 47 Commercial Commitments Exelon, ComEd, PECO and Generation's commercial commitments as of June 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, are as follows:
Expiration within ----------------------------------------------------------------------- 2008 Exelon Total 2003 2004-2005 2006-2007 and beyond ----------------------------------------------------------------------------------------------------------------------- Related to Obligations Recorded on the Balance Sheet --------------------------------------------------------- Credit Facility (a) $ 1,500 $ 1,500 $ -- $ -- $ -- Letters of Credit (non-debt) (b) 119 45 74 -- -- Letters of Credit (long-term debt) (c) 456 158 298 -- -- Preferred Securities Guarantee (d, e) 528 -- -- -- 528 Guarantees of Long-Term Debt (f) 41 -- 2 -- 39 Midwest Generation Capacity Reservation Agreement Guarantee (g) 34 2 7 7 18 Other ----- Guarantees of Letters of Credit (h) 93 77 16 -- -- Performance Guarantees (i) 101 -- -- -- 101 Surety Bonds (j) 681 241 286 3 151 Energy Marketing Contract Guarantees (k) 207 92 115 -- -- Nuclear Insurance Guarantees (l) 1,380 -- -- -- 1,380 Lease Guarantees (m) 13 -- -- 2 11 EBG Equity Guarantee (n) 38 38 -- -- -- Fuel purchase agreements (o) 2,169 308 690 637 534 ----------------------------------------------------------------------------------------------------------------------- Total $ 7,360 $ 2,461 $ 1,488 $ 649 $ 2,762 ======================================================================================================================= Expiration within ----------------------------------------------------------------------- 2008 ComEd Total 2003 2004-2005 2006-2007 and beyond ----------------------------------------------------------------------------------------------------------------------- Related to Obligations Recorded on the Balance Sheet ---------------------------------------------------- Credit Facility (a) $ 100 $ 100 $ -- $ -- $ -- Letters of Credit (non-debt) (b) 23 4 19 -- -- Letters of Credit (long-term debt) (c) 92 92 -- -- -- Preferred Securities Guarantees (e) 350 -- -- -- 350 Midwest Generation Capacity Reservation Agreement Guarantee (g) 34 2 7 7 18 Other ----- Surety Bonds (j) 21 -- 3 -- 18 ----------------------------------------------------------------------------------------------------------------------- Total $ 620 $ 198 $ 29 $ 7 $ 386 ======================================================================================================================= 48 Expiration within ----------------------------------------------------------------------- 2008 PECO Total 2003 2004-2005 2006-2007 and beyond ----------------------------------------------------------------------------------------------------------------------- Related to Obligations Recorded on the Balance Sheet ---------------------------------------------------- Credit Facility (a) $ 400 $ 400 $ -- $ -- $ -- Letters of Credit (non-debt) (b) 31 1 30 -- -- Preferred Securities Guarantees (d) 178 -- -- -- 178 Other ----- Surety Bonds (j) 45 1 44 -- -- ---------------------------------------------------------------------------------------------------------------------- Total $ 654 $ 402 $ 74 $ -- $ 178 ======================================================================================================================= Expiration within ----------------------------------------------------------------------- 2008 Generation Total 2003 2004-2005 2006-2007 and beyond ---------------------------------------------------------------------------------------------------------------------- Related to Obligations Recorded on the Balance Sheet ---------------------------------------------------- Credit Facility (a) $ -- $ -- $ -- $ -- $ -- Letters of Credit (non-debt) (b) 16 9 7 -- -- Letters of Credit (long-term debt) (c) 364 66 298 -- -- Other ----- Guarantees of Letters of Credit (h) 66 66 -- -- -- Performance Guarantees (i) 101 -- -- -- 101 Surety Bonds (j) 43 -- -- -- 43 Energy Marketing Contract Guarantees (k) 24 24 -- -- -- Nuclear Insurance Guarantee (p) 134 -- -- -- 134 EBG Equity Guarantee (n) 38 38 -- -- -- Fuel purchase agreements (o) 2,169 308 690 637 534 ---------------------------------------------------------------------------------------------------------------------- Total $ 2,955 $ 511 $ 995 $ 637 $ 812 =======================================================================================================================
(a) Credit Facility - Exelon, along with ComEd, PECO and Generation, maintain a $1.5 billion 364-day credit facility to support commercial paper issuances. At June 30, 2003, there were no borrowings against the credit facility. Additionally, at June 30, 2003, commercial paper outstanding was as follows: Exelon Corporate $ 411 ComEd -- PECO 170 Generation -- (b) Letters of Credit (non-debt) - Exelon and certain of its subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties. (c) Letters of Credit (long-term debt) - Direct-pay letters of credit issued in connection with variable-rate debt in order to provide liquidity in the event that it is not possible to remarket all of the debt as required following specific events, including changes in the basis of determining the interest rate on the debt. (d) Preferred Securities Guarantee - Guarantees issued to guarantee the preferred securities of the subsidiary trusts of PECO. (e) Preferred Securities Guarantees - Guarantees issued to guarantee the preferred securities of the subsidiary trusts of ComEd. (f) Guarantees of Long-Term Debt - Issued to guarantee payment of Enterprises' debt. (g) 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 fair value of this guarantee under FIN 45 of $4 million is included as a liability on Exelon and ComEd's Consolidated Balance Sheets. Additional information regarding this liability is included within this section under the heading "General" below. (h) 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. (i) Performance Guarantees - Guarantees issued to ensure performance under specific contracts. (j) Surety Bonds - Guarantees issued related to contract and commercial surety bonds, excluding bid bonds. 49 (k) Energy Marketing Contract Guarantees - Guarantees issued to ensure performance under energy commodity contracts. (l) Nuclear Insurance Guarantees - Guarantees of nuclear insurance required under the Price-Anderson Act. $1.1 billion of this total exposure is exempt from the $4.5 billion PUHCA guarantee limit by SEC rule. (m) Lease Guarantees - Guarantees issued to ensure payments on building leases. (n) 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. (o) Fuel Purchase Agreements - Commitments to purchase fuel supplies for nuclear generation. (p) Nuclear Insurance Guarantee - Guarantees of nuclear insurance required under the Price-Anderson Act. This amount relates to Generation's guarantee of AmerGen's plants. Exelon has a $1.2 billion guarantee relating to Generation's directly owned plants that is not included in this amount. Credit Contingencies Generation is a counterparty to Dynegy in various energy transactions. In early July 2002, the credit ratings of Dynegy were downgraded to below investment grade by two credit rating agencies. As of June 30, 2003, Generation had a net receivable from Dynegy of approximately $4 million and, consistent with the terms of the existing credit arrangement, has received collateral in support of this receivable. Generation also has credit risk associated with Dynegy through Generation's equity investment in Sithe. Sithe is a 60% owner of the Independence generating station (Independence), a 1,040-MW gas-fired qualified facility that has an energy-only long-term tolling agreement with Dynegy, with a related financial swap arrangement. As of June 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 terms 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 $17 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. In connection with ComEd's sale of assets to Midwest Generation prior to the Merger, ComEd had entered into an Agency Agreement with Midwest Generation and certain of Midwest Generation's related parties (the "Guarantors") whereby the Guarantors assumed the benefits and liabilities of a coal purchase contract. ComEd remained the signatory to the coal contract, and in connection with the Merger and subsequent restructuring, Generation assumed the signatory obligation on this contract from ComEd. Midwest Generation's credit ratings have recently been downgraded by certain credit rating agencies. In the event of Midwest Generation and the Guarantors non-performance under the coal purchase contract, Generation would be required to fulfill the purchase commitments which 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 contract years 2003 to 2012 are estimated to be approximately $81 million related to this agreement. Generation and ComEd have entered 50 into other agreements with Midwest Generation in which the non-performance by Midwest Generation is currently not anticipated to result in significant contingent obligations to Generation or ComEd. Spent Fuel Storage In connection with a July 2000 agreement between PECO and the U.S. Department of Energy (DOE) relating to the Peach Bottom Station Nuclear Waste Fund and interim spent nuclear fuel storage costs, Generation is currently in discussions with the DOE regarding possible repayment of amounts received as credits against contributions to the Nuclear Waste Fund. Based upon discussions with the DOE, Generation estimates the range of potential liability to be $0 to $20 million, excluding any additional recoveries. At June 30, 2003, based upon the status of the discussions and uncertainty surrounding the amounts to be repaid, if any, no amounts have been accrued. See Note 9 - Nuclear Decommissioning and Spent Nuclear Fuel Storage in Generation's Form 10-K for the year ended December 31, 2002 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 from Midwest Generation $22 million 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). The fees for these agreements are contingent upon a successful outcome and are based upon a percentage of the refunds recovered from the IRS, if any. As such, ComEd and PECO would have positive net cash flows related to these agreements if any fees are paid to the tax consultant. These potential tax benefits and associated fees could be material to the financial position, results of operations and cash flows of ComEd and PECO. ComEd'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. 51 In the second quarter of 2003, Exelon progressed in its plans to implement its new business model referred to as The Exelon Way. The Exelon Way is focused on improving operating cash flows while meeting service and financial commitments through improved integration of operations and consolidation of support functions. Exelon is working to meet its goals of 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 anticipates incurring expenses associated with the rationalization of certain business functions and employee separation costs. These expenses may be significant and are expected to be incurred during the remaining half of 2003 through 2005. However, these costs cannot be reasonably estimated at this time. 9. LONG-TERM DEBT AND PREFERRED SECURITIES (Exelon, ComEd, PECO and Generation) 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 redeemed $200 million of its trust preferred securities at a redemption price of 100% of the principal amount, plus accrued distributions. 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 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. 52 During the six months ended June 30, 2003, Exelon and ComEd retired $267 million and $52 million of commercial paper classified as long-term debt, respectively. During the six months ended June 30, 2003, ComEd recorded prepayment premiums of $15 million and net unamortized premiums, discounts and debt issuance expenses of $31 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. On June 24, 2003, PECO issued $100 million of trust preferred securities with an annual distribution rate of 5.75% that are mandatorily redeemable in 2033. These securities were recorded as liabilities in accordance with SFAS No. 150 (see Note 2 - New Accounting Principles and Accounting Changes). The proceeds of the issue were used to redeem the trust preferred securities and preferred stock discussed below. Also on June 24, 2003, 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. 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 13, 2003, Generation closed on a $550 million revolving credit facility. 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 from Sithe. This note was restructured in June 2003 to provide for a payment of $210 million of the principal on June 16, 2003 and the remaining principal on the earlier of December 1, 2003 or change of control. 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. 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. See Note 7 - Fair Value of Financial Assets and Liabilities for additional information regarding interest rate swaps of ComEd, PECO and Generation. 53 10. UNCONSOLIDATED INVESTMENTS (Exelon and Generation) During the three months ended June 30, 2003, Exelon recorded an impairment charge of $35 million (before income taxes) in other income and deductions within the Consolidated Statements of Income and Comprehensive Income related to an other-than-temporary decline in value of certain investments held by Enterprises. Management of Exelon and Enterprises considered various factors in the decision to record an impairment of these investments, including recent valuations of the investments. This impairment reduced the book value of these investments from $42 million at December 31, 2002 to $7 million at June 30, 2003. Generation Generation is a 49.9% owner of Sithe and has accounted for the investment as an unconsolidated equity investment through June 30, 2003. In the first quarter of 2003, Exelon and Generation recorded an impairment charge of $200 million (before income taxes) in other income and deductions, associated with a decline in the Sithe investment fair value, which was considered to be other than temporary. Exelon and Generation's management considered various factors in the decision to record an impairment of this investment, including management's recent experience of exploring the sale of its interest in Sithe. The discussions surrounding the sale indicated that the fair value of the Sithe investment was below its book value, and as such, an impairment charge was required. The book value of Generation's investment in Sithe was $209 million at June 30, 2003. For the six months ended June 30, 2003, Sithe had revenues of $356 million. Generation recorded $1.6 million of equity method losses for Sithe for the six months ended June 30, 2003. See Note 2 - New Accounting Principles and Accounting Changes for 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 35.2% interest in Sithe owned by Apollo Energy, LLC and the 14.9% interest owned by subsidiaries of Marubeni Corporation. The total call price was based on the terms of the existing Put and Call Agreement (PCA) among the parties and approximated $650 million. The transfer of ownership requires various regulatory approvals, including FERC, the state environmental agency in New Jersey, and expiration of the Hart Scott Rodino waiting period. Under the terms of the PCA, the call must be funded within six months of the call notice being issued. Additionally, because the Federal Power Act restricts Exelon's ownership of 50% or more of qualifying facilities, the qualifying facilities owned by Sithe must be sold or restructured before closing to preserve their status as qualifying facilities. Despite the issuance of the call notice, Generation continues to pursue options to sell its investment in Sithe in its entirety. Generation is a 50% owner of AmerGen and has accounted for the investment as an unconsolidated equity investment through June 30, 2003. The book value of Generation's investment in AmerGen was $260 million at June 30, 2003. For the six months ended June 30, 2003, AmerGen had revenues of $307 million. Generation recorded $29 million of equity method earnings for AmerGen for the six months ended June 30, 2003. 54 11. RELATED-PARTY TRANSACTIONS (Exelon, ComEd, PECO and Generation) Exelon's financial statements reflect related-party transactions with unconsolidated affiliates as reflected in the tables below.
Three Months Ended June 30, Six Months Ended June 30, --------------------------- ------------------------- 2003 2002 2003 2002 ----------------------------------------------------------------------------------------------------------------------- Purchased power from AmerGen (1) $ 110 $ 60 $ 177 $ 116 Interest income from AmerGen (2) -- -- 1 1 Interest expense to Sithe (3) 3 -- 6 -- Services provided to AmerGen (4) 18 16 35 30 Services provided to Sithe (5) -- -- 1 -- Services provided by Sithe (6,7) 2 -- 5 1 ----------------------------------------------------------------------------------------------------------------------- June 30, 2003 December 31, 2002 ----------------------------------------------------------------------------------------------------------------------- Net receivable from AmerGen (1,2,4) $ -- $ 39 Net payable to AmerGen (1,2,4) 17 -- Net payable to Sithe (5,6,7) 5 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 has agreed to purchase all of the residual energy from Clinton through December 31, 2004. Currently, the residual output is approximately 31% of the total output of Clinton. (2) In February 2002, Generation entered into an agreement to loan AmerGen up to $75 million at an interest rate equal to the one-month London Interbank Offering Rate plus 2.25%. In July 2002, the limit of the loan agreement was increased to $100 million and the maturity date was extended to July 1, 2003. As of June 30, 2003, the principal balance of the loan was paid in full. (3) Under the terms of the agreement to acquire Exelon New England dated November 1, 2002, Generation issued a $534 million note to be paid in full on June 18, 2003 to Sithe. 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 and the balance of the note is to be paid by December 1, 2003 or upon change of control. The note bears interest at the rate equal to LIBOR plus 0.875%. Interest accrued on the note as of June 30, 2003 was $0.3 million. (4) Under a service agreement dated March 1, 1999, Generation provides AmerGen with certain operation and support services to the nuclear facilities owned by AmerGen. This service agreement has an indefinite term and may be terminated by Generation or AmerGen with 90 days notice. Generation is compensated for these services at cost. Exelon also provides AmerGen with certain payroll processing services. (5) Under a service agreement dated December 18, 2000, Generation provides certain engineering and environmental services for fossil facilities owned by Sithe and for certain developmental projects. Generation is compensated for these services at cost. (6) Under a service agreement dated December 18, 2000, Sithe provides Generation certain fuel and project development services. Sithe is compensated for these services at cost. (7) Under a service agreement dated November 1, 2002, Sithe provides Generation certain transition services related to the transition of the New England acquisition that occurred on November 1, 2002. 55 ComEd ComEd's financial statements reflect related-party transactions as reflected in the tables below.
Three Months Ended June 30, Six Months Ended June 30, -------------------------- ------------------------ 2003 2002 2003 2002 --------------------------------------------------------------------------------------------------------- Operating revenues from affiliates Generation (1) $ 15 $ 10 $ 26 $ 19 Enterprises (1) 1 2 3 4 Purchased power from affiliate Generation (2) 528 547 1,099 1,079 Operating & maintenance from affiliates BSC (3) 25 26 52 65 Enterprises (4,5) 3 3 6 6 Interest income from affiliates UII (6) 6 7 12 15 Generation (11) 1 -- 1 -- Other -- 1 -- 1 Capitalized costs BSC (3) 1 2 2 3 Enterprises (5) 6 6 12 13 Cash dividends paid to parent 91 117 211 235 --------------------------------------------------------------------------------------------------------- June 30, 2003 December 31, 2002 --------------------------------------------------------------------------------------------------------- Receivables from affiliates (current) UII (6) $ 12 $ 15 Generation (11) 165 -- Receivables from affiliates (noncurrent) UII (6) 1,284 1,284 Generation (9) 1,094 -- Other 19 16 Payables to affiliates (current) Generation decommissioning (8) 11 59 Generation (1, 2, 7) 185 339 BSC (3, 7) 11 18 Other 2 -- Payables to affiliates (noncurrent) Generation decommissioning obligation (8) 19 218 Other 7 6 Shareholders' equity - receivable from parent (10) 554 615 ---------------------------------------------------------------------------------------------------------
(1) ComEd provides electric, transmission, and other ancillary services to Generation and Enterprises. (2) Effective January 1, 2001, ComEd entered into a PPA with Generation. See Note 8 - Commitments and Contingencies for further information regarding the PPA. The Generation payable primarily consists of services related to the PPA. (3) ComEd receives a variety of corporate support services from Exelon Business Services Company (BSC), including legal, human resource, financial, information technology, supply management and corporate governance services. A portion of such services, provided at cost including applicable overhead, is capitalized. (4) ComEd has contracted with Exelon Services to provide energy conservation services to ComEd customers. (5) ComEd receives substation and transmission engineering and construction services under contracts with InfraSource. A portion of such services is capitalized. (6) ComEd has a note and interest receivable 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. 56 (7) In order to benefit from economies of scale, ComEd processes certain invoice payments on behalf of Generation and BSC. (8) 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. (9) 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. (10) ComEd has a non-interest bearing receivable from Exelon related to Exelon's agreement to fund future income tax payments resulting from the collection by ComEd of instrument funding changes. The receivable is expected to be settled over the years 2003 through 2008. (11) ComEd participates in Exelon's intercompany money pool. ComEd had various notes to and earned interest from Generation under the money pool. PECO PECO's financial statements reflect a number of related-party transactions as reflected in the table below.
Three Months Ended June 30, Six Months Ended June 30, --------------------------- ------------------------- 2003 2002 2003 2002 -------------------------------------------------------------------------------------------------------- Operating revenues from affiliate Generation (1) $ 3 $ 3 $ 5 $ 7 Purchased power from affiliate Generation (2) 324 346 681 649 Operating & maintenance from affiliates BSC (3) 10 9 22 26 Enterprises (4) 1 8 3 16 Capitalized costs BSC (3) 2 5 5 6 Enterprises (4) 7 -- 13 10 Cash dividends paid to parent 76 85 165 170 -------------------------------------------------------------------------------------------------------- June 30, 2003 December 31, 2002 -------------------------------------------------------------------------------------------------------- Payables to affiliates (current) Generation (2) $ 121 $ 124 BSC (3) 12 26 Enterprises (4) 3 19 Other 1 1 Payable to affiliate (noncurrent) Generation (5) 16 -- Shareholders' equity - receivable from parent (6) 1,698 1,758 --------------------------------------------------------------------------------------------------------
(1) PECO provides energy to Generation for Generation's own use. (2) Effective January 1, 2001, PECO entered into a PPA with Generation. See Note 8 - Commitments and Contingencies for further information regarding the PPA. (3) PECO provides services to BSC related to invoice processing. PECO receives a variety of corporate support services from BSC, including legal, human resource, financial, information technology, supply management and corporate governance services. Such services are provided at cost, including applicable overhead. Some of these costs are capitalized. (4) PECO receives services from Enterprises for construction, which are capitalized, and the deployment of automated meter reading technology, which 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. 57 Generation Generation's financial statements reflect related-party transactions with unconsolidated affiliates as reflected in the tables below.
Three Months Ended June 30, Six Months Ended June 30, --------------------------- ------------------------- 2003 2002 2003 2002 ----------------------------------------------------------------------------------------------------------------------- Purchased power from AmerGen (1) $ 110 $ 60 $ 177 $ 116 Interest income from AmerGen (2) -- -- 1 1 Interest expense to Sithe (3) 3 -- 6 -- Services provided to AmerGen (4) 18 16 35 30 Services provided to Sithe (5) -- -- 1 -- Services provided by Sithe (6,7) 2 -- 5 1 ---------------------------------------------------------------------------------------------------------------------- June 30, 2003 December 31, 2002 ---------------------------------------------------------------------------------------------------------------------- Net receivable from AmerGen (1,2,4) $ -- $ 39 Net payable to AmerGen (1,2,4) 19 -- Net payable to Sithe (5,6,7) 5 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. (2) In February 2002, Generation entered into an agreement to loan AmerGen up to $75 million at an interest rate equal to the one-month London Interbank Offering Rate plus 2.25%. In July 2002, the limit of the loan agreement was increased to $100 million and the maturity date was extended to July 1, 2003. As of June 30, 2003, the principal balance of the loan was paid in full. Total interest earned on the loan was less than $1 million during the three and six months ended June 30, 2003 and 2002. (3) Under the terms of the agreement to acquire Exelon New England dated November 1, 2002, Generation issued a $534 million note to be paid in full on June 18, 2003 to Sithe. 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 and the balance of the note is to be paid by December 1, 2003 or upon change of control. The note bears interest at the rate equal to LIBOR plus 0.875%. Interest accrued on the note as of June 30, 2003 was $0.3 million. (4) Under a service agreement dated March 1, 1999, Generation provides AmerGen with certain operation and support services to the nuclear facilities owned by AmerGen. This service agreement has an indefinite term and may be terminated by Generation or AmerGen with 90 days notice. Generation is compensated for these services at cost. (5) Under a service agreement dated December 18, 2000, Generation provides certain engineering and environmental services for fossil facilities owned by Sithe and for certain developmental projects. Generation is compensated for these services at cost. Total revenue earned under this service agreement was less than $1 million for the three and six months ended June 30, 2003 and 2002. (6) Under a service agreement dated December 18, 2000, Sithe provides Generation certain fuel and project development services. Sithe is compensated for these services at cost. (7) Under a service agreement dated November 1, 2002, Sithe provides Generation certain transition services related to the transition of the Exelon New England asset acquisition which occurred November 1, 2002. 58 In addition to the transactions with unconsolidated affiliates described above, Generation's financial statements reflect a number of related-party transactions as reflected in the tables below.
Three Months Ended June 30, Six Months Ended June 30, -------------------------- ------------------------- 2003 2002 2003 2002 ------------------------------------------------------------------------------------------------------------------------- Operating revenues from affiliates ComEd (1) $ 528 $ 547 $ 1,099 $ 1,079 PECO (1) 324 346 681 649 Exelon Energy Company (2) 44 60 109 117 Purchased power from affiliates ComEd (4) 13 8 20 14 PECO (4) -- 3 -- 5 Exelon Energy Company (4) 2 -- 9 2 Operating & maintenance from affiliates ComEd (4) 2 2 6 5 PECO (4) 3 -- 5 2 BSC (6) 35 35 71 87 Interest expense - affiliate ComEd (8) 1 -- 1 -- Exelon (3) -- 1 1 1 Cash distribution paid to member 45 -- 45 -- ------------------------------------------------------------------------------------------------------------------------- June 30, 2003 December 31, 2002 ------------------------------------------------------------------------------------------------------------------------- Receivables from affiliates (current) ComEd (1) $ 185 $ 339 ComEd decommissioning receivable (7) 11 59 PECO (1) 121 124 BSC (6) -- 14 Exelon Energy Company (2) 16 19 Other 1 -- Receivables from affiliates (noncurrent) ComEd decommissioning receivable (7) 19 218 PECO decommissioning receivable (5) 16 -- Other -- 2 Payables to affiliates (current) Exelon (3) 3 3 BSC (6) 18 -- Payable to affiliate (noncurrent) ComEd decommissioning (5) 1,094 -- Notes payable to affiliate - Exelon (3) 226 329 Notes payable to affiliates - ComEd (8) 165 -- ----------------------------------------------------------------------------------------------------------------------- (1) Effective January 1, 2001, Generation entered into PPAs with ComEd and PECO. See Note 8 - Commitments and Contingencies for further information on the PPAs. (2) Generation sells power to Exelon Energy Company (an Enterprises company). (3) Generation has a payable to Exelon related to certain compensation plans. (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. (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. 59 (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 has a note payable to ComEd related to Generation's short-term liquidity requirements.
12. SUPPLEMENTAL FINANCIAL INFORMATION (Exelon, ComEd and PECO)
June 30, December 31, ComEd 2003 2002 ----------------------------------------------------------------------------------------------------------------------- Regulatory Assets (Liabilities) Nuclear decommissioning (see Note 2 - New Accounting Principles and Accounting Changes) $ (1,094) $ -- Nuclear decommissioning costs for retired plants -- 248 Recoverable transition costs 153 175 Reacquired debt costs and interest rate swap settlements 173 84 Recoverable deferred income taxes (64) (68) Other 22 8 ----------------------------------------------------------------------------------------------------------------------- Total $ (810) $ 447 ======================================================================================================================= June 30, December 31, PECO 2003 2002 ----------------------------------------------------------------------------------------------------------------------- Regulatory Assets Competitive transition charge $ 4,478 $ 4,639 Recoverable deferred income taxes 744 729 Non-pension postretirement benefits 62 64 Reacquired debt costs 51 53 Nuclear decommissioning and decontamination funds 29 32 Nuclear decommissioning (see Note 2 - New Accounting Principles and Accounting Changes) 16 -- MGP regulatory asset (see Note 8 - Commitments and Contingencies) 16 20 Compensated absences 15 6 Post-employment benefits 3 3 ----------------------------------------------------------------------------------------------------------------------- Long-term regulatory assets 5,414 5,546 Deferred energy costs (current asset) 55 31 ----------------------------------------------------------------------------------------------------------------------- Total $ 5,469 $ 5,577 =======================================================================================================================
Exelon's long-term regulatory assets and liabilities as of June 30, 2003 were $5,414 million and $810 million, respectively. Exelon's long-term regulatory assets as of December 31, 2002 were $5,993 million. 60 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Dollars in millions, unless otherwise noted) EXELON CORPORATION ------------------ GENERAL Exelon Corporation (Exelon), a registered public utility holding company, through its subsidiaries, operates in three business segments: o Energy Delivery, 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 6 of the Condensed Combined Notes to Consolidated Financial Statements for further segment information. RESULTS OF OPERATIONS Three Months Ended June 30, 2003 Compared To Three Months Ended June 30, 2002 Net Income and Earnings Per Share Exelon's net income for the three months ended June 30, 2003 decreased $113 million or 23%, compared to the same period in 2002. Diluted earnings per common share on the same basis decreased $0.36 per share, or 24%. The decrease in net income was due to unfavorable weather impacts at Energy Delivery due to cooler spring weather and a goodwill impairment charge recorded at the InfraSource, Inc. reporting unit within Enterprises during the second quarter 2003. Also, a gain was recorded in the second quarter of 2002 due to the sale of an investment in AT&T Wireless held by Enterprises. These decreases were partially offset by increased market sales and mark-to-market activity at Generation, reduced depreciation expense resulting from lower depreciation rates at Energy Delivery and decreased interest expense at Energy Delivery due to refinancing of outstanding debt at lower interest rates. 61 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 June 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 June 30, --------------------------- 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------------ Energy Delivery $ 291 $ 322 $ (31) (9.6%) Generation 142 84 58 69.0% Enterprises (61) 83 (144) (173.5%) Corporate -- (4) 4 (100.0%) ------------------------------------------------------------------------------------------------------ Total $ 372 $ 485 $ (113) (23.3%) ======================================================================================================
Results of Operations - Energy Delivery
Three Months Ended June 30, --------------------------- Energy Delivery 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------------ Operating revenues $ 2,322 $ 2,476 $ (154) (6.2%) Revenue, net of purchased power & fuel expense 1,336 1,465 (129) (8.8%) Operating income 666 736 (70) (9.5%) Income before income taxes 481 522 (41) (7.9%) Net income 291 322 (31) (9.6%) -------------------------------------------------------------------------------------------------------------------------
The changes in Energy Delivery's revenue, net of purchased power and fuel expense, for the three months ended June 30, 2003 compared to the same period in 2002, included the following: o unfavorable weather impacts of $66 million, primarily the result of cooler spring weather, o unfavorable pricing changes of $22 million related to ComEd's Power Purchase Agreement (PPA) with Generation, o net unfavorable changes due to customer choice of $20 million, including ComEd's customers electing to purchase energy from alternative energy suppliers or electing ComEd's Power Purchase Option (PPO), under which non-residential customers can purchase power from ComEd at a market-based rate, and customers in PECO's service territory selecting an alternative electric generation supplier, 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 were not recorded in purchased power in 2002 (see Note 2 of the Condensed Combined Notes to Consolidated Financial Statements), o changes in customer rates resulting in an $8 million unfavorable variance, and o lower PJM ancillary charges resulting in a favorable variance of $7 million. The changes in operating income, other than changes in revenue net of purchased power and fuel expense, for the three months ended June 30, 2003 compared to the same period in 2002, included the following: o reduction in depreciation expense of $24 million due to the impact of lower depreciation rates at ComEd effective July 1, 2002, partially offset by increased depreciation expense in 2003 of $11 million due to higher plant in service balances, o reduction of amortization expense of $16 million for nuclear decommissioning of retired plants at ComEd due to the adoption of SFAS No. 143 (see Note 2 of the Condensed Combined Notes to Consolidated Financial Statements), o decreased costs of $7 million associated with the initial implementation of automated meter reading services at PECO, and o a reversal of $12 million of accrued use tax at PECO as a result of an audit settlement. The changes in income before income taxes for the three months ended June 30, 2003 compared to the same period in 2002 included a reduction in interest expense primarily related to a decrease of $24 million attributable to less outstanding debt and refinancing of existing debt at lower interest rates. Energy Delivery's effective income tax rate was 39.5% for the three months ended June 30, 2003, compared to 38.3% for the same period in 2002. 63
Energy Delivery Operating Statistics and Revenue Detail Energy Delivery's electric sales statistics and revenue detail are as follows: Three Months Ended June 30, --------------------------- Retail Deliveries - (in gigawatthours (GWhs))(1) 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Bundled Deliveries (2) Residential 7,437 7,977 (540) (6.8%) Small Commercial & Industrial 6,646 7,481 (835) (11.2%) Large Commercial & Industrial 5,378 6,049 (671) (11.1%) Public Authorities & Electric Railroads 1,555 1,885 (330) (17.5%) ------------------------------------------------------------------------------------------------------- Total Bundled Deliveries 21,016 23,392 (2,376) (10.2%) ------------------------------------------------------------------------------------------------------- Unbundled Deliveries (3) Alternative Energy Suppliers ---------------------------- Residential 186 557 (371) (66.6%) Small Commercial & Industrial 1,580 1,179 401 34.0% Large Commercial & Industrial 2,320 1,635 685 41.9% Public Authorities & Electric Railroads 247 181 66 36.5% ------------------------------------------------------------------------------------------------------- 4,333 3,552 781 22.0% ------------------------------------------------------------------------------------------------------- PPO (ComEd Only) ---------------- Small Commercial & Industrial 869 839 30 3.6% Large Commercial & Industrial 1,318 1,392 (74) (5.3%) Public Authorities & Electric Railroads 531 274 257 93.8% ------------------------------------------------------------------------------------------------------- 2,718 2,505 213 8.5% ------------------------------------------------------------------------------------------------------- Total Unbundled Deliveries 7,051 6,057 994 16.4% ------------------------------------------------------------------------------------------------------- Total Retail Deliveries 28,067 29,449 (1,382) (4.7%) ======================================================================================================= (1) One GWh is the equivalent of one million kilowatthours (kWh). (2) Bundled service reflects deliveries to customers taking electric generation service under tariffed rates. (3) Unbundled service reflects customers electing to receive electric generation service from an alternative energy supplier or ComEd's PPO.
64
Three Months Ended June 30, --------------------------- Electric Revenue 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------ Bundled Revenues (1) Residential $ 769 $ 801 $ (32) (4.0%) Small Commercial & Industrial 585 669 (84) (12.6%) Large Commercial & Industrial 351 404 (53) (13.1%) Public Authorities & Electric Railroads 102 121 (19) (15.7%) ------------------------------------------------------------------------------------------------------- Total Bundled Revenues 1,807 1,995 (188) (9.4%) ------------------------------------------------------------------------------------------------------- Unbundled Revenues (2) Alternative Energy Suppliers ---------------------------- Residential 14 42 (28) (66.7%) Small Commercial & Industrial 49 30 19 63.3% Large Commercial & Industrial 48 33 15 45.5% Public Authorities & Electric Railroads 8 5 3 60.0% ------------------------------------------------------------------------------------------------------- 119 110 9 8.2% ------------------------------------------------------------------------------------------------------- PPO (ComEd Only) ---------------- Small Commercial & Industrial 59 55 4 7.3% Large Commercial & Industrial 72 76 (4) (5.3%) Public Authorities & Electric Railroads 28 17 11 64.7% ------------------------------------------------------------------------------------------------------- 159 148 11 7.4% ------------------------------------------------------------------------------------------------------- Total Unbundled Revenues 278 258 20 7.8% ------------------------------------------------------------------------------------------------------- Total Electric Retail Revenues 2,085 2,253 (168) (7.5%) ------------------------------------------------------------------------------------------------------- Wholesale and Miscellaneous Revenue (3) 127 139 (12) (8.6%) ------------------------------------------------------------------------------------------------------- Total Electric Revenue $ 2,212 $ 2,392 $ (180) (7.5%) ======================================================================================================= (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 (CTC). (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 June 30, 2003 as compared to the same period in 2002 were attributable to the following: Variance ------------------------------------------------------------------------- Weather $ (129) Customer choice (46) Volume 18 Rate changes (8) Other effects (3) ------------------------------------------------------------------------- Electric retail revenue $ (168) ========================================================================= 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 June 30, 2003 was unfavorable compared to the same period in 2002 as a result of cooler spring weather in 2003. Cooling degree-days in the ComEd and PECO service territories 65 were 63% lower and 40% lower, respectively, in 2003 as compared to 2002. Heating degree-days in the ComEd and PECO service territories were 1% lower and 38% higher, respectively, in 2003 as compared to 2002. 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 June 30, 2003, 15% 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 $38 million from customers in Illinois electing to purchase energy from an ARES or ComEd's PPO, and a decrease in revenues of $8 million from customers in Pennsylvania selecting an alternative electric generation supplier. During the second quarter of 2003, approximately 2,500 customers temporarily returned to ComEd's PPO as a result of an ARES no longer providing service in Illinois. 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. The auction for the second phase of the residential customer MST plan is scheduled for September 2003 and the selected customers would be transferred effective December 2003. Any customer transferred would 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. o Volume. Revenues from higher delivery sales, exclusive of the effect of weather, increased $25 million at ComEd due to an increased number of customers and increased usage per customer, primarily residential and ComEd's PPO. Revenues from delivery sales, exclusive of the effect of weather, decreased $7 million at PECO due to lower usage in the residential and large commercial and industrial customer classes, partially offset by an increase in usage by small commercial and industrial customers. o Rate Changes. The decrease in revenues attributable to rate changes reflects decreased wholesale market prices which decreased energy revenue received under ComEd's PPO by 66 $48 million. This was partially offset by the collection of $40 million in additional CTC's in 2003 by ComEd due to an increase in sales to customers choosing an alternative energy supplier (ARES) or the ComEd PPO and an increase in CTC rates due to lower wholesale market price of electricity, net of increased mitigation factors. Energy Delivery's gas sales statistics and revenue detail were as follows:
Three Months Ended June 30, --------------------------- 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------------- Deliveries in million cubic feet (mmcf) 15,001 14,286 715 5.0% Revenue $ 110 $ 84 $ 26 31.0% -------------------------------------------------------------------------------------------------------------------------
The changes in gas revenue for the three months ended June 30, 2003 as compared to the same period in 2002, were as follows:
Variance ------------------------------------------------------------------------------------------------------------------------ Weather $ 14 Rate changes 10 Volume 2 ------------------------------------------------------------------------------------------------------------------------ Gas revenue $ 26 ========================================================================================================================
o Weather. The demand for gas is impacted by weather conditions. Very cold weather in non-summer months is referred to as "favorable weather conditions," because these weather conditions result in increased sales of gas. Conversely, mild weather reduces demand. The weather impact was favorable compared to the prior year as a result of cooler spring weather. Heating degree-days increased 38% in PECO's service territory for the three months ended June 30, 2003 compared to the same period in 2002. o Rate Changes. The favorable variance in rate changes is attributable to a 15% increase and a 7% increase 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 June 30, 2003 was 22% higher than the rate in 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 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. Exclusive of weather impacts, delivery volume was consistent in the three months ended June 30, 2003 compared to the same period in 2002 with increased retail sales partially offset by lower transportation volumes. Deliveries to customers, excluding transportation and the effects of weather, increased 4% in the three months ended June 30, 2003 compared to the same period in 2002. 67 Results of Operations - Generation
Three Months Ended June 30, --------------------------- 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------------ Operating revenues $ 1,886 $ 1,559 $ 327 21.0% Revenue, net of purchased power & fuel expense 738 630 108 17.1% Operating income 201 113 88 77.9% Income before income taxes 233 135 98 72.6% Net income 142 84 58 69.0% ------------------------------------------------------------------------------------------------------------------------
The changes in Generation's revenue, net of purchased power and fuel expense, for the three months ended June 30, 2003 compared to the same period in 2002, included the following: o increased market sales of $385 million primarily attributable to regional demand and price increases, partially offset by increased purchased power of $95 million and increased fuel expense of $124 million, o increases of $31 million for generation from plants acquired during 2002 resulting in higher market sales, o unfavorable weather conditions in the ComEd and PECO service territories in 2003 resulted in a net volume decrease offset by overall price increases of $57 million, o increased revenue from ComEd of $16 million associated with the adoption of SFAS No. 143, which was not included in revenue in 2002, o mark-to-market gains on hedging activities of $32 million in 2003 compared to $4 million in 2002, and o additional nuclear fuel amortization of $10 million resulting from under performing fuel at the Quad Cities Unit 1. The changes in operating income, other than changes in revenue net of purchased power and fuel expense, for the three months ended June 30, 2003 compared to the same period in 2002, included the following: o higher costs of $8 million for employee medical, pension and other employee payroll and benefit costs in 2003, o increased operating and maintenance (O&M) costs of $8 million due to asset acquisitions made after the second quarter of 2002 and including a $5 million impairment charge recorded in 2003 related to Mystic Station Units 4, 5, and 6, o reduced refueling outage costs of $21 million, including $17 million at one of Generation's co-owned facilities, resulting from fewer refueling outage days in 2003, o additional depreciation of $4 million due to capital additions placed in service and plant acquisitions made after the second quarter of 2002 and $7 million related to plant acquisitions made after the second quarter of 2002, partially offset by $3 million of lower depreciation due to life extensions of asset additions in 2002, and o accretion expense of $43 million recognized in 2003 to accrete the asset retirement obligation established at the adoption of SFAS No. 143, partially offset by the elimination of decommissioning expense of $31 million, also as a result of the adoption of SFAS No. 143. 68 The changes in income before income taxes for the three months ended June 30, 2003 compared to the same period in 2002, included the following: o increased decommissioning trust investment income of $15 million, which is almost entirely offset by accretion expense recorded in O&M, o increased equity in earnings of unconsolidated affiliates of $9 million, and o increased interest expense of $9 million primarily due to reduced capitalized interest in 2003 in addition to interest incurred on the note payable to Sithe. Generation's effective income tax rate was 39.2% for the three months ended June 30, 2003 compared to 37.7% for the same period in 2002. This increase was primarily attributable to an increase in taxes related to the nuclear decommissioning trust funds. Generation Operating Statistics Generation's sales and the supply of these sales, excluding the trading portfolio, were as follows:
Three Months Ended June 30, --------------------------- Sales (in GWhs) 2003 2002 Variance % Change ----------------------------------------------------------------------------------------------------------------------- Energy Delivery and Exelon Energy Company 26,869 29,649 (2,780) (9.4%) Market Sales 27,449 20,589 6,860 33.3% ----------------------------------------------------------------------------------------------------------- Total Sales 54,318 50,238 4,080 8.1% =========================================================================================================== Three Months Ended June 30, --------------------------- Supply of Sales (in GWhs) 2003 2002 Variance % Change ----------------------------------------------------------------------------------------------------------------------- Nuclear Generation (1) 29,619 28,776 843 2.9% Purchases - non-trading portfolio (2) 19,344 17,978 1,366 7.6% Fossil and Hydro Generation 5,355 3,484 1,871 53.7% ----------------------------------------------------------------------------------------------------------- Total Supply 54,318 50,238 4,080 8.1% =========================================================================================================== (1) Excluding AmerGen. (2) Including purchased power agreements with AmerGen.
Trading volume of 7,919 GWhs and 8,566 GWhs for the three months ended June 30, 2003 and 2002, respectively, is 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 Exelon's Risk Management Committee and approved by the Board of Directors. 69 Generation's average margin and other operating data for the three months ended June 30, 2003 and 2002 were as follows:
Three Months Ended June 30, --------------------------- ($/MWh) 2003 2002 % Change ----------------------------------------------------------------------------------------------------------------------- Average Revenue Energy Delivery and Exelon Energy Company $ 32.67 $ 32.06 1.9% Market Sales 34.98 30.69 14.0% Total - excluding the trading portfolio 33.83 31.50 7.4% Average Supply Cost (1) - excluding the trading portfolio $ 20.71 $ 18.79 10.2% Average Margin - excluding the trading portfolio $ 13.12 $ 12.71 3.2% ----------------------------------------------------------------------------------------------------------------------- (1) Average supply cost includes purchased power and fuel costs.
Three Months Ended June 30, --------------------------- 2003 2002 ------------------------------------------------------------------------------------------------------------------------ Nuclear fleet capacity factor (1) 94.0% 92.1% Nuclear fleet production cost per MWh (1) $ 12.08 $ 12.54 Average purchased power cost for wholesale operations per MWh $ 43.15 $ 39.96 ------------------------------------------------------------------------------------------------------------------------ (1) Including AmerGen and excluding Salem.
The factors below contributed to the overall increase in Generation's average margin for the three months ended June 30, 2003 as compared to the same period in 2002. Generation's average revenue per MWh was affected by: o increased weighted average on and off-peak prices per MWh for supply agreements with ComEd, o higher prices per MWh on sales under supply agreements with PECO, and o higher market prices. Generation's supply mix changed 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 Sithe New England (now known as Exelon New England) plants acquired in November 2002, which in total account for an increase of 1,498 GWhs, and o increased quantity of purchased power to service greater than anticipated customer loads outside of the Energy Delivery service areas. Higher nuclear capacity factors and decreased nuclear production costs are primarily due to 20 fewer planned refueling outage days, resulting in a $4 million decrease in outage costs, in the three months ended June 30, 2003 as compared to the same period in 2002. Additionally, the three months ended June 30, 2003 included nine unplanned outages compared to eight unplanned outages during the three months ended June 30, 2002. 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 70 factors. Problems that may occur at nuclear facilities that result in increased costs include accelerated replacement of suspect fuel assemblies, generation reductions to make repairs and mid-cycle outages. For example, in the second quarter of 2003, the Quad Cities Unit 1 required a significant repair and is unable to operate above an 85% capacity factor until the Nuclear Regulatory Commission (NRC) inspects and approves the maintenance work. 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 anticipates NRC approval of the maintenance work and to return the unit to its normal operating capacity in the near future. Results of Operations - Enterprises
Three Months Ended June 30, --------------------------- 2003 2002 Variance % Change --------------------------------------------------------------------------------------------------------------------- Operating revenues $ 443 $ 476 $ (33) (6.9%) Operating loss (57) (15) (42) n.m. Income (loss) before income taxes (95) 142 (237) (166.9%) Net income (loss) (61) 83 (144) (173.5%) --------------------------------------------------------------------------------------------------------------------- n.m. - not meaningful
The changes in Enterprises' operating loss for the three months ended June 30, 2003 compared to the same period in 2002, included the following: o an impairment charge of $47 million before income taxes related to the goodwill of InfraSource, Inc. The applicable assets and liabilities of InfraSource, Inc. were classified as held for sale during the second quarter of 2003, o lower operating income at InfraSource, Inc. of $12 million primarily resulting from a decrease in the electric line of business, o higher operating income at Exelon Energy Company of $9 million resulting from lower operating expense from the discontinuance of retail sales in the PJM region including accelerated depreciation of assets of $7 million and general and administrative costs of $2 million in 2002, o higher operating income at Exelon Thermal of $3 million resulting from lower production costs, and o reductions in general and administrative expenses of $6 million. The changes in income (loss) before income taxes for the three months ended June 30, 2003 compared to the same period in 2002, include the following additional impacts: o a pre-tax gain of $198 million recorded on the AT&T Wireless sale in 2002, o an impairment charge in 2003 of energy-related investments of $22 million and communications investments of $13 million due to an other than temporary decline in value compared to an impairment charge in 2002 of communications investments of $27 million, energy related investments of $9 million and a net impairment of other assets of $4 million, and o lower equity in earnings of unconsolidated affiliates of $3 million resulting from lower earnings at a communications joint venture. 71 The effective income tax rate was 35.8% for the three months ended June 30, 2003, compared to 41.5% for the same period in 2002. This decrease in the effective tax rate was attributable to lower effective income tax rates on the impairments. Six Months Ended June 30, 2003 and Six Months Ended June 30, 2002 Net Income and Earnings Per Share Exelon's net income for the six months ended June 30, 2003 increased $241 million or 49%, compared to the same period in 2002. Diluted earnings per common share on the same basis increased $0.72 per share, or 47%. Net income for the six months ended June 30, 2003 reflects $112 million of income for the cumulative effect of a change in accounting principle as a result of the adoption of Financial Accounting Standards Board (FASB) Statement of Financial Accounting (SFAS) No. 143, "Asset Retirement Obligations" (SFAS No. 143), while net income for the six months ended June 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 six months ended June 30, 2003 decreased $101 million, or 14%, compared to the same period in 2002. Diluted earnings per common share on the same basis decreased $0.33 per share, or 15%. The decrease in income before cumulative effect of changes in accounting principles reflects an impairment of an investment in Sithe held by Generation in the first quarter of 2003 and a goodwill impairment charge recorded at the InfraSource, Inc. reporting unit within Enterprises during the second quarter 2003. Also, Energy Delivery recorded a one-time charge in the first quarter of 2003 as the result of an agreement (see Note 4 of the Condensed Combined Notes to Consolidated Financial Statements) and a gain was recorded in the second quarter of 2002 due to the sale of an investment in AT&T Wireless held by Enterprises. These items were partially offset by increased recoveries of competitive transition charges (CTCs), increased market sales and mark-to-market activity at Generation, reduced depreciation expense resulting from lower depreciation rates at Energy Delivery and decreased interest expense at Energy Delivery due to refinancing of outstanding debt at lower interest rates. Results of Operations by Business Segment The comparisons presented under this heading are comparisons of operating results and other statistical information for the six months ended June 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. 72 Net Income (Loss) Before Cumulative Effect of Changes in Accounting Principles by Business Segment
Six Months Ended June 30, ------------------------- 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------------- Energy Delivery $ 616 $ 538 $ 78 14.5% Generation 89 150 (61) (40.7%) Enterprises (78) 55 (133) n.m. Corporate (6) (21) 15 (71.4%) ------------------------------------------------------------------------------------------------------ Total $ 621 $ 722 $ (101) (14.0%) ====================================================================================================== n.m. - not meaningful Net Income (Loss) by Business Segment Six Months Ended June 30, ------------------------- 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------------- Energy Delivery $ 621 $ 538 $ 83 15.4% Generation 197 163 34 20.9% Enterprises (79) (188) 109 (58.0%) Corporate (6) (21) 15 (71.4%) ------------------------------------------------------------------------------------------------------ Total $ 733 $ 492 $ 241 49.0% ====================================================================================================== Results of Operations - Energy Delivery Six Months Ended June 30, ------------------------- Energy Delivery 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------------ Operating revenues $ 4,964 $ 4,811 $ 153 3.2% Revenue, net of purchased power & fuel expense 2,789 2,777 12 0.4% Operating income 1,360 1,296 64 4.9% Income before income taxes and cumulative effect of a change in accounting principle 998 864 134 15.5% Income before cumulative effect of a change in accounting principle 616 538 78 14.5% Net income 621 538 83 15.4% ------------------------------------------------------------------------------------------------------------------------
The changes in Energy Delivery's revenue, net of purchased power and fuel expense, for the six months ended June 30, 2003 compared to the same period in 2002, included the following: o changes in customer rates resulting in a $75 million increase, o increases in weather normalized volumes of $34 million as a result of increases in the number of customers and additional average usage per customer, primarily residential customers at ComEd, and small and large commercial and industrial customers at PECO, o net favorable weather impacts of $12 million, primarily the results of colder winter weather, partially offset by cooler spring weather, o net unfavorable changes due to customer choice of $28 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 unfavorable pricing changes of $39 million related to ComEd's PPA with Generation, 73 o unfavorable variance of $31 million under the ComEd PPA with Generation related to decommissioning collections associated with the adoption of SFAS No. 143 in 2003, which were not recorded in purchased power in 2002 (see Note 2 of the Condensed Combined Notes to Consolidated Financial Statements), and o higher PJM ancillary charges resulted in an unfavorable variance of $8 million. The changes in operating income, other than changes in revenue net of purchased power and fuel expense, for the six months ended June 30, 2003 compared to the same period in 2002, included the following: o a net one-time charge of $41 million in 2003 at ComEd as the result of an agreement described in Note 4 of Condensed Combined Notes to Consolidated Financial Statements, 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 $20 million due to higher plant in service balances, o reduction of amortization expense of $31 million for nuclear decommissioning of retired plants at ComEd due to the adoption of SFAS No. 143 (see Note 2 of the Condensed Combined Notes to Consolidated Financial Statements), o lower amortization of ComEd's recoverable transition costs of $20 million in 2003, o a reversal of $12 million of accrued use tax at PECO as a result of an audit settlement, and o additional amortization in 2003 of $15 million at PECO related to PECO's competitive transition charge in accordance with the Pennsylvania Competitive Act. The changes in income before income taxes and cumulative effect of a change in accounting principle for the six months ended June 30, 2003 compared to the same period in 2002, included the following: o a reduction in interest expense primarily related to a decrease of $45 million attributable to less outstanding debt and refinancing of existing debt at lower interest rates, and o the reversal in 2003 of a $12 million reserve for a potential capital disallowance as the result of an agreement described in Note 4 of the Condensed Combined Notes to Consolidated Financial Statements. Energy Delivery's effective income tax rate was 38.3% for the six months ended June 30, 2003, compared to 37.7% 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. 74 Energy Delivery Operating Statistics and Revenue Detail Energy Delivery's electric sales statistics and revenue detail are as follows:
Six Months Ended June 30, ------------------------- Retail Deliveries - (GWhs) 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------------ Bundled Deliveries (1) Residential 17,438 16,441 997 6.1% Small Commercial & Industrial 14,053 14,687 (634) (4.3%) Large Commercial & Industrial 10,344 11,357 (1,013) (8.9%) Public Authorities & Electric Railroads 3,224 3,879 (655) (16.9%) ----------------------------------------------------------------------------------------------------------- Total Bundled Deliveries 45,059 46,364 (1,305) (2.8%) ----------------------------------------------------------------------------------------------------------- Unbundled Deliveries (2) Alternative Energy Suppliers ---------------------------- Residential 450 1,348 (898) (66.6%) Small Commercial & Industrial 3,131 2,280 851 37.3% Large Commercial & Industrial 4,362 3,124 1,238 39.6% Public Authorities & Electric Railroads 529 319 210 65.8% ----------------------------------------------------------------------------------------------------------- 8,472 7,071 1,401 19.8% ----------------------------------------------------------------------------------------------------------- PPO (ComEd Only) ---------------- Small Commercial & Industrial 1,662 1,602 60 3.7% Large Commercial & Industrial 2,750 2,703 47 1.7% Public Authorities & Electric Railroads 1,069 517 552 106.8% ----------------------------------------------------------------------------------------------------------- 5,481 4,822 659 13.7% ----------------------------------------------------------------------------------------------------------- Total Unbundled Deliveries 13,953 11,893 2,060 17.3% ----------------------------------------------------------------------------------------------------------- Total Retail Deliveries 59,012 58,257 755 1.3% =========================================================================================================== (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.
75
Six Months Ended June 30, ------------------------- Electric Revenue 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------------- Bundled Revenues (1) Residential $ 1,673 $ 1,563 $ 110 7.0% Small Commercial & Industrial 1,177 1,249 (72) (5.8%) Large Commercial & Industrial 692 750 (58) (7.7%) Public Authorities & Electric Railroads 207 230 (23) (10.0%) ------------------------------------------------------------------------------------------------------------ Total Bundled Revenues 3,749 3,792 (43) (1.1%) ------------------------------------------------------------------------------------------------------------ Unbundled Revenues (2) Alternative Energy Suppliers ---------------------------- Residential 31 96 (65) (67.7%) Small Commercial & Industrial 99 48 51 106.3% Large Commercial & Industrial 103 45 58 128.9% Public Authorities & Electric Railroads 17 7 10 142.9% ------------------------------------------------------------------------------------------------------------ 250 196 54 27.6% ------------------------------------------------------------------------------------------------------------ PPO (ComEd Only) ---------------- Small Commercial & Industrial 109 98 11 11.2% Large Commercial & Industrial 144 140 4 2.9% Public Authorities & Electric Railroads 55 29 26 89.7% ------------------------------------------------------------------------------------------------------------ 308 267 41 15.4% ------------------------------------------------------------------------------------------------------------ Total Unbundled Revenues 558 463 95 20.5% ------------------------------------------------------------------------------------------------------------ Total Electric Retail Revenues 4,307 4,255 52 1.2% ------------------------------------------------------------------------------------------------------------ Wholesale and Miscellaneous Revenue (3) 258 263 (5) (1.9%) ------------------------------------------------------------------------------------------------------------ Total Electric Revenue $ 4,565 $ 4,518 $ 47 1.0% ============================================================================================================ (1) Bundled revenue reflects deliveries to customers taking electric service under tariffed rates, which include the cost of energy and the delivery cost of the transmission and the distribution of the energy. 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 six months ended June 30, 2003 as compared to the same period in 2002 were attributable to the following:
Variance ------------------------------------------------------------------------------------------------------------------------- Rate changes 75 Volume 68 Customer choice (66) Weather (28) Other effects 3 ------------------------------------------------------------------------------------------------------------------------- Electric retail revenue $ 52 =========================================================================================================================
o Rate Changes. The increase in revenues attributable to rate changes reflects the collection of additional CTC's in 2003 by ComEd of $146 million due to an increase in sales to customers choosing an ARES or the ComEd PPO and an increase in CTC rates due to lower wholesale market price of electricity, net of increased mitigation factors. Lower wholesale market prices decreased energy revenue received under ComEd's PPO by $71 million. 76 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 customer class for ComEd and in the small and large commercial and industrial customer classes for PECO. o Customer Choice. For the six months ended June 30, 2003, 14% 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 $77 million from customers in Illinois electing to purchase energy from an ARES or ComEd's PPO, partially offset by an increase in revenues of $11 million from customers in Pennsylvania selecting or returning to PECO as their electric generation supplier. o Weather. The weather impact for the six months ended June 30, 2003 was unfavorable compared to the same period in 2002 as a result of cooler spring weather in 2003, partially offset by colder winter weather. Cooling degree-days in the ComEd and PECO service territories were 63% lower and 40% lower, respectively, in 2003 as compared to 2002. Heating degree-days in the ComEd and PECO service territories were 13% higher and 34% higher, respectively, in 2003 as compared to 2002. Energy Delivery's gas sales statistics and revenue detail were as follows:
Six Months Ended June 30, ------------------------- 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------------ Deliveries in million cubic feet (mmcf) 54,627 45,643 8,984 19.7% Revenue $ 399 $ 293 $ 106 36.2% ------------------------------------------------------------------------------------------------------------------------
The changes in gas revenue for the six months ended June 30, 2003 as compared to the same period in 2002, were as follows:
Variance ------------------------------------------------------------------------------------------------------------------------ Weather $ 73 Volume 17 Rate changes 13 Other 3 ------------------------------------------------------------------------------------------------------------------------ Gas revenue $ 106 ========================================================================================================================
o Weather. The weather impact was favorable compared to the prior year as a result of colder winter weather. Heating degree-days increased 34% in PECO's service territory for the six months ended June 30, 2003 compared to the same period in 2002. o Volume. Exclusive of weather impacts, higher delivery volume increased revenue in the six months ended June 30, 2003 compared to the same period in 2002 resulting from increased retail sales partially offset by lower transportation volumes. Deliveries to customers, excluding transportation and the effects of weather, increased 6% in the six months ended June 30, 2003 compared to the same period in 2002. 77 o Rate Changes. The favorable variance in rate changes is attributable to a 15% increase and a 7% increase 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 six months ended June 30, 2003 was 13% 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. Results of Operations - Generation
Six Months Ended June 30, ------------------------- 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------------ Operating revenues $ 3,765 $ 3,020 $ 745 24.7% Revenue, net of purchased power & fuel expense 1,417 1,264 153 12.1% Operating income 295 202 93 46.0% Income before income taxes and cumulative effect of changes in accounting principles 160 246 (86) (35.0%) Income before cumulative effect of changes in accounting principles 89 150 (61) (40.7%) Net income 197 163 34 20.9% ------------------------------------------------------------------------------------------------------------------------
The changes in Generation's revenue, net of purchased power and fuel expense, for the six months ended June 30, 2003 compared to the same period in 2002, included the following: o increased demand due to customers returning to PECO from alternative energy suppliers and overall favorable weather conditions in the ComEd and PECO service territories in 2003 resulting in net volume and price increases of $22 million, o increases of $63 million for generation from plants acquired during 2002 resulting in higher market sales, o increased revenue from ComEd of $31 million associated with the adoption of SFAS No. 143, which was not included in revenue in 2002, o mark-to-market gains on hedging activities of $1 million in 2003 compared to $10 million in 2002, and o additional nuclear fuel amortization of $16 million in 2003 resulting from under performing fuel at the Quad Cities Unit 1. The changes in operating income, other than changes in revenue net of purchased power and fuel expense, for the six months ended June 30, 2003 compared to the same period in 2002, included the following: o increased accretion expense of $103 million due to the adoption of SFAS No. 143, partially offset by reduced decommissioning expense of $64 million, o higher costs of $36 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, o increased O&M costs of $38 million due to asset acquisitions made during 2002 and a $5 million impairment charge recorded in 2003 related to Mystic Station Units 4, 5, and 6, o reduced refueling outage costs of $53 million, including $17 million at one of Generation's co-owned facilities, resulting from fewer refueling outage days in 2003, 78 o additional depreciation of $10 million due to capital additions placed in service and plant acquisitions made during 2002 and $16 million due to plant acquisitions made after the second quarter of 2002, partially offset by a $10 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 income before income taxes and cumulative effect of changes in accounting principles for the six months ended June 30, 2003 compared to the same period in 2002, included the following: o a pre-tax impairment charge of $200 million related to Generation's equity investment in Sithe, o increased decommissioning trust investment income of $33 million, which is almost entirely offset with accretion expense recorded in O&M, o increased equity in earnings of unconsolidated affiliates of $5 million, and o increased interest expense of $10 million primarily due to reduced capitalized interest in 2003 in addition to interest incurred on the note payable to Sithe. Generation's effective income tax rate was 44.2% for the six months ended June 30, 2003 compared to 39.0% for the same period in 2002. This increase was primarily attributable to the impact of the impairment of Generation's investment in Sithe, as well as an increase in taxes related to the nuclear decommissioning trust funds. Cumulative effect of changes in accounting principles recorded in the six months ended June 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. 79 Generation Operating Statistics Generation's sales and the supply of these sales, excluding the trading portfolio, were as follows:
Six Months Ended June 30, ------------------------- Sales (in GWhs) 2003 2002 Variance % Change ----------------------------------------------------------------------------------------------------------------------- Energy Delivery and Exelon Energy Company 57,463 58,649 (1,186) (2.0%) Market Sales 51,264 39,913 11,351 28.4% ----------------------------------------------------------------------------------------------------------- Total Sales 108,727 98,562 10,165 10.3% =========================================================================================================== Six Months Ended June 30, ------------------------- Supply of Sales (in GWhs) 2003 2002 Variance % Change ----------------------------------------------------------------------------------------------------------------------- Nuclear Generation (1) 58,949 56,309 2,640 4.7% Purchases - non-trading portfolio (2) 39,373 36,071 3,302 9.2% Fossil and Hydro Generation 10,405 6,182 4,223 68.3% ----------------------------------------------------------------------------------------------------------- Total Supply 108,727 98,562 10,165 10.3% =========================================================================================================== (1) Excluding AmerGen. (2) Including purchased power agreements with AmerGen.
Trading volume of 17,446 GWhs and 22,805 GWhs for the six months ended June 30, 2003 and 2002, respectively, is 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 six months ended June 30, 2003 and 2002 were as follows:
Six Months Ended June 30, ------------------------- ($/MWh) 2003 2002 % Change ------------------------------------------------------------------------------------------------------------------------ Average Revenue Energy Delivery and Exelon Energy Company $ 32.06 $ 31.35 2.3% Market Sales 35.94 29.44 22.1% Total - excluding the trading portfolio 33.89 30.58 10.8% Average Supply Cost (1) - excluding the trading portfolio $ 20.58 $ 17.78 15.7% Average Margin - excluding the trading portfolio $ 13.31 $ 12.80 4.0% ------------------------------------------------------------------------------------------------------------------------ (1) Average supply cost includes purchased power and fuel costs.
Six Months Ended June 30, ------------------------- 2003 2002 --------------------------------------------------------------------------------------------------------------------------- Nuclear fleet capacity factor (1) 94.2% 91.2% Nuclear fleet production cost per MWh (1) $ 12.40 $ 13.38 Average purchased power cost for wholesale operations per MWh $ 41.71 $ 36.76 --------------------------------------------------------------------------------------------------------------------------- (1) Including AmerGen and excluding Salem.
The factors below contributed to the overall increase in Generation's average margin for the six months ended June 30, 2003 as compared to the same period in 2002. 80 Generation's average revenue per MWh was affected by: o increased weighted average on and off-peak prices per MWh for supply agreements with ComEd, o higher prices per MWh on sales under supply agreements with PECO, and o higher market prices. Generation's supply mix changed 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 Sithe New England (currently known as Exelon New England) plants acquired in November 2002, which in total account for an increase of 2,995 GWhs, and o increased quantity of purchased power at higher prices. Higher nuclear capacity factors and decreased nuclear production costs are primarily due to 50 fewer planned refueling outage days, resulting in a $36 million decrease in outage costs, in the six months ended June 30, 2003 as compared to the same period in 2002. Additionally, the six months ended June 30, 2003 included 11 unplanned outages compared to 13 unplanned outages during the six months ended June 30, 2002. Results of Operations - Enterprises
Six Months Ended June 30, ------------------------- 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------------ Operating revenues $ 1,022 $ 966 $ 56 5.8% Operating loss (84) (50) (34) 68.0% Income (loss) before income taxes and cumulative effect of changes in accounting principles (125) 95 (220) n.m. Income (loss) before cumulative effect of changes in accounting principles (78) 55 (133) n.m. Net loss (79) (188) 109 (58.0%) ------------------------------------------------------------------------------------------------------------------------ n.m. - not meaningful
The changes in Enterprises' operating loss for the six months ended June 30, 2003 compared to the same period in 2002, included the following: o an impairment charge of $47 million before income taxes related to the goodwill of InfraSource, Inc. The applicable assets and liabilities of InfraSource, Inc. were classified as held for sale during the second quarter of 2003, o lower operating income at InfraSource Inc. of $5 million primarily resulting from a decrease in the electric line of business of $13 million and a $2 million decrease in metering services partially offset by lower costs of $7 million in the telecom line of business and $3 million from bad debt expense recorded in 2002, o higher operating income at Exelon Energy Company of $6 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 81 costs of $3 million. These costs were partially offset by lower gross margins of $11 million in 2003. The lower gross margins resulted from the reversal of mark-to-market adjustments of $11 million and additional gas supply costs of $11 million attributable to gas purchases at high rates in the Northeast, partially offset by higher gross margins of $8 million in the Midwest attributable to increased unit margins and higher volumes, and $2 million favorable related to the wind-down of a contract, o higher operating income at Exelon Thermal of $4 million resulting from lower production costs, and o reductions in general and administrative expenses of $9 million. The changes in income (loss) before income taxes and cumulative effect of changes in accounting principles for the six months ended June 30, 2003 compared to the same period in 2002, include the following additional impacts: o a pre-tax gain of $198 million in 2002 and higher equity in earnings of unconsolidated affiliates of $4 million in 2003 primarily as a result of the discontinuation of losses on the investment in AT&T Wireless due to the sale of the investment in the second quarter of 2002, 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 37.6% for the six months ended June 30, 2003, compared to 42.1% 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 compared to the tax rate on the gain on the sale of Enterprises' AT&T Wireless investment. 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 taxes (see Note 2 of the Condensed Combined Notes to Consolidated Financial Statements). 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. 82 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. In the second quarter of 2003, Exelon progressed in its plans to implement its new business model referred to as The Exelon Way. The Exelon Way is focused on improving operating cash flows while meeting service and financial commitments through improved integration of operations and consolidation of support functions. Exelon is working to meet its goals of 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 anticipates incurring expenses associated with the rationalization of certain business functions and employee separation costs. These expenses may be significant and are expected to be incurred during the remaining half of 2003 through 2005. However, these costs cannot be reasonably estimated at this time. Cash Flows from Operating Activities Cash flows provided by operations for the six months ended June 30, 2003 were $1.3 billion compared to $1.6 billion in the six months ended June 30, 2002. The decrease in cash flows was primarily attributable to a $229 million decrease in working capital and the $240 million funding of the pension benefit obligation. Energy Delivery's cash flow from operating activities primarily results from sales of electricity and gas to a stable and diverse base of retail 83 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 and customer choice on its revenues. Generation's cash flows from operating activities primarily result from the sale of electric energy to wholesale customers, including Energy Delivery and Enterprises. Generation's future cash flow from operating activities will depend upon future demand and market prices for energy and the ability to continue to produce and supply power at competitive costs. Although the amounts may vary from period to period as a result of the uncertainties inherent in business, Exelon expects that Energy Delivery and Generation will continue to provide a reliable and steady source of internal cash flow from operations for the foreseeable future. Cash Flows used in Investing Activities Cash flows used in investing activities for the six months ended June 30, 2003 were $1.0 billion, compared to $1.3 billion for the six months ended June 30, 2002. The decrease in cash flows is primarily attributable to a reduction in plant acquisition costs of $443 million as a result of the acquisition of generating plants during the six months ended June 30, 2002, a reduction of capital expenditures of $9 million, the receipt of liquidating damages of $86 million from Raytheon during the six months ended June 30, 2003, partially offset by increased investments in nuclear decommissioning trust funds of $52 million and a reduction of proceeds from the sale of investments of $279 million primarily attributable to the sale of AT&T Wireless during the six months ended June 30, 2002. Capital expenditures by business segment for the six months ended June 30, 2003 and 2002 were as follows:
Six Months Ended June 30, ------------------------- 2003 2002 ------------------------------------------------------------------------------------------------------------------ Energy Delivery $ 487 $ 495 Generation 424 475 Enterprises 11 28 Corporate and other 11 30 ------------------------------------------------------------------------------------------------------------------ Total capital expenditures (net of liquidated damages received) $ 933 $ 1,028 ==================================================================================================================
Energy Delivery's capital expenditures for 2003 reflect the continuation of efforts to further improve the reliability of its distribution system. 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 Exelon New England generating facilities with projected capacity of 2,421 MWs of energy, additions to and upgrades of existing facilities (including nuclear refueling outages), and nuclear fuel. During the six months ended June 30, 2003, Generation received $86 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 generating facilities. In February 2002, Generation entered into an agreement to loan AmerGen up to $75 million at an interest rate of one-month LIBOR plus 2.25%. In July 2002, the loan agreement and the loan were increased to $100 million and the maturity date was extended to July 1, 2003. As of June 30, 2003, the loan has 84 been fully repaid by AmerGen. 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 $284 million for the six months ended June 30, 2003 compared to $142 million for the same period in 2002. The increase in cash flows is primarily attributable to debt and preferred securities issuances of $2.1 billion and an increase of proceeds from the exercise of employee stock options over the same period in 2002 of $31 million partially offset by retirements and redemptions of debt and preferred securities of $1.9 billion, the $210 million payment of the acquisition note payable to Sithe and increased interest rate swap settlement payments of $41 million over the same period in 2002. See Note 9 of the Condensed Combined Notes to Consolidated Financial Statements for further discussion of Exelon's debt and preferred securities financing activities in 2003. 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, PECO and Generation. 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. As of June 30, 2003, Exelon Corporate's sublimit was $1.0 billion, ComEd's was $100 million, PECO's was $400 million and the sublimit for Generation was zero. The credit facility is used principally to support the commercial paper programs of Exelon Corporate, ComEd, PECO and Generation. At June 30, 2003, Exelon's Consolidated Balance Sheet reflected $581 million of commercial paper outstanding. For the six months ended June 30, 2003, the average interest rate on notes payable was approximately 1.38%. 85 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 June 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 June 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's subsidiary, Commonwealth Edison Company of Indiana, Inc., PECO, Generation and Exelon Business Services Company (BSC) may participate in the money pool as lenders and borrowers, and Exelon Corporate and ComEd as lenders. Contributions to and permitted 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 six months ended June 30, 2003, ComEd had various loans to Generation under the money pool. The maximum amount of loans outstanding at any time during the six months ended June 30, 2003 was $342 million. As of June 30, 2003, the outstanding loan balance was $165 million. Exelon Boston Generating, LLC (EBG), an indirect subsidiary of Generation, has approximately $1.1 billion of debt outstanding under a $1.25 billion credit facility (EBG Facility) at June 30, 2003. The EBG Facility was entered into primarily to finance the construction of the Mystic 8 and 9 and Fore River generating units. The EBG Facility requires 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 are 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 are in commercial operation, although construction has not progressed to the point of Project Completion. Construction of Fore River is substantially complete and the unit is currently undergoing testing. EBG does not anticipate that the projects will achieve Project Completion by August 29, 2003. The EBG Facility is non-recourse to Exelon and 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. 86 As a result of Exelon's continuing evaluation of the projects and discussions with the lenders in July 2003, 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 Exelon's 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. Exelon expects Generation will incur an impairment of its EBG related assets, which, in aggregate, could reach approximately $550 million after income taxes. The debt outstanding under the EBG Facility of approximately $1.1 billion at June 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 relating to the $536 million note that was used to purchase the EBG facilities. This note was restructured in June 2003 to provide for a payment of $210 million of the principal on June 16, 2003 and payment of the remaining principal on the earlier of December 1, 2003 or change of control. 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. 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 June 30, 2003, there was $2.3 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 June 30, 2003, Exelon had provided $1.7 billion of guarantees under the SEC order. See Contractual Obligations, Commercial Commitments and Off-Balance Sheet Obligations in this section for further discussion of guarantees. The SEC order requires Exelon and ComEd to maintain a ratio of common equity to total capitalization (including securitization debt) on and after June 30, 2002 of not less than 30%. At June 30, 2003, Exelon and ComEd's common 87 equity ratios were 34% and 46%, 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. 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 June 30, 2003, Exelon had retained earnings of $2.5 billion, including ComEd's retained earnings of $767 million, PECO's retained earnings of $455 million and Generation's undistributed earnings of $1.1 billion. 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 June 30, 2003, Exelon had invested $2.2 billion in EWGs, leaving $1.8 billion of investment authority under the order. Exelon's request for an additional $1.5 billion in EWG investment authorization is pending with the SEC. Contractual Obligations, 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 June 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. 88 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. 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 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 and PECO have entered into several agreements with a tax consultant related to the filing of refund claims with the Internal Revenue Service (IRS). The fees for these agreements are contingent upon a successful outcome and are based upon a percentage of the refunds recovered from the IRS, if any. As such, ComEd and PECO would have positive net cash flows related to these agreements if any fees are paid to the tax consultant. These potential tax benefits and associated fees could be material to the financial position, results of operations and cash flows of 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 9 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 Nuclear Power Station (Oyster Creek) through April 9, 2009. See Note 8 of the Condensed Combined Notes to Consolidated Financial Statements for commercial commitments tables 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 35.2% interest in Sithe owned by Apollo Energy, LLC and the 14.9% interest owned by subsidiaries of Marubeni Corporation. The total call price was based on the terms of the existing Put and Call Agreement (PCA) among the parties and approximated $650 million. The transfer of ownership requires various regulatory approvals including FERC, the state environmental agency in New Jersey, and expiration of the Hart Scott Rodino waiting period. Under the terms of the PCA, the call must be funded within six months of the call notice being issued. Additionally, because the Federal Power Act restricts Exelon's ownership of 50% or more of Qualifying Facilities (QFs), the QFs owned by Sithe must be sold or restructured before closing to preserve their QF status. Despite the issuance of the call notice, Generation continues to pursue options to sell its investment in Sithe in its entirety. o In June 2003, Generation entered an agreement with USEC Inc. to purchase approximately $700 million of nuclear fuel from 2005 through 2010. 89 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 June 30, 2003 Compared to Three Months Ended June 30, 2002 Significant Operating Trends - ComEd
Three Months Ended June 30, --------------------------- 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------ OPERATING REVENUES $ 1,361 $ 1,481 $ (120) (8.1%) OPERATING EXPENSES Purchased power 533 553 (20) (3.6%) Operating and maintenance 221 220 1 0.5% Depreciation and amortization 96 133 (37) (27.8%) Taxes other than income 68 73 (5) (6.8%) ------------------------------------------------------------------------------------------------------ Total operating expenses 918 979 (61) (6.2%) ------------------------------------------------------------------------------------------------------ OPERATING INCOME 443 502 (59) (11.8%) OTHER INCOME AND DEDUCTIONS Interest expense (106) (127) 21 (16.5%) Distributions on mandatorily redeemable preferred securities (6) (7) 1 (14.3%) Other, net 12 14 (2) (14.3%) ------------------------------------------------------------------------------------------------------ Total other income and deductions (100) (120) 20 (16.7%) ------------------------------------------------------------------------------------------------------ INCOME BEFORE INCOME TAXES 343 382 (39) (10.2%) INCOME TAXES 138 151 (13) (8.6%) ------------------------------------------------------------------------------------------------------ NET INCOME $ 205 $ 231 $ (26) (11.3%) ======================================================================================================
Net Income Net income decreased $26 million, or 11% for the three months ended June 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 customers purchasing energy from an ARES or the PPO, partially offset by lower depreciation and amortization expense and interest expense. 90 Operating Revenues ComEd's electric sales statistics are as follows:
Three Months Ended June 30, --------------------------- Retail Deliveries - (in GWhs) 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Bundled Deliveries (1) Residential 5,163 5,862 (699) (11.9%) Small Commercial & Industrial 5,114 5,600 (486) (8.7%) Large Commercial & Industrial 1,683 2,122 (439) (20.7%) Public Authorities & Electric Railroads 1,333 1,685 (352) (20.9%) ------------------------------------------------------------------------------------------------ 13,293 15,269 (1,976) (12.9%) ------------------------------------------------------------------------------------------------ Unbundled Deliveries (2) ARES ---- Small Commercial & Industrial 1,257 1,177 80 6.8% Large Commercial & Industrial 2,128 1,622 506 31.2% Public Authorities & Electric Railroads 247 181 66 36.5% ------------------------------------------------------------------------------------------------ 3,632 2,980 652 21.9% ------------------------------------------------------------------------------------------------ PPO --- Small Commercial & Industrial 869 839 30 3.6% Large Commercial & Industrial 1,318 1,392 (74) (5.3%) Public Authorities & Electric Railroads 531 274 257 93.8% ------------------------------------------------------------------------------------------------ 2,718 2,505 213 8.5% ------------------------------------------------------------------------------------------------ Total Unbundled Deliveries 6,350 5,485 865 15.8% ------------------------------------------------------------------------------------------------ Total Retail Deliveries 19,643 20,754 (1,111) (5.4%) ================================================================================================ (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.
91
Three Months Ended June 30, --------------------------- Electric Revenue 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------ Bundled Revenues (1) Residential $ 472 $ 523 $ (51) (9.8%) Small Commercial & Industrial 405 445 (40) (9.0%) Large Commercial & Industrial 84 116 (32) (27.6%) Public Authorities & Electric Railroads 81 102 (21) (20.6%) -------------------------------------------------------------------------------------------------- 1,042 1,186 (144) (12.1%) -------------------------------------------------------------------------------------------------- Unbundled Revenues (2) ARES ---- Small Commercial & Industrial 32 30 2 6.7% Large Commercial & Industrial 43 32 11 34.4% Public Authorities & Electric Railroads 8 5 3 60.0% -------------------------------------------------------------------------------------------------- 83 67 16 23.9% -------------------------------------------------------------------------------------------------- PPO --- Small Commercial & Industrial 59 55 4 7.3% Large Commercial & Industrial 72 76 (4) (5.3%) Public Authorities & Electric Railroads 28 17 11 64.7% -------------------------------------------------------------------------------------------------- 159 148 11 7.4% -------------------------------------------------------------------------------------------------- Total Unbundled Revenues 242 215 27 12.6% -------------------------------------------------------------------------------------------------- Total Electric Retail Revenues 1,284 1,401 (117) (8.4)% Wholesale and Miscellaneous Revenue (3) 77 80 (3) (3.8)% -------------------------------------------------------------------------------------------------- Total Electric Revenue $ 1,361 $ 1,481 $ (120) (8.1)% -------------------------------------------------------------------------------------------------- (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 June 30, 2003, as compared to the same period in 2002, are attributable to the following:
Variance ------------------------------------------------------------------------------------------------------------------- Weather $ (108) Customer choice (38) Volume 25 Rate changes (8) Other effects 12 ------------------------------------------------------------------------------------------------------------------- Electric retail revenue $ (117) ===================================================================================================================
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 June 30, 2003 was unfavorable compared to the same period in 2002 as a result of cooler spring weather in 2003. Cooling degree-days decreased 63% in the three months ended June 30, 2003 compared to the same period in 2002 and were 49% lower than normal. 92 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 June 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 June 30, 2003, the energy provided by alternative suppliers was 3,632 GWhs or 18.5% as compared to 2,980 GWhs or 14.4% for the three months ended June 30, 2002. The decrease in revenues reflects customers in Illinois electing to purchase energy from an ARES or the PPO. As of June 30, 2003, the number of retail customers that had elected to purchase energy from an ARES or the ComEd PPO was approximately 22,000 or 0.6% as compared to 22,700 or 0.6% as of June 30, 2002. MWhs delivered to such customers increased from approximately 5.5 million for the three months ended June 30, 2002 to 6.3 million for the three months ended June 30, 2003, or from 26% to 32% of total quarterly retail deliveries. During the second quarter 2003, approximately 2,500 customers temporarily came back to the ComEd PPO as a result of an ARES no longer providing service in Illinois. o Volume. Revenues from higher delivery volume, exclusive of weather, increased due to an increased usage per customer, primarily residential and PPO. o Rate Changes. The decrease in revenues attributable to rate changes reflects decreased wholesale market prices which decreased energy revenue received under ComEd's PPO by $48 million. This was partially offset by the collection of additional CTC's in 2003 by ComEd of $40 million due to an increase in sales to customers choosing an ARES or the ComEd PPO and an increase in the CTC rates due to lower wholesale market prices of electricity, net of increased mitigation factors. 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 4 of the Condensed Combined Notes to Consolidated Financial Statements, decreases the collection of CTC's as compared to the respective period in 2002. Wholesale and miscellaneous revenue for the three months ended June 30, 2003 were comparable to the three months ended June 30, 2002. Purchased Power Purchased power expense decreased $20 million, or 4% for the three months ended June 30, 2003. The decrease in purchased power expense was primarily attributable to a $47 million decrease due to unfavorable weather conditions, a $21 million decrease as a result of customers choosing to purchase energy from an ARES, partially offset by an increase of $10 million due to higher volume, $22 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 that were not included in purchased power in 2002. The $16 million increase in purchased power expense related to SFAS No. 143 is offset by lower regulatory asset amortization. 93 Operating and Maintenance O&M expense increased $1 million for the three months ended June 30, 2003. The increase in O&M expense was primarily attributable to an increase of $6 million in the reserve for manufactured gas plant (MGP) investigation and remediation as a result of increased costs of a MGP site in Oak Park, Illinois, partially offset by lower other O&M's. Depreciation and Amortization Depreciation and amortization expense decreased $37 million, or 28%, for the three months ended June 30, 2003 as follows:
Three Months Ended June 30, --------------------------- 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Depreciation expense $ 76 $ 92 $ (16) (17.4%) Recoverable transition costs amortization 12 20 (8) (40.0%) Other amortization expense 8 21 (13) (61.9%) -------------------------------------------------------------------------------------------------- Total depreciation and amortization $ 96 $ 133 $ (37) (27.8%) ==================================================================================================
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 $24 million ($14 million, net of income taxes) for the three months ended June 30, 2003. Recoverable transition costs amortization decreased in the three months ended June 30, 2003 compared to the same period in 2002. The decrease is a result of the extension of the rate freeze through 2006 that occurred in June 2002. ComEd expects to fully recover its recoverable transition costs regulatory asset balance of $153 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 is offset by increased purchased power expense from Generation. Taxes Other Than Income Taxes other than income decreased by $5 million or 7%, as a result of a 2003 refund of $5 million for Illinois Electricity Distribution Taxes, a $5 million decrease in other taxes partially offset by a $5 million increase in Illinois Public Utility Fund taxes, which were not charged in 2002. 94 Interest Charges Interest charges consist of interest expense and distributions on mandatorily redeemable preferred securities. Interest charges decreased $21 million, or 17%, for the three months ended June 30, 2003 as a result of scheduled principal payments and refinancing existing debt at lower interest rates. Other, Net Other, net decreased by $2 million for the three months ended June 30, 2003 as compared to the same period in 2002. Income Taxes The effective income tax rate was 40.2% for the three months ended June 30, 2003, compared to 39.5% for the three months ended June 30, 2002. Six Months Ended June 30, 2003 Compared to Six Months Ended June 30, 2002 Significant Operating Trends - ComEd
Six Months Ended June 30, ------------------------- 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- OPERATING REVENUES $ 2,785 $ 2,796 $ (11) (0.4%) OPERATING EXPENSES Purchased power 1,110 1,091 19 1.7% Operating and maintenance 483 457 26 5.7% Depreciation and amortization 190 268 (78) (29.1%) Taxes other than income 148 146 2 1.4% ------------------------------------------------------------------------------------------------------- Total operating expenses 1,931 1,962 (31) (1.6%) ------------------------------------------------------------------------------------------------------- OPERATING INCOME 854 834 20 2.4% OTHER INCOME AND DEDUCTIONS Interest expense (215) (252) 37 (14.7%) Distributions on mandatorily redeemable preferred securities (14) (15) 1 (6.7%) Other, net 34 29 5 17.2% ------------------------------------------------------------------------------------------------------- Total other income and deductions (195) (238) 43 (18.1%) ------------------------------------------------------------------------------------------------------- INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE 659 596 63 10.6% INCOME TAXES 263 236 27 11.4% ------------------------------------------------------------------------------------------------------- NET INCOME BEFORE CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE 396 360 36 10.0% CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE 5 -- 5 n.m. ------------------------------------------------------------------------------------------------------- NET INCOME $ 401 $ 360 $ 41 11.4% ======================================================================================================= n.m. - not meaningful
95 Net Income Net income increased $41 million, or 11% for the six months ended June 30, 2003 as compared to the same period in 2002. Net income was positively impacted by lower depreciation and amortization expense and lower interest expense, partially offset by lower operating revenues primarily due to unfavorable weather and customers purchasing energy from an ARES or the PPO. Operating Revenues ComEd's electric sales statistics are as follows:
Six Months Ended June 30, ------------------------- Retail Deliveries - (in GWhs) 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Bundled Deliveries (1) Residential 12,049 12,271 (222) (1.8%) Small Commercial & Industrial 10,741 11,049 (308) (2.8%) Large Commercial & Industrial 3,167 4,078 (911) (22.3%) Public Authorities & Electric Railroads 2,749 3,486 (737) (21.1%) ------------------------------------------------------------------------------------------------- 28,706 30,884 (2,178) (7.1%) ------------------------------------------------------------------------------------------------- Unbundled Deliveries (2) ARES ---- Small Commercial & Industrial 2,606 2,181 425 19.5% Large Commercial & Industrial 3,960 3,008 952 31.6% Public Authorities & Electric Railroads 529 319 210 65.8% ------------------------------------------------------------------------------------------------- 7,095 5,508 1,587 28.8% ------------------------------------------------------------------------------------------------- PPO --- Small Commercial & Industrial 1,662 1,602 60 3.7% Large Commercial & Industrial 2,750 2,703 47 1.7% Public Authorities & Electric Railroads 1,069 517 552 106.8% ------------------------------------------------------------------------------------------------- 5,481 4,822 659 13.7% ------------------------------------------------------------------------------------------------- Total Unbundled Deliveries 12,576 10,330 2,246 21.7% ------------------------------------------------------------------------------------------------- Total Retail Deliveries 41,282 41,214 68 0.2% ================================================================================================= (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.
96
Six Months Ended June 30, ------------------------- Electric Revenue 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------ Bundled Revenues (1) Residential $ 1,018 $ 1,041 $ (23) (2.2%) Small Commercial & Industrial 802 836 (34) (4.1%) Large Commercial & Industrial 158 218 (60) (27.5%) Public Authorities & Electric Railroads 165 194 (29) (14.9%) ------------------------------------------------------------------------------------------------- 2,143 2,289 (146) (6.4%) ------------------------------------------------------------------------------------------------- Unbundled Revenues (2) ARES ---- Small Commercial & Industrial 73 43 30 69.8% Large Commercial & Industrial 91 41 50 122.0% Public Authorities & Electric Railroads 17 7 10 142.9% ------------------------------------------------------------------------------------------------- 181 91 90 98.9% ------------------------------------------------------------------------------------------------- PPO --- Small Commercial & Industrial 109 98 11 11.2% Large Commercial & Industrial 144 140 4 2.9% Public Authorities & Electric Railroads 55 29 26 89.7% ------------------------------------------------------------------------------------------------- 308 267 41 15.4% ------------------------------------------------------------------------------------------------- Total Unbundled Revenues 489 358 131 36.6% ------------------------------------------------------------------------------------------------- Total Electric Retail Revenues 2,632 2,647 (15) (0.6%) Wholesale and Miscellaneous Revenue (3) 153 149 4 2.7% ------------------------------------------------------------------------------------------------- Total Electric Revenue $ 2,785 $ 2,796 $ (11) (0.4%) ================================================================================================= (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 six months ended June 30, 2003, as compared to the same period in 2002, are attributable to the following:
Variance ------------------------------------------------------------------------------------------------------------------ Customer choice $ (77) Rate changes 75 Weather (54) Volume 32 Other effects 9 ------------------------------------------------------------------------------------------------------------------ Electric retail revenue $ (15) ==================================================================================================================
o Customer Choice. The decrease in revenues reflects customers in Illinois electing to purchase energy from an ARES or the PPO. For the six months ended June 30, 2003, the energy provided by alternative suppliers was 7,095 GWhs or 17.2% as compared to 5,508 GWhs or 13.4% for the six months ended June 30, 2002. As of June 30, 2003, the number of retail customers that had elected to purchase energy from an ARES or the ComEd PPO was approximately 22,000 or 0.6% as compared to 97 22,700 or 0.6% as of June 30, 2002. MWhs delivered to such customers increased from approximately 10.3 million for the six months ended June 30, 2002 to 12.6 million for the six months ended June 30, 2003, or from 25% to 30% of total year-to-date retail deliveries. During the second quarter 2003, approximately 2,500 customers temporarily came back to the ComEd PPO as a result of an ARES no longer providing service in Illinois. o Rate Changes. The increase in revenues attributable to rate changes reflects the collection of additional CTC's in 2003 by ComEd of $146 million due to an increase in sales to customers choosing an ARES or the ComEd PPO and an increase in CTC rates due to lower wholesale market price of electricity, net of increased mitigation factors. Lower wholesale market prices decreased revenue received under ComEd's PPO by $71 million. o Weather. The weather impact for the six months ended June 30, 2003 was unfavorable compared to the same period in 2002 as a result of cooler spring weather in 2003. Cooling degree-days decreased 63% in the six months ended June 30, 2003 compared to the same period in 2002 and were partially offset by a 13% increase in heating degree days in the six months ended June 30, 2003 compared to the same period in 2002. 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 PPO. The $4 million increase in wholesale and miscellaneous revenue for the six months ended June 30, 2003 was comparable to the six months ended June 30, 2002. Purchased Power Purchased power expense increased $19 million, or 2% for the six months ended June 30, 2003. The increase in purchased power expense was primarily attributable to an increase of $22 million due to higher volume, an increase of $39 million due to pricing changes related to ComEd's PPA with Generation and an increase of $31 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, partially offset by a $27 million decrease due to unfavorable weather and a $49 million decrease as a result of customers choosing to purchase energy from an ARES. The $31 million increase in purchased power expense related to SFAS No. 143 is offset by lower regulatory asset amortization. Operating and Maintenance O&M expense increased $26 million, or 6%, for the six months ended June 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 4 of the Condensed Combined Notes to Consolidated Financial Statements and an increase of $6 million in the reserve for MGP investigation and remediation as a result of increased costs of a MGP site in Oak Park, Illinois, partially offset by higher corporate allocations in 2002 due to executive severance. 98 Depreciation and Amortization Depreciation and amortization expense decreased $78 million, or 29%, for the six months ended June 30, 2003 as follows:
Six Months Ended June 30, ------------------------- 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------ Depreciation expense $ 152 $ 183 $ (31) (16.9%) Recoverable transition costs amortization 23 43 (20) (46.5%) Other amortization expense 15 42 (27) (64.3%) ------------------------------------------------------------------------------------------------- Total depreciation and amortization $ 190 $ 268 $ (78) (29.1%) =================================================================================================
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 six months ended June 30, 2003. Recoverable transition costs amortization decreased in the six months ended June 30, 2003 compared to the same period in 2002. The decrease is a result of the extension of the rate freeze through 2006 that occurred in June 2002. ComEd expects to fully recover its recoverable transition costs regulatory asset balance of $153 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 is offset by increased purchased power expense from Generation. Taxes Other Than Income Taxes other than income were comparable for the six months ended June 30, 2003 and 2002, primarily as a result of a $5 million refund in 2003 of Illinois Electricity Distribution taxes offset by $6 million in Illinois Public Utility Fund taxes that were not charged in 2002. Interest Charges Interest charges consist of interest expense and distributions on mandatorily redeemable preferred securities. Interest charges decreased $37 million, or 15%, for the six months ended June 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 six months ended June 30, 2003 as compared to the six months ended June 30, 2002 and the annual retirement of $340 million in Transitional Trust Notes. 99 Other, Net Other, net increased by $5 million for the six months ended June 30, 2003 as compared to the same period in 2002. The increase was primarily attributable to the reversal of a $12 million reserve in 2003 for a potential plant disallowance as the result of the Agreement as more fully described in Note 4 to the Condensed Combined Notes to Consolidated Financial Statements. Income Taxes The effective income tax rate was 39.9% for the six months ended June 30, 2003, compared to 39.6% for the six months ended June 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. 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, 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 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. In the second quarter of 2003, ComEd progressed in its plans to implement the new business model referred to as The Exelon Way. The Exelon Way is focused on improving operating cash flows while meeting service and financial commitments through improved integration of operations and consolidation of support functions. As part of the implementation of The Exelon Way, ComEd anticipates incurring expenses associated with the rationalization of certain business functions and employee separation costs. These expenses may be significant and are expected to be incurred during the remaining half of 2003 through 2005. However, these costs cannot be reasonably estimated at this time. 100 Cash Flows from Operating Activities Cash flows provided by operations were $430 million for the six months ended June 30, 2003 compared to $740 million for the six months ended June 30, 2002. The decrease in cash flows in 2003 was primarily attributable to a $155 million decrease in working capital as a result of the paydown of intercompany payables to affiliates and other outstanding liabilities, a decrease of $87 million for pension and non-pension postretirement benefits obligation, a decrease in depreciation and amortization of $78 million partially offset by an increase in net income of $41 million. ComEd's future cash flows will depend upon the ability to achieve cost savings in operations and the impact of the economy, weather, and customer choice on its revenues. Although the amounts may vary from period to period as a result of 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 $506 million for the six months ended June 30, 2003 compared to $352 million for the six months ended June 30, 2002. The increase in cash flows used in investing activities in 2003 was primarily attributable to the $165 million loaned to Generation as part of the 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. Cash Flows from Financing Activities Cash flows from financing activities were $94 million for the six months ended June 30, 2003 as compared to cash flows used in financing of $57 million for the six months ended June 30, 2002. Cash flows from financing activities were primarily attributable to debt issuances partially offset by retirements and redemptions and payments of dividends to Exelon. The increase in cash flows from financing activities is primarily attributable to increased debt and preferred securities issuances of $634 million partially offset by increased debt and preferred securities redemptions of $452 million and increased interest rate swap settlement payments of $41 million. See Note 9 of the Condensed Combined Notes to Consolidated Financial Statements for further discussion of ComEd's debt and preferred securities financing activities. ComEd paid a $211 million dividend to Exelon during the six months ended June 30, 2003 compared to a $235 million dividend for the six months ended June 30, 2002. 101 Credit Issues ComEd meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from Exelon's intercompany money pool. ComEd, along with Exelon, PECO, and Generation, participates in a $1.5 billion unsecured 364-day revolving credit facility with a group of banks. 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 June 30, 2003, ComEd's sublimit was $100 million. The credit facility is used principally to support ComEd's commercial paper program. At June 30, 2003, ComEd had no commercial paper outstanding. For the six months ended June 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 June 30, 2003. At June 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's subsidiary, Commonwealth Edison Company of Indiana, Inc., PECO, Generation and BSC may participate in the money pool as lenders and borrowers, and Exelon Corporate and ComEd as lenders. Funding of, and borrowings from, the money pool are predicated on whether such funding results in mutual economic benefits to each of the participants, although Exelon is not permitted to be a net borrower from the money pool. 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 six months ended June 30, 2003, ComEd had various loans to Generation under the money pool. The maximum amount of outstanding loans at any time during 2003 was $342 million. As of June 30, 2003, Generation owed ComEd $165 million on these loans. For the six months ended June 30, 2003, ComEd earned $1 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 can only pay dividends from retained or current earnings. However, the SEC has authorized ComEd to pay up to $500 million in dividends out of additional paid-in capital, provided ComEd may not pay dividends out of paid-in capital after December 31, 2002 if its common equity is less than 30% of its total capitalization (including 102 transitional trust notes). At June 30, 2003, ComEd had retained earnings of $767 million and its common equity ratio was 46%. Long-term debt included $1.8 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 June 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 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 103 $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. The fees for these agreements are contingent upon a successful outcome and are based upon a percentage of the refunds recovered from the IRS, if any. As such, ComEd would have positive net cash flows related to these agreements if any fees are paid to the tax consultant. These potential tax benefits and associated fees could be material to the financial position, results of operations and cash flows of ComEd. 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 9 to the Condensed Combined Notes to Consolidated Financial Statements for discussion of material changes in ComEd's debt and preferred securities obligations from those set forth in the 2002 Form 10-K. o See Note 8 of the Condensed Combined Notes to Consolidated Financial Statements for commercial commitments tables 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. 104 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 June 30, 2003 Compared to Three Months Ended June 30, 2002 Significant Operating Trends - PECO
Three Months Ended June 30, --------------------------- 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- OPERATING REVENUES $ 961 $ 995 $ (34) (3.4%) OPERATING EXPENSES Purchased power 386 405 (19) (4.7%) Fuel 67 53 14 26.4% Operating and maintenance 121 131 (10) (7.6%) Depreciation and amortization 116 109 7 6.4% Taxes other than income 47 63 (16) (25.4%) ------------------------------------------------------------------------------------------------------ Total operating expenses 737 761 (24) (3.2%) ------------------------------------------------------------------------------------------------------ OPERATING INCOME 224 234 (10) (4.3%) ------------------------------------------------------------------------------------------------------ OTHER INCOME AND DEDUCTIONS Interest expense (83) (92) 9 (9.8%) Distributions on mandatorily redeemable preferred securities (2) (2) -- -- Other, net 1 2 (1) (50.0%) ------------------------------------------------------------------------------------------------------ Total other income and deductions (84) (92) 8 (8.7%) ------------------------------------------------------------------------------------------------------ INCOME BEFORE INCOME TAXES 140 142 (2) (1.4%) INCOME TAXES 52 49 3 6.1% ------------------------------------------------------------------------------------------------------ NET INCOME 88 93 (5) (5.4%) Preferred stock dividends (2) (2) -- -- ------------------------------------------------------------------------------------------------------ NET INCOME ON COMMON STOCK $ 86 $ 91 $ (5) (5.5%) ======================================================================================================
105 Net Income Net income on common stock decreased $5 million, or 6% for the three months ended June 30, 2003 as compared to the same period in 2002. The decrease was a result of lower sales volume and unfavorable weather conditions, partially offset by lower operating and maintenance expenses, taxes other than income and interest expense on debt. Operating Revenue PECO's electric sales statistics are as follows:
Three Months Ended June 30, --------------------------- Retail Deliveries - (in GWhs) 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------ Bundled Deliveries (1) Residential 2,274 2,115 159 7.5% Small Commercial & Industrial 1,532 1,881 (349) (18.6%) Large Commercial & Industrial 3,695 3,927 (232) (5.9%) Public Authorities & Electric Railroads 222 200 22 11.0% ------------------------------------------------------------------------------------------------ 7,723 8,123 (400) (4.9%) ------------------------------------------------------------------------------------------------ Unbundled Deliveries (2) Residential 186 557 (371) (66.6%) Small Commercial & Industrial 323 2 321 n.m. Large Commercial & Industrial 192 13 179 n.m. Public Authorities & Electric Railroads (3) -- -- -- -- ------------------------------------------------------------------------------------------------ 701 572 129 22.6% ------------------------------------------------------------------------------------------------ Total Retail Deliveries 8,424 8,695 (271) (3.1%) ================================================================================================ (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 alternative energy supplier. (3) PECO's unbundled sales to Public Authorities and Electric Railroads were less than one GWh per quarter. n.m. - not meaningful
Three Months Ended June 30, --------------------------- Electric Revenue 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------ Bundled Revenue (1) Residential $ 297 $ 278 $ 19 6.8% Small Commercial & Industrial 180 224 (44) (19.6%) Large Commercial & Industrial 267 288 (21) (7.3%) Public Authorities & Electric Railroads 21 19 2 10.5% ------------------------------------------------------------------------------------------------- 765 809 (44) (5.4%) ------------------------------------------------------------------------------------------------- Unbundled Revenue (2) Residential 14 42 (28) (66.7%) Small Commercial & Industrial 17 -- 17 100.0% Large Commercial & Industrial 5 1 4 n.m. Public Authorities & Electric Railroads (3) -- -- -- -- ------------------------------------------------------------------------------------------------- 36 43 (7) (16.3%) ------------------------------------------------------------------------------------------------- Total Electric Retail Revenues 801 852 (51) (6.0%) Wholesale and Miscellaneous Revenue (4) 50 59 (9) (15.3%) ------------------------------------------------------------------------------------------------- Total Electric Revenue $ 851 $ 911 $ (60) (6.6%) ================================================================================================= (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. 106 (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 June 30, 2003, as compared to the same period in 2002, are as follows:
Variance ------------------------------------------------------------------------------------------------------------------- Weather $ (21) Customer choice (8) Volume (7) Other effects (15) ------------------------------------------------------------------------------------------------------------------- Retail revenue $ (51) ===================================================================================================================
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 spring weather during the quarter. Cooling degree-days decreased 40% and heating degree-days increased 38% for the three months ended June 30, 2003 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 three months ended June 30, 2003, the energy provided by alternative suppliers was 701 GWhs or 8.3% as compared to 572 GWhs or 6.6% for the three months ended June 30, 2002. As of June 30, 2003, the number of customers served by alternative suppliers was 310,821 or 20.3% as compared to 308,866 or 20.2% as of June 30, 2002. The decrease in retail deliveries is primarily a result of customers selecting an alternative electric generation supplier. The PUC's 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 107 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. The auction for the second phase of the residential customer MST plan is scheduled for September 2003 and the selected customers would be transferred effective December 2003. Any customer transferred would 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. o Volume. Exclusive of weather impacts, lower delivery volume affected PECO's revenue by $7 million compared to the same period in 2002 primarily related to decreases in usage by the residential and large commercial and industrial customer classes partially offset by an increase in usage by the small commercial and industrial class. o Other Effects. The decrease in revenues from other effects is attributable to a decrease of $15 million in the average price mix related to all customer classes as compared to the same period in 2002. PECO's gas sales statistics for the three months ended June 30, 2003 as compared to the same period in 2002 are as follows:
Three Months Ended June 30, --------------------------- 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------------ Deliveries in mmcf 15,001 14,286 715 5.0% Revenue $ 110 $ 84 $ 26 31.0% ------------------------------------------------------------------------------------------------------------
The changes in gas revenue for the three months ended June 30, 2003, as compared to the same period in 2002, are as follows:
Variance ----------------------------------------------------------------------------------------------------------------------- Weather $ 14 Rate changes 10 Volume 2 ----------------------------------------------------------------------------------------------------------------------- Gas revenue $ 26 =======================================================================================================================
o Weather. The demand for gas is impacted by weather conditions. Very cold weather in non-summer months is referred to as "favorable weather conditions," because these weather conditions result in increased sales of gas. Conversely, mild weather reduces demand. The weather impact was favorable compared to the prior year as a result of cooler spring weather during the quarter. Heating degree-days increased 38% in the three months ended June 30, 2003 compared to the same period in 2002. o Rate Changes. The favorable variance in rate changes is attributable to a 15% increase and a 7% increase 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 June 30, 2003 was 22% 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. 108 o Volume. Exclusive of weather impacts, delivery volume was consistent in the three months ended June 30, 2003 compared to the same period in 2002 with increased retail sales, partially offset by lower transportation volumes. Deliveries to customers, excluding transportation and the effects of weather, increased 4% in the three months ended June 30, 2003 compared to the same period in 2002. Purchased Power Purchased power expense for the three months ended June 30, 2003 decreased $19 million, or 5%, as compared to the same period in 2002. The decrease in purchased power expense was primarily attributable to $12 million as a result of unfavorable weather conditions, $7 million related to lower PJM ancillary charges and $5 million from customers in Pennsylvania selecting an alternative electric generation supplier. Fuel Fuel expense for the three months ended June 30, 2003 increased $14 million, or 26%, as compared to the same period in 2002. This increase was primarily attributable to $11 million attributable to higher gas prices and $10 million as a result of favorable weather conditions partially offset by $8 million related to lower wholesale sales of gas. Operating and Maintenance O&M expense for the three months ended June 30, 2003 decreased $10 million, or 8%, as compared to the same period in 2002. The decrease in O&M expense was primarily attributable to $7 million of lower expense related to the allowance for the uncollectible accounts, $7 million of lower costs associated with the initial implementation of automated meter reading services, partially offset by $2 million related to higher corporate allocations and $2 million of additional severance costs. Depreciation and Amortization Depreciation and amortization expense for the three months ended June 30, 2003 increased $7 million, or 6%, as compared to the same period in 2002 as follows:
Three Months Ended June 30, --------------------------- 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Competitive transition charge amortization $ 79 $ 72 $ 7 9.7% Depreciation expense 33 32 1 3.1% Other amortization expense 4 5 (1) (20.0%) -------------------------------------------------------------------------------------------------- Total depreciation and amortization $ 116 $ 109 $ 7 6.4% ==================================================================================================
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 June 30, 2003 decreased $16 million, or 25%, as compared to the same period in 2002. The decrease was primarily attributable to $12 million related to the reversal of a use tax accrual resulting from an audit settlement and $2 million of lower gross receipts tax related to lower revenues. 109 Interest Charges Interest charges consist of interest expense and distributions on mandatorily redeemable preferred securities. Interest charges decreased $9 million, or 10%, in the three months ended June 30, 2003 as compared to the same period in 2002. The decrease was primarily attributable to lower interest expense on long-term debt of $9 million as a result of scheduled principal payments and refinancing of existing debt at lower interest rates. Other, Net Other, net decreased income by $1 million in the three months ended June 30, 2003 as compared to the same period in 2002. The decrease was attributable to lower interest income of $1 million. Income Taxes The effective tax rate was 37.1% for the three months ended June 30, 2003 as compared to 34.5% 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 June 30, 2003 were consistent as compared to the same period in 2002. 110 Six Months Ended June 30, 2003 Compared to Six Months Ended June 30, 2002 Significant Operating Trends - PECO
Six Months Ended June 30, ------------------------- 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------ OPERATING REVENUES $ 2,178 $ 2,015 $ 163 8.1% OPERATING EXPENSES Purchased power 808 756 52 6.9% Fuel 257 188 69 36.7% Operating and maintenance 261 267 (6) (2.2%) Depreciation and amortization 236 221 15 6.8% Taxes other than income 110 122 (12) (9.8%) ------------------------------------------------------------------------------------------------------- Total operating expenses 1,672 1,554 118 7.6% ------------------------------------------------------------------------------------------------------- OPERATING INCOME 506 461 45 9.8% ------------------------------------------------------------------------------------------------------- OTHER INCOME AND DEDUCTIONS Interest expense (168) (187) 19 (10.2%) Distributions on mandatorily redeemable preferred securities (5) (5) -- -- Other, net 10 2 8 n.m. ------------------------------------------------------------------------------------------------------- Total other income and deductions (163) (190) 27 (14.2%) ------------------------------------------------------------------------------------------------------- INCOME BEFORE INCOME TAXES 343 271 72 26.6% INCOME TAXES 119 90 29 32.2% ------------------------------------------------------------------------------------------------------- NET INCOME 224 181 43 23.8% Preferred stock dividends (3) (4) 1 (25.0%) ------------------------------------------------------------------------------------------------------- NET INCOME ON COMMON STOCK $ 221 $ 177 $ 44 24.9% ======================================================================================================= n.m. - not meaningful
Net Income Net income on common stock increased $44 million, or 25% for the six months ended June 30, 2003 as compared to the same period in 2002. The increase was a result of higher sales volume, favorable weather conditions and lower interest expense on debt, partially offset by increased income taxes and depreciation and amortization expense. 111 Operating Revenue PECO's electric sales statistics are as follows:
Six Months Ended June 30, ------------------------- Retail Deliveries (in GWhs) 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------ Bundled Deliveries (1) Residential 5,389 4,171 1,218 29.2% Small Commercial & Industrial 3,312 3,638 (326) (9.0%) Large Commercial & Industrial 7,177 7,278 (101) (1.4%) Public Authorities & Electric Railroads 475 393 82 20.9% ------------------------------------------------------------------------------------------------- 16,353 15,480 873 5.6% ------------------------------------------------------------------------------------------------- Unbundled Deliveries (2) Residential 450 1,348 (898) (66.6%) Small Commercial & Industrial 525 99 426 n.m. Large Commercial & Industrial 402 116 286 n.m. Public Authorities & Electric Railroads (3) -- -- -- -- ------------------------------------------------------------------------------------------------- 1,377 1,563 (186) (11.9%) ------------------------------------------------------------------------------------------------- Total Retail Deliveries 17,730 17,043 687 4.0% ================================================================================================= (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. n.m. - not meaningful
Six Months Ended June 30, ------------------------- Electric Revenue 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Bundled Revenue (1) Residential $ 656 $ 522 $ 134 25.7% Small Commercial & Industrial 374 413 (39) (9.4%) Large Commercial & Industrial 534 532 2 0.4% Public Authorities & Electric Railroads 42 37 5 13.5% -------------------------------------------------------------------------------------------------- 1,606 1,504 102 6.8% -------------------------------------------------------------------------------------------------- Unbundled Revenue (2) Residential 31 96 (65) (67.7%) Small Commercial & Industrial 27 5 22 n.m. Large Commercial & Industrial 11 3 8 n.m. Public Authorities & Electric Railroads (3) -- -- -- -- -------------------------------------------------------------------------------------------------- 69 104 (35) (33.7%) -------------------------------------------------------------------------------------------------- Total Electric Retail Revenues 1,675 1,608 67 4.2% Wholesale and Miscellaneous Revenue (4) 104 114 (10) (8.8%) -------------------------------------------------------------------------------------------------- Total Electric Revenue $ 1,779 $ 1,722 $ 57 3.3% ================================================================================================== (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.
112 The changes in electric retail revenues for the six months ended June 30, 2003, as compared to the same period in 2002, are as follows:
Variance ------------------------------------------------------------------------------------------------------------------------ Volume $ 36 Weather 26 Customer choice 11 Other effects (6) ------------------------------------------------------------------------------------------------------------------------ Retail revenue $ 67 ========================================================================================================================
o Volume. Exclusive of weather impacts, higher delivery volume affected PECO's revenue by $36 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 spring weather. Heating degree-days increased 34% and cooling degree-days decreased 40% for the six months ended June 30, 2003 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 six months ended June 30, 2003, the energy provided by alternative suppliers was 1,377 GWhs or 7.8% as compared to 1,563 GWhs or 9.2% for the six months ended June 30, 2002. As of June 30, 2003, the number of customers served by alternative suppliers was 310,821 or 20.3% as compared to 308,866 or 20.2% as of June 30, 2002. The increase in retail deliveries is primarily a result of customers selecting or returning to PECO as their electric generation supplier. o Other Effects. The decrease in revenues from other effects is attributable to a decrease of $6 million in the average price mix related to all customer classes as compared to the same period in 2002. 113 PECO's gas sales statistics for the six months ended June 30, 2003 as compared to the same period in 2002 are as follows:
Six Months Ended June 30, ------------------------- 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Deliveries in mmcf 54,627 45,643 8,984 19.7% Revenue $ 399 $ 293 $ 106 36.2% -------------------------------------------------------------------------------------------------------
The changes in gas revenue for the six months ended June 30, 2003, as compared to the same period in 2002, are as follows:
Variance ------------------------------------------------------------------------------------------------------------------ Weather $ 73 Volume 17 Rate changes 13 Other 3 ------------------------------------------------------------------------------------------------------------------ Gas revenue $ 106 ==================================================================================================================
o Weather. The weather impact was favorable compared to the prior year as a result of colder winter weather. Heating degree-days increased 34% in the six months ended June 30, 2003 compared to the same period in 2002. o Volume. Exclusive of weather impacts, higher delivery volume increased revenue in the six months ended June 30, 2003 compared to the same period in 2002 resulting from increased retail sales partially offset by lower transportation volumes. Deliveries to customers, excluding transportation and the effects of weather, increased 6% in the six months ended June 30, 2003 compared to the same period in 2002. o Rate Changes. The favorable variance in rates is attributable to a 15% increase and a 7% increase 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 six months ended June 30, 2003 was 13% 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. Purchased Power Purchased power expense for the six months ended June 30, 2003 increased $52 million, or 7%, as compared to the same period in 2002. The increase in purchased power expense was primarily attributable to $21 million as a result of higher electric delivery volume, $11 million from customers in Pennsylvania selecting or returning to PECO as their electric generation supplier, $10 million as a result of favorable weather conditions and $10 million related to higher PJM ancillary charges. 114 Fuel Fuel expense for the six months ended June 30, 2003 increased $69 million, or 40%, as compared to the same period in 2002. This increase was primarily attributable to $50 million as a result of favorable weather conditions, $14 million from higher gas prices and $8 million attributable to higher delivery volumes. Operating and Maintenance O&M expense for the six months ended June 30, 2003 decreased $6 million, or 2%, as compared to the same period in 2002. The decrease in O&M expense was primarily attributable to $13 million of lower costs associated with the initial implementation of automated meter reading services, $9 million of lower expense related to the allowance for uncollectible accounts and $5 million related to lower corporate allocations partially offset by $3 million of additional employee benefits costs, $4 million of incremental storm costs in 2003, $2 million of additional severance costs and $5 million of additional miscellaneous other net positive impacts. Depreciation and Amortization Depreciation and amortization expense for the six months ended June 30, 2003 increased $15 million, or 7%, as compared to the same period in 2002 as follows:
Six Months Ended June 30, ------------------------- 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------ Competitive transition charge amortization $ 161 $ 146 $ 15 10.3% Depreciation expense 66 63 3 4.8% Other amortization expense 9 12 (3) (25.0%) -------------------------------------------------------------------------------------------------- Total depreciation and amortization $ 236 $ 221 $ 15 6.8% ==================================================================================================
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 six months ended June 30, 2003 decreased $12 million, or 10%, as compared to the same period in 2002. The decrease was primarily attributable to $12 million related to the reversal of the use tax accrual resulting from an audit settlement and a $3 million decrease in real estate taxes partially offset by $5 million of additional gross receipts tax related to additional revenues. Interest Charges Interest charges consist of interest expense and distributions on mandatorily redeemable preferred securities. Interest charges decreased $19 million, or 10%, in the six months ended June 30, 2003 as compared to the same period in 2002. The decrease was primarily attributable to lower interest expense on long-term debt of $19 million as a result of scheduled principal payments and refinancing of existing debt at lower interest rates. 115 Other, Net Other, net increased by $8 million in the six months ended June 30, 2003 as compared to the same period in 2002. The increase was primarily attributable to higher interest income of $4 million and the favorable settlement of a customer contract of $3 million. Income Taxes The effective tax rate was 34.6% for the six months ended June 30, 2003 as compared to 33.2% 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 six months ended June 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 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. In the second quarter of 2003, PECO progressed in its plans to implement the new business model referred to as The Exelon Way. The Exelon Way is focused on improving operating cash flows while meeting service and financial commitments through improved integration of operations and consolidation of support functions. As part of the implementation of The Exelon Way, PECO anticipates incurring expenses associated with the rationalization of certain business functions and employee separation costs. These expenses may be significant and are expected to be incurred during the remaining half of 2003 through 2005. However, these 116 costs cannot be reasonably estimated at this time. Cash Flows from Operating Activities Cash flows provided by operations for the six months ended June 30, 2003 and 2002 were $425 million and $468 million, respectively. The decrease in cash flows was primarily attributable to a $73 million change in deferred energy costs and a $4 million decrease in working capital, partially offset by a $43 million increase in net income. PECO's cash flow from operating activities primarily results from sales of electricity and gas to a stable and diverse base of retail customers at fixed prices. PECO's future cash flows will depend upon the ability to achieve operating cost reductions and the impact of the economy, weather and customer choice on its revenues. Although the amounts may vary from period to period as a result of the uncertainties inherent in its business, PECO expects that it will continue to provide a reliable and steady source of internal cash flow from operations for the foreseeable future. Cash Flows from Investing Activities Cash flows used in investing activities for the six months ended June 30, 2003 and 2002 were $126 million and $122 million, respectively. The increase in cash flows used in investing activities was primarily attributable to an increase in other investing activities. PECO's projected capital expenditures for 2003 are $265 million. Approximately 60% of the budgeted 2003 expenditures are for capital additions and upgrades to existing facilities and the remainder are for capital additions to support customer load 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. Cash Flows from Financing Activities Cash flows used in financing activities for the six months ended June 30, 2003 and 2002 were $301 million and $306 million, respectively. Cash flows used in financing activities are primarily attributable to debt service and payment of dividends to Exelon. The decrease in cash flows used in financing activities is primarily attributable to additional issuances of long-term debt of $550 million, partially offset by increased debt and preferred securities redemptions of $485 million. See Note 9 of the Condensed Combined Notes to Consolidated Financial Statements for further discussion of PECO's debt financing activities. For the six months ended June 30, 2003, PECO paid Exelon $165 million in common stock dividends compared to $170 million for the same period in 2002. 117 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 June 30, 2003, PECO's sublimit was $400 million. The credit facility is used by PECO principally to support its commercial paper program. At June 30, 2003, PECO's Consolidated Balance Sheet reflects $170 million in commercial paper outstanding. For the six months ended June 30, 2003, the average interest rate on notes payable was approximately 1.31%. 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 June 30, 2003. At June 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's subsidiary, Commonwealth Edison Company of Indiana, Inc., PECO, Generation and BSC may participate in the money pool as lenders and borrowers, and Exelon Corporate and ComEd as lenders. Funding of, and borrowings from, the money pool are predicated on whether such funding results in mutual economic benefits to each of the participants, although Exelon is not permitted to be a net borrower from the money pool. 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 by PECO during the six months ended June 30, 2003. 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 can pay dividends only from retained or current earnings. At June 30, 2003, PECO had retained earnings of $455 million. Long-term debt included $4.1 billion of transition bonds. 118 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 June 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. 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, PECO would have positive net cash flows related to these agreements if any fees are paid to the tax consultant. These potential tax benefits and associated fees could be material to the financial position, results of operations and cash flows of PECO. PECO cannot predict the timing of the final resolution of these refund claims. o See Note 9 of the Condensed Combined Notes to Consolidated Financial Statements for further discussion of material changes in PECO's debt obligations from those set forth in the 2002 Form 10-K. o See Note 8 of the Condensed Combined Notes to Consolidated Financial Statements for commercial commitments tables representing 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. 119 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 June 30, 2003 Compared to Three Months Ended June 30, 2002
Significant Operating Trends - Generation Three Months Ended June 30, --------------------------- 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- OPERATING REVENUES $ 1,886 $ 1,559 $ 327 21.0% OPERATING EXPENSES Purchased power 800 705 95 13.5% Fuel 348 224 124 55.4% Operating and maintenance 451 411 40 9.7% Depreciation and amortization 46 65 (19) (29.2%) Taxes other than income 40 41 (1) (2.4%) ------------------------------------------------------------------------------------------------------- Total operating expenses 1,685 1,446 239 16.5% ------------------------------------------------------------------------------------------------------- OPERATING INCOME 201 113 88 77.9% ------------------------------------------------------------------------------------------------------- OTHER INCOME AND DEDUCTIONS Interest expense (20) (11) (9) (81.8%) Equity in earnings of unconsolidated affiliates 18 9 9 100.0% Other, net 34 24 10 41.7% ------------------------------------------------------------------------------------------------------- Total other income and deductions 32 22 10 45.5% ------------------------------------------------------------------------------------------------------- INCOME BEFORE INCOME TAXES 233 135 98 72.6% INCOME TAXES 91 51 40 78.4% ------------------------------------------------------------------------------------------------------- NET INCOME $ 142 $ 84 $ 58 69.0% =======================================================================================================
Net Income Generation's net income increased by $58 million, or 69%, for the three months ended June 30, 2003 compared to the same period in 2002 primarily due to a $328 million increase in market electric sales. The increase was partially offset by an increase in fuel and purchased power expense related to the increase in market sales, and a $74 million decrease in electric sales to other Exelon businesses. Operating Revenues Revenues increased by $327 million, or 21% for the three months ended June 30, 2003 compared to the same period in 2002. For the three months ended June 30, 2003 and 2002, Generation's sales were as follows: 120
Three Months Ended June 30, --------------------------- Revenue (in millions) 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Energy Delivery and Exelon Energy Company $ 877 $ 951 $ (74) (7.8%) Market Sales 960 632 328 51.9% ------------------------------------------------------------------------------------------------------ Total Energy Sales Revenue 1,837 1,583 254 16.0% Trading Portfolio (1) (16) 15 93.8% Other Revenue 50 (8) 58 n.m. ------------------------------------------------------------------------------------------------------ Total Revenue $ 1,886 $ 1,559 $ 327 21.0% ====================================================================================================== n.m. - not meaningful Three Months Ended June 30, --------------------------- Sales (in GWhs) 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Energy Delivery and Exelon Energy Company 26,869 29,649 (2,780) (9.4%) Market Sales 27,449 20,589 6,860 33.3% ------------------------------------------------------------------------------------------------------ Total Sales 54,318 50,238 4,080 8.1% ======================================================================================================
Trading volume of 7,919 GWhs and 8,566 GWhs for the three months ended June 30, 2003 and 2002, respectively, is 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 June 30, 2003 and 2002 is as follows:
Three Months Ended June 30, --------------------------- ($/MWh) 2003 2002 % Change ------------------------------------------------------------------------------------------------------------------- Average Revenue Energy Delivery and Exelon Energy Company $ 32.67 $ 32.06 1.9% Market Sales 34.98 30.69 14.0% Total - excluding the trading portfolio 33.83 31.50 7.4% -------------------------------------------------------------------------------------------------------------------
Energy Delivery and Exelon Energy Company. Sales to Energy Delivery decreased by $57 million primarily due to unfavorable weather in ComEd and PECO's service territories during the three months ended June 30, 2003 compared to the same period in 2002. Generation's average revenue per MWh was affected by increased prices per MWh for supply agreements with ComEd and PECO. Sales to Exelon Energy Company decreased $17 million for the three months ended June 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 $328 million resulted primarily from increased production from generating assets acquired during 2002, as well as lower load requirements to affiliates and higher wholesale market prices, which were primarily attributable to increased fossil fuel prices. Trading Revenues. Trading activity decreased revenue by $1 million during the three months ended June 30, 2003 compared to $16 million for the same period in 2002 due to reduced trading volume. Other Revenues. Other revenues in the three months ended June 30, 2003 included $21 million from market gas sales, and $18 million from ComEd related to nuclear decommissioning cost recoveries, and $7 million of cost recoveries from PECO. 121 Purchased Power and Fuel Generation's supply source of its sales and average supply costs are summarized below:
Three Months Ended June 30, --------------------------- Supply of Sales (in GWhs) 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Purchases - non-trading portfolio (1) 19,344 17,978 1,366 7.6% Nuclear Generation (2) 29,619 28,776 843 2.9% Fossil and Hydro Generation 5,355 3,484 1,871 53.7% ----------------------------------------------------------------------------------------------------- Total Supply 54,318 50,238 4,080 8.1% ===================================================================================================== (1) Including purchased power agreements with AmerGen. (2) Excluding AmerGen.
Three Months Ended June 30, --------------------------- ($/MWh) 2003 2002 % Change ------------------------------------------------------------------------------------------------------------------ Average Supply Cost (1) - excluding trading portfolio $ 20.71 $ 18.79 10.2% ------------------------------------------------------------------------------------------------------------------ (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 Exelon New England plants acquired in November 2002, which in total account for an increase of 1,498 GWhs, and o increased quantity of purchased power at higher prices to serve expected affiliate load obligations. In addition, Generation entered into a new purchase power agreement with AmerGen in the second quarter of 2003. As a result, 1,258 GWhs were purchased from Oyster Creek nuclear facility in the second quarter of 2003. Purchased power increased $95 million, or 14%, for the three months ended June 30, 2003 compared to the same period in 2002 due to a $125 million increase related to higher market prices and the delay of Exelon New England commercial operations commencement dates. The increase in purchased power was partially offset by a $32 million gain on mark-to-market hedging activity for the three months ended June 30, 2003 compared to a $4 million gain in the same period in 2002. Fuel expense increased $124 million, or 55%, for the three months ended June 30, 2003 compared to the same period in 2002, as summarized below:
Three Months Ended June 30, --------------------------- (in millions) 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Nuclear Generation (1) $ 132 $ 120 $ 12 10.0% Fossil and Hydro Generation 216 104 112 107.7% ----------------------------------------------------------------------------------------------------- Total $ 348 $ 224 $ 124 55.4% ===================================================================================================== (1) Excluding AmerGen
This increase is primarily due to a $92 million increase in fossil fuel generation resulting from the acquisition of plant assets in 2002. In addition, fuel expense increased $10 million due to additional nuclear fuel amortization resulting from under performing fuel at the Quad Cities Unit 1, which was completely replaced in May 2003. 122 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, generation reductions to make repairs and mid-cycle outages. For example, in the second quarter of 2003, the Quad Cities Unit 1 required a significant repair and is unable to operate above an 85% capacity factor until the Nuclear Regulatory Commission (NRC) inspects and approves the maintenance work. 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 anticipates NRC approval of the maintenance work and to return the unit to its normal operating capacity in the near future. Operating and Maintenance O&M expense increased $40 million, or 10%, for the three months ended June 30, 2003 compared to the same period in 2002. The increase in O&M expense was primarily attributable to $46 million of accretion expense related to SFAS No. 143, which includes $39 million of accretion of the asset retirement obligation and $7 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, $8 million of additional employee payroll and benefits costs, and $19 million of additional expenses due to asset acquisitions made after the second 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. This increase was partially offset by $21 million of lower nuclear refueling outage costs, including $17 million for Generation's ownership in Salem, which is operated by the co-owner, and other nonrecurring charges in 2002. For a further discussion of SFAS No. 143 see Note 2 of the Condensed Combined Notes to Consolidated Financial Statements.
Three Months Ended June 30, --------------------------- 2003 2002 --------------------------------------------------------------------------------------------------------------------- Nuclear fleet capacity factor (1) 94.0% 92.1% Nuclear fleet production cost per MWh (1) $ 12.08 $ 12.54 Average purchased power cost for wholesale operations per MWh $ 43.15 $ 39.96 --------------------------------------------------------------------------------------------------------------------- (1) Including AmerGen and excluding Salem.
The higher nuclear capacity factor and decreased nuclear production costs are primarily due to 20 fewer planned refueling outage days, resulting in a $4 million decrease in outage costs, in the three months ended June 30, 2003 as compared to the same period in 2002. Additionally, the three months ended June 30, 2003 included nine unplanned outages compared to eight unplanned outages during the same period in 2002. Depreciation and Amortization Depreciation and amortization expense decreased $19 million, or 29%, for the three months ended June 30, 2003 compared to the same period in 2002. The decrease was primarily attributable to a $31 million reduction in decommissioning expense 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, partially offset by $4 million of additional depreciation expense on capital additions placed in service after the second quarter of 2002, $7 million related to plant acquisitions made after the second quarter of 2002, and $1 123 million of depreciation for the ARC asset related to SFAS No. 143. 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 $1 million, or 2%, for the three months ended June 30, 2003 compared to the same period in 2002 primarily due to a $1 million decrease in property taxes. Interest Expense Interest expense increased $9 million, or 82%, for the three months ended June 30, 2003 compared to the same period in 2002. The increase was primarily due to a $7 million decrease in capitalized interest, $2 million of interest expense on the $536 million note payable issued to Sithe in November 2002 and $2 million of interest expense on the long-term debt obtained as a part of the Sithe New England asset acquisition. 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. Equity in Earnings of Unconsolidated Affiliates Equity in earnings of unconsolidated affiliates increased $9 million, or 100%, for the three months ended June 30, 2003 compared to the same period in 2002. The increase was due to a $18 million increase in Generation's equity earnings of AmerGen. AmerGen's earnings were primarily affected by increased power sales, reduced outage costs, and favorable impacts of SFAS 143. The increase was partially offset by a $9 million decrease in Generation's equity 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 for the period at Sithe. Other, Net Other, net increased $10 million, or 42%, for the three months ended June 30, 2003 compared to the same period in 2002. The increase is primarily due to 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 operating and maintenance expense. Income Taxes The effective income tax rate was 39.2% for the three months ended June 30, 2003 compared to 37.7% for the same period in 2002. This increase was primarily attributable to an increase in taxes related to the nuclear decommissioning trust funds. 124 Six Months Ended June 30, 2003 Compared to Six Months Ended June 30, 2002
Significant Operating Trends - Generation Six Months Ended June 30, ------------------------- 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- OPERATING REVENUES $ 3,765 $ 3,020 $ 745 24.7% OPERATING EXPENSES Purchased power 1,642 1,323 319 24.1% Fuel 706 433 273 63.0% Operating and maintenance 943 844 99 11.7% Depreciation and amortization 91 128 (37) (28.9%) Taxes other than income 88 90 (2) (2.2%) ------------------------------------------------------------------------------------------------------ Total operating expenses 3,470 2,818 652 23.1% ------------------------------------------------------------------------------------------------------ OPERATING INCOME 295 202 93 46.0% ------------------------------------------------------------------------------------------------------ OTHER INCOME AND DEDUCTIONS Interest expense (38) (28) (10) (35.7%) Equity in earnings of unconsolidated affiliates 37 32 5 15.6% Other, net (134) 40 (174) n.m. ------------------------------------------------------------------------------------------------------ Total other income and deductions (135) 44 (179) n.m. ------------------------------------------------------------------------------------------------------ INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES 160 246 (86) (35.0%) INCOME TAXES 71 96 (25) (26.0%) ------------------------------------------------------------------------------------------------------ INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES 89 150 (61) (40.7%) CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES, NET OF INCOME TAXES 108 13 95 n.m. ------------------------------------------------------------------------------------------------------ NET INCOME $ 197 $ 163 $ 34 20.9% ====================================================================================================== n.m. - not meaningful
Net Income Generation's net income increased by $34 million, or 21%, for the six months ended June 30, 2003 compared to the same period in 2002. Income before cumulative effect of changes in accounting principles decreased by $61 million for the six months ended June 30, 2003 compared to the same period in 2002 primarily due to the after-tax impairment charge for Generation's equity investment in Sithe of $130 million, partially offset by higher revenue due to increased market electric sales. 125 Operating Revenues Revenues increased by $745 million, or 25% for the six months ended June 30, 2003 compared to the same period in 2002. For the six months ended June 30, 2003 and 2002, Generation's sales were as follows:
Six Months Ended June 30, ------------------------- Revenue (in millions) 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Energy Delivery and Exelon Energy Company $ 1,842 $ 1,839 $ 3 0.2% Market Sales 1,863 1,175 688 58.6% ------------------------------------------------------------------------------------------------------ Total Energy Sales Revenue 3,705 3,014 691 22.9% ------------------------------------------------------------------------------------------------------ Trading Portfolio (2) (15) 13 (86.7%) Other Revenue 62 21 41 195.2% ------------------------------------------------------------------------------------------------------ Total Revenue $ 3,765 $ 3,020 $ 745 24.7% ====================================================================================================== n.m. - not meaningful Six Months Ended June 30, ------------------------- Sales (in GWhs) 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Energy Delivery and Exelon Energy Company 57,463 58,649 (1,186) (2.0%) Market Sales 51,264 39,913 11,351 28.4% ------------------------------------------------------------------------------------------------------ Total Sales 108,727 98,562 10,165 10.3% ======================================================================================================
Trading volume of 17,446 GWhs and 22,805 GWhs for the six months ended June 30, 2003 and 2002, respectively, is 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 June 30, 2003 and 2002 is as follows:
Six Months Ended June 30, ------------------------- ($/MWh) 2003 2002 % Change ------------------------------------------------------------------------------------------------------------------- Average Revenue Energy Delivery and Exelon Energy Company $ 32.06 $ 31.35 2.3% Market Sales 35.94 29.44 22.1% Total - excluding the trading portfolio 33.89 30.58 10.8% -------------------------------------------------------------------------------------------------------------------
Energy Delivery and Exelon Energy Company. Sales to Energy Delivery increased by $22 million as a result of increased prices per MWh for supply agreements with ComEd and PECO, partially offset by a net overall reduction in volume demand resulting from unfavorable weather and customers choosing alternative suppliers under the customer choice program. Sales to Exelon Energy Company decreased by $19 million for the six months ended June 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 $688 million resulted primarily from increased production from generating assets acquired during 2002, as well as lower load requirements to affiliates and higher wholesale market prices, primarily attributable to higher fossil fuel prices. Trading Revenues. Trading activity reduced revenue by $2 million during the six months ended June 30, 2003 compared to $15 million during the same period in 2002 due to lower trading activity. 126 Other Revenues. Other revenues in the six months ended June 30, 2003 included $31 million from ComEd related to nuclear decommissioning cost recoveries associated with the adoption of SFAS No. 143 that was not included in revenues in 2002 and $27 million in gas sales. Purchased Power and Fuel Generation's supply source of its sales and average supply costs are summarized below:
Six Months Ended June 30, ------------------------- Supply of Sales (in GWhs) 2003 2002 Variance % Change ------------------------------------------------------------------------------------------------------------------- Purchases - non-trading portfolio (1) 39,373 36,071 3,302 9.2% Nuclear Generation (2) 58,949 56,309 2,640 4.7% Fossil and Hydro Generation 10,405 6,182 4,223 68.3% ----------------------------------------------------------------------------------------------------- Total Supply 108,727 98,562 10,165 10.3% ===================================================================================================== (1) Including purchased power agreements with AmerGen. (2) Excluding AmerGen.
Six Months Ended June 30, ------------------------- ($/MWh) 2003 2002 % Change ------------------------------------------------------------------------------------------------------------------ Average Supply Cost (1) - excluding trading portfolio $ 20.58 $ 17.78 15.7% ------------------------------------------------------------------------------------------------------------------ (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 2,995 GWhs, and o increased quantity of purchased power at higher prices. In addition, Generation entered into a new purchase power agreement with AmerGen in the second quarter of 2003. As a result, 1,258 GWhs were purchased from Oyster Creek nuclear facility in the second quarter of 2003. Purchased power increased $319 million, or 24%, for the six months ended June 30, 2003 compared to the same period in 2002 due to $185 million related to higher market prices and the delay of Exelon New England commercial operations commencement dates. The increase in purchased power also reflects mark-to-market hedging gains of $1 million for the six months ended June 30, 2003 compared to $10 million in the same period in 2002. Fuel expense increased $273 million, or 63%, for the six months ended June 30, 2003 compared to the same period in 2002, as summarized below:
Six Months Ended June 30, ------------------------- (in millions) 2003 2002 Variance % Change ----------------------------------------------------------------------------------------------------------------- Nuclear Generation (1) $ 260 $ 237 $ 23 9.7% Fossil and Hydro Generation 446 196 250 127.6% ------------------------------------------------------------------------------------------------------- Total $ 706 $ 433 $ 273 63.0% ======================================================================================================= (1) Excluding AmerGen
127 This increase is primarily due to the increase in fossil fuel generated energy required to meet increased market demand for energy and operation of new base load plants in New England as well as demand in all regions during the first quarter of 2003. Fossil and other fuel expense increased $267 million, as a result of operating the generation plants acquired after the second quarter of 2002. Increased fossil fuel expense includes $149 million related to increased market sales from the generating plants acquired after the second quarter of 2002. Nuclear fuel expense increased $23 million, including $7 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. These increases in fuel expense were partially offset by a $4 million loss on emissions allowance sales recorded in 2002. Operating and Maintenance O&M expense increased $99 million, or 12%, for the six months ended June 30, 2003 compared to the same period in 2002. The increase in O&M expense was primarily attributable to $103 million of accretion expense related to SFAS No. 143, which includes $77 million of accretion of the asset retirement obligation and $26 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, $36 million of additional employee payroll and benefits costs, and $38 million of additional expenses due to asset acquisitions made after the second 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. This increase was partially offset by $53 million of lower nuclear refueling outage costs, including $17 million for Generation's ownership interest in Salem, which is operated by the co-owner, a one-time executive severance expense recorded in 2002 of $19 million, an $8 million reduction in worker's compensation expense and other non-recurring items. For a further discussion of SFAS No. 143 see Note 2 of the Condensed Combined Notes to Consolidated Financial Statements.
Six Months Ended June 30, ------------------------- 2003 2002 --------------------------------------------------------------------------------------------------------------------- Nuclear fleet capacity factor (1) 94.2% 91.2% Nuclear fleet production cost per MWh (1) $ 12.40 $ 13.38 Average purchased power cost for wholesale operations per MWh $ 41.71 $ 36.76 --------------------------------------------------------------------------------------------------------------------- (1) Including AmerGen and excluding Salem.
The higher nuclear capacity factor and decreased nuclear production costs are primarily due to 50 fewer planned refueling outage days, resulting in a $36 million decrease in outage costs, in the six months ended June 30, 2003 as compared to the same period in 2002. Additionally, the six months ended June 30, 2003 included 11 unplanned outages compared to 13 unplanned outages during the same period in 2002. Depreciation and Amortization Depreciation and amortization expense decreased $37 million, or 29%, for the six months ended June 30, 2003 compared to the same period in 2002. The decrease was primarily attributable to a $64 million reduction in decommissioning expense as these costs are included in operating and maintenance expense after the adoption of SFAS No. 143 and a $10 million decrease due to life extensions of asset additions in 2002. The decrease was partially offset by $10 million of additional depreciation expense on capital additions placed in service after the 128 second quarter of 2002, $16 million of expense related to plant acquisitions made after the second quarter of 2002, and $2 million of depreciation for the ARC asset related to SFAS No. 143. 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 $2 million, or 2%, for the six months ended June 30, 2003 compared to the same period in 2002 primarily due to a $4 million decrease in payroll taxes partially offset by a $2 million increase in property taxes related to asset acquisitions made after the second quarter of 2002. Interest Expense Interest expense increased $10 million, or 36%, for the six months ended June 30, 2003 compared to the same period in 2002. The increase was primarily due to a $7 million decrease in capitalized interest. In addition, the increase was due to $5 million of additional interest expense on the $536 million note payable issued to Sithe in November 2002 and $2 million of interest expense on the long term debt obtained as a part of the Sithe New England asset acquisition. This increase is partially offset by a $2 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 increased $5 million, or 16%, for the six months ended June 30, 2003 compared to the same period in 2002. This increase was due to a $20 million increase in Generation's equity earnings in AmerGen. AmerGen's earnings were primarily affected by increased power sales, reduced outage costs, and lower accretion expense resulting from the adoption of SFAS No. 143. The increase was partially offset by a $15 million decrease in Generation's equity earnings of Sithe. Sithe's earnings were primarily affected by Generation's purchase of Sithe New England's assets and unfavorable mark-to-market losses for the period at Sithe. Other, Net Other, net decreased $174 million for the six months ended June 30, 2003 compared to the same period in 2002. This decrease is primarily a result of the $200 million impairment charge related to Generation's equity investment in Sithe due to an other than temporary decline in value. This charge was partially offset by $26 million of higher net realized gains and investment income related to the decommissioning trust funds. These net realized gains and investment income are almost entirely offset with accretion expense in 2003, which is included in operating and maintenance expense. Income Taxes The effective income tax rate was 44.2% for the six months ended June 30, 2003 compared to 39.0% for the same period in 2002. The increase was primarily attributed to the impact of the impairment of Generation's investment in Sithe as well as the increase in taxes related to the nuclear decommissioning trust funds. 129 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. 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. LIQUIDITY AND CAPITAL RESOURCES Generation's business is capital intensive and requires considerable capital resources. Generation's capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financings including the issuance of commercial paper, participation in the intercompany money pool 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 dividends. Any future acquisitions could require external financing or borrowings or capital contributions from Exelon. In the second quarter of 2003, Generation progressed in its plans to implement the new business model referred to as The Exelon Way. The Exelon Way is focused on improving operating cash flows while meeting service and financial commitments through improved integration of operations and consolidation of support functions. As part of the implementation of The Exelon Way, Generation anticipates incurring expenses associated with the rationalization of certain business functions and employee separation costs. These expenses may be significant and are expected to be incurred during the remaining half of 2003 through 2005. However, these costs cannot be reasonably estimated at this time. Cash Flows from Operating Activities Cash flows provided by operations were $539 million for the six months ended June 30, 2003, compared to $519 million for the same period in 2002. The increase in cash flows from operating activities was primarily attributable to a $114 million increase in working capital. Cash flows used in operating activities for collateral were $136 million as of June 30, 2003, 130 compared to $30 million for the same period in 2002. The decrease in cash flows from collateral activities of $106 million was attributable to Generation exceeding its negotiated credit positions with counterparties. Cash flow used for collateral will depend upon future market prices for energy and to the extent forward energy deals are done under agreements with negotiated collateral provisions. When power prices return to previous levels or when Generation delivers the power under its forward conracts, 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 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 $496 million for the six months ended June 30, 2003, compared to $1,048 million for the same period in 2002. The decrease in cash flows used in investing activities was primarily attributable to a reduction in plant acquisition cost of $443 million as a result of the acquisition of generating plants during the six months ended June 30, 2002, and $86 million for liquidated damages received from Raytheon in 2003 (see Note 8 of the Condensed Combined Notes to Consolidated Financial Statements). Generation's proposed capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors. Generation's capital expenditures for 2003 reflect the construction of three Exelon New England generating 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 six months ended June 30, 2003, Generation received $86 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 the Mystic 8 and 9 and Fore River nuclear generating plants. In February 2002, Generation entered into an agreement to loan AmerGen up to $75 million at an interest rate of one-month LIBOR plus 2.25%. In July 2002, the loan agreement and the loan were increased to $100 million and the maturity date was extended to July 1, 2003. As of June 30, 2003, AmerGen has repaid the balance of the loan. 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 $27 million for the six months ended June 30, 2003, compared to cash flows provided by financing activities of $329 million for the same period in 2002. The decrease in cash provided by financing was primarily due to a $273 million decrease in cash receipts from affiliates, $45 million dividend to Exelon Corporation, the $210 million partial payment of the acquisition note payable to Sithe, and a $38 million decrease in restricted cash as a result of liquidated damages received from Raytheon in 2003. The decrease in cash provided by financing activities was partially offset by $211 million of borrowings under the revolving credit facility. See Note 9 of the Condensed Combined Notes to Consolidated Financial Statements for further discussion of Generation's debt financing activities. 131 Credit Issues Generation meets its short-term liquidity requirements primarily through intercompany borrowings from Exelon, the issuance of commercial paper 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 June 30, 2003, the sublimit for Generation was zero. The credit facility is expected to be used by Generation principally to support its commercial paper program. 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 June 30, 2003. At June 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's subsidiary, Commonwealth Edison Company of Indiana, Inc., PECO, Generation and BSC may participate in the money pool as lenders and borrowers, and Exelon Corporate and ComEd as lenders. Funding of, and borrowings from, the money pool are predicated on whether such funding results in mutual economic benefits to each of the participants, although Exelon is not permitted to be a net borrower from the money pool. Interest on borrowings is based on short-term market rates of interest, or, if from an external source, specific borrowing rates. During the six months ended June 30, 2003, Generation had various borrowings from ComEd under the money pool. The maximum amount of loans outstanding at any time during the quarter was $342 million. As of June 30, 2003, Generation owed ComEd $165 million on these loans. For the six months ended June 30, 2003, Generation paid $1 million in interest to ComEd EBG, an indirect subsidiary of Generation, has approximately $1.1 billion of debt outstanding under the EBG Facility at June 30, 2003. The EBG Facility was entered into primarily to finance the construction of the Mystic 8 and 9 and Fore River generating units. The EBG Facility requires that all of the projects achieve "Project Completion," as defined in the EBG Facility, 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 are 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 are in commercial operation, although construction has not 132 progressed to the point of Project Completion. Construction of Fore River is substantially complete and the unit is currently undergoing testing. EBG does not anticipate that the projects will achieve Project Completion by August 29, 2003. The EBG Facility is non-recourse to Exelon and 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. As a result of Exelon's continuing evaluation of the projects and discussions with the lenders in July 2003, 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 Exelon's 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. Exelon expects Generation will incur an impairment of its EBG related assets, which, in aggregate, could reach approximately $550 million after income taxes. The debt outstanding under the EBG Facility of approximately $1.1 billion at June 30, 2003 is reflected in Generation's Consolidated Balance Sheet as a current liability. On June 13, 2003, Generation entered into a $550 million revolving credit facility. Generation used the facility to make the first payment to Sithe relating to the $536 million note that was used to purchase the EBG facilities. This note was restructured in June 2003 to provide for a payment of $210 million of the principal on June 16, 2003 and payment of the remaining principal on the earlier of December 1, 2003 or change of control. 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. Under PUHCA, Generation can only pay dividends from undistributed or current earnings. Generation is precluded from lending or extending credit or indemnity to Exelon. At June 30, 2003, Generation had undistributed earnings of $1.1 billion. 133 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 June 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 8 of the Condensed Combined Notes to Consolidated Financial Statements for commercial commitments tables 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 for the 35.2% interest in Sithe owned by Apollo Energy, LLC and the 14.9% interest owned by subsidiaries of Marubeni Corporation. The total call price was based on the terms of the existing Put and Call Agreement (PCA) among the parties and approximated $650 million. The transfer of ownership requires various regulatory approvals including FERC, the state environmental agency in New Jersey, and expiration of the Hart Scott Rodino waiting period. Under the terms of the PCA, the call must be funded within six months of the call notice being issued. Additionally, because the Federal Power Act restricts Exelon's ownership of 50% or more of Qualifying Facilities (QFs), the QFs owned by Sithe must be sold or restructured before closing to preserve their QF status. Despite the issuance of the call notice, Generation continues to pursue options to sell its investment in Sithe in its entirety. o In June 2003, Generation entered an agreement with USEC Inc. to purchase approximately $700 million of nuclear fuel from 2005 through 2010. As discussed in Note 2 of the Condensed Combined Notes to Consolidated Financial Statements, it is reasonably possible that Generation will consolidate Sithe as of July 1, 2003 pursuant to FIN No. 46, "Consolidation of Variable Interest Entities." 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 approximately $1.0 billion and incurred a net 134 loss of approximately $348 million. Exelon 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. 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 91% 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. 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 $37 million decrease in net income, or approximately $0.11 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. 135 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. 136 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 six months ended June 30, 2003. Normal operations and hedging activities represent the marketing of electricity available from Generation's owned or contracted generation, including ComEd and PECO's retail load, sold into the wholesale market. As the information in 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 June 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 109 (1) 108 Changes in valuation techniques and assumptions -- -- -- Reclassification to realized at settlement of contracts (77) (1) (78) ------------------------------------------------------------------------------------------------------------------- Total change in unrealized fair value 32 (2) 30 Realized net settlement of transactions subject to mark-to-market 77 1 78 ------------------------------------------------------------------------------------------------------------------- Total mark-to-market activities gross margin $ 109 $ (1) $ 108 ------------------------------------------------------------------------------------------------------------------- Accrual activities: ------------------- Accrual activities revenue $ 1,107 $ -- $ 1,107 Hedge gains/(losses) reclassified from OCI 616 -- 616 ------------------------------------------------------------------------------------------------------------------- Total revenue - accrual activities 1,723 -- 1,723 ------------------------------------------------------------------------------------------------------------------- Purchased power and fuel 388 -- 388 Hedges of purchased power and fuel reclassified from OCI 705 -- 705 ------------------------------------------------------------------------------------------------------------------- Total purchased power and fuel 1,093 -- 1,093 ------------------------------------------------------------------------------------------------------------------- Total accrual activities gross margin 630 -- 630 ------------------------------------------------------------------------------------------------------------------- Total gross margin $ 739 $ (1) $ 738 (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.
137
Six Months Ended June 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 135 (3) 132 Changes in valuation techniques and assumptions -- -- -- Reclassification to realized at settlement of contracts (134) (1) (135) ------------------------------------------------------------------------------------------------------------------ Total change in unrealized fair value 1 (4) (3) Realized net settlement of transactions subject to mark-to-market 134 1 135 ------------------------------------------------------------------------------------------------------------------ Total mark-to-market activities gross margin $ 135 $ (3) $ 132 ------------------------------------------------------------------------------------------------------------------ Accrual activities: ------------------- Accrual activities revenue $ 2,459 $ -- $ 2,459 Hedge gains/(losses) reclassified from OCI 1,014 -- 1,014 ------------------------------------------------------------------------------------------------------------------ Total revenue - accrual activities 3,473 -- 3,473 ------------------------------------------------------------------------------------------------------------------ Purchased power and fuel 980 -- 980 Hedges of purchased power and fuel reclassified from OCI 1,208 -- 1,208 ------------------------------------------------------------------------------------------------------------------ Total purchased power and fuel 2,188 -- 2,188 ------------------------------------------------------------------------------------------------------------------ Total accrual activities gross margin 1,285 -- 1,285 ------------------------------------------------------------------------------------------------------------------ Total gross margin $ 1,420 $ (3) $ 1,417 (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.
138 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 June 30, 2003. It indicates the drivers behind changes in the balance sheet amounts. This table will incorporate the mark-to-market activities that are immediately recorded in earnings, as shown in the previous table, as well as the settlements from OCI to earnings and changes in fair value for the hedging activities that are recorded in Accumulated Other Comprehensive Income on the June 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 six months ended June 30, 2003 of contracts recorded in earnings 135 (3) 132 Reclassification to realized at settlement of contracts recorded in earnings (134) (1) (135) Reclassification to realized at settlement from OCI 194 -- 194 Effective portion of changes in fair value - recorded in OCI (367) -- (367) Purchase/sale of existing contracts or portfolios subject to mark-to-market -- -- -- ------------------------------------------------------------------------------------------------------------------ Total mark-to-market energy contract net assets (liabilities) at June 30, 2003 $ (340) $ 1 $ (339) ==================================================================================================================
The following table details the balance sheet classification of the mark-to-market energy contract net assets recorded as of June 30, 2003:
Normal Operations and Proprietary Hedging Activities Trading Total ------------------------------------------------------------------------------------------------------------------ Current assets $ 251 $ 2 $ 253 Noncurrent assets 68 -- 68 ------------------------------------------------------------------------------------------------------------------ Total mark-to-market energy contract assets 319 2 321 ------------------------------------------------------------------------------------------------------------------ Current liabilities (490) -- (490) Noncurrent liabilities (169) (1) (170) ------------------------------------------------------------------------------------------------------------------ Total mark-to-market energy contract liabilities (659) (1) (660) ------------------------------------------------------------------------------------------------------------------ Total mark-to-market energy contract net assets (liabilities) $ (340) $ 1 $ (339) ==================================================================================================================
139 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 June 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. 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 $(190) $(150) $ (11) $ (7) $ -- $ -- $ (358) --------------------------------------------------------------------------------------------------------------------- Total $(190) $(150) $ (11) $ (7) $ -- $ -- $ (358) --------------------------------------------------------------------------------------------------------------------- Normal Operations, other derivative contracts (2): Actively quoted prices $ 18 $ 8 $ -- $ -- $ -- $ -- $ 26 Prices provided by other external sources 6 16 5 4 -- -- 31 Prices based on model or other valuation methods 12 (34) (5) (9) (3) -- (39) --------------------------------------------------------------------------------------------------------------------- Total $ 36 $ (10) $ -- $ (5) $ (3) $ -- $ 18 --------------------------------------------------------------------------------------------------------------------- Proprietary Trading, other derivative contracts (3): Actively quoted prices $ 1 $ 2 $ -- $ -- $ -- $ -- $ 3 Prices provided by other external sources (1) (5) -- -- -- -- (6) Prices based on model or other valuation methods 3 1 -- -- -- -- 4 --------------------------------------------------------------------------------------------------------------------- Total $ 3 $ (2) $ -- $ -- $ -- $ -- $ 1 --------------------------------------------------------------------------------------------------------------------- Average tenor of proprietary trading portfolio (4) 1.5 years ===================================================================================================================== (1) Mark-to-market gains and losses on contracts that qualify as cash flow hedges are recorded in other comprehensive income. (2) Mark-to-market gains and losses on other non-trading derivative contracts that do not qualify as cash flow hedges are recorded in earnings. (3) Mark-to-market gains and losses on trading contracts are recorded in earnings. (4) Following the recommendations of the Committee of Chief Risk Officers, the average tenor of the proprietary trading portfolio measures the average time to collect value for that portfolio. Generation measures the tenor by separating positive and negative mark-to-market values in its proprietary trading portfolio, estimating the mid-point in years for each and then reporting the highest of the two mid-points calculated. In the event that this methodology resulted in significantly different absolute values of the positive and negative cash flow streams, Generation would use the mid-point of the portfolio with the largest cash flow stream as the tenor.
140 The table below provides details of effective cash flow hedges under SFAS No. 133 included in the balance sheet as of June 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 six months ended June 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, January 1, 2003 $ (114) $ (5) $ (119) Changes in fair value (223) (12) (235) Reclassifications from OCI to net income 119 -- 119 ---------------------------------------------------------------------------------------------------------------------- Accumulated OCI derivative gain/(loss) at June 30, 2003 $ (218) $ (17) $ (235) ====================================================================================================================== (1) Includes interest rate hedges at Generation.
Generation uses a Value-at-Risk (VaR) model to assess the market risk associated with financial derivative instruments entered into for proprietary trading purposes. The measured VaR represents an estimate of the potential change in value of Generation's proprietary trading portfolio. The VaR estimate includes a number of assumptions about current market prices, estimates of volatility and correlations between market factors. These estimates, however, are not necessarily indicative of actual results, which may differ because actual market rate fluctuations may differ from forecasted fluctuations and because the portfolio may change over the holding period. Generation estimates VaR using a model based on the Monte Carlo simulation of commodity prices that captures the change in value of forward purchases and sales as well as option values. Parameters and values are back tested daily against daily changes in mark-to-market value for proprietary trading activity. VaR assumes that normal market conditions prevail and that there are no changes in positions. Generation uses a 95% confidence interval, one-day holding period, one-tailed statistical measure in calculating its VaR. This means that Generation may state that there is a one in 20 chance that if prices move against its portfolio positions, its pre-tax loss in liquidating its portfolio in a one-day holding period would exceed the calculated VaR. To account for unusual events and loss of liquidity, Generation uses stress tests and scenario analysis. For financial reporting purposes only, Generation calculates several other VaR estimates. The higher the confidence interval, the less likely the chance that the VaR estimate would be exceeded. A longer holding period considers the effect of liquidity in being able to actually 141 liquidate the portfolio. A two-tailed test considers potential upside in the portfolio in addition to the potential downside in the portfolio considered in the one-tailed test. The following table provides the VaR for all proprietary trading positions of Generation as of June 30, 2003. Proprietary Trading VaR --------------------------------------------------------------------------- 95% Confidence Level, One-Day Holding Period, One-Tailed Period end $ 0.0 Average for the period 0.1 High 0.2 Low 0.0 95% Confidence Level, Ten-Day Holding Period, Two-Tailed Period End $ 0.6 Average for the period 0.5 High 0.8 Low 0.3 99% Confidence Level, One-Day Holding Period, Two-Tailed Period end $ 0.2 Average for the period 0.2 High 0.3 Low 0.1 --------------------------------------------------------------------------- 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. 142 The following table provides information on Generation's credit exposure, net of collateral, as of June 30, 2003. It further delineates that exposure by the credit rating of the counterparties and provides guidance on the concentration of credit risk to individual counterparties and an indication of the maturity of a company's credit risk by credit rating of the counterparties. The table below does not include sales to Generation's affiliates or exposure through Independent System Operators.
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 $ 158 $ -- $ 158 3 $ 81 Split rating -- -- -- -- -- Non-investment grade 10 9 1 -- -- No external ratings Internally rated - investment grade 12 -- 12 3 10 Internally rated - non-investment grade 13 1 12 3 12 ------------------------------------------------------------------------------------------------------------------- Total $ 193 $ 10 $ 183 9 $ 103 ====================================================================================================================
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 $ 148 $ 10 $ -- $ 158 Split rating -- -- -- -- Non-investment grade 10 -- -- 10 No external ratings Internally rated - investment grade 11 1 -- 12 Internally rated - non-investment grade 13 -- -- 13 ------------------------------------------------------------------------------------------------------------------ Total $ 182 $ 11 $ -- $ 193 ==================================================================================================================
Generation is a counterparty to Dynegy in various energy transactions. In early July 2002, the credit ratings of Dynegy were downgraded to below investment grade by two credit rating agencies. As of June 30, 2003, Generation had a net receivable from Dynegy of approximately $4 million and, consistent with the terms of the existing credit arrangement, has received collateral in support of this receivable. Generation also has credit risk associated with Dynegy through Generation's equity investment in Sithe. Sithe is a 60% owner of the Independence generating station, a 1,040-MW gas-fired qualified facility that has an energy-only long-term tolling agreement with Dynegy, with a related financial swap arrangement. As of June 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 terms 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 $17 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. 143 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. In connection with ComEd's sale of assets to Midwest Generation prior to the Merger, ComEd had entered into an Agency Agreement with Midwest Generation and certain of Midwest Generation's related parties (the "Guarantors") whereby the Guarantors assumed the benefits and liabilities of a coal purchase contract. ComEd remained the signatory to the coal contract, and in connection with the Merger and subsequent restructuring, Generation assumed the signatory obligation on this contract from ComEd. Midwest Generation's credit ratings have recently been downgraded by certain credit rating agencies. In the event of Midwest Generation and the Guarantors non-performance under the coal purchase contract, Generation would be required to fulfill the purchase commitments which 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 contract years 2003 to 2012 are estimated to be approximately $81 million related to this agreement. Generation and ComEd have entered into other agreements with Midwest Generation in which the non-performance by Midwest Generation is currently not anticipated to result in significant contingent obligations to Generation or ComEd. Interest Rate Risk ComEd ComEd uses a combination of fixed rate and variable rate debt to reduce interest rate exposure. Interest rate swaps may be used to adjust exposure when deemed appropriate based upon market conditions. ComEd also utilizes forward-starting interest rate swaps and treasury rate locks to lock in interest rate levels in anticipation of future financing. These strategies are employed to maintain the lowest cost of capital. At June 30, 2003, these interest rate swaps with an aggregate notional amount of $200 million, designated as cash flow hedges, had an aggregate fair market value exposure of $6 million based on the present value of the difference between the contract and market rates at June 30, 2003. If these derivative instruments had been terminated at June 30, 2003, this estimated fair value represents the amount to be paid by ComEd 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 June 30, 2003 is estimated to be $13 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 June 30, 2003 is estimated to be less than $1 million in the counterparties favor. 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 June 30, 2003, these interest rate swaps, designated as fair value hedges, had an aggregate fair market value of $46 million based on the present value difference between the contract and market rates at June 30, 2003. If these derivative 144 instruments had been terminated at June 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 June 30, 2003 is estimated to be $53 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 June 30, 2003 is estimated to be $39 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 June 30, 2003, these interest rate swaps had an aggregate fair market value exposure of $17 million based on the present value difference between the contract and market rates at June 30, 2003. If these derivative instruments had been terminated at June 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 June 30, 2003 is estimated to be $18 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 June 30, 2003 is estimated to be $15 million in the counterparties favor. 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. 145 As of June 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 six months ended June 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 June 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 at June 30, 2003. The fair market value exposure of these swaps, designated as cash flow hedges, is $105 million. If these derivative instruments had been terminated at June 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 June 30, 2003 is estimated to be $119 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 June 30, 2003 is estimated to be $91 million in the counterparties favor. In June 2003, Generation entered into forward-starting interest rate swaps in the aggregate amount of $200 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 June 30, 2003, these interest rate swaps, designated as cash flow hedges, had an aggregate fair market value of $4 million based on the present value of the difference between the contract and market rates at June 30, 2003. If these derivative instruments had been terminated at June 30, 2003, this estimated fair value represents the amount to be paid by the counterparties to Generation. 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 June 30, 2003 is estimated to be $4 million in the counterparties favor. 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 June 30, 2003 is estimated to be $12 million in Generation's favor. 146 Equity Price Risk Generation Generation maintains trust funds, as required by the NRC, to fund certain costs of decommissioning its nuclear plants. As of June 30, 2003, decommissioning trust funds are reflected at fair value on Exelon and Generation's Consolidated Balance Sheets. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to compensate for inflationary increases in decommissioning costs. However, the equity securities in the trust funds are exposed to price fluctuations in equity markets, and the value of fixed rate, fixed income securities are exposed to changes in interest rates. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocation in accordance with Generation's nuclear decommissioning trust fund investment policy. A hypothetical 10% increase in interest rates and decrease in equity prices would result in a $175 million reduction in the fair value of the trust assets. ITEM 4. CONTROLS AND PROCEDURES Exelon During the second 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. As of June 30, 2003, these officers concluded that, subject to limitations noted above, the design of the disclosure controls and procedures provides reasonable assurance that the disclosure controls and procedures can 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. 147 In the second quarter of 2003, Exelon implemented a new general ledger accounting system. The new general ledger system was implemented in order to provide a consistent system platform for the affiliated Exelon companies and to enhance management reporting and analysis. This change in systems was subject to thorough testing and review by internal and external parties both before and after final implementation. Exelon continually strives to improve its internal control over financial reporting to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. ComEd During the second 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. As of June 30, 2003, these officers concluded that, subject to limitations noted above, the design of the disclosure controls and procedures provides reasonable assurance that the disclosure controls and procedures can 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. In the second quarter of 2003, ComEd implemented a new general ledger accounting system. The new general ledger system was implemented in order to provide a consistent system platform for the affiliated Exelon companies and to enhance management reporting and analysis. This change in systems was subject to thorough testing and review by internal and external parties both before and after final implementation. ComEd continually strives to improve its internal control over financial reporting to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. PECO During the second quarter of 2003, PECO's management, including the principal executive officer and principal financial officer, evaluated PECO's disclosure controls and 148 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. As of June 30, 2003, these officers concluded that, subject to limitations noted above, the design of the disclosure controls and procedures provides reasonable assurance that the disclosure controls and procedures can accomplish their 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. In the second quarter of 2003, PECO implemented a new general ledger accounting system. The new general ledger system was implemented in order to provide a consistent system platform for the affiliated Exelon companies and to enhance management reporting and analysis. This change in systems was subject to thorough testing and review by internal and external parties both before and after final implementation. PECO continually strives to improve its internal control over financial reporting to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Generation During the second 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 149 does not control or manage certain of its unconsolidated entities and as such, the disclosure controls and procedures with respect to such entities are more limited than those it maintains with respect to its consolidated subsidiaries. As of June 30, 2003, these officers concluded that, subject to limitations noted above, the design of the disclosure controls and procedures provides reasonable assurance that the disclosure controls and procedures can 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. In the second quarter of 2003, Generation implemented a new general ledger accounting system. The new general ledger system was implemented in order to provide a consistent system platform for the affiliated Exelon companies and to enhance management reporting and analysis. This change in systems was subject to thorough testing and review by internal and external parties both before and after final implementation. Generation continually strives to improve its internal control over financial reporting to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. PART II - OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS ComEd As previously reported in the 2002 Form 10-K and the March 2003 Form 10-Q, three of ComEd's wholesale municipal customers had filed a complaint and request for refund with FERC alleging that ComEd failed to properly adjust its rates pursuant to the terms of the respective electric service contracts. ComEd and the municipal customers have executed a settlement agreement ending the litigation. Under the settlement, ComEd will pay a total of approximately $3 million to the three municipalities. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Exelon On April 29, 2003, Exelon held its 2003 Annual Meeting of Shareholders. Proposal 1 was the election of five Class III directors to serve three-year terms expiring in 2006. The following directors were elected: Votes For Votes Withheld M. Walter D'Alessio 259,812,777 5,103,938 Rosemarie B. Greco 259,802,051 5,114,664 John M. Palms 257,952,983 6,963,732 John W. Rogers, Jr. 256,121,360 8,795,355 Richard L. Thomas 259,607,872 5,308,843 150 Proposal 2 was the ratification of PricewaterhouseCoopers LLP as independent accountants for Exelon and its subsidiaries for 2003. The shareholders approved the proposal with 253,274,833 votes cast for, 9,037,160 votes cast against and 2,604,722 votes abstaining. Proposal 3 described in the proxy statement was a non-binding shareholder proposal made by the AFL-CIO Reserve Fund that urged the Board of Directors of Exelon to seek shareholder approval of any extraordinary pension benefits for executives. The proponent withdrew the proposal after Exelon agreed to make certain changes in its compensation practices. As a result, the proposal was not voted on at the Exelon annual meeting. Recognizing shareholder concern about executive compensation, Exelon agreed that after January 1, 2004, it would not grant additional unearned service credits for current executives in the Exelon pension plans without shareholder approval. It also agreed that it would not provide more than two years' service credit under new change-in-control agreements without shareholder approval. If Exelon should need to offer new executives more than the pension benefits that they would give up to come work for Exelon, the additional pension benefits would be performance-based and not guaranteed. The agreement does not affect benefits or compensation under existing agreements, arrangements or change-in-control provisions. It does not limit Exelon's rights to provide compensation or benefits outside the pension plans. ComEd On May 29, 2003 ComEd held its 2003 Annual Meeting of Shareholders. Proposal 1 was the election of 5 directors to serve a term of one year. The following directors were elected: Votes For Votes Withheld John W. Rowe 127,002,904 -- Pamela B. Strobel 127,002,904 -- Kenneth G. Lawrence 127,002,904 -- Frank M. Clark 127,002,904 -- Robert S. Shapard 127,002,904 -- Proposal 2 was to amend the Articles of Incorporate to add the practice of professional engineering to the purposes for which ComEd has been organized. The amendment was approved with 127,002,904 votes cast for, 0 votes cast against, and 0 votes abstaining. 151 PECO On May 29, 2003 PECO Energy Company held its Annual Meeting of Shareholders. Proposal 1 was the election of 5 directors into three classes in compliance with the Bylaws. The three-year terms of each class were staggered so that the term of one class will expire at each annual meeting. The following directors were elected: Votes For Votes Withheld Class I, with term expiring in 2006: John W. Rowe 170,478,507 -- Class II, with term expiring in 2005: Pamela B. Strobel 170,478,507 -- Kenneth G. Lawrence 170,478,507 -- Class III, with term expiring in 2004: Frank M. Clark 170,478,507 -- Robert S. Shapard 170,478,507 -- ITEM 5. OTHER INFORMATION ComEd As previously reported in the 2002 Form 10-K, in July 2002, FERC conditionally approved ComEd's decision to join PJM. On April 1, 2003, ComEd received approval from FERC to transfer control of ComEd's transmission assets to PJM. FERC also accepted for filing the PJM tariff 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. ComEd expects to transfer functional control of its transmission assets to PJM and to integrate fully into PJM's energy market structures on November 1, 2003. PECO As previously reported in the 2002 Form 10-K and the March 2003 Form 10-Q, on August 15, 2002, the International Brotherhood of Electrical Workers (IBEW) filed a petition with the National Labor Relations Board (NLRB) to conduct a unionization vote of certain of PECO's employees. On May 21, 2003, the PECO union election was held and a majority of PECO workers voted against union representation. The results of the election have not been certified due to pending challenges and objections. 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, a total of 375,000 residential customers may be transferred to alternative electric generation suppliers in December 2003. Customers transferred will have the right to return to PECO at any time. 152 Generation As previously reported in the 2002 Form 10-K, on April 9, 2003, the IBEW filed a petition with the NLRB to represent all production and maintenance employees in Generation's fossil and hydroelectric operations in the Mid-Atlantic operating group. These approximate 300 employees had not been covered by a collective bargaining agreement. . Pursuant to an election held on June 18, 2003, the employees voted to become represented by the IBEW. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits: 4.1 - Indenture to Subordinated Debt Securities dated as of June 24, 2003 between PECO Energy Company, as Issuer, and Wachovia Bank National Association, as Trustee. 4.2 - Preferred Securities Guarantee Agreement between PECO Energy Company, as Guarantor, and Wachovia Trust Company, National Association, as Trustee, dated as of June 24, 2003. 4.3 - PECO Energy Capital Trust IV Amended and Restated Declaration of Trust among PECO Energy Company, as Sponsor, Wachovia Trust Company, National Association, as Delaware Trustee and Property Trustee, and J. Barry Mitchell, George R. Shicora and Charles S. Walls as Administrative Trustees dated as of June 24, 2003. 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 June 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 June 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 -------------------------------------------------------------------------------- 153 (b) Reports on Form 8-K: Exelon, ComEd, PECO and/or Generation filed Current Reports on Form 8-K during the three months ended June 30, 2003 regarding the following items:
Date of Earliest Event Reported Description of Item Reported ---------------------------------------------------------------------------------------------- April 3, 2003 "ITEM 9. REGULATION FD DISCLOSURE" filed for Exelon, ComEd, PECO and Generation regarding a presentation by John W. Rowe, Chairman and CEO, at the Berenson & Company and The Williams Capital Group Midwest Utilities Seminar. The exhibits include the slides used during the presentation. April 7, 2003 "ITEM 5. OTHER EVENTS" filed by ComEd regarding the issuance of $395 million in First Mortgage Bonds. April 28, 2003 "ITEM 9. REGULATION FD DISCLOSURE" filed under Item 9 in compliance with Item 12 for Exelon, ComEd, PECO and Generation regarding the first quarter 2003 earnings release and items discussed during the earnings conference call. Also included as an exhibit to this report was a new release regarding the "Exelon Way" business model. May 2, 2003 "ITEM 5. OTHER EVENTS" filed for Exelon regarding Richard H. Glanton's acceptance of the position of Senior Vice President, Corporate Development and his relinquishment of his directorship on the Exelon Board. May 7, 2003 "ITEM 5. OTHER EVENTS" filed for Exelon, PECO and Generation announcing that the U.S. Nuclear Regulatory Commission approved a 20-year extension of the operating licenses for Exelon Nuclear's Peach Bottom Atomic Power Station. May 20, 2003 "ITEM 9. REGULATION FD DISCLOSURE" filed for Exelon regarding a presentation by Robert S. Shapard, Executive Vice President and CFO. The exhibit includes the slides used during the presentation. May 29, 2003 "ITEM 5. OTHER EVENTS" filed for Exelon and Generation announcing the issuance of a call notice for the remaining 50.1% interest in Sithe Energies, Inc. June 2, 2003 "ITEM 5. OTHER EVENTS" filed for Exelon and Generation regarding a request for an amendment to the Exelon Boston 154 Generating, LLC credit facility and the construction of the Mystic 8 and 9 and Fore River generating units. June 2, 2003 "ITEM 5. OTHER EVENTS" filed for Exelon and Generation regarding the approval of an amendment to the Exelon Boston Generating, LLC credit facility. June 11, 2003 "ITEM 9. REGULATION FD DISCLOSURE" filed for Exelon, ComEd, PECO and Generation regarding a presentation by Robert S. Shapard, Executive Vice President and CFO. The exhibits include the slides and handouts used during the presentation. June 13, 2003 "ITEM 5. OTHER EVENTS" filed for Exelon regarding the dismissal of a class action lawsuit. June 18, 2003 "ITEM 5. OTHER EVENTS" filed for Exelon announcing an agreement to sell certain businesses of its subsidiary InfraSource, Inc. June 18, 2003 "ITEM 5. OTHER EVENTS" filed for Exelon, ComEd, PECO and Generation regarding the sale of certain businesses of InfraSource, Inc. June 25, 2003 "ITEM 5. OTHER EVENTS" filed for Exelon, ComEd, and Generation regarding the exercise of Generation's call option under an existing purchase power agreement with Midwest Generation, LLC. ----------------------------------------------------------------------------------------------
155 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) July 30, 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 ---------------------------------- DUANE M. DESPARTE Vice President and Controller, Exelon Energy Delivery (Principal Accounting Officer) July 30, 2003 156 -------------------------------------------------------------------------------- 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 ---------------------------------- DUANE M. DESPARTE Vice President and Controller, Exelon Energy Delivery (Principal Accounting Officer) July 30, 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) July 30, 2003 157