UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q/A AMENDMENT NO. 1 (Mark One) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934. FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2002 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934. For the transition period from ______________ to _______________ ______________________________ Commission file number 1-16455 RELIANT RESOURCES, INC. (Exact Name of Registrant as Specified in Its Charter) Delaware 76-0655566 (State or Other Jurisdiction of (I.R.S. Employer Incorporation or Organization) Identification No.) 1111 Louisiana Houston, Texas 77002 (Address of Principal Executive Offices) (Zip Code) (713) 497-3000 (Registrant's telephone number, including area code) ______________________________ 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 __ As of November 8, 2002, Reliant Resources, Inc. (Reliant Resources) had 290,441,403 shares of common stock outstanding excluding 9,362,597 shares held as treasury stock. RELIANT RESOURCES, INC. QUARTERLY REPORT ON FORM 10-Q/A FOR THE QUARTER ENDED SEPTEMBER 30, 2002 Reliant Resources, Inc. (Reliant Resources) hereby amends Items 1 and 2 of Part 1 of its Quarterly Report on Form 10-Q for the quarterly periods ended September 30, 2001 and 2002 as originally filed on November 14, 2002. Restatement. Subsequent to the issuance of our financial statements for 2001, we identified four natural gas financial swap transactions that should not have been recorded in our records. We have concluded, based on the offsetting nature of the transactions and manner in which the transactions were documented, that none of the transactions should have been given accounting recognition. We previously accounted for these transactions in our financial statements as a reduction in revenues in December 2000 and an increase in revenues in January 2001, with the effect of decreasing net income in the fourth quarter of 2000 and increasing net income in the first quarter of 2001, in each case by $20.0 million pre-tax ($12.7 million after-tax) and the effect of increasing basic and diluted earnings per share by $0.05 in the first quarter of 2001. There were no cash flows associated with the transactions. Also, subsequent to the issuance of our financial statements for 2001 and for the first three quarters of 2002, we determined that we incorrectly calculated the amount of hedge ineffectiveness for 2001 and the first three quarters of 2002 for hedging instruments entered into prior to the adoption of Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended (SFAS No. 133). These hedging instruments included long-term forward contracts for the sale of power in the California market through December 2006. The amount of hedge ineffectiveness for these forward contracts was calculated using the trade date. However, the proper date for the hedge ineffectiveness calculation is hedge inception, which for these contracts was deemed to be January 1, 2001, concurrent with the adoption of SFAS No. 133. In addition, we did not record the amount of ineffectiveness for any hedging instruments during the first three quarters of 2001. These errors in accounting for hedge ineffectiveness resulted in an understatement of revenues of $57.3 million ($37.1 million after-tax) and earnings per share of $0.14 in the first nine months of 2001. These errors in accounting for hedge ineffectiveness resulted in an overstatement of revenues of $16.5 million ($10.7 million after-tax) and earnings per share of $0.04 in the first nine months of 2002. As more fully described in Note 1 to the interim financial statements, the statements of consolidated operations for the three and nine months ended September 30, 2001 and 2002 have been restated from amounts previously reported to remove the effects of the four natural gas swap transactions from the first quarter of 2001 and to correctly account for the amount of hedge ineffectiveness in the first three quarters of 2001 and 2002. The restatement had no impact on previously reported consolidated operating, investing and financing cash flows for the first three quarters of 2001 or 2002. A summary of the principal effects of the restatement for the quarters ended March 31, 2001 and 2002, June 30, 2001 and 2002, and September 30, 2001 and 2002 are set forth in Note 1 to our consolidated financial statements. For purposes of this Form 10-Q/A, and in accordance with Rule 12b-15 under the Securities Exchange Act of 1934, as amended, each item of the September 30, 2002 Form 10-Q as originally filed on November 14, 2002 that was affected by the restatement has been amended and restated, in its entirety. No attempt has been made in this Form 10-Q/A to modify or update other disclosures as presented in the original Form 10-Q except as required to reflect the effects of the restatement, as described above. i TABLE OF CONTENTS PART I. FINANCIAL INFORMATION Item 1. Financial Statements Statements of Consolidated Income (unaudited) Three and Nine Months Ended September 30, 2001 (as restated) and 2002 (as restated)..........1 Consolidated Balance Sheets (unaudited) December 31, 2001 (as restated) and September 30, 2002 (as restated).........................2 Statements of Consolidated Cash Flows (unaudited) Nine Months Ended September 30, 2001 (as restated) and 2002 (as restated)....................4 Notes to Unaudited Consolidated Financial Statements.........................................5 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.......52 Item 3. Quantitative and Qualitative Disclosures About Market Risk..................................78 Item 4. Controls and Procedures.....................................................................80 PART II. OTHER INFORMATION Item 1. Legal Proceedings...........................................................................81 Item 5. Other Information...........................................................................81 Item 6. Exhibits and Reports on Form 8-K............................................................82 ii PART I. FINANCIAL INFORMATION RELIANT RESOURCES, INC. AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED INCOME (THOUSANDS OF DOLLARS, EXCEPT PER SHARE AMOUNTS) (UNAUDITED) THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------- ------------- 2001 2002 2001 2002 (AS RESTATED) (AS RESTATED) (AS RESTATED) (AS RESTATED) Revenues .......................................................... $ 2,473,419 $ 5,225,655 $ 5,392,307 $ 9,204,325 Trading margins (See Note 3) ...................................... 61,869 118,375 311,478 291,031 ----------- ----------- ----------- ----------- Total .......................................................... 2,535,288 5,344,030 5,703,785 9,495,356 ----------- ----------- ----------- ----------- EXPENSES: Fuel and cost of gas sold ...................................... 476,532 495,711 1,744,606 1,083,043 Purchased power ................................................ 1,308,183 3,863,918 2,190,671 6,062,458 Accrual for payment to CenterPoint Energy, Inc. ................ -- 89,000 -- 89,000 Operation and maintenance ...................................... 138,922 259,139 385,610 673,622 General, administrative and development ........................ 114,099 223,869 406,846 503,805 Depreciation ................................................... 36,094 134,962 96,675 303,865 Amortization ................................................... 35,774 6,561 82,669 14,962 ----------- ----------- ----------- ----------- Total ..................................................... 2,109,604 5,073,160 4,907,077 8,730,755 ----------- ----------- ----------- ----------- OPERATING INCOME .................................................. 425,684 270,870 796,708 764,601 ----------- ----------- ----------- ----------- OTHER INCOME (EXPENSE): Gain (loss) from investments, net .............................. 3,700 (2,338) 15,015 2,493 Income from equity investments in unconsolidated subsidiaries .. 2,132 955 66,482 10,263 Other, net ..................................................... 250 10,487 7,152 14,081 Interest expense ............................................... (8,355) (103,130) (52,220) (208,974) Interest income ................................................ 3,010 11,183 18,360 19,493 Interest income - affiliated companies, net .................... 11,319 570 7,888 4,754 ----------- ----------- ----------- ----------- Total other income (expense) ................................. 12,056 (82,273) 62,677 (157,890) ----------- ----------- ----------- ----------- INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE ......................................... 437,740 188,597 859,385 606,711 INCOME TAX EXPENSE ................................................ 176,179 138,163 313,876 284,346 ----------- ----------- ----------- ----------- INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE .............. 261,561 50,434 545,509 322,365 Cumulative effect of accounting change, net of tax ............. -- -- 3,062 (233,600) ----------- ----------- ----------- ----------- NET INCOME ........................................................ $ 261,561 $ 50,434 $ 548,571 $ 88,765 =========== =========== =========== =========== BASIC EARNINGS PER SHARE: Income before cumulative effect of accounting change ........... $ 0.87 $ 0.17 $ 2.00 $ 1.11 Cumulative effect of accounting change, net of tax ............. -- -- 0.01 (0.80) ----------- ----------- ----------- ----------- Net Income ................................................. $ 0.87 $ 0.17 $ 2.01 $ 0.31 =========== =========== =========== =========== DILUTED EARNINGS PER SHARE: Income before cumulative effect of accounting change ........... $ 0.87 $ 0.17 $ 2.00 $ 1.10 Cumulative effect of accounting change, net of tax ............. -- -- 0.01 (0.80) ----------- ----------- ----------- ----------- Net Income ................................................. $ 0.87 $ 0.17 $ 2.01 $ 0.30 =========== =========== =========== =========== See Notes to the Company's Interim Financial Statements 1 RELIANT RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (THOUSANDS OF DOLLARS) (UNAUDITED) ASSETS DECEMBER 31, SEPTEMBER 30, 2001 2002 ---- ---- CURRENT ASSETS: (AS RESTATED) (AS RESTATED) Cash and cash equivalents .................................... $ 118,453 $ 1,443,605 Restricted cash .............................................. 167,421 447,087 Accounts and notes receivable, principally customer, net ..... 1,167,870 1,270,346 Accrued unbilled revenues .................................... 14,270 418,585 Note receivable related to receivable facility ............... -- 253,928 Accounts and notes receivable - affiliated companies, net .... 415,081 -- Fuel stock and petroleum products ............................ 109,036 218,782 Materials and supplies ....................................... 64,999 117,787 Stranded costs settlement receivable ......................... 201,503 -- Trading and marketing assets ................................. 1,611,393 1,376,817 Non-trading derivative assets ................................ 392,900 370,464 Margin deposits on energy trading and hedging activities ..... 213,727 284,086 Collateral for electric generating equipment ................. 141,701 -- Prepayments and other current assets ......................... 126,936 179,851 ------------ ------------ Total current assets ....................................... 4,745,290 6,381,338 ------------ ------------ Property, plant and equipment ................................... 4,834,122 9,494,171 Less accumulated depreciation ................................... (275,729) (525,810) ------------ ------------ Property, plant and equipment - net ............................. 4,558,393 8,968,361 ------------ ------------ OTHER ASSETS: Goodwill, net ................................................ 891,061 2,157,244 Air emissions regulatory allowances and other intangibles, net 315,438 402,704 Notes receivable - affiliated companies, net ................. 30,278 -- Trading and marketing assets ................................. 446,610 551,308 Non-trading derivative assets ................................ 254,168 271,375 Equity investments in unconsolidated subsidiaries ............ 386,841 288,297 Stranded costs indemnification receivable .................... 203,693 225,931 Accumulated deferred income taxes ............................ 46,322 -- Prepaid lease ................................................ 121,699 214,809 Restricted funds for stranded costs .......................... -- 1,514 Collateral for electric generating equipment ................. 88,268 -- Other ........................................................ 203,645 216,541 ------------ ------------ Total other assets ......................................... 2,988,023 4,329,723 ------------ ------------ TOTAL ASSETS ............................................ $ 12,291,706 $ 19,679,422 ============ ============ See Notes to the Company's Interim Financial Statements 2 RELIANT RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS - (CONTINUED) (THOUSANDS OF DOLLARS) (UNAUDITED) LIABILITIES AND STOCKHOLDERS' EQUITY DECEMBER 31, SEPTEMBER 30, 2001 2002 ---- ---- CURRENT LIABILITIES: (AS RESTATED) (AS RESTATED) Current portion of long-term debt ..................................... $ 23,769 $ 31,768 Short-term borrowings ................................................. 296,769 5,284,717 Accounts payable, principally trade ................................... 1,002,326 1,315,417 Trading and marketing liabilities ..................................... 1,478,336 1,265,655 Non-trading derivative liabilities .................................... 399,277 376,801 Accumulated deferred income taxes ..................................... 37,034 115,891 Margin deposits from customers on energy trading and hedging activities 144,700 66,602 Other ................................................................. 253,800 468,577 ------------ ------------ Total current liabilities ...................................... 3,636,011 8,925,428 ------------ ------------ OTHER LIABILITIES: Accumulated deferred income taxes ..................................... -- 344,553 Trading and marketing liabilities ..................................... 361,786 437,966 Non-trading derivative liabilities .................................... 639,211 433,274 Major maintenance reserve ............................................. 16,784 20,882 Accrual for payment to CenterPoint Energy, Inc. ....................... -- 89,000 Non-derivative stranded costs liability ............................... 203,693 225,931 Benefit obligations ................................................... 127,012 148,748 Other ................................................................. 455,865 386,904 ------------ ------------ Total other liabilities ........................................ 1,804,351 2,087,258 ------------ ------------ LONG-TERM DEBT ........................................................... 867,712 2,425,140 ------------ ------------ COMMITMENTS AND CONTINGENCIES (NOTE 12) STOCKHOLDERS' EQUITY: Preferred stock (125,000,000 shares authorized; none outstanding) ..... -- -- Common stock (2,000,000,000 shares authorized; 299,804,000 issued and outstanding, respectively) ....................................... 61 61 Additional paid-in capital ............................................ 5,789,869 5,809,757 Treasury stock at cost, 11,000,000 shares and 9,364,221 shares ........ (189,460) (161,333) Retained earnings ..................................................... 563,351 652,116 Accumulated other comprehensive loss .................................. (180,189) (59,005) Stockholders' equity ........................................... 5,983,632 6,241,596 ------------ ------------ TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY ................... $ 12,291,706 $ 19,679,422 ============ ============ See Notes to the Company's Interim Financial Statements 3 RELIANT RESOURCES, INC. AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED CASH FLOWS (THOUSANDS OF DOLLARS) (UNAUDITED) NINE MONTHS ENDED SEPTEMBER 30, 2001 2002 ---- ---- CASH FLOWS FROM OPERATING ACTIVITIES: (AS RESTATED) (AS RESTATED) Net income ...................................................................... $ 548,571 $ 88,765 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization ................................................. 179,344 318,826 Deferred income taxes ......................................................... 12,129 294,182 Net trading and marketing assets and liabilities .............................. (43,122) (13,994) Net non-trading derivative assets and liabilities ............................. (59,059) (36,386) Amortization of contractual rights and obligations ............................ -- (50,128) Curtailment and related benefit enhancement ................................... 99,523 -- Accounting settlement for certain benefit plans ............................... -- 47,356 Accrual for payment to CenterPoint Energy, Inc. ............................... -- 89,000 Undistributed earnings of unconsolidated subsidiaries ......................... (31,884) (7,612) Gain on settlement of stranded costs contracts ................................ -- (109,000) Cumulative effect of accounting change ........................................ (3,062) 233,600 Changes in other assets and liabilities, net of effects of acquisitions: Restricted cash ............................................................ 50,000 56,650 Accounts and notes receivable and unbilled revenue, net .................... 332,181 (354,577) Accounts receivable/payable - affiliated companies, net .................... 111,472 26,603 Inventory .................................................................. (52,779) (103,552) Collateral for electric generating equipment, net .......................... (62,366) 136,013 Margin deposits on energy trading activities, net .......................... 123,995 (147,267) Net non-trading derivative assets and liabilities .......................... (74,879) (147,204) Prepaid lease obligation ................................................... (195,239) (93,309) Other current assets ....................................................... 56,954 (5,019) Other assets ............................................................... (31,563) (32,059) Accounts payable ........................................................... (959,614) 162,385 Taxes accrued .............................................................. 177,773 41,667 Other current liabilities .................................................. 63,424 21,268 Other liabilities .......................................................... 27,435 (74,999) Other, net ................................................................... (7,489) (21,865) ----------- ----------- Net cash provided by operating activities ................................ 261,745 319,344 ----------- ----------- CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures ............................................................ (719,577) (474,974) Business acquisitions, net of cash acquired ..................................... -- (2,963,801) Distribution from equity investment in unconsolidated subsidiary ................ -- 137,475 Other, net ...................................................................... 10,675 27 ----------- ----------- Net cash used in investing activities .................................... (708,902) (3,301,273) ----------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from long-term debt .................................................... -- 22,324 Proceeds from issuance of stock, net ............................................ 1,697,848 -- Purchase of treasury stock ...................................................... (20,420) -- Payments of long-term debt ...................................................... (2,286) (229,785) Increase in short-term borrowings, net .......................................... 184,779 4,109,925 Change in notes with affiliated companies, net .................................. (1,234,444) 385,652 Contributions from owner ........................................................ 9,441 -- Other, net ...................................................................... (3) 13,120 ----------- ----------- Net cash provided by financing activities ................................ 634,915 4,301,236 ----------- ----------- EFFECT OF EXCHANGE RATE CHANGES ON CASH AND CASH EQUIVALENTS ....................... (5,865) 5,845 ----------- ----------- NET INCREASE IN CASH AND CASH EQUIVALENTS .......................................... 181,893 1,325,152 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD ................................... 89,755 118,453 ----------- ----------- CASH AND CASH EQUIVALENTS AT END OF PERIOD ......................................... $ 271,648 $ 1,443,605 =========== =========== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash Payments: Interest (net of amounts capitalized) ........................................... $ 63,692 $ 198,279 Income taxes .................................................................... 116,716 6,743 See Notes to the Company's Interim Financial Statements 4 RELIANT RESOURCES, INC. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (1) BACKGROUND AND BASIS OF PRESENTATION Included in this Quarterly Report on Form 10-Q/A (Form 10-Q/A) for Reliant Resources, Inc. (Reliant Resources), together with its subsidiaries (collectively, the Company), are the Company's consolidated interim financial statements and notes (Interim Financial Statements). The Interim Financial Statements are unaudited, omit certain financial statement disclosures and should be read with the amended annual report on Form 10-K/A (Amendment No. 2) of Reliant Resources (Reliant Resources Form 10-K/A) for the year ended December 31, 2001 filed on November 12, 2002, the Quarterly Report on Form 10-Q of Reliant Resources for the quarter ended March 31, 2002 (First Quarter 10-Q) and the Quarterly Report on Form 10-Q of Reliant Resources for the quarter ended June 30, 2002 (Second Quarter 10-Q). RESTATEMENT Restatement. Subsequent to the issuance of the Company's financial statements for 2001, the Company identified four natural gas financial swap transactions that should not have been recorded in its records. The Company has concluded, based on the offsetting nature of the transactions and manner in which the transactions were documented, that none of the transactions should have been given accounting recognition. The Company previously accounted for these transactions in its financial statements as a reduction in revenues in December 2000 and an increase in revenues in January 2001, with the effect of decreasing net income in the fourth quarter of 2000 and increasing net income in the first quarter of 2001, in each case by $20.0 million pre-tax ($12.7 million after-tax) and the effect of increasing basic and diluted earnings per share by $0.05 in the first quarter of 2001. There were no cash flows associated with the transactions. Also, subsequent to the issuance of the Company's financial statements for 2001 and for the first three quarters of 2002, the Company determined that it had incorrectly calculated the amount of hedge ineffectiveness for 2001 and the first three quarters of 2002 for hedging instruments entered into prior to the adoption of Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended (SFAS No. 133). These hedging instruments included long-term forward contracts for the sale of power in the California market through December 2006. The amount of hedge ineffectiveness for these forward contracts was calculated using the trade date. However, the proper date for the hedge ineffectiveness calculation is hedge inception, which for these contracts was deemed to be January 1, 2001, concurrent with the adoption of SFAS No. 133. In addition, the Company did not record the amount of ineffectiveness for any hedging instruments during the first three quarters of 2001. These errors in accounting for hedge ineffectiveness resulted in an understatement of revenues of $57.3 million ($37.1 million after-tax) and earnings per share of $0.14 in the first nine months of 2001. These errors in accounting for hedge ineffectiveness resulted in an overstatement of revenues of $16.5 million ($10.7 million after-tax) and earnings per share of $0.04 in the first nine months of 2002. A summary of the principal combined effects of the four natural gas financial swap transactions and the hedge ineffectiveness issues for 2001 is as follows (increase (decrease)): YEAR ENDED DECEMBER 31, 2001 ---------------------------- FIRST QUARTER SECOND QUARTER THIRD QUARTER FOURTH QUARTER TOTAL ------------- -------------- ------------- -------------- ----- (IN MILLIONS, EXCEPT PER SHARE AMOUNTS) Revenues .................................... $ (17) $ (19) $ 73 $ (28) $ 9 Operating income ............................ (17) (19) 73 (28) 9 Income before cumulative effect of accounting change ................................... (11) (12) 48 (19) 6 Net income .................................. (11) (12) 48 (19) 6 Basic and diluted earnings per share ........ $(0.05) $(0.04) $0.16 $(0.06) $0.02 5 A summary of the principal effects of the hedge ineffectiveness miscalculation for the quarterly periods ended March 31, 2002, June 30, 2002 and September 30, 2002 is as follows (increase (decrease)): NINE MONTHS ENDED SEPTEMBER 30, 2002 ------------------------------------ FIRST QUARTER SECOND QUARTER THIRD QUARTER TOTAL ------------- -------------- ------------- ----- (IN MILLIONS, EXCEPT PER SHARE AMOUNTS) Revenues.............................................. $ (1) $ (4) $ (11) $ (16) Operating income...................................... (1) (4) (11) (16) Income before cumulative effect of accounting change.. (1) (3) (7) (11) Net income (loss)..................................... (1) (3) (7) (11) Basic and diluted earnings per share................... $ -- $(0.01) $(0.03) $(0.04) Revisions Related to Changes in Accounting Principles. Beginning with the quarter ended September 30, 2002, the Company now reports all energy trading and marketing activities on a net basis in the statements of consolidated operations. For information regarding the presentation of trading and marketing activities on a net basis, see Note 3. Accordingly, the interim periods for 2001 and the interim periods ended March 31, 2002 and June 30, 2002 have been reclassified to conform to this presentation. See Note 3 for the effect of adoption of net reporting in the three and nine months ended September 30, 2001. The adoption of net reporting resulted in reclassifications of revenues, fuel and cost of gas sold and purchased power expense for the three months ended March 31, 2001 and 2002 and the three months ended June 30, 2001 and 2002 as follows: THREE MONTHS ENDED MARCH 31, THREE MONTHS ENDED JUNE 30, ---------------------------- --------------------------- 2001 2002 2001 2002 ---- ---- ---- ---- (IN MILLIONS) Total revenues .......... $7,112 $5,222 $6,300 $6,212 Fuel and cost of gas sold 5,112 2,390 3,431 3,752 Purchased power ......... 2,000 2,832 2,869 2,460 ------ ------ ------ ------ Net impact on margins $ -- $ -- $ -- $ -- ====== ====== ====== ====== During the third quarter of 2002, the Company completed the transitional impairment test for the adoption of SFAS No. 142, "Goodwill and Other Intangible Assets," (SFAS No. 142) on its consolidated financial statements, including the review of goodwill for impairment as of January 1, 2002 (see Note 7). Based on this impairment test, the Company recorded an impairment of its European Energy segment's goodwill of $234 million, net of tax. This impairment loss was recorded retroactively as a cumulative effect of a change in accounting principle for the quarter ended March 31, 2002. Impact of Restatement and Revisions Related to Changes in Accounting Principles. The consolidated financial statements for the first three quarters of 2001 and 2002 have been restated from amounts previously reported to remove the effects of the four natural gas swap transactions from the first quarter of 2001 and to correctly account for the amount of hedge ineffectiveness in the first three quarters of 2001 and 2002. The restatement had no impact on previously reported consolidated operating, investing and financing cash flows in the first three quarters of 2001 or 2002. The following is a summary of the principal effects of the restatement and the revisions for changes in accounting principles for the quarters ended March 31, 2001 and 2002 and June 30, 2001 and 2002, as applicable. In addition, the following is a summary of the principle effects of the restatement for the three and nine months ended September 30, 2001 and 2002 and as of December 31, 2001 and September 30, 2002. (Note - Those line items for which no change in amounts is shown were not affected by the restatement.) 6 THREE MONTHS ENDED MARCH 31, 2001 --------------------------------- AS REVISED FOR CHANGES IN ACCOUNTING AS PREVIOUSLY AS RESTATED PRINCIPLES REPORTED ----------- ---------- -------- (IN MILLIONS) Revenues .................................................................... $ 1,393 $ 1,410 $ 8,640 Trading margins ............................................................. 118 118 -- ------- ------- ------- Total revenues ........................................................... 1,511 1,528 8,640 ------- ------- ------- Fuel and cost of gas sold ................................................... 644 644 5,756 Purchased power ............................................................. 396 396 2,396 Other operating expenses .................................................... 374 374 374 ------- ------- ------- Total operating expenses .................................................... 1,414 1,414 8,526 ------- ------- ------- Operating income ............................................................ 97 114 114 Other expense, net .......................................................... (5) (5) (5) ------- ------- ------- Income before income tax expense and cumulative effect of accounting change . 92 109 109 Income tax expense .......................................................... 24 30 30 ------- ------- ------- Income before cumulative effect of accounting change ........................ 68 79 79 Cumulative effect of accounting change, net of tax .......................... 3 3 3 ------- ------- ------- Net income .................................................................. $ 71 $ 82 $ 82 ======= ======= ======= Basic and Diluted Earnings Per Share: Income before cumulative effect of accounting change ..................... $ 0.28 $ 0.33 $ 0.33 Cumulative effect of accounting change, net of tax ....................... 0.01 0.01 0.01 ------- ------- ------- Net income ............................................................. $ 0.29 $ 0.34 $ 0.34 ======= ======= ======= 7 THREE MONTHS ENDED MARCH 31, 2002 --------------------------------- AS REVISED FOR CHANGES IN ACCOUNTING AS PREVIOUSLY AS RESTATED PRINCIPLES REPORTED ----------- ---------- -------- (IN MILLIONS) Revenues ................................................ $ 1,753 $ 1,754 $ 7,030 Trading margins ......................................... 54 54 -- ------- ------- ------- Total revenues ....................................... 1,807 1,808 7,030 ------- ------- ------- Fuel and cost of gas sold ............................... 243 243 2,633 Purchased power ......................................... 1,036 1,036 3,868 Other operating expenses ................................ 363 363 363 ------- ------- ------- Total operating expenses ................................ 1,642 1,642 6,864 ------- ------- ------- Operating income ........................................ 165 166 166 Other expense, net ...................................... (27) (27) (27) ------- ------- ------- Income before income tax expense and cumulative effect of accounting change ............................... 138 139 139 Income tax expense ...................................... 42 42 42 ------- ------- ------- Income before cumulative effect of accounting change .... 96 97 97 Cumulative effect of accounting change, net of tax ...... 234 234 -- ------- ------- ------- Net (loss) income ....................................... $ (138) $ (137) $ 97 ======= ======= ======= Basic and Diluted Earnings Per Share: Income before cumulative effect of accounting change . $ 0.33 $ 0.33 $ 0.33 Cumulative effect of accounting change, net of tax ... (0.81) (0.81) -- ------- ------- ------- Net (loss) income .................................. $ (0.48) $ (0.48) $ 0.33 ======= ======= ======= 8 THREE MONTHS ENDED JUNE 30, 2001 -------------------------------- AS REVISED FOR CHANGES IN ACCOUNTING AS PREVIOUSLY AS RESTATED PRINCIPLES REPORTED ----------- ---------- -------- (IN MILLIONS) Revenues .................................................................... $1,526 $1,545 $7,976 Trading margins ............................................................. 131 131 -- ------ ------ ------ Total revenues ........................................................... 1,657 1,676 7,976 ------ ------ ------ Fuel and cost of gas sold ................................................... 623 623 4,054 Purchased power ............................................................. 486 486 3,355 Other operating expenses .................................................... 273 273 273 ------ ------ ------ Total operating expenses .................................................... 1,382 1,382 7,682 ------ ------ ------ Operating income ............................................................ 275 294 294 Other income, net ........................................................... 54 54 54 Income before income tax expense and cumulative effect of accounting changes 329 348 348 Income tax expense .......................................................... 113 120 120 ------ ------ ------ Income before cumulative effect of accounting change ........................ 216 228 228 Cumulative effect of accounting change, net of tax .......................... -- -- -- ------ ------ ------ Net income .................................................................. $ 216 $ 228 $ 228 ====== ====== ====== Basic Earnings Per Share: Income before cumulative effect of accounting change ..................... $ 0.78 $ 0.83 $ 0.83 Cumulative effect of accounting change, net of tax ....................... -- -- -- ------ ------ ------ Net income ............................................................. $ 0.78 $ 0.83 $ 0.83 ====== ====== ====== Diluted Earnings Per Share: Income before cumulative effect of accounting change ..................... $ 0.78 $ 0.82 $ 0.82 Cumulative effect of accounting change, net of tax ....................... -- -- -- ------ ------ ------ Net income ............................................................. $ 0.78 $ 0.82 $ 0.82 ====== ====== ====== 9 THREE MONTHS ENDED JUNE 30, 2002 -------------------------------- AS REVISED FOR CHANGES IN ACCOUNTING AS PREVIOUSLY AS RESTATED PRINCIPLES REPORTED ----------- ---------- -------- (IN MILLIONS) Revenues .................................................................... $ 2,226 $ 2,230 $ 8,561 Trading margins ............................................................. 119 119 -- ------- ------- ------- Total revenues ........................................................... 2,345 2,349 8,561 ------- ------- ------- Fuel and cost of gas sold ................................................... 344 344 4,096 Purchased power ............................................................. 1,163 1,163 3,623 Other operating expenses .................................................... 509 509 509 ------- ------- ------- Total operating expenses .................................................... 2,016 2,016 8,228 ------- ------- ------- Operating income ............................................................ 329 333 333 Other expense, net .......................................................... (50) (50) (50) ------- ------- ------- Income before income tax expense and cumulative effect of accounting changes 279 283 283 Income tax expense .......................................................... 104 105 105 ------- ------- ------- Income before cumulative effect of accounting change ........................ 175 178 178 Cumulative effect of accounting change, net of tax .......................... -- -- -- ------- ------- ------- Net income .................................................................. $ 175 $ 178 $ 178 ======= ======= ======= Basic Earnings Per Share: Income before cumulative effect of accounting change ..................... $ 0.61 $ 0.62 $ 0.62 Cumulative effect of accounting change, net of tax ....................... -- -- -- ------- ------- ------- Net income ............................................................. $ 0.61 $ 0.62 $ 0.62 ======= ======= ======= Diluted Earnings Per Share: Income before cumulative effect of accounting change ..................... $ 0.60 $ 0.61 $ 0.61 Cumulative effect of accounting change, net of tax ....................... -- -- -- ------- ------- ------- Net income ............................................................. $ 0.60 $ 0.61 $ 0.61 ======= ======= ======= 10 THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, 2001 SEPTEMBER 30, 2001 ------------------ ------------------ AS PREVIOUSLY AS PREVIOUSLY AS RESTATED REPORTED AS RESTATED REPORTED ----------- -------- ----------- -------- (IN MILLIONS) Revenues ........................................................... $2,473 $2,400 $5,393 $5,355 Trading margins .................................................... 62 62 311 311 ------ ------ ------ ------ Total revenues .................................................. 2,535 2,462 5,704 5,666 ------ ------ ------ ------ Fuel and cost of gas sold .......................................... 476 476 1,745 1,745 Purchased power .................................................... 1,308 1,308 2,191 2,191 Other operating expenses ........................................... 326 326 971 971 ------ ------ ------ ------ Total operating expenses ........................................... 2,110 2,110 4,907 4,907 ------ ------ ------ ------ Operating income ................................................... 425 352 797 759 Other income, net .................................................. 12 12 63 63 ------ ------ ------ ------ Income before income tax expense and cumulative effect of accounting changes ......................................................... 437 364 860 822 Income tax expense ................................................. 175 150 314 301 ------ ------ ------ ------ Income before cumulative effect of accounting change ............... 262 214 546 521 Cumulative effect of accounting change, net of tax ................. -- -- 3 3 ------ ------ ------ ------ Net income ......................................................... $ 262 $ 214 $ 549 $ 524 ====== ====== ====== ====== Basic Earnings Per Share: Income before cumulative effect of accounting change ............ $ 0.87 $ 0.71 $ 2.00 $ 1.92 Cumulative effect of accounting change, net of tax .............. -- -- 0.01 0.01 ------ ------ ------ ------ Net income .................................................... $ 0.87 $ 0.71 $ 2.01 $ 1.93 ====== ====== ====== ====== Diluted Earnings Per Share: Income before cumulative effect of accounting change ............ $ 0.87 $ 0.71 $ 2.00 $ 1.91 Cumulative effect of accounting change, net of tax .............. -- -- 0.01 0.01 ------ ------ ------ ------ Net income .................................................... $ 0.87 $ 0.71 $ 2.01 $ 1.92 ====== ====== ====== ====== 11 THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, 2002 SEPTEMBER 30, 2002 ------------------ ------------------ AS PREVIOUSLY AS PREVIOUSLY AS RESTATED REPORTED AS RESTATED REPORTED ----------- -------- ----------- -------- (IN MILLIONS) Revenues ........................................................... $ 5,225 $ 5,236 $ 9,204 $ 9,220 Trading margins .................................................... 119 119 291 291 ------- ------- ------- ------- Total revenues .................................................. 5,344 5,355 9,495 9,511 ------- ------- ------- ------- Fuel and cost of gas sold .......................................... 496 496 1,083 1,083 Purchased power .................................................... 3,864 3,864 6,062 6,062 Other operating expenses ........................................... 713 713 1,585 1,585 ------- ------- ------- ------- Total operating expenses ........................................... 5,073 5,073 8,730 8,730 ------- ------- ------- ------- Operating income ................................................... 271 282 765 781 Other expense, net ................................................. (82) (82) (158) (158) ------- ------- ------- ------- Income before income tax expense and cumulative effect of accounting changes ......................................................... 189 200 607 623 Income tax expense ................................................. 138 142 284 290 ------- ------- ------- ------- Income before cumulative effect of accounting change ............... 51 58 323 333 Cumulative effect of accounting change, net of tax ................. -- -- 234 234 ------- ------- ------- ------- Net income ......................................................... $ 51 $ 58 $ 89 $ 99 ======= ======= ======= ======= Basic Earnings Per Share: Income before cumulative effect of accounting change ............ $ 0.17 $ 0.20 $ 1.11 $ 1.15 Cumulative effect of accounting change, net of tax .............. -- -- (0.80) (0.81) ------- ------- ------- ------- Net income .................................................... $ 0.17 $ 0.20 $ 0.31 $ 0.34 ======= ======= ======= ======= Diluted Earnings Per Share: Income before cumulative effect of accounting change ............ $ 0.17 $ 0.20 $ 1.10 $ 1.14 Cumulative effect of accounting change, net of tax .............. -- -- (0.80) (0.80) ------- ------- ------- ------- Net income .................................................... $ 0.17 $ 0.20 $ 0.30 $ 0.34 ======= ======= ======= ======= DECEMBER 31, 2001 SEPTEMBER 30, 2002 ----------------- ------------------ AS PREVIOUSLY AS PREVIOUSLY AS RESTATED REPORTED AS RESTATED REPORTED ----------- -------- ----------- -------- ASSETS (IN MILLIONS) Current assets ................................... $ 4,745 $ 4,745 $ 6,381 $ 6,381 Total long-term assets ........................... 7,547 7,547 13,298 13,298 -------- -------- -------- -------- Total Assets ............................. $ 12,292 $ 12,292 $ 19,679 $ 19,679 ======== ======== ======== ======== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities .............................. $ 3,636 $ 3,636 $ 8,925 $ 8,925 Total long-term liabilities ...................... 2,672 2,672 4,512 4,512 Stockholders' Equity: Preferred stock ............................... -- -- -- -- Common Stock .................................. -- -- -- -- Additional paid-in capital .................... 5,790 5,777 5,810 5,797 Treasury stock ................................ (189) (189) (161) (161) Retained earnings ............................. 563 557 652 657 Accumulated other comprehensive loss .......... (180) (161) (59) (51) -------- -------- -------- -------- Stockholders' equity ........................ 5,984 5,984 6,242 6,242 -------- -------- -------- -------- Total Liabilities and Stockholders' Equity $ 12,292 $ 12,292 $ 19,679 $ 19,679 ======== ======== ======== ======== 12 BASIS OF PRESENTATION The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. This basis of accounting in the Interim Financial Statements contemplates the recovery of the Company's assets and the satisfaction of its liabilities in the normal course of conducting business, which in turn is dependent upon the Company's ability to successfully execute its refinancing plans, as described in Note 2. The Company expects to successfully execute its refinancing plans; accordingly, management believes it will be able to meet its obligations in a manner consistent with this accounting treatment. However, there can be no assurance that the Company will be successful in executing its refinancing plans. If the Company is unable to complete the necessary future refinancings on acceptable terms and conditions, given the magnitude of the refinancings the Company may be forced to consider a reorganization under the protection of bankruptcy laws. For discussion of the Company's refinancing plans, see Note 2. The Company records gross revenue for energy sales and services related to its electric power generation facilities under the accrual method and these revenues generally are recognized upon delivery. Electric power and other energy services are sold at market-based prices through existing power exchanges or through third-party contracts. The Company records gross revenue for energy sales and services to retail customers under the accrual method and these revenues generally are recognized upon delivery, except for sales to large commercial, industrial and institutional customers under contract. Energy sales and services related to its electric power generation facilities and to retail customers not billed by month-end are accrued based upon estimated energy and services delivered. The Company's energy trading, marketing, power origination and risk management services activities and sales of electricity to large commercial, industrial and institutional customers under contract are accounted for under the mark-to-market method of accounting. Under the mark-to-market method of accounting, derivative instruments and contractual commitments are recorded at fair value in revenues upon contract execution. The net changes in their fair values are recognized in the Statements of Consolidated Income as revenues in the period of change. Trading and marketing revenues related to the sale of natural gas, electric power and other energy related commodities are recorded on a net basis. For information regarding the Company's adoption of Emerging Issues Task Force (EITF) No. 02-03, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (EITF No. 02-03) and the presentation of trading and marketing activities on a net basis beginning in the quarter ending September 30, 2002, see Note 3. For additional discussion regarding trading and marketing revenue recognition and the related estimates and assumptions that can affect reported amounts of such revenues, see Note 6 to the Reliant Resources 10-K/A Notes. The gains and losses related to financial instruments and contractual commitments qualifying and designated as hedges related to the purchase and sale of electric power and purchase of fuel are deferred in accumulated other comprehensive income to the extent the contracts are effective, and then are recognized in the same period as the settlement of the underlying physical transaction. Realized gains and losses on financial contracts designated as hedges are included in operating revenues in the Statements of Consolidated Income. Revenues, fuel and cost of gas sold, and purchased power related to physical sale and purchase contracts designated as hedges are generally recorded on a gross basis in the delivery period. For additional discussion, see Note 6 to the Reliant Resources 10-K/A Notes. The Company's effective tax rate for the three and nine months ended September 30, 2002 varied from the historical customary statutory rate as a result of an additional United States federal tax provision for future cash distributions from an European equity investment, adjustments to state income taxes primarily due to Texas franchise tax associated with the Company's retail energy operations, and valuation allowances that increased due to losses incurred by the Company's European Energy segment trading and origination operations. The Interim Financial Statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position and results of operations of the Company for the 13 respective periods. Amounts reported in the Statements of Consolidated Income are not necessarily indicative of amounts expected for a full year period due to the effects of, among other things, (a) seasonal fluctuation in demand for energy and energy services, (b) changes in energy commodity prices, (c) timing of maintenance and other expenditures, (d) acquisitions and dispositions of businesses, assets and other interests and (e) changes in interest expense. In addition, certain amounts from the prior period have been reclassified to conform to the Company's presentation of financial statements in the current period. These reclassifications do not affect the earnings of the Company. The following Reliant Resources 10-K/A Notes relate to certain contingencies. See applicable note in the Reliant Resources 10-K/A Notes. Notes to Consolidated Financial Statements included in the Reliant Resources Form 10-K/A: Note 4 (Related Party Agreements - Agreements Between Reliant Energy and the Company), Note 5 (Business Acquisitions), Note 6 (Derivative Instruments), Note 13 (Commitments and Contingencies), Note 17 (Bankruptcy of Enron Corp. and its Affiliates) and Note 19 (Subsequent Events). For information regarding certain legal, regulatory proceedings and environmental matters, see Note 12. Reliant Energy adopted a business separation plan in response to the Texas Electric Choice Plan (Texas electric restructuring law) adopted by the Texas legislature in June 1999. The Texas electric restructuring law substantially amended the regulatory structure governing electric utilities in Texas in order to allow retail electric competition with respect to all customer classes beginning in January 2002. Under its business separation plan filed with the Public Utility Commission of Texas (Texas Utility Commission), Reliant Energy transferred substantially all of its unregulated businesses to the Company in order to separate its regulated and unregulated operations. In accordance with the plan, the Company completed its initial public offering (IPO) of nearly 20% of its common stock in May 2001 and received net proceeds from the IPO of $1.7 billion. For additional information regarding the IPO, see Note 1 and Note 9(a) to the Reliant Resources 10-K/A Notes. CenterPoint Energy, Inc. (CenterPoint Energy) was formed on August 31, 2002 as the new holding company of Reliant Energy. CenterPoint Energy is a diversified international energy services and energy delivery company that owned the majority of Reliant Resources outstanding common stock prior to September 30, 2002. On September 30, 2002, CenterPoint Energy distributed all of the 240 million shares of Reliant Resources common stock it owned to its common shareholders of record as of the close of business on September 20, 2002 (Distribution). The Distribution completed the separation of Reliant Resources and CenterPoint Energy into two separate publicly held companies. (2) REFINANCING AND LIQUIDITY ISSUES During the first nine months of 2002, many factors negatively impacted the Company. These factors include weaker pricing for capacity, ancillary services and power, coupled with a narrowing of the spread between power prices and natural gas fuel costs (spark spread) in the United States; market contraction, reduced volatility and reduced liquidity in the power trading markets in the United States and Northwest Europe; downgrades in the Company's credit ratings to below investment grade by each of the major rating agencies; various legal and regulatory investigations and proceedings (see Notes 1 and 12); reduced market confidence in the Company's financial reporting in light of previous restatements and amendments; reduced access to capital and increased demands for collateral in connection with the Company's trading, hedging and commercial obligations; the decline in market prices of the Company's common stock; and continued weakness in the United States economy generally. Many of these factors are discussed in more detail below. Refinancing Issues. As of September 30, 2002, the Company had approximately $6.6 billion of credit facilities that will mature prior to September 30, 2003, including $5.2 billion prior to March 31, 2003. In October 2002, $1.6 billion of these credit facilities was refinanced as further discussed below and Note 16(b). The Company expects to extend or replace the remaining facilities. However, in light of the negative factors summarized above and the current credit environment, the Company believes that any extended or replacement facilities are likely to, as compared to the current facilities: include higher interest rates; more significantly restrict the use of the Company's cash; require collateral or additional collateral, as the case may be, as security; and otherwise contain more restrictive terms associated with loans to non-investment grade borrowers. If the Company is unable to extend or replace these facilities on acceptable terms and conditions, given the magnitude of the refinancings, the Company may be forced to consider other alternatives, including a reorganization under the protection of bankruptcy laws. 14 The following table provides a summary of the amounts owed and amounts available as of September 30, 2002 under the Company's various credit facilities. TOTAL EXPIRING BY COMMITTED LETTERS OF UNUSED SEPTEMBER CREDIT DRAWN AMOUNT CREDIT AMOUNT 30, 2003 EXPIRATION DATE ------ ------------ ------ ------ -------- --------------- (IN MILLIONS) RELIANT RESOURCES: Orion acquisition term loan................... $2,908 $2,908 $ -- $ -- $2,908 February 2003 364-day revolver/term loan.................... 800 800 -- -- 800 August 2003 Three-year revolver........................... 800 569 218 13 -- August 2004 WHOLESALE ENERGY: Orion Power and Subsidiaries: Orion Power................................. 62 51 11 -- 62 (1) December 2002 Orion MidWest............................... 1,063 1,048 15 -- 1,063 (1) October 2002 Orion NY.................................... 442 412 10 20 442 (1) December 2002 October 2002 - Liberty Project............................. 292 270 17 5 8 April 2026 Reliant Energy Channelview LP: Equity bridge............................... 92 92 -- -- 92 November 2002 Construction term loan and working capital October 2002 - facility................................. 383 348 -- 35 3 (2) July 2024 REMA letter of credit facility................ 51 -- 38 13 51 August 2003 EUROPEAN ENERGY: Reliant Energy Capital Europe, Inc........... 592 592 -- -- 592 (3) March 2003 REPGB 364-day revolver........................ 182 35 17 130 182 (3) July 2003 REPGB letter of credit facility............... 420 -- 271 149 420 (3) July 2003 ------ ------ ---- ---- ------ Total............................................ $8,087 $7,125 $597 $365 $6,623 ====== ====== ==== ==== ====== ------------ (1) As discussed in Note 16(b), these Orion Power and subsidiaries credit facilities were restructured in October 2002. (2) Excludes $369 million of facilities expiring in November 2002 as borrowings under such facilities are convertible into a long-term loan. (3) The results of the Company's European Energy segment are consolidated on a one-month lag basis. During October 2002, the Company restructured (a) the Orion Power Holdings, Inc. (Orion Power) revolving senior credit facility that matured in December 2002, (b) the Orion Power MidWest, LP (Orion MidWest) credit facility that matured in October 2002 and (c) the Orion Power New York, LP (Orion NY) credit facility that matured in December 2002. As part of this restructuring, the Orion Power revolving credit facility was terminated, and the Orion MidWest and Orion NY credit facilities were extended until October 2005. For further information regarding this restructuring, please read Note 16(b). It is Reliant Resources' current expectation to invest equity or subordinated debt in Reliant Energy Channelview LP totaling $92 million using cash on hand during November 2002. Reliant Energy Channelview LP must use the funds from this debt or equity investment to repay its equity bridge loan totaling $92 million during November 2002. The Company's $2.9 billion term loan to finance the purchase of Orion Power was funded on February 19, 2002. This term loan must be repaid within one year from the date on which it was funded, or February 19, 2003. The Company is currently negotiating with the lead banks regarding the appropriate terms and conditions for an extension of the maturity of this loan. The Company expects to complete this extension on or before the maturity. The Company anticipates that the banks will require that the loan be collateralized, contain additional and more restrictive covenants, have higher interest rates or fees or contain other provisions that may be dilutive to stockholders. 15 In August 2002, the Company exercised its option to convert its $800 million 364-day revolving facility to a one-year term loan with a maturity of August 22, 2003. The Company expects to extend and/or refinance this facility, as well as the $800 million three-year revolver that expires in August 2004, in conjunction with any extension of the $2.9 billion Orion acquisition term loan on terms and conditions substantially similar to any extended $2.9 billion Orion acquisition loan. The Company is considering the possibility of requesting equity and debt participants under the credit agreement related to its construction agency agreements to restructure and extend the maturity of the existing commitments in connection with the proposed extensions/refinancings described above. For further discussion of the construction agency agreements, see Note 12(f). To the extent that the Company is successful in such effort, it expects that such equity and debt participants under the credit agreements to the construction agency agreement may require additional collateral, additional and more restrictive covenants, and higher interest rates and fees. The Euro 600 million (approximately $592 million) term loan facility at Reliant Energy Capital Europe, Inc. (RECE) matures on March 1, 2003. Preliminary work has commenced on the refinancing of this term loan facility. The Company anticipates the completion of such refinancing during the first quarter of 2003. In addition, the Company has various other facilities that mature over the next twelve months. The Company anticipates refinancing or replacing the Reliant Energy Mid-Atlantic (REMA) letter of credit facility totaling $51 million maturing in August 2003, the Reliant Energy Power Generation Benelux (REPGB) 364-day revolver totaling Euro 184 million maturing in July 2003 and the REPGB letter of credit facility totaling $420 million maturing in July 2003 prior to their maturity, to the extent it continues to need access to this amount of committed credit. The Company anticipates that the lenders may require that these facilities be secured, contain additional and more restrictive covenants and have higher interest rates and fees. Credit Ratings. During the third quarter of 2002, each of the major rating agencies downgraded the Company's credit ratings to sub-investment grade. Credit ratings impact the Company's ability to obtain short- and long-term financing, the execution of its commercial strategies and the cost of financing because many of the Company's credit facilities have fees and interest rate margins based on the Company's credit rating. As of November 8, 2002, the Company's credit ratings for its senior unsecured debt were as follows: DATE ASSIGNED RATING AGENCY RATING RATING DESCRIPTION ------------- ------------- ------ ------------------ July 31, 2002 Moody's Ba3 Review for potential downgrade September 13, 2002 Standard & Poor's BB+ Credit watch with negative implications September 18, 2002 Fitch BB Rating watch negative The credit ratings of the Company's subsidiaries have been affected as well. As of November 8, 2002, the REMA lease certificates were rated BB+ by Standard & Poor's and Baa3 by Moody's. The ratings remain on credit watch with negative implications and review for possible downgrade, respectively. As of November 8, 2002, the RECE senior unsecured bank credit facility was rated Ba3 by Moody's. The rating remains on review for possible downgrade. The Standard & Poor's issuer rating was BB+ and remains on credit watch with negative implications. As of November 8, 2002, the long-term issuer rating assigned by Moody's to REPGB was Baa2 and remains on review for possible downgrade. The senior unsecured bank loan rating assigned by Standard & Poor's was BBB- and remains on credit watch with negative implications. As of November 8, 2002, the Moody's senior unsecured debt rating for Orion Power was Ba3. The rating remains on review for possible downgrade. Standard & Poor's senior unsecured debt and issuer ratings for Orion Power were BB- and BB+, respectively. These ratings remain on credit watch with negative implications. The Company cannot assure that these ratings will remain in effect for any given period of time or that one or more of these ratings will not be lowered again. As discussed above, the Company expects to provide additional collateral as security to obtain future financings and refinancings which may adversely affect the Company's current credit ratings thereby increasing the cost of future financings or refinancings. The Company notes that these credit ratings are not recommendations to buy, sell or hold its securities and may be revised or withdrawn at any time by such rating agency. Each rating should be evaluated independently of any other rating. Any future incremental reduction or withdrawal of one or more of the Company's credit ratings could have a material adverse impact on its ability to access capital on acceptable terms, including its ability to refinance debt obligations as they mature. The Company's financial and operational flexibility is likely to be reduced as a result of more restrictive covenants, the 16 requirement for security and other terms that are typically imposed on sub-investment grade borrowers as further discussed above. The Company could be adversely impacted by its downgrade to sub-investment grade in connection with certain commercial agreements. These commercial arrangements primarily include: (a) commercial contracts and/or guarantees related to the Company's wholesale and retail trading, marketing, risk management and hedging activities and (b) surety bonds and contractual obligations related to the development and construction or refurbishment of power plants and related facilities. In most cases, the consequences of ratings downgrades are limited to the requirement by the Company's counterparties that the Company provide credit support to the counterparties in the form of a pledge of cash collateral, a letter of credit or other similar credit support. In addition, certain of the Company's retail electricity contracts with large commercial, industrial and institutional customers of the Retail Energy segment permit the customers to terminate their contracts if the Company's unsecured debt ratings fall below investment grade or if its ratings are withdrawn entirely by a rating agency. As of November 8, 2002, no retail contracts have been terminated pursuant to these terms. In light of the credit rating downgrades, the Company is working with its various commercial counterparties to minimize the disruption to its normal commercial activities and to reduce the magnitude of the collateral the Company must post in support of its obligations to such counterparties. In addition, the Company has been involved in certain commercial activities (including term sales of electric energy or capacity from its generating facilities) that prospectively may not be feasible due to the Company's current credit and liquidity situation, among other factors. The credit downgrades have resulted also in more limited access to credit worthy counterparties to transact with and the need to make commercial concessions with counterparties as an inducement to do business with the Company. Given these factors, the Company has reduced the level of its trading, marketing and hedging activities, which could result in greater volatility in future earnings. On October 1, 2002, the Company's Retail Energy segment, through its subsidiary, entered into a master power contract with Texas Genco, LP (Texas Genco), a subsidiary of CenterPoint Energy, covering, among other things, the Company's purchases of capacity and/or energy from Texas Genco's generating units, under an unsecured line of credit. This contract contains covenants that restrict the activities of several of the Retail Energy segment's subsidiaries transacting business in Texas. These restrictions include limitations on the ability of these subsidiaries to (a) sell assets (including customers), consolidate or merge with other companies, including affiliated companies outside the Retail Energy segment; (b) grant liens on their properties; (c) borrow money in excess of agreed upon levels; (d) enter into or guaranty certain trading arrangements; and (e) incur liabilities outside the ordinary course of the Retail Energy segment's business. In addition, there are restrictions involving transactions with affiliates. Under some circumstances, the Company would be required to post collateral in favor of Texas Genco. The primary term of this contract ends on December 31, 2003. Other Liquidity Issues and Concerns. Currently, the Company is satisfying its capital requirements and other commitments primarily with cash from operations, cash on hand and borrowings available under its credit facilities. The following table summarizes the Company's credit capacity and liquidity position at September 30, 2002. RELIANT ORION EUROPEAN TOTAL RESOURCES POWER(2) ENERGY(3) OTHER ----- --------- -------- --------- ----- (IN MILLIONS) Total Committed Credit.......... $8,087 $4,508 $1,859 $1,194 $526 Outstanding Borrowings.......... 7,125 4,277 1,781 627 440 Outstanding Letters of Credit... 597 218 53 288 38 ------ ------ ------ ------ ---- Unused Borrowing Capacity ...... 365 13 25 279 48 Cash and Cash Equivalents....... 1,444 1,169 - 79 196 Restricted Cash (1)............. 447 7 380 60 - ------ ------ ------ ------ ---- Total Available Liquidity....... $2,256 $1,189 $ 405 $ 418 $244 ====== ====== ====== ====== ==== ------------ (1) Restricted cash includes cash at certain subsidiaries that is restricted by financing agreements, but is available to the applicable subsidiary to use to satisfy certain of its obligations. (2) On October 30, 2002, Orion Power and its subsidiaries repaid approximately $144 million in borrowings with cash and restricted cash. (3) The results of the Company's European Energy segment are consolidated on a one-month lag basis. 17 Based on current commodity prices, the Company estimates that as of November 8, 2002, it could be required to post collateral of up to $478 million. This estimate could increase based on commodity prices and a reduction in the current credit rating of REPGB. As of November 8, 2002, the Company had posted cash collateral and letters of credit in the amount of $363 million and $629 million, respectively. Factors which could lead to an increase in the Company's actual posting of collateral include additional downgrades, adverse changes in the Company's industry or in reaction to the possible secured nature of any extension or refinancing of the Company's debt facilities. As of November 8, 2002, the Company had $1.2 billion in unrestricted available cash and cash equivalents and $5 million available under committed corporate credit facilities of the Company to support domestic requirements and $82 million in unrestricted available cash and cash equivalents and $165 million available under committed European facilities to support European operations. These amounts are currently available to meet working capital needs and possible future requirements for credit support related to the Company's credit ratings. Assuming successful extension or replacement of its credit facilities as they mature, the Company believes that its current level of cash and borrowing capability, along with its future anticipated cash flows from operations, will be sufficient to meet the liquidity needs of its business for the next twelve months. Under certain unfavorable commodity price scenarios, however, it is possible that the Company could experience inadequate liquidity. In order to enhance the Company's liquidity position, the Company may sell some of its assets. The Company has identified certain non-strategic generating assets for potential sale to enhance the Company's liquidity position. To date, the Company has not reached an agreement to dispose of assets nor has it contemplated any proceeds from asset sales in its current liquidity plan. Due to unfavorable market conditions in the wholesale power markets, there can be no assurance that the Company will be successful in disposing of generating assets at reasonable prices or on a timely basis. All of the Company's operations are conducted by its subsidiaries. The Company's cash flow and its ability to service certain of its indebtedness when due is dependent upon its receipt of cash dividends, distributions or other cash transfers. The terms of some of the Company's subsidiaries' indebtedness restrict their ability to pay dividends or make other restricted payments to the Company, and future financings at the Company's subsidiaries may contain similar or even more stringent restrictions. Further, Reliant Resources may elect to make the interest payments on Orion Power's 12% senior notes to avoid an event of default under these notes, if, at the time of such payments are due, dividends are restricted under the Orion NY and Orion MidWest credit facilities, and funds generated by Orion Power's other subsidiaries or from other sources are insufficient to make such payments. As further discussed in Note 13(d) to the Reliant Resources Form 10-K/A, during the period from 1994 through 1997, under cross border lease transactions, REPGB leased several of its power plants and related equipment and turbines to non-Netherlands based investors. Pursuant to these transactions, REPGB is required, in specified situations, to post letters of credit. In the case of early termination of these contracts, REPGB would be contingently liable for some payments to the sublessors. Letters of credit have been posted as of September 30, 2002 in the total amount of $307 million. In the event that REPGB credit ratings fall one notch below their current levels, REPGB will be required to post an additional $45 million under the cross border leases. As of November 8, 2002, under its $420 million letter of credit facility, REPGB has unused letter of credit capacity of $113 million available for this purpose. As of September 30, 2002, the Company had forward-starting interest rate swaps having an aggregate notional amount of $500 million to hedge the interest rate on a portion of future offerings of long-term fixed-rate notes. The Company liquidated the swaps in November 2002 for $52 million. For additional information regarding the accounting related to these swaps, see Notes 4 and 16(d). In early 2004, the Company expects to pay to CenterPoint Energy approximately $155 million to $185 million, with a most probable estimate of $170 million, pursuant to the Texas electric restructuring law. For additional information, see Note 12(e). For additional information regarding Reliant Energy Desert Basin generating facility and the potential requirement of additional letters of credit, see Note 12(h). For additional information regarding Liberty Electric Power, LLC and Liberty Electric PA, LLC credit facility and related issues and concerns, see Notes 9 and 12(i). 18 For discussion of a covenant violation under the Receivables Facility, see Note 16(a). The Company estimates its consolidated forecasted capital commitments for the fourth quarter of 2002 and the year ended December 31, 2003 to be approximately $130 million and $533 million, respectively. We expect these capital commitments to be met with cash flows from operations, project financings, securitization of assets and other borrowings. Additional capital expenditures, some of which may be substantial, depend to a large extent upon the nature and extent of future project commitments which are discretionary. In addition to the above, the Company currently estimates the capital expenditures by off-balance sheet special purpose entities to be $207 million and $304 million in the fourth quarter of 2002 and the year ended December 31, 2003, respectively. For additional information regarding these off-balance sheet transactions, see Note 12(f). Also, in connection with the Company's separation from CenterPoint Energy, CenterPoint Energy granted the Company an option to purchase all of the shares of capital stock owned by CenterPoint Energy in January 2004 of Texas Genco that owns the Texas generating assets of Reliant Energy's former electric utility division. This option may be exercised between January 10, 2004 and January 24, 2004. If the Company exercises its purchase option, the Company expects to fund the purchase obligation with proceeds from asset sales, cash flows from operations, proceeds from debt and equity offerings, and/or other borrowings. The Company's liquidity position and restrictive covenants of future financings, may limit its ability to exercise the option. If the Company does not exercise the option, the Company will need to contract with Texas Genco or others to meet its retail supply obligations. For additional information regarding this option to purchase CenterPoint Energy's interest in Texas Genco, please read Note 4(b) to the Reliant Resources Form 10-K/A. (3) NEW ACCOUNTING PRONOUNCEMENTS In July 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 141 "Business Combinations" (SFAS No. 141). SFAS No. 141 requires business combinations initiated after June 30, 2001 to be accounted for using the purchase method of accounting and broadens the criteria for recording intangible assets separate from goodwill. Recorded goodwill and intangibles will be evaluated against these new criteria and may result in certain intangibles being transferred to goodwill, or alternatively, amounts initially recorded as goodwill may be separately identified and recognized apart from goodwill. The Company adopted the provisions of the statement which apply to goodwill and intangible assets acquired prior to June 30, 2001 on January 1, 2002. The adoption of SFAS No. 141 did not have a material impact on the Company's historical results of operations or financial position. In August 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS No. 143). SFAS No. 143 requires the fair value of a liability for an asset retirement legal obligation to be recognized in the period in which it is incurred. When the liability is initially recorded, associated costs are capitalized by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. SFAS No. 143 requires entities to record a cumulative effect of change in accounting principle in the income statement in the period of adoption. The Company plans to adopt SFAS No. 143 on January 1, 2003, and is in the process of determining the effect of adoption on its consolidated financial statements. In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144). SFAS No. 144 provides new guidance on the recognition of impairment losses on long-lived assets to be held and used or to be disposed of and also broadens the definition of what constitutes a discontinued operation and how the results of a discontinued operation are to be measured and presented. SFAS No. 144 supercedes SFAS No. 121 "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" and Accounting Principles Board Opinion No. 30, "Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions," while retaining many of the requirements of these two statements. Under SFAS No. 144, assets held for sale that are a component of an entity will be included in discontinued operations if the operations and cash flows will be or have been eliminated from the ongoing operations of the entity and the entity will not have any significant continuing involvement in the operations prospectively. SFAS No. 144 did not materially change the methods used by the Company to measure impairment losses on long-lived assets, but may result in additional future dispositions being reported as discontinued operations. The Company adopted SFAS No. 144 on January 1, 2002. 19 In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections" (SFAS No. 145). SFAS No. 145 eliminates the current requirement that gains and losses on debt extinguishment must be classified as extraordinary items in the income statement. Instead, such gains and losses will be classified as extraordinary items only if they are deemed to be unusual and infrequent. SFAS No. 145 also requires sale-leaseback accounting for certain lease modifications that have economic effects that are similar to sale-leaseback transactions. The changes related to debt extinguishment will be effective for fiscal years beginning after May 15, 2002, and the changes related to lease accounting will be effective for transactions occurring after May 15, 2002. The Company will apply this guidance prospectively. In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities" (SFAS No. 146). SFAS No. 146 nullifies EITF No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)" (EITF No. 94-3). The principal difference between SFAS No. 146 and EITF No. 94-3 relates to the requirements for recognition of a liability for cost associated with an exit or disposal activity. SFAS No. 146 requires that a liability be recognized for a cost associated with an exit or disposal activity when it is incurred. A liability is incurred when a transaction or event occurs that leaves an entity little or no discretion to avoid the future transfer or use of assets to settle the liability. Under EITF No. 94-3, a liability for an exit cost was recognized at the date of an entity's commitment to an exit plan. In addition, SFAS No. 146 also requires that a liability for a cost associated with an exit or disposal activity be recognized at its fair value when it is incurred. SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002 with early application encouraged. The Company will apply the provisions of SFAS No. 146 to all exit or disposal activities initiated after December 31, 2002. See Note 4 for a discussion regarding the Company's adoption of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended (SFAS No. 133) on January 1, 2001 and adoption of subsequent cleared guidance. See Note 7 for a discussion regarding the Company's adoption of SFAS No. 142 on January 1, 2002. In June 2002, the EITF reached a consensus that all mark-to-market gains and losses on energy trading contracts should be shown net in the income statement whether or not settled physically. In October 2002, the EITF issued a consensus that superceded the June 2002 consensus. The October 2002 consensus required, among other things, that energy derivatives held for trading purposes be shown net in the income statement. This new consensus is effective for fiscal periods beginning after December 15, 2002. However, consistent with the new consensus and as allowed under EITF No. 98-10, beginning with the quarter ended September 30, 2002, the Company now reports all energy trading and marketing activities on a net basis in the Statements of Consolidated Income. Comparative financial statements for prior periods have been reclassified to conform to this presentation. The adoption of net reporting resulted in a reduction of revenues, fuel and cost of gas sold, purchase power expense during the three and nine months ended September 30, 2001, and six months ended June 30, 2002 as follows (in millions): FOR THE THREE FOR THE NINE FOR THE SIX MONTHS ENDED MONTHS ENDED MONTHS ENDED SEPTEMBER 30, 2001 SEPTEMBER 30, 2001 JUNE 30, 2002 ------------------ ------------------ ------------- Revenues........................ $6,278 $19,687 $11,434 Fuel and cost of gas sold....... 2,471 11,011 6,142 Purchased power................. 3,807 8,676 5,292 ------ ------- ------- Net impact on margins...... $ -- $ -- $ -- ====== ======= ======= Furthermore, in October 2002, under EITF No. 02-03, the EITF reached a consensus to rescind EITF No. 98-10. All new contracts that would have been accounted for under EITF No. 98-10, and that do not fall within the scope of SFAS No. 133, should no longer be marked-to-market through earnings beginning October 25, 2002. In addition, inventories used in the trading and marketing operations should no longer be marked-to-market through earnings. This transition is effective for the Company for the first quarter of 2003. A cumulative effect of a change in accounting principle should be recorded effective January 1, 2003 related to all contracts and inventories that will no longer be recorded at fair value that were entered into or held, as applicable, prior to October 25, 2002. The Company is in process of determining the effect of adoption on its consolidated financial statements. 20 Finally, the EITF has not reached a consensus on whether recognition of dealer profit, or unrealized gains and losses at inception of an energy trading contract is appropriate in the absence of quoted market prices or current market transactions for contracts with similar terms. In the June 2002 EITF meeting and again in the October 2002 EITF meeting, the FASB staff indicated that until such time as a consensus is reached, the FASB staff will continue to hold the view that previous EITF consensus do not allow for recognition of dealer profit, unless evidenced by quoted market prices or other current market transactions for energy trading contracts with similar terms and counterparties. During the three and nine months ended September 30, 2002, the Company recorded $8 million and $54 million, respectively, of fair value at the contract inception related to trading and marketing activities. The Company believes that any material inception gains recorded subsequent to the FASB staff comment regarding this issue were evidenced by quoted market prices and other current market transactions for energy trading contracts with similar terms and counterparties. (4) DERIVATIVE FINANCIAL INSTRUMENTS Adoption of SFAS No. 133 on January 1, 2001 resulted in an after-tax increase in net income of $3 million and a cumulative after-tax increase in accumulated other comprehensive loss of $460 million. The adoption also increased current assets, long-term assets, current liabilities and long-term liabilities by $566 million, $127 million, $811 million and $339 million, respectively, in the Company's Consolidated Balance Sheet. For additional information regarding the adoption of SFAS No. 133 and the Company's accounting policies for derivative financial instruments, see Note 6 to the Reliant Resources 10-K/A Notes. The application of SFAS No. 133 is still evolving as the FASB clears issues submitted to the Derivatives Implementation Group for consideration. During the second quarter of 2001, an issue that applies exclusively to the electric industry and allows the normal purchases and normal sales exception for option-type contracts if certain criteria are met was approved by the FASB with an effective date of July 1, 2001. The adoption of this cleared guidance had no impact on the Company's results of operations. Certain criteria of this previously approved guidance were revised in October and December 2001 and became effective on April 1, 2002. The effect of adoption of the revised guidance did not impact the Company's consolidated financial statements. During the third quarter of 2001, the FASB cleared an issue related to application of the normal purchases and normal sales exception to contracts that combine forward and purchased option contracts. The effective date of this guidance was April 1, 2002, and the effect of adoption of this guidance did not materially impact the Company's consolidated financial statements. Cash Flow Hedges. During the three and nine months ended September 30, 2001 and 2002, the amount of hedge ineffectiveness recognized in earnings from derivatives that are designated and qualify as cash flow hedges, including interest rate swaps, was a $73 million and a $57 million gain, respectively, for 2001 and was a $26 million and a $22 million loss, respectively, for 2002. No component of the derivative instruments' gain or loss was excluded from this assessment of effectiveness. During the nine months ended September 30, 2002, there was a loss of approximately $0.2 million recognized in earnings as a result of the discontinuance of cash flow hedges because it was no longer probable that the forecasted transaction would occur. As of September 30, 2002, the Company expects $16 million in accumulated other comprehensive income to be reclassified into net income during the next twelve months. Interest Rate Swaps. As of September 30, 2002, the Company holds interest rate swaps with an aggregate notional amount of $1.2 billion to fix the interest rate applicable to floating rate short-term debt and floating rate long-term debt. The Company pays floating interest at LIBOR for a fixed interest rate of 6.92%. The swaps relating to both short-term and long-term debt qualify for hedge accounting under SFAS No. 133 and the periodic settlements are recognized as an adjustment to interest expense in the Statements of Consolidated Income over the term of the swap agreements. During January 2002, the Company entered into forward-starting interest rate swaps having an aggregate notional amount of $1.0 billion, of which $500 million has been liquidated as discussed below, to hedge the interest rate on a portion of future offerings of long-term fixed-rate notes. With respect to the $500 million of forward-starting interest rate swaps that are outstanding, the Company pays fixed interest at a rate of 5.2% for floating interest at LIBOR. These swaps qualify as cash flow hedges under SFAS No. 133. On May 9, 2002, the Company liquidated $500 million of the forward starting interest rate swaps that were entered into in January 2002. The liquidation of these swaps resulted in a loss of $3 million, which was recorded in other comprehensive income and will be amortized into interest expense in the same period during which the forecasted interest payment affects earnings. Should the forecasted interest payments no longer be probable, any remaining deferred amount will be recognized immediately as an expense. The maximum length of time the Company is hedging its exposure to the 21 payment of variable interest rates is 7 years. In November 2002, the Company liquidated $500 million of the forward-starting interest rate swaps at a cost of $52 million. For further discussion of the liquidation of these swaps, see Note 16 (d). Hedge of Net Investment in Foreign Subsidiaries. The Company has hedged its entire net investment in its European subsidiaries against a material decline of the Euro through a combination of Euro-denominated borrowings and foreign currency option contracts. During the nine months ended September 30, 2002, the derivative and non-derivative instruments designated as hedging the net investment in the Company's European subsidiaries resulted in a loss of $163 million, which is included in the balance of the cumulative translation adjustment in accumulated other comprehensive income. Other Derivatives. In December 2000, the Dutch parliament adopted legislation allocating to the Dutch generation sector, including REPGB, financial responsibility for various out-of-market contracts and other liabilities. The legislation became effective in all material respects on January 1, 2001. In particular, the legislation allocated to the Dutch generation sector, including REPGB, financial responsibility to purchase imported electricity and gas under certain long-term power contracts and a gas contract entered into by NEA B.V. (NEA), the regulated entity which formerly purchased and sold energy in the Netherlands. The Company accounts for the gas supply contract at fair value as a non-trading derivative pursuant to SFAS No. 133. Prior to amending the electricity import contracts in May 2002, the Company also accounted for the electricity import contracts at fair value as non-trading derivatives pursuant to SFAS No. 133. However, subsequent to amending the electricity import contracts, the Company began to account for the electricity contracts as a part of the Company's energy trading activities. As of December 31, 2001, the Company has a recorded liability of $369 million for the REPGB stranded cost gas and electric commitments in non-trading derivative liabilities. As of September 30, 2002, the Company has a recorded liability of $141 million for the REPGB stranded cost gas supply contract in non-trading derivative liabilities. Pursuant to SFAS No. 133, during nine months ended September 30, 2002, the Company recognized a net $16 million gain, net of derivative transactions entered into to economically hedge the stranded cost gas contracts, recorded in fuel expense related to changes in the valuation of these non-trading derivative liabilities, excluding the effects of the gain related to amending the two power contracts as discussed in Note 12(d). For additional information regarding REPGB's obligations under these out-of-market contracts and the related indemnification by former shareholders of these stranded costs during 2001, see Note 13(f) to the Reliant Resources 10-K/A Notes and Note 12(d). During the May 2001 through September 2001 time frame, the Company entered into two structured transactions which were recorded on the balance sheet in non-trading derivative assets and liabilities involving a series of forward contracts to buy and sell an energy commodity in 2001 and to buy and sell an energy commodity in 2002 or 2003. The change in fair value of these derivative assets and liabilities must be recorded in the statement of income for each reporting period. As of December 31, 2001, the Company has recognized $221 million of non-trading derivative assets and $103 million of non-trading derivative liabilities related to these transactions. During the three and nine months ended September 30, 2002, $46 million and $96 million, respectively, of net non-trading derivative assets were settled related to these transactions, and a $1 million and $3 million pre-tax unrealized gain, respectively, was recognized. As of September 30, 2002, the Company has recognized $33 million of non-trading derivative assets and $8 million of non-trading derivative liabilities related to these transactions. (5) HISTORICAL RELATED PARTY TRANSACTIONS The Interim Financial Statements include significant transactions between the Company and CenterPoint Energy and its subsidiaries involving services, including various corporate support services (including accounting, finance, investor relations, planning, legal, communications, governmental and regulatory affairs and human resources), information technology services and other shared services such as corporate security, facilities management, accounts receivable, accounts payable and payroll, office support services and purchasing and logistics. The costs of these services have been directly charged or allocated to the Company using methods that management believes are reasonable. These methods include negotiated usage rates, dedicated asset assignment, and proportionate corporate formulas based on assets, operating expenses and employees. These charges and allocations are not necessarily indicative of what would have been incurred had the Company been an unaffiliated entity. Amounts charged and allocated to the Company for these services were $1 million and $5 million for the three 22 months ended September 30, 2001 and 2002, respectively. Amounts charged and allocated to the Company for these services were $6 million and $15 million for the nine months ended September 30, 2001 and 2002, respectively, and are included primarily in operation and maintenance expenses and general and administrative expenses. In addition, during the three and nine months ended September 30, 2001, the Company incurred costs primarily related to corporate support services which were billed to CenterPoint Energy and its affiliates of $8 million and $29 million, respectively. Some subsidiaries of the Company have entered into office rental agreements with CenterPoint Energy. During the three months ended September 30, 2001 and 2002, the Company incurred $5 million and $8 million, respectively, of rent expense to CenterPoint Energy. The Company incurred $13 million and $24 million of rent expense to CenterPoint Energy during the nine months ended September 30, 2001 and 2002, respectively. The Company purchases natural gas, electric generation energy and capacity, electric transmission services and natural gas transportation services from, supplies natural gas to, and provides marketing and risk management services to affiliates of CenterPoint Energy. Purchases of electric generation energy and capacity, electric transmission services, natural gas transportation services and natural gas from CenterPoint Energy and its subsidiaries were $634 million for the three months ended September 30, 2002 and $1.5 billion for the nine months ended September 30, 2002. During the three months ended September 30, 2001 and 2002, the sales and services to CenterPoint Energy and its subsidiaries totaled $87 million and $18 million, respectively, and $416 million and $176 million for the nine months ended September 30, 2001 and 2002, respectively. During the fourth quarter of 2001 and the first and third quarters of 2002, the Company purchased entitlements to some of the generation capacity of electric generation assets of Texas Genco. The Company purchased these entitlements under the terms of a master separation agreement between Reliant Resources and Reliant Energy (Master Separation Agreement) and in capacity auctions conducted by Texas Genco. Under the Texas electric restructuring law, Texas Genco is required to sell at auction entitlements to at least 15% of its installed generating capacity (State Mandated Auctions). Under the law, the Company is not permitted to participate in the State Mandated Auctions. However, the Company is entitled to purchase capacity and energy in the auction entitlements required by the Texas electric restructuring law of the power generation companies affiliated with the other Texas electric utilities. Under the Master Separation Agreement, Texas Genco is obligated to auction entitlements to all of its capacity and related ancillary services available after the State Mandated Auctions subject to certain permitted reductions, for a specified period of time, subject to certain agreements (Contractually Mandated Auctions). Under the Master Separation Agreement, the Company is entitled to elect to purchase 50% of the capacity to be auctioned by Texas Genco in the Contractually Mandated Auctions at the prices established in such auctions. In addition to this right, the Company may participate in the Contractually Mandated Auctions. As of September 30, 2002, the Company has purchased entitlements to capacity of Texas Genco averaging 5,967 MW per month for the remainder of 2002 and 775 MW per month in 2003. The Company has no minimum obligations for energy or ancillary services under the Master Separation Agreement. The Company's anticipated capacity payments related to these capacity entitlements are $46 million in 2002 and $58 million in 2003. During the fourth quarter of 2002, through November 8, 2002, the Company purchased additional entitlements to some of the generation capacity of electric generation assets of Texas Genco averaging 4,173 MW per month in 2003. The Company's anticipated capacity payments related to these additional capacity entitlements are $246 million in 2003. For additional information regarding agreements relating to Texas Genco, see Note 4(b) to the Reliant Resources 10-K/A Notes. During the nine months ended September 30, 2001, CenterPoint Energy or its subsidiaries made equity contributions to the Company of $1.8 billion. The contributions in the nine months ended September 30, 2001, primarily related to the conversion into equity of debt and related interest expense as discussed above and the contribution of net benefit assets and liabilities, net of deferred income taxes. During the nine months ended September 30, 2002, CenterPoint Energy made contributions to the Company of $21 million, which primarily related to benefit obligations pursuant to the Master Separation Agreement. (6) ACQUISITIONS Orion Power Holdings, Inc. In February 2002, the Company acquired all of the outstanding shares of common stock of Orion Power for $26.80 per share in cash for an aggregate purchase price of $2.9 billion. The Company funded the Orion Power acquisition with a $2.9 billion credit facility (see Note 9) and $41 million of cash on hand. As a result of the acquisition, the Company's consolidated net debt obligations also increased by the amount of Orion Power's net debt obligations. As of February 19, 2002, Orion Power's debt obligations were $2.4 billion ($2.1 billion net of restricted cash pursuant to debt covenants). Orion Power is an electric power generating company formed in March 1998 to acquire, develop, own and operate power-generating facilities in certain 23 deregulated wholesale markets throughout North America. As of February 19, 2002, Orion Power had 81 power plants with a total generating capacity of 5,644 MW and two development projects with an additional 804 MW of capacity under construction. As of September 30, 2002, both projects under construction had reached commercial operation. The Company accounted for the acquisition as a purchase with assets and liabilities of Orion Power reflected at their estimated fair values. The Company's fair value adjustments primarily included adjustments in property, plant and equipment, contracts, severance liabilities, debt, unrecognized pension and postretirement benefits liabilities and related deferred taxes. The Company expects to finalize these fair value adjustments no later than February 2003, based on valuations of property, plant and equipment, intangible assets and other assets and obligations. The Company's results of operations include the results of Orion Power only for the period beginning February 19, 2002. The following table presents selected financial information and unaudited pro forma information for the three months ended September 30, 2001 and nine months ended September 30, 2001 and 2002, as if the acquisition had occurred on January 1, 2001 and 2002, as applicable. THREE MONTHS ENDED SEPTEMBER 30, 2001 ------------------ ACTUAL PRO FORMA ------ --------- (IN MILLIONS) Revenues...................................... $2,535 $2,917 Net income.................................... 262 314 Basic and diluted earnings per share.......... $ 0.87 $ 1.05 NINE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, 2001 SEPTEMBER 30, 2002 ------------------ ------------------ ACTUAL PRO FORMA ACTUAL PRO FORMA ------ --------- ------ --------- (IN MILLIONS) Revenues ........................................................ $5,704 $6,667 $9,495 $9,618 Income before cumulative effect of accounting changes ........... 546 611 323 264 Net income ...................................................... 549 614 89 30 Basic earnings per share before cumulative effect of accounting changes ...................................................... $ 2.00 $ 2.24 $ 1.11 $ 0.91 Basic earnings per share ........................................ 2.01 2.25 0.31 0.11 Diluted earnings per share before cumulative effect of accounting changes ...................................................... $ 2.00 $ 2.24 $ 1.10 $ 0.90 Diluted earnings per share ...................................... 2.01 2.25 0.30 0.10 These unaudited pro forma results, based on assumptions deemed appropriate by the Company's management, have been prepared for informational purposes only and are not necessarily indicative of the amounts that would have resulted if the acquisition of Orion Power had occurred on January 1, 2001 and 2002, as applicable. Purchase-related adjustments to the results of operations include the effects on depreciation and amortization, interest expense, interest income and income taxes. The unaudited pro forma condensed consolidated financial statements reflect the acquisition of Orion Power in accordance with SFAS No. 141 and SFAS No. 142. For additional information regarding the Company's adoption of SFAS No. 141 and SFAS No. 142, see Notes 3 and 7. Each of Orion Power New York, LP, Orion Power New York GP, Inc., Astoria Generating Company, L.P., Carr Street Generating Station, LP, Erie Boulevard Hydropower, LP, Orion Power MidWest, LP, Orion Power Midwest GP, Inc., Twelvepole Creek, LLC and Orion Power Capital, LLC is a separate legal entity and has its own assets. 24 (7) GOODWILL AND INTANGIBLES In July 2001, the FASB issued SFAS No. 142, which provides that goodwill and certain intangibles with indefinite lives will not be amortized into results of operations, but instead will be reviewed periodically for impairment and written down and charged to results of operations only in the periods in which the recorded value of goodwill and certain intangibles with indefinite lives is more than its fair value. The Company adopted the provisions of the statement which apply to goodwill and intangible assets acquired prior to June 30, 2001 on January 1, 2002. On January 1, 2002, the Company discontinued amortizing goodwill into its results of operations pursuant to SFAS No. 142. A reconciliation of previously reported net income and earnings per share to the amounts adjusted for the exclusion of goodwill amortization: THREE MONTHS ENDED SEPTEMBER 30, -------------------------------- 2001 2002 ---- ---- (IN MILLIONS, EXCEPT PER SHARE AMOUNTS) Reported net income .................. $ 262 $ 51 Add: Goodwill amortization, net of tax 27 -- ----- ----- Adjusted net income .................. $ 289 $ 51 ===== ===== Basic and Diluted Earnings Per Share: Reported net income .................. $0.87 $0.17 Add: Goodwill amortization, net of tax 0.09 -- ----- ----- Adjusted basic and diluted earnings .. $0.96 $0.17 ===== ===== NINE MONTHS ENDED SEPTEMBER 30, ------------------------------- 2001 2002 ---- ---- (IN MILLIONS, EXCEPT PER SHARE AMOUNTS) Reported net income........................ $ 549 $ 89 Add: Goodwill amortization, net of tax..... 44 -- ----- ----- Adjusted net income........................ $ 593 $ 89 ===== ===== Basic Earnings Per Share: Reported net income........................ $2.01 $0.31 Add: Goodwill amortization, net of tax..... 0.16 -- ----- ----- Adjusted basic earnings.................... $2.17 $0.31 ===== ===== Diluted Earnings Per Share: Reported net income........................ $2.01 $0.30 Add: Goodwill amortization, net of tax..... 0.16 -- ----- ----- Adjusted diluted earnings.................. $2.17 $0.30 ===== ===== The components of the Company's other intangible assets consist of the following: DECEMBER 31, 2001 SEPTEMBER 30, 2002 ----------------- ------------------ CARRYING ACCUMULATED CARRYING ACCUMULATED AMOUNT AMORTIZATION AMOUNT AMORTIZATION ------ ------------ ------ ------------ (IN MILLIONS) Air Emission Regulatory Allowances..... $255 $(78) $271 $ (88) Water Rights........................... 68 (4) 68 (6) Other Power Generation Site Permits.... 77 (3) 77 (5) Contractual rights..................... -- -- 92 (9) Other.................................. -- -- 3 -- ---- ---- ---- ----- Total.................................. $400 $(85) $511 $(108) ==== ==== ==== ===== The Company recognizes specifically identifiable intangibles, including air emissions regulatory allowances, water rights and permits, when specific rights and contracts are acquired. The Company has no intangible assets with indefinite lives recorded as of September 30, 2002. The Company amortizes air emissions regulatory allowances primarily on a units-of-production basis as utilized. The Company amortizes other acquired intangibles, 25 excluding contractual rights, on a straight-line basis over the lesser of their contractual or estimated useful lives with a weighted average amortization period of 35 years. In connection with the acquisition of Orion Power, the Company recorded the fair value of certain fuel and power contracts acquired. The Company estimated the fair value of the contracts using forward pricing curves over the life of each contract. Those contracts with positive fair value at the date of acquisition (Contractual Rights) were recorded to intangible assets and those contracts with negative fair value at the date of acquisition (Contractual Obligations) were recorded to other current and long-term liabilities in the Consolidated Balance Sheet. Contractual Rights and Contractual Obligations are amortized to fuel expense and revenues, as applicable, based on the estimated realization of the fair value established on the acquisition date over the contractual lives. Additionally, the time value portion of the contract's value is amortized to interest expense over the contractual lives. There may be times during the life of the contract when accumulated amortization exceeds the carrying value of the recorded assets or liabilities due to the timing of realizing the fair value established on the acquisition date. Amortization expense for other intangibles, excluding Contractual Rights, for the three months ended September 30, 2001 and 2002 was $9 million and $7 million, respectively. Amortization expense for other intangibles, excluding Contractual Rights, for the nine months ended September 30, 2001 and 2002 was $39 million and $15 million, respectively. Estimated amortization expense for the remainder of 2002 and the five succeeding fiscal years is as follows (in millions): 2002........................... $ 7 2003........................... 23 2004........................... 13 2005........................... 13 2006........................... 12 2007........................... 12 ---- Total....................... $ 80 ==== The Company amortized $2 million and $9 million of Contractual Rights during the three and nine months ended September 30, 2002, respectively. The Company amortized $49 million and $59 million of Contractual Obligations during the three and nine months ended September 30, 2002, respectively. Estimated amortization of Contractual Rights and Contractual Obligations for the remainder of 2002 and the five succeeding fiscal years is as follows (in millions): CONTRACTUAL CONTRACTUAL NET (INCREASE) RIGHTS OBLIGATIONS DECREASE IN INCOME ------ ----------- ------------------ 2002.................. $ 8 $ -- $ 8 2003.................. 25 (52) (27) 2004.................. 30 (44) (14) 2005.................. 18 (7) 11 2006.................. 14 (1) 13 2007.................. 21 -- 21 ----- ------ ----- Total.............. $ 116 $ (104) $ 12 ===== ====== ===== Changes in the carrying amount of goodwill for the nine months ended September 30, 2002, by reportable segment, are as follows: GOODWILL AS OF ACQUIRED FOREIGN AS OF JANUARY 1, DURING CURRENCY SEPTEMBER 30, 2002 THE PERIOD IMPAIRMENT EXCHANGE IMPACT OTHER 2002 ---- ---------- ---------- --------------- ----- ---- (IN MILLIONS) Wholesale Energy..... $ 184 $ 1,448 $ -- $ -- $ 1 $ 1,633 European Energy...... 675 -- (234) 51 -- 492 Retail Energy........ 32 -- -- -- -- 32 ----- -------- ------ ----- ---- ------- Total............. $ 891 $ 1,448 $ (234) $ 51 $ 1 $ 2,157 ===== ======== ====== ===== ==== ======= 26 During the third quarter of 2002, the Company completed the transitional impairment test for the adoption of SFAS No. 142 on its Consolidated Financial Statements, including the review of goodwill for impairment as of January 1, 2002. This impairment test was performed in two steps. The initial step was designed to identify potential goodwill impairment by comparing an estimate of the fair value of the applicable reporting unit to its carrying value, including goodwill. If the carrying value exceeded fair value, a second step was performed, which compared the implied fair value of the applicable reporting unit's goodwill with the carrying amount of that goodwill, to measure the amount of the goodwill impairment, if any. Based on this impairment test, the Company recorded an impairment of its European Energy segment's goodwill of $234 million. This impairment loss was recorded retroactively as a cumulative effect of a change in accounting principle for the quarter ended March 31, 2002. Based on the first step of the goodwill impairment test, no other reporting units' goodwill was impaired. The circumstances leading to the goodwill impairment of the Company's European Energy segment included a significant decline in electric margins attributable to the deregulation of the European electricity market in 2001, lack of growth in the wholesale energy trading markets in Northwest Europe and continued regulation of the European fuel markets. The Company's measurement of the fair value of European Energy was based on both an income approach, using future discounted cash flows, and a market approach, using acquisition multiples, including price per Megawatt, based on publicly available data for recently completed European transactions. An impairment analysis requires estimates of future market prices, valuation of plant and equipment, growth, competition and many other factors as of the determination date. The resulting impairment loss is highly dependent on these underlying assumptions. Such assumptions are generally consistent with those utilized in the Company's annual planning process and industry valuation and appraisal reports. If the assumptions and estimates underlying this goodwill impairment evaluation differ greatly from the actual results or to the extent that such assumptions change through time, there could be additional goodwill impairments in the future. SFAS No. 142 also requires goodwill to be tested annually and between annual tests if events occur or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. The Company has elected to perform its annual test for indications of goodwill impairment as of November 1, in conjunction with the Company's annual planning process. Subsequent impairments, if any, will be classified as an operating expense. The Company anticipates finalizing its annual impairment test during the fourth quarter of 2002 and currently cannot estimate the outcome. As of March 31, 2002, the Company completed its assessment of intangible assets and no indefinite lived intangible assets were identified. No related impairment losses were recorded in the first quarter of 2002 and no changes were made to the expected useful lives of its intangible assets as a result of this assessment. (8) COMPREHENSIVE INCOME The following table summarized the component of total comprehensive income: FOR THE THREE MONTHS ENDED FOR THE NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------- ------------- 2001 2002 2001 2002 (IN MILLIONS) Net income ....................................................... $ 262 $ 51 $ 549 $ 89 Other comprehensive income (loss): Foreign currency translation adjustments....................... (79) (15) (74) 61 Changes in minimum benefit liability........................... -- -- (6) -- Cumulative effect of adoption of SFAS No. 133.................. -- -- (460) -- Deferred gain (loss) from cash flow hedges..................... 14 (113) 451 73 Reclassification of deferred loss (gain) from cash flow hedges realized in net income....................................... (140) 15 (6) (8) Unrealized (loss) gain on available-for-sale securities........ (3) (3) 11 (2) Reclassification adjustments for loss (gain) on sales of available-for-sale securities realized in net income.............. -- (1) (1) (3) ----- ------ ----- ---- Comprehensive income ............................................. $ 54 $ (66) $ 464 $210 ===== ====== ===== ==== 27 (9) BORROWINGS FROM THIRD PARTIES Credit Facilities. As of September 30, 2002, the Company had $8.1 billion in committed credit facilities of which $365 million remained unused. Credit facilities aggregating $5.3 billion were unsecured. As of September 30, 2002, letters of credit outstanding under these facilities aggregated $597 million and borrowings of $7.1 billion of which $1.9 billion were classified as long-term debt, based upon the restructuring of Orion Power subsidiaries' credit facilities as described in Note 16(b) and the availability of committed credit facilities and management's intention to maintain these borrowings in excess of one year. In addition to credit facilities, the Company had long-term debt totaling $457 million of which $411 million related to bonds issued by Orion Power. As of September 30, 2002, the Company had $6.6 billion of committed credit facilities which will expire by September 30, 2003, $1.7 billion of which will expire by December 31, 2002. For a discussion of the repayment, refinancing and/or amendment of certain of these committed credit facilities and our liquidity concerns, please read Note 2. The Company entered into a term loan facility during the fourth quarter of 2001 and amended in January 2002 that provided for $2.9 billion in funding to finance the purchase of Orion Power. Interest rates on the borrowings under this facility are based on LIBOR plus 1.75% or a base rate. This facility was funded on February 19, 2002 for $2.9 billion. As of September 30, 2002, the weighted average interest rate on outstanding borrowings was 3.0%. This term loan must be repaid within one year from the date on which it was funded. For discussion of the acquisition of Orion Power, see Note 6. The Company termed out its $800 million unsecured 364-day revolving credit facility before it matured on August 22, 2002. The facility agreement allowed the Company the option to borrow the entire amount and convert it, provided that there was no default on the conversion date, to a one-year term loan with a maturity of August 22, 2003. Interest rates on the borrowings are based on the London inter-bank offered rate (LIBOR) plus a margin, based on the Company's credit rating, a base rate or a rate determined through a bidding process. The LIBOR margin as of September 30, 2002 was 1.375%. Sale of Receivables. In July 2002, the Company entered into an arrangement (Receivables Facility) with a financial institution to sell an undivided interest in accounts receivable from residential and small commercial retail electric customers under which, on an ongoing basis, the financial institution will invest a maximum of $250 million for its interest in such receivables. The Receivables Facility expires July 2003 and may be renewed at the Company's option and the option of the financial institution participating in the Receivables Facility. If the Receivables Facility is not renewed on its termination date, the collections from the receivables purchased will repay the financial institution's investment and no new receivables will be purchased under the Receivables Facility. There can be no assurance that the financial institution participating in the Receivables Facility will agree to a renewal. The Receivables Facility may be increased to an amount greater than $250 million on a seasonal basis, subject to the availability of receivables and approval by the participating financial institution. The Company received net proceeds in an initial amount of $230 million at the inception of the Receivables Facility. That amount was increased to $250 million on August 23, 2002. The amount of funding available to the Company under the Receivables Facility will fluctuate based on the amount of receivables available which, in turn, is effected by seasonal changes in demand for electricity. As of November 8, 2002, the amount of funding outstanding under the Company's Receivables facility was $235 million as the Company's receivables had decreased with the lower demand for electricity due to cooler autumn weather. Pursuant to the Receivables Facility, the Company formed a qualified special purpose entity (QSPE), as a bankruptcy remote subsidiary. The QSPE was formed for the sole purpose of buying and selling receivables generated by the Company. The QSPE is a separate entity and its assets will be available first and foremost to satisfy the claims of its creditors. The Company, irrevocably and without recourse, transfers receivables to the QSPE. The QSPE, in turn, sells an undivided interest in these receivables to the participating financial institution. The Company is not ultimately liable for any failure of payment of the obligors on the receivables. The Company has, however, guaranteed the performance obligations of the sellers and the servicer of the receivables under the related documents. The two-step transaction described in the above paragraph is accounted for as a sale of receivables under the provisions of SFAS No. 140 "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities" (SFAS No. 140), and as a result the related receivables are excluded from the Consolidated Balance 28 Sheet. Costs associated with the sale of receivables, $4 million for both the three and nine months ended September 30, 2002, primarily the discount and loss on sale, is included in other expense in the Company's Statement of Consolidated Income. During the three and nine months ended September 30, 2002, an accumulated $521 million of receivables had been sold and the sale has been reflected as a reduction of accounts receivable in the Company's Consolidated Balance Sheet. The Company has a note receivable from the QSPE for approximately $254 million at September 30, 2002, which is included on the Consolidated Balance Sheet. This note is the difference between the amount of receivables sold to the QSPE and the receivables sold by the QSPE to the financial institution. Refinancing of Certain REPGB Debt. During July 2002, REPGB renewed its 364-day revolving credit facility for another year. The term of this facility is now scheduled to expire in July 2003. The amount of the credit facility was reduced from Euro 250 million (approximately $247 million) to Euro 184 million (approximately $182 million). An option was added that permits REPGB to utilize up to Euro 100 million (approximately $99 million) of the facility for letters of credit. As of September 30, 2002, there were $35 million and $17 million of borrowings and letters of credit outstanding, respectively, under this facility. The revolving credit facility bears interest at the rate of inter-bank offered rate for Euros (EURIBOR) plus a margin depending on REPGB's credit rating. The EURIBOR margin as of September 30, 2002 was 1.40%. The weighted average interest rate on outstanding borrowings as of September 30, 2002, was 4.73%. The credit facility contains certain covenants and negative pledges that must be met by REPGB to borrow funds or obtain letters of credit, that require REPGB to, among other things, maintain a ratio of net balance sheet debt to the sum of net balance sheet debt and total equity of 0.60 to 1.00. These covenants are not anticipated to materially restrict REPGB from borrowing funds or obtaining letters of credit, as applicable, under this facility. Orion Power's Debt Obligations. As a result of the Company's acquisition of Orion Power, the Company's consolidated net debt obligations also increased by the amount of Orion Power's net debt obligations, which are discussed below. Revolving Senior Credit Facility. As of September 30, 2002, Orion Power had an unsecured revolving senior credit facility. As part of the ongoing refinancing negotiations the amount of this facility was reduced on September 6, 2002, from $75 million to $62 million in conjunction with a reduction of the total letters of credit outstanding. Amounts outstanding under the facility bore interest at a floating rate. As of September 30, 2002, there were $51 million of borrowings outstanding under this facility, and a total of $11 million in letters of credit were also outstanding. This credit facility contained various covenants that included, among others, restrictions on the payment of dividends by Orion Power. As of September 30, 2002, restricted cash under this revolving senior credit facility totaled $10 million. The senior credit facility of Orion Power contained various business and financial covenants that required Orion Power to, among other things, maintain a debt service coverage ratio of at least 1.4 to 1.0. Orion Power did not meet the debt service coverage ratio for the three months ended June 30, 2002 and September 30, 2002, as required. While the failure to meet such ratio for two consecutive fiscal quarters is a default under the senior credit facility, the senior credit facility was amended to provide that such failure was not considered to be an event of default until the maturity date of the Orion MidWest credit facility. This facility was terminated in October 2002 in connection with the execution of the amended and restated Orion Midwest and Orion NY credit facilities. See Note 16(b) for further discussion of the debt restructuring. New York Credit Agreement. As of September 30, 2002, Orion NY, a wholly owned subsidiary of Orion Power, had a secured credit agreement (New York Credit Agreement), which includes a $412 million acquisition facility and a $30 million revolving working capital facility, including letters of credit. As of September 30, 2002, Orion NY had $412 million of acquisition loans outstanding. As of September 30, 2002, there were no revolving loans outstanding. A total of $10 million in letters of credit were also outstanding under the New York Credit Agreement. The loans bore interest at the borrower's option at a base rate plus 0.75% or LIBOR plus 1.75%. As of September 30, 2002, the weighted average interest rate on outstanding borrowings was 3.90%. The credit agreement was secured by substantially all of the assets of Orion NY and its subsidiaries excluding certain plant assets. As of September 30, 2002, restricted cash under the New York Credit Agreement was $261 million. A subsidiary of Orion NY provided a mortgage with respect to one of the hydropower plants to the City of Cohoes Industrial Development Agency (CCIDA), in violation of the negative covenant in the New York Credit Agreement that limits liens, other than those permitted, on the assets. The transaction was approved by the lenders 29 and the default was cured in October 2002, in connection with the restructuring of the Orion New York Credit Agreement. See Note 16(b) for further discussion of the debt restructuring. MidWest Credit Agreement. As of September 30, 2002, Orion MidWest, a wholly owned subsidiary of Orion Power, had a secured credit agreement (Midwest Credit Agreement), which includes a $988 million acquisition facility and a $75 million revolving working capital facility, including letters of credit. As of September 30, 2002, Orion MidWest had $988 million and $60 million of acquisition loans and revolving loans outstanding, respectively. A total of $15 million in letters of credit were also outstanding under the MidWest Credit Agreement. The loans bore interest at the borrower's option at a base rate plus 1.00% or LIBOR plus 2.00%. As of September 30, 2002, the weighted average interest rate on outstanding borrowings was 3.83%. Borrowings under the MidWest Credit Agreement were secured by substantially all the assets of Orion MidWest and its subsidiary. As of September 30, 2002, restricted cash under the MidWest Credit Agreement was $85 million. See Note 16(b) for further discussion of the debt restructuring. In connection with the Orion Power acquisition, the existing interest rate swaps for the New York Credit Agreement and MidWest Credit Agreement (collectively, the Orion Credit Agreements) were bifurcated into a debt component and a derivative component. The fair value of the debt component, approximately $31 million for the New York Credit Agreement and $59 million for the MidWest Credit Agreement, was based on the Company's incremental borrowing rates at the acquisition date for similar types of borrowing arrangements. The value of the debt component will be amortized to interest expense over the life of the interest rate swaps to which they relate. For the period from February 20, 2002 through September 30, 2002, $5 million and $12 million was amortized to interest expense for Orion NY and Orion MidWest, respectively. See Note 4 for information regarding the Company's derivative financial instruments. The Orion Credit Agreements contained various business and financial covenants requiring Orion NY or Orion MidWest to, among other things, maintain a debt service coverage ratio of at least 1.5 to 1.0. Because it was anticipated that Orion MidWest would not meet this ratio for the quarter ended September 30, 2002, the MidWest Credit Agreement was amended to provide that Orion MidWest was not required to meet this ratio for that quarter, and was subsequently amended to remove this requirement entirely. The Midwest and New York Credit Agreements were amended and restated in October 2002 to extend the maturity of the agreements by 3 years, to October 28, 2005. See Note 16(b) for additional discussion of the amended and restated agreements. Liberty Credit Agreement. Liberty Electric Power, LLC (LEP) and Liberty Electric PA, LLC (Liberty), wholly owned subsidiaries of Orion Power, entered into a facility that provides for (a) a construction/term loan in an amount of up to $105 million; (b) an institutional term loan in an amount of up to $165 million; (c) a revolving working capital facility for an amount of up to $5 million; and (d) a debt service reserve letter of credit facility of $17.5 million (Liberty Credit Agreement). In May 2002, the construction loan was converted to a term loan. As of the conversion date, the term loan had an outstanding principal balance of $270 million, with $105 million having a final maturity in 2012 and the balance having maturities through 2026. On the conversion date, Orion Power made the required cash equity contribution of $30 million into Liberty, which was used to repay a like amount of equity bridge loans advanced by the lenders. A related $41 million letter of credit furnished by Orion Power as credit support was returned for cancellation. In addition, on the conversion date, a $17.5 million letter of credit was issued in satisfaction of Liberty's obligation to provide a debt service reserve. The project financing facility also provides for a $5 million working capital line of credit. The debt service reserve letter of credit facility and the working capital facility expire in May 2007. Amounts outstanding under the Liberty Credit Agreement bear interest at a floating rate for a portion of the facility, which may be either LIBOR plus 1.25% or a base rate, except for the institutional term loan which bears interest at a fixed rate. At September 30, 2002, the weighted average interest rate on the outstanding borrowings was 3.11% on the floating rate component and 9.02% on the fixed rate portion. As of September 30, 2002, Liberty had $105 million and $165 million of the floating rate and fixed rate portions of the facility outstanding, respectively. A total of $17.5 million in letters of credit were also outstanding under the Liberty Credit Agreement. The lenders under the Liberty Credit Agreement have a security interest in substantially all of the assets of Liberty. The Liberty Credit Agreement contains restrictive covenants that restrict Liberty's ability to, among other 30 things, make dividend distributions unless Liberty satisfies various conditions. As of September 30, 2002, restricted cash under the Liberty Credit Agreement totaled $24 million. For additional information regarding the LEP and Liberty credit facility related issues and concerns, see Note 12(i). Senior Notes. Orion Power has outstanding $400 million aggregate principal amount of 12% senior notes due 2010 (Senior Notes). The Senior Notes are senior unsecured obligations of Orion Power. Orion Power is not required to make any mandatory redemption or sinking fund payments with respect to the Senior Notes. The Senior Notes are not guaranteed by any of Orion Power's subsidiaries. In connection with the Orion Power acquisition, the Company recorded the Senior Notes at estimated fair value of $479 million. The $79 million premium will be amortized against interest expense over the life of the Senior Notes. For the period February 20, 2002 to September 30, 2002, $4 million was amortized to interest expense for the Senior Notes. The fair value of the Senior Notes was based on the Company's incremental borrowing rates for similar types of borrowing arrangements as of the acquisition date. The Senior Notes indenture contains covenants that include among others, restrictions on the payment of dividends by Orion Power. Pursuant to certain change of control provisions, Orion Power commenced an offer to repurchase the Senior Notes on March 21, 2002. The offer to repurchase expired on April 18, 2002. There were no acceptances of the offer to repurchase and the entire $400 million aggregate principal amount remains outstanding. Before May 1, 2003, Orion Power may redeem up to 35% of the Senior Notes issued under the indenture at a redemption price of 112% of the principal amount of the notes redeemed, plus accrued and unpaid interest and special interest, with the net cash proceeds of an equity offering provided that certain provisions under the indenture are met. Convertible Senior Notes. Orion Power had outstanding $200 million of aggregate principal amount of 4.5% convertible senior notes, due on June 1, 2008 (Convertible Senior Notes). Pursuant to certain change of control provisions, Orion Power commenced an offer to repurchase the Convertible Senior Notes on March 1, 2002, which expired on April 10, 2002. During the second quarter of 2002, the Company repurchased $189 million in principal amount under the offer to repurchase and $11 million aggregate principal amount of the Convertible Senior Notes remained outstanding as of September 30, 2002. During the fourth quarter of 2002, the remaining $11 million aggregate principal amount of the Convertible Senior Notes were repurchased for $8.4 million. (10) TREASURY STOCK On December 6, 2001, Reliant Resources' Board of Directors authorized the Company to purchase up to 10 million shares of its common stock through June 2003. Any purchases will be made on a discretionary basis in the open market or otherwise at times and in amounts as determined by management subject to market conditions, legal requirements and other factors. Since the date of authorization through November 8, 2002, the Company has not purchased any shares of its common stock under this program. In January and July 2002, the Company sold 550,781 and 776,062, respectively, treasury shares to employees under an employee stock purchase plan at a price of $14.07 per share and $7.44 per share, respectively. In April 2002, the Company made a discretionary annual contribution of 308,936 shares to the employee savings plan. The Company funded its contribution using treasury shares. 31 (11) EARNINGS PER SHARE The following tables present Reliant Resources' basic and diluted earnings per share (EPS) calculation. There were no dilutive reconciling items to net income. FOR THE THREE MONTHS ENDED SEPTEMBER 30, -------------------- 2001 2002 ------- ------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Weighted average shares outstanding ................ 299,164 290,425 ======= ======= Diluted EPS Calculation: Weighted average shares outstanding ................ 299,164 290,425 Plus: Incremental shares from assumed conversions: Stock options ................................... -- 13 Restricted stock ................................ 186 977 Employee stock purchase plan .................... 60 169 ------- ------- Weighted average shares assuming dilution ........ 299,410 291,584 ======= ======= Basic and Diluted EPS .............................. $ 0.87 $ 0.17 ======= ======= For the three months ended September 30, 2002, the computation of diluted EPS excludes purchase options for 20,008,790 shares of common stock that have an exercise price (ranging from $6.20 - $34.03 per share) greater than the per share average market price ($5.21) for the period and would thus be anti-dilutive if exercised. For the three months ended September 30, 2001, the computation of diluted EPS excludes purchase options for 8,671,268 shares of common stock that have an exercise price (ranging from $23.20 - $34.03) greater than the per share average market price ($21.08) for the period and would thus be anti-dilutive if exercised. FOR THE NINE MONTHS ENDED SEPTEMBER 30, --------------------------------------- 2001 2002 ----------- ----------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Weighted average shares outstanding .................. 272,253 289,788 =========== =========== Diluted EPS Calculation: Weighted average shares outstanding .................. 272,253 289,788 Plus: Incremental shares from assumed conversions: Stock options .................................... 2 769 Restricted stock ................................. 186 977 Employee stock purchase plan ..................... 60 169 ----------- ----------- Weighted average shares assuming dilution .......... 272,501 291,703 =========== =========== Basic EPS: Income before cumulative effect of accounting change $ 2.00 $ 1.11 Cumulative effect of accounting changes, net of tax 0.01 (0.80) ----------- ----------- Net income ......................................... $ 2.01 $ 0.31 =========== =========== Diluted EPS: Income before cumulative effect of accounting change $ 2.00 $ 1.10 Cumulative effect of accounting changes, net of tax 0.01 (0.80) ----------- ----------- Net income ......................................... $ 2.01 $ 0.30 =========== =========== For the nine months ended September 30, 2002, the computation of diluted EPS excludes purchase options for 14,581,582 shares of common stock that have an exercise price (ranging from $10.29 - $34.03 per share) greater than the per share average market price ($10.23) for the period and would thus be anti-dilutive if exercised. For the nine months ended September 30, 2001, the computation of diluted EPS excludes purchase options for 8,505,100 shares of common stock that have an exercise price (ranging from $30.00 - $34.03) greater than the per share average market price ($25.48) for the period and would thus be anti-dilutive if exercised. 32 (12) COMMITMENTS AND CONTINGENCIES (a) Legal Matters. Southern California Class Actions. Reliant Energy, Reliant Energy Services, Inc. (Reliant Energy Services), Reliant Energy Power Generation, Inc. (REPG) and several other subsidiaries of Reliant Resources, as well as two former officers and one present officer, have been named as defendants in class action lawsuits and other lawsuits filed against a number of companies that own generation plants in California and other sellers of electricity in California markets. Three of these lawsuits were filed in the Superior Court of the State of California, San Diego County; two were filed in the Superior Court in San Francisco County; and one was filed in the Superior Court of Los Angeles County. While the plaintiffs allege various violations by the defendants of state antitrust laws and state laws against unfair and unlawful business practices, each of the lawsuits is grounded on the central allegation that the defendants conspired to drive up the wholesale price of electricity. In addition to injunctive relief, the plaintiffs in these lawsuits seek treble the amount of damages alleged, restitution of alleged overpayments, disgorgement of alleged unlawful profits for sales of electricity, costs of suit and attorneys' fees. Plaintiffs have voluntarily dismissed Reliant Energy from two of the three class actions in which it was named as a defendant. The cases were initially removed to federal court and were then assigned to Judge Robert H. Whaley, United States District Judge, pursuant to the federal procedures for multi-district litigation. On July 30, 2001, Judge Whaley remanded the cases to state court. Upon remand to state court, the cases were assigned to Superior Court Judge Janis L. Sammartino pursuant to the California state coordination procedures. On March 4, 2002, Judge Sammartino adopted a schedule proposed by the parties that would result in a trial beginning on March 1, 2004. On March 8, 2002, the plaintiffs filed a single, consolidated complaint naming numerous defendants, including Reliant Energy Services and other Reliant Resources' subsidiaries, that restated the allegations described above and alleged that damages against all defendants could be as much as $1 billion. On April 22 and 23, 2002, the Company and Duke Energy filed cross complaints in the coordinated proceedings seeking, in an alternative pleading, relief against other market participants in California, the surrounding states, Canada and Mexico including Powerex Corp., the Los Angeles Department of Water and Power and the Bonneville Power Administration. Powerex Corp., Bonneville Power Administration and British Columbia Hydro and Power Authority removed the case once again to federal court where it was re-assigned to Judge Whaley. On July 10, 2002, a motion to dismiss was filed in coordinated proceedings seeking dismissal of the complaints on the basis of the filed rate doctrine and federal preemption. On September 19, 2002, Judge Whaley heard arguments on plaintiffs' motion to remand the cases back to state court. The matter is under consideration by the court. California Attorney General Actions. On March 11, 2002, the California Attorney General filed a civil lawsuit in San Francisco Superior Court naming Reliant Energy, Reliant Resources, Reliant Energy Services, REPG, and several other subsidiaries of Reliant Resources as defendants. The Attorney General alleges various violations by the defendants of state laws against unfair and unlawful business practices arising out of transactions in the markets for ancillary services run by the California Independent System Operator (Cal ISO). In addition to injunctive relief, the Attorney General seeks restitution and disgorgement of alleged unlawful profits for sales of electricity and civil penalties. The Company removed this lawsuit to federal court, where it has been assigned to Judge Vaughn Walker in the Northern District of California. Judge Walker denied the California Attorney General's motion to remand this case to state court. The Company filed a motion to dismiss this action, which is under consideration by the court. On March 19, 2002, the California Attorney General filed a complaint with the Federal Energy Regulatory Commission (FERC) naming Reliant Energy Services and "all other public utility sellers" in California as defendants. The complaint alleges that sellers with market-based rates have violated their tariffs by not filing with the FERC transaction-specific information about all of their sales and purchases at market-based rates. The California Attorney General argued that, as a result, all past sales should be subject to refund if found to be above just and reasonable levels. On May 31, 2002, the FERC issued an order that largely denied the complaint and required only that Reliant Energy Services and other sellers file revised transaction reports regarding prior sales in California spot markets. On September 23, 2002, the FERC issued an order denying rehearing of the May 31, 2002 order. On September 24, 2002, the California Attorney General petitioned the Court of Appeals for the Ninth Circuit for review of these orders. On April 15, 2002, the California Attorney General filed a lawsuit in San Francisco County Superior Court against Reliant Energy, Reliant Resources, Reliant Energy Services and several other subsidiaries of Reliant Resources. The complaint is substantially similar to the compliant described above filed by the California Attorney General with the FERC on March 19, 2002. The complaint also alleges that the Company consistently charged 33 unjust and unreasonable prices for electricity, and that each instance of overcharge violated California law. The lawsuit seeks fines of up to $2,500 for each alleged violation, and "other equitable relief as appropriate." The Company has removed this case to federal court, where it has been assigned to Judge Vaughn Walker in the Northern District of California. Judge Walker has denied the California Attorney General's motion to remand this case to state court. The Company filed a motion to dismiss this action which is under consideration by the court. On April 15, 2002, the California Attorney General and the California Department of Water Resources filed a complaint in the United States District Court for the Northern District of California against Reliant Energy, Reliant Resources and a number of Reliant Resources' subsidiaries. In this lawsuit, the Attorney General alleges that the Company's acquisition of electric generating facilities from Southern California Edison in 1998 violated Section 7 of the Clayton Act, which prohibits mergers or acquisitions that substantially lessen competition. The lawsuit claims that the acquisitions gave the Company market power which it then exercised to overcharge California consumers for electricity. The lawsuit seeks injunctive relief against alleged unfair competition, divestiture of the Company's California facilities, disgorgement of alleged illegal profits, damages, and civil penalties for each alleged exercise of market power. This lawsuit also has been assigned to Judge Vaughn Walker. The Company filed a motion to dismiss this action, which is under consideration by the court. Northern California Class Actions. In the wake of the filing of the Attorney General cases, there have been seven new class action cases filed in state courts in Northern California. Each of these purports to represent the same class of California ratepayers, assert the same claims as asserted in the Southern California class action cases, and in some instances repeat as well the allegations in the Attorney General cases. All of these cases have been removed to federal court and plaintiffs filed motions to remand. In October 2002, the Panel on Multidistrict Litigation transferred these cases to Judge Whaley for coordination with the Southern California class actions. On October 21, 2002, the Company received notice that a new class action has been filed in Los Angeles County Superior Court. The complaint is virtually identical to those filed in Northern California and names as defendants Reliant Energy and five subsidiaries of Reliant Resources. The Company has not yet been served. Washington Class Action. After the filing of the Northern California class actions, a separate class action suit was filed in federal court in Los Angeles on behalf of the Snohomish County Public Utility District and its customers in the State of Washington. In September 2002, the Panel on Multidistrict Litigation transferred this case to Judge Whaley for coordination with the Southern California class actions. Defendants have filed a motion to dismiss the case and a hearing on such motion has been set for December 19, 2002. The Company has not answered any of the above referenced class action cases; however, it has moved to dismiss each of the cases on the grounds that the claims are barred by federal preemption and the filed rate doctrine. Pursuant to the terms of the Master Separation Agreement (see Note 4(c) to the Reliant Resources 10-K/A Notes), Reliant Resources has agreed to indemnify CenterPoint Energy for any damages arising under these lawsuits and may elect to defend these lawsuits at the Company's own expense. FERC Complaints. On April 11, 2002, the FERC set for hearing a series of complaints filed by Nevada Power Company, which seek reformation of certain forward power contracts, including two contracts with Reliant Energy Services that have since been terminated. Proceedings are ongoing before an administrative law judge who anticipates issuing a decision in December 2002 for consideration by the FERC. PacifiCorp Company filed a similar complaint challenging two ninety-day contracts with Reliant Energy Services, which the FERC also has set for hearing. The FERC has stated that it intends to issue a decision in both cases by May 31, 2003. Trading and Marketing Activities. The Company is party to numerous lawsuits and regulatory proceedings relating to its trading and marketing activities, including (a) round trip trades, as more fully described in Note 1, and (b) structured transactions. In addition, various state and federal governmental agencies have commenced investigations relating to such activities. Their ultimate outcome cannot be predicted at this time. Additional information regarding certain of these matters is set forth below. In June 2002, the SEC advised the Company that it had issued a formal order in connection with its investigation of the Company's financial reporting, internal controls and related matters. Reliant Resources understands that the investigation is focused on its round trip trades and structured transactions. These matters were previously the subject of an informal inquiry by the SEC. The SEC's formal order is also addressed to Reliant Energy. Reliant Resources is cooperating with the SEC staff. 34 As part of the Commodity Futures Trading Commission's (CFTC) industry-wide investigation of so-called round trip trading, the CFTC has subpoenaed documents, requested information and conducted discovery relating to Reliant Resources' natural gas and power trading activities, including round trip trades and alleged price manipulation, occurring since January 1, 1999. Reliant Resources is cooperating with the CFTC staff. On August 13, 2002, the FERC staff issued its Initial Report on Fact Finding Investigation of Potential Manipulation of Electric and Gas Prices (Initial Report). Certain findings, conclusions and observations in the staff report, if adopted or otherwise acted on by the FERC, could have a material adverse effect on the Company. For example, in the Initial Report the FERC staff recommends that the mitigated market clearing prices for purposes of determining refunds in the pending refund proceeding described in Note 12(c) should be based on gas costs determined using producing basin spot prices plus regulated transportation costs instead of the published gas price indices for deliveries in California, as the FERC originally ordered. Such a change in the refund methodology, if adopted, would likely have an adverse impact on the Company's potential refund obligations. Other findings, conclusions and observations in the report may likewise have a material adverse effect on the Company if adopted or otherwise acted upon. In the Initial Report, the FERC Staff indicated that it is continuing to receive and review data, including information relevant to the subjects covered in the report. In this regard, the Company has provided information to FERC about its trading activities in the Western United States during 2000 and 2001. Included among the data requests the Company has received from the FERC are requests asking for information regarding power trading activity, natural gas trading for specific periods or locations, certain trading practices, round trip trades and compliance with supplemental dispatch requests. The Company has received additional data requests regarding gas trading in the West. The Company is cooperating and will continue to cooperate with the FERC. The ultimate outcome of the investigation cannot be predicted at this time. The Company has received subpoenas and informal request from the United States Attorney for the Southern District of New York and Northern District of California requesting documents, interviews and other information pertaining to the round trip trades, and the Company's energy trading activities. These inquiries appear to parallel that of the SEC, the CFTC and the FERC. The Company is cooperating with the office of the United States Attorney. In connection with the Texas Utility Commission's industry-wide investigation into potential manipulation of the ERCOT market, the Company has provided information to the Texas Utility Commission concerning its scheduling and trading practices on and after July 31, 2001. Also, the Company, and four other qualified scheduling entities in ERCOT, reached a settlement relating to scheduling issues that arose during August 2001. The Texas Utility Commission approved the settlement on November 7, 2002. In May, June and July 2002, eleven class action lawsuits were filed on behalf of purchasers of securities of Reliant Resources and/or Reliant Energy. Reliant Resources and several of its executive officers are named as defendants. Reliant Energy is also named as a defendant in three of the lawsuits. Two of the lawsuits also name as defendants the underwriters of the IPO. One of those two lawsuits also names Reliant Resources' and Reliant Energy's independent auditors as a defendant. The dates of filing of these lawsuits are as follows: two lawsuits on May 15, 2002; two lawsuits on May 16, 2002; one lawsuit on May 17, 2002; one lawsuit on May 20, 2002; one lawsuit on May 21, 2002; one lawsuit on May 23, 2002; one lawsuit on June 19, 2002; one lawsuit on June 20, 2002; and one lawsuit on July 1, 2002. Ten of the lawsuits were filed in the United States District Court, Southern District of Texas, Houston Division. One lawsuit was filed in the United States District Court, Eastern District of Texas, Texarkana Division. The complaints allege that the defendants overstated the revenues of the Company by including transactions involving the purchase and sale of commodities with the same counterparty at the same price and that the Company improperly accounted for certain other transactions. The complaints seek monetary damages and, in one of the lawsuits rescission, on behalf of a supposed class. In eight of the lawsuits, the supposed class is composed of persons who purchased or otherwise acquired Reliant Resources and/or Reliant Energy securities during specified class periods. The three lawsuits that include Reliant Energy as a named defendant were also filed on behalf of purchasers of securities of Reliant Resources and/or Reliant Energy during specified class periods. Additionally, in May and June 2002, four class action lawsuits were filed on behalf of purchasers of securities of Reliant Energy. Reliant Energy and several of its executive officers are named as defendants. The dates of filing 35 of the four lawsuits are as follows: one on May 16, 2002; one on May 21, 2002; one on June 13, 2002; and one on June 17, 2002. The lawsuits were filed in the United States District Court, Southern District of Texas, Houston Division. The complaints allege that the defendants violated federal securities laws by issuing false and misleading statements to the public. The plaintiffs allege that the defendants made false and misleading statements as part of an alleged scheme to artificially inflate trading volumes and revenues by including transactions involving the purchase and sale of commodities with the same counterparty at the same price, to spin-off Reliant Resources to avoid exposure to Reliant Resources' liabilities and to cause the price of Reliant Resources' stock to rise artificially, among other things. The complaints seek monetary damages on behalf of persons who purchased Reliant Energy securities during specified class periods. By order dated August 1, 2002, the court consolidated ten of the cases pending in the United States District Court, Southern District of Texas, Houston Division. By order dated August 27, 2002, the court consolidated the remaining four cases in the Houston Division. In the same order, the court appointed the Boca Raton Police & Firefighters Retirement System and the Louisiana Retirement Funds to be lead plaintiffs. By order dated August 22, 2002, the remaining securities case was transferred from United States District Court for the Eastern District of Texas, Texarkana Division, to the Southern District of Texas, Houston Division. By order dated September 20, 2002, the court consolidated the case originally filed in the Texarkana Division with the fourteen cases previously consolidated in the Houston Division. In May 2002, three class action lawsuits were filed on behalf of participants in various employee benefits plans sponsored by Reliant Energy. Reliant Energy and its directors are named as defendants in all of the lawsuits. Reliant Resources is named as a defendant in two of the lawsuits. The lawsuits were filed on May 29, 2002, May 30, 2002, and May 31, 2002. All of the lawsuits were filed in the United States District Court, Southern District of Texas, Houston Division. By order dated June 20, 2002, the Court granted the motion for voluntary dismissal filed by the plaintiffs in one of the cases and dismissed that case without prejudice. By Order dated August 21, 2002, the Court granted the motion for voluntary dismissal filed by the plaintiff in one of the two remaining cases and dismissed that case without prejudice. The remaining complaint alleges that the defendants breached their fiduciary duties to various employee benefits plans sponsored by Reliant Energy, in violation of the Employee Retirement Income Security Act. The plaintiffs allege that the defendants permitted the plans to purchase or hold securities issued by Reliant Energy when it was imprudent to do so, including after the prices for such securities became artificially inflated because of alleged securities fraud engaged in by the defendants. The complaints seek monetary damages for losses suffered by a putative class of plan participants whose accounts held Reliant Energy or Reliant Resources securities, as well as equitable relief in the form of restitution. In May 2002, a derivative action was filed against the directors and independent auditors of Reliant Resources. The lawsuit was filed on May 17, 2002, in the 269th Judicial District, Harris County, Texas. The petition alleges that the defendants breached their fiduciary duties to the Company. The shareholder plaintiff alleges that the defendants caused the Company to conduct its business in an imprudent and unlawful manner, including allegedly failing to implement and maintain an adequate internal accounting control system, engaging in transactions involving the purchase and sale of commodities with the same counterparty at the same price, and disseminating materially misleading and inaccurate information regarding the Company's revenue and trading volume. The petition seeks monetary damages on behalf of the Company. The above-described lawsuits and proceedings are currently the subject of intense, highly-charged media and political attention. As these matters progress, additional issues may be identified that could expose the Company to further lawsuits and proceedings. Their ultimate outcome cannot be predicted at this time. Other Legal and Environmental Matters. The Company is involved in other environmental and legal proceedings before various courts and governmental agencies regarding matters arising in the ordinary course of business, some of which involve substantial amounts. The Company's management regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. (b) Environmental Matters. REMA Ash Disposal Site Closures and Site Contaminations. Under the agreement to acquire REMA (see Note 5(a) to the Reliant Resources 10-K/A Notes), the Company became responsible for liabilities associated with ash disposal site closures and site contamination at the acquired facilities in Pennsylvania and New Jersey prior to a 36 plant closing, except for the first $6 million of remediation costs at the Seward Generating Station. A prior owner retained liabilities associated with the disposal of hazardous substances to off-site locations prior to November 24, 1999. As of September 30, 2002, REMA had liabilities associated with six future ash disposal site closures and six current site investigations and environmental remediations. The Company has recorded its estimate of these environmental liabilities in the amount of $32 million as of September 30, 2002. The Company expects approximately $13 million will be paid over the next five years. REPGB Asbestos Abatement and Environmental Remediation. Prior to the Company's acquisition of REPGB (see Note 5(b) to the Reliant Resources 10-K/A Notes), REPGB had a $23 million obligation primarily related to asbestos abatement, as required by Dutch law, and soil remediation at six sites. During 2000, the Company initiated a review of potential environmental matters associated with REPGB's properties. REPGB began remediation in 2000 of the properties identified to have exposed asbestos and soil contamination, as required by Dutch law and the terms of some leasehold agreements with municipalities in which the contaminated properties are located. All remediation efforts are to be fully completed by 2005. As of September 30, 2002, the recorded undiscounted liability for asbestos abatement, soil remediation and plant water system compliance was $20 million. Orion Power Environmental Contingencies. In connection with Orion Power's acquisition of 70 hydro plants in northern and central New York and four gas- or oil- fired plants in New York City, Orion Power assumed the liability for the estimated cost of environmental remediation at several properties. Orion Power developed remediation plans for each of these properties and entered into Consent Orders with the New York State Department of Environmental Conservation at two New York City sites and one hydro site for releases of petroleum and other substances by the prior owners. The liability assumed and recorded by the Company for all New York assets was approximately $10 million, which the Company expects to pay out through 2006. In connection with the acquisition of Midwest assets by Orion Power, Orion Power became responsible for the liability associated with the closure of three ash disposal sites in Pennsylvania. The liability assumed and recorded by the Company for these disposal sites was approximately $12 million, with $1 million to be paid over the next five years. (c) California Wholesale Market Uncertainty. Receivables. During portions of 2000 and 2001, prices for wholesale electricity in California increased dramatically as a result of a combination of factors, including higher natural gas prices and emission allowance costs, reduction in available hydroelectric generation resources, increased demand, decreased net electric imports and limitations on supply as a result of maintenance and other outages. The resulting supply and demand imbalance disproportionately impacted California utilities that relied heavily on short-term power markets to meet their load requirements. Although wholesale prices increased, California's deregulation legislation kept retail rates frozen at 10% below 1996 levels for two of California's public utilities, Pacific Gas and Electric (PG&E) and Southern California Edison Company (SCE), until rates were raised by the California Public Utilities Commission (CPUC) early in 2001. Due to the disparity between wholesale and retail rates, the credit ratings of PG&E and SCE fell below investment grade. Additionally, PG&E filed for protection under the bankruptcy laws on April 6, 2001. As a result, PG&E and SCE are no longer considered creditworthy, and since January 17, 2001, have not directly purchased power from third-party suppliers through the Cal ISO to serve that portion of load that cannot be met from their own supply sources (net short load). Pursuant to emergency legislation enacted by the California Legislature, the California Department of Water Resources (DWR) has negotiated and purchased power through short- and long-term contracts and through real-time markets operated by the Cal ISO to serve the net short load requirements of PG&E and SCE. In December 2001, the DWR began making payments to the Cal ISO for real-time transactions. On May 15, 2002, the FERC issued an order stating that sellers, including the Company, should receive interest payments on past due amounts owed by the Cal ISO and DWR. The DWR has now made payment through the Cal ISO for its real-time energy deliveries subsequent to January 17, 2001, although the Cal ISO's distribution of DWR's payment for the month of January 2001, and the allocation of interest to past due amounts, are the subjects of motions that the Company has filed with the FERC objecting to the Cal ISO's failure to allocate the January payment and interest solely to post- January 17, 2001 transactions. In addition, the Company is prosecuting a lawsuit in California to recover the market value of forward contracts seized by California Governor Gray Davis in violation of the Federal Power Act. Governor Davis' actions prevented the liquidation of the contracts by the California Power Exchange (Cal PX) to satisfy the outstanding obligations of SCE and PG&E to wholesale suppliers, including the Company. The timing and ultimate resolution of this claim is uncertain at this time. 37 On September 20, 2001, PG&E filed a Plan of Reorganization and an accompanying disclosure statement with the bankruptcy court. Under this plan, PG&E would pay all allowed creditor claims in full, through a combination of cash and long-term notes. Components of the plan will require the approval of the FERC, the SEC and the Nuclear Energy Regulatory Commission, in addition to the bankruptcy court. PG&E has stated it seeks to have this plan confirmed by December 31, 2002. On April 24, 2002, the bankruptcy judge approved PG&E's disclosure statement. A number of parties are contesting PG&E's reorganization plan, including a number of California parties and agencies. The bankruptcy judge in the PG&E case has ordered that the CPUC may file a competing plan. The ability of PG&E to have its reorganization plan confirmed, including the provision providing for the payment in full of unsecured creditors, is uncertain at this time. The CPUC has filed a competing plan and disclosure statement which provides for payment of allowed creditor claims in full in cash. The CPUC disclosure statement was approved on May 15, 2002. The timing and probability of confirmation of either plan, including the provision for payment in full of all unsecured creditors, is uncertain at this time. The Company has signed a stipulation with PG&E whereby it has agreed to vote for PG&E's reorganization plan and PG&E has agreed to pay amounts it indirectly owed to the Company subject to any refunds ordered by the FERC. The stipulation does not preclude the Company from approving other reorganization plans, including the CPUC plan. On October 5, 2001, a federal district court in California entered a stipulated judgment approving a settlement between SCE and the CPUC in an action brought by SCE regarding the recovery of its wholesale power costs under the filed rate doctrine. Under the stipulated judgment, a rate increase approved earlier in 2001 will remain in place until the earlier of SCE recovering $3.3 billion or December 31, 2002. After that date, the CPUC will review the sufficiency of retail rates through December 31, 2005. A consumer organization has appealed the judgment to the Ninth Circuit Court of Appeals, and no hearing has been held to date. Under the stipulated judgment, any settlement with SCE's creditors that is entered into after March 1, 2002 must be approved by the CPUC. The Company has appealed this provision of the judgment. On March 1, 2002, SCE made a payment to the Cal PX that included amounts it owed the Company. The Company has made a filing with FERC seeking an order providing for the disbursement of the funds owed to the suppliers. The FERC and the bankruptcy court governing the Cal PX bankruptcy proceedings are considering how to dispense this money and it remains uncertain when those funds will be paid over to the Company. As of December 31, 2001 and September 30, 2002, the Company was owed a total of $302 million and $233 million (net of estimated refund provision), respectively, by the Cal ISO, the Cal PX, the DWR, and California Energy Resources Scheduling for energy sales in the California wholesale market during the fourth quarter of 2000 through September 30, 2002. From September 30, 2002 through November 8, 2002, the Company has collected $9 million of these receivable balances. As of December 31, 2001, the Company had a pre-tax credit provision of $68 million against receivable balances related to energy sales in the California market. For the nine months ended September 30, 2002, $44 million of a previously accrued credit provision for energy sales in California was reversed. The reversal resulted from collections of outstanding receivables during the period, a determination that credit risk had been reduced on the remaining outstanding receivables as a result of payments in 2002 to the Cal PX and the reversal of $11 million of credit provision due to the write-off of receivables as a result of a May 15, 2002 FERC order discussed below. As of September 30, 2002, the Company had a remaining pre-tax credit provision of $24 million against these receivable balances. Management will continue to assess the collectability of these receivables based on further developments affecting the California electricity market and the market participants described herein. FERC Market Mitigation. In response to the filing of a number of complaints challenging the level of wholesale prices in California, the FERC initiated a staff investigation and issued a number of orders implementing a series of wholesale market reforms. In these orders, the FERC also instituted a refund proceeding, described below, as a result of which the Company may face an as yet undetermined amount of refund liability. See " - FERC Refunds" below. Prior to adopting a methodology for calculating refunds in the refund proceeding, the FERC identified, for the period January 1, 2001 through June 19, 2001, approximately $20 million of the $149 million charged by the Company for sales in California to the Cal ISO and the Cal PX as being subject to possible refunds. During the nine months ended September 30, 2001, the Company accrued refunds of $15 million. The FERC initially established an interim market monitoring and mitigation plan for the California markets that extended until September 30, 2002, and included imposition of price controls to California and other Western states in all hours as well as a requirement that generators in California offer all their available capacity for sale in the real-time market. The FERC set July 2, 2001 as the refund effective date for sales subject to the price mitigation plan throughout the West region. This meant that transactions after that date may be subject to refund if they exceed the 38 calculated price cap. Sellers other than marketers that bid higher than the capped price, had a limited opportunity to justify their bids if they could demonstrate higher gas costs than those assumed in the price cap calculation. On July 17, 2002, the FERC issued an order directing short-term and longer-term redesign of the California wholesale electricity market to take effect following the interim mitigation plan. On October 11, 2002, the FERC issued an order clarifying and modifying certain aspects of the new California market design. On September 26, 2002, FERC granted the Cal ISO's motion to extend the interim market mitigation measures discussed above until October 30, 2002. Effective October 31, 2002, a $250/MWh soft cap was adopted in place of the existing price cap of $91.87/MWh and so called automatic mitigation procedures were implemented. Under this approach, mitigation will be applied if a bid exceeds $91.87/MWh, results in a 200% or $100/MWh increase above an as yet undetermined unit-specific reference level, and results in a 200% or $50/MWh increase in the market clearing price for the zone where the relevant unit is located. A variation of this formula will be used to cap bids in congested areas. Bids from outside California are exempt from the automatic mitigation procedures. Instead, bidders outside California will continue to be "price takers" by submitting zero bids into Cal ISO markets. The FERC approved new penalties for generators that fail to generate at levels instructed by the Cal ISO. The Cal ISO may not impose penalties, however, until it develops software to recognize various operating constraints on units. The market redesign ordered by the FERC on July 17, 2002 continues the requirement that generators offer all available supply into the California market until the FERC determines that "long-term market-based solutions can be fully implemented." The October 11, 2002 order of the FERC instructed the Cal ISO to develop a modified day-ahead market for implementation January 1, 2003, with full implementation of integrated forward markets by late 2003. The Cal ISO has petitioned FERC to delay these implementation deadlines. The July 17, 2002 order also requires adoption by the Cal ISO of a resource adequacy requirement but does not set a deadline for its development. Other long-term aspects of the redesign of the Cal ISO market remain open for consideration by the FERC. In a separate order issued July 17, 2002, the FERC ordered that the current Cal ISO Board of Governors be disbanded and replaced with an independent Board by January 1, 2003. The Cal ISO Board responded with a filing stating that it would not disband. The FERC has sued in federal district court for enforcement of its order and the Cal ISO Board has filed a motion to dismiss that suit. FERC Refunds. The FERC issued an order on July 25, 2001 adopting a refund methodology and initiating a hearing schedule to determine (a) revised mitigated prices for each hour from October 2, 2000 through June 20, 2001; (b) the amount owed in refunds by each supplier according to the methodology; and (c) the amount currently owed to each supplier. The amounts of any refunds will be determined by the FERC after the Administrative Law Judge makes his recommendations to the FERC in late 2002. However, the Company does not know when the FERC will issue its final decision. This decision may be delayed pending a final report from FERC staff regarding the gas price component of the refund methodology. Based on the FERC's May 15, 2002 order and the FERC staff's interpretation of such order, the Company estimates its refund obligation to be between $70 million and $190 million for energy sales in the West region. Until the FERC issues additional guidance for refunds, the Company is unable to narrow the range of estimates for its refund obligations. During the second quarter of 2002, the Company recorded a reserve for refunds of $34 million related to energy sales in the West region based on the May 15, 2002 order. In the third quarter of 2002, the Company recorded an additional reserve for refunds of $21 million based in further FERC staff interpretations of the May 15, 2002 FERC order. As discussed above, $15 million was recognized in the second quarter of 2001. As of September 30, 2002, the Company's total reserve for refunds related to energy sales in the West region is $70 million. Refunds will likely be offset against unpaid amounts owed to the Company for its prior sales. The ultimate outcome of the total refunds within the above range related to energy sales in the West regions cannot be estimated. On November 20, 2001, the FERC instituted an investigation under Section 206 of the Federal Power Act regarding the tariffs of all sellers with market-based rates authority, including the Company. In this proceeding, the FERC proposes to condition the market-based rate authority of all sellers on their not engaging in anti-competitive behavior. Such condition would depend upon a further order from the FERC establishing a refund effective date. This condition would allow the FERC, if it determines that a seller has engaged in anti-competitive behavior subsequent to the start of the refund effective period, to order refunds back to the date of such behavior. The FERC invited comments regarding this proposal, and the Company has filed comments in opposition to the proposal. The timing of further action by the FERC is uncertain, although the FERC has publicly indicated that it is considering modifications that would limit the scope and application of its original proposal. If the FERC implements its 39 proposed approach for dealing with anti-competitive behavior without modification, the resulting refund obligation could affect the Company's future earnings. On February 13, 2002, the FERC issued an order initiating a staff investigation into potential manipulation of electric and natural gas prices in the West region for the period January 1, 2000 forward. On August 13, 2002, the FERC staff issued its Initial Report on Fact Finding Investigation of Potential Manipulation of Electric and Gas Prices (Initial Report), which is described above. See Note 12(a) - "Trading and Marketing Activities." Other Investigations. In addition to the FERC investigation discussed above, several state and other federal regulatory investigations and complaints have commenced in connection with the wholesale electricity prices in California and other neighboring Western states to determine the causes of the high prices and potentially to recommend remedial action. In California, the California State Senate and the California Office of the Attorney General have separate ongoing investigations into the high prices and their causes. Although these investigations have not been completed and no findings have been made in connection with either of them, the California Attorney General has filed a civil lawsuit in San Francisco Superior Court alleging that the Company has violated state laws against unfair and unlawful business practices and a complaint with the FERC alleging the Company violated the terms of its tariff with the FERC (see Note 12(a)). Adverse findings or rulings could result in punitive legislation, sanctions, fines or even criminal charges against the Company or its employees. The Company is cooperating with both investigations and has produced a substantial amount of information requested in subpoenas issued by each body. The Washington and Oregon attorneys general have also begun similar investigations. As the above-described investigation and complaints progress, additional issues may be identified that could expose the Company to further investigations and complaints. Their ultimate outcome cannot be predicted at this time. Legislative Efforts. Since the inception of the California energy crisis, various pieces of legislation, including tax proposals, have been introduced in the United States Congress and the California Legislature addressing several issues related to the increase in wholesale power prices in 2000 and 2001. For example, a bill was introduced in the California legislature that would have created a "windfall profits" tax on wholesale electricity sales and would subject exempt wholesale generators, such as the Company's subsidiaries that own generation facilities in California, to regulation by the CPUC as "public utilities." To date, only a few energy-related bills have passed, such as the recently enacted plant inspection law, which would empower the CPUC to monitor activities of the Company's generating plants. The Company believes this bill is vulnerable to challenge based on the preemptive effect of the Federal Power Act. The Company does not believe that this or other legislation that has been enacted to date will have a material adverse effect on the Company. However, it is possible that legislation could be enacted at either the state or federal level that could have a material adverse effect on the Company's financial condition, results of operations and cash flows. (d) Dutch Stranded Costs. Background. In January 2001, the Dutch Electricity Production Sector Transitional Arrangements Act (Transition Act) became effective. Among other things, the Transition Act allocated to REPGB and the three other large-scale Dutch generation companies, a share of the assets, liabilities and stranded cost commitments of NEA. Prior to the enactment of the Transition Act, NEA acted as the national electricity pooling and coordinating body for the generation output of REPGB and the three other large-scale national Dutch generation companies. REPGB and the three other large-scale Dutch generation companies are shareholders of NEA. The Transition Act and related agreements specify that REPGB has a 22.5% share of NEA's assets, liabilities and stranded cost commitments. NEA's stranded cost commitments consisted primarily of various uneconomical or stranded cost investments and commitments, including a gas supply contract, three power contracts entered into prior to the liberalization of the Dutch wholesale electricity market and a contract relating to the construction of an interconnection cable between Norway and the Netherlands subject to a long-term power exchange agreement (PEA) (the NorNed Project). REPGB's stranded cost obligations also include uneconomical district heating contracts which were previously administrated by NEA prior to deregulation of the Dutch power market. In January 2001, NEA assigned to REPGB a 22.5% interest in the stranded cost contracts, including the gas supply contract, which expires in 2016, and provides for gas imports aggregating 2.283 billion cubic meters per year. During December 2001, one of the stranded power contracts was settled. In May 2002, NEA amended the two remaining long-term power contracts in order to bring them to market-conforming terms and, in connection with these amendments, assigned the contracts to NEA's shareholders. The district heating obligations relate to three water heating supply contacts entered into with various municipalities expiring from 2008 through 2015. Under the 40 district heating contracts, the municipal districts are required to take annually a combined minimum of 5,549 terajoules (TJ) increasing annually to 7,955 TJ over the life of the contracts. The Transition Act provided that, subject to the approval of the European Commission, the Dutch government will provide financial compensation to the Dutch generation companies, including REPGB, for liabilities associated with long-term district heating contracts. In July 2001, the European Commission ruled that under certain conditions the Dutch government can provide financial compensation to the generation companies for the district heating contracts. To the extent that this compensation is not ultimately provided to the generation companies by the Dutch government, REPGB is entitled to claim compensation directly from the former shareholders of REPGB as further discussed below. Settlement of Stranded Cost Indemnification Agreement. Until December 2001, the former shareholders of REPGB were obligated to indemnify REPGB for up to Dutch Guilders (NLG) 1.9 billion of its share of NEA's stranded cost liabilities. In December 2001, REPGB and its former shareholders agreed to settle the indemnity obligations of the former shareholders in so far as they related to NEA's stranded cost gas supply and power contracts and other obligations (excluding district heating). Under the settlement agreement, the former shareholders of REPGB paid REPGB NLG 500 million ($202 million) in the first quarter of 2002. REPGB deposited the settlement payment into an escrow account, withdrawals from which are at the discretion of REPGB for use in discharging stranded cost obligations related to the gas and electric import contracts. As of September 30, 2002, the escrow funds equaled $62 million, of which $60 million and $2 million were recorded in restricted cash and long-term assets, respectively. Any remaining funds as of January 1, 2004 will be distributed to REPGB. Under the settlement agreement, the former shareholders continue to be under an obligation to indemnify REPGB for certain district heating contracts. Under the terms of the indemnity, REPGB can elect between two forms of indemnification within 21 days after the date that the Ministry of Economic Affairs of the Netherlands publishes regulations for compensation of stranded costs associated with district heating projects. If the compensation to be paid by the Netherlands under these rules is at least as much as the compensation to be paid under the original indemnification agreement, REPGB can elect to receive a one-time payment of NLG 60 million ($24 million). In addition, unless the decree implementing the new compensation rules provides for compensation for the lifetime of the district heating projects, REPGB can receive an additional cash payment of NLG 15 million ($6 million). If the compensation rules do not provide for compensation at least equal to that provided under the original indemnification agreement, REPGB can claim indemnification for stranded cost losses up to a maximum of NLG 700 million ($282 million) less the amount of compensation provided by the new compensation rules and certain proceeds received from arbitrations. If no new compensation rules have taken effect on or prior to December 31, 2003, REPGB is entitled, but not obligated, to elect to receive indemnification under the formula described above. As of November 8, 2002, the Ministry of Economic Affairs had not published its compensation rules. Based on current assumptions, it is not anticipated that such rules will be published until 2003. Prior to the settlement agreement, pursuant to the purchase agreement of REPGB, as amended, REPGB was entitled to a NLG 125 million (approximately $51 million) dividend from NEA with any remainder owing to the former shareholders. Under the settlement agreement, the former shareholders waived all rights to distributions of NEA. As a result of this settlement, the Company recognized in the fourth quarter of 2001 a net gain of $37 million for the difference between (a) the sum of the cash settlement payment of $202 million and the additional rights to claim distributions of the NEA investment recognized of $248 million and (b) the sum of the amount recorded as stranded cost indemnity receivable related to the stranded cost gas and electric commitments of $369 million and claims receivable related to stranded costs incurred in 2001 of $44 million, both previously recorded in the Company's Consolidated Balance Sheet. Amendments to Stranded Cost Electricity Import Contracts. In May 2002, NEA and its four shareholders (including REPGB) entered into agreements amending the terms of the two remaining power supply agreements (Settlement Agreements). These two contracts provide for the following capacities and terms: (a) 300 MW through 2003, and (b) 600 MW through March 2002, increasing to 750 MW through March 2009. Under the terms of the Settlement Agreements, NEA paid the counterparties a net aggregate payment of Euro 485 million, approximately $446 million (the Settlement Payment) (of which REPGB's proportionate share as a 41 NEA shareholder was Euro 109 million, approximately $100 million). In July 2002, REPGB paid its share of the Settlement Payment with funds from the stranded cost indemnity escrow account, as discussed above. In exchange for its portion of the Settlement Payment, the counterparties to the power contracts replaced the existing terms with a market-based electricity price index for comparable electricity products in addition to other changes. As a result of the Settlement Agreements, in the second quarter of 2002, the Company recognized a pre-tax net gain of $109 million for the difference between (a) the fair values of the original power contracts ($203 million net liability previously recorded in non-trading derivative liabilities) and the fair values of the amended power contracts ($6 million net asset recorded in trading and marketing assets) and (b) the Settlement Payment of $100 million, as described above. The pre-tax net gain of $109 million was recorded as a reduction of purchased power expense in the Statement of Consolidated Income in the second quarter of 2002. In the future, these two power trading contracts will be marked-to-market as a part of the Company's energy trading activities. Separately, in May 2002, following the execution of the Settlement Agreements, NEA declared a Euro 625 million, approximately $616 million, cash distribution to its shareholders, which was paid on July 1, 2002. REPGB's share of the distribution was Euros 141 million, approximately $137 million. Remaining Liability for Original Stranded Costs. In January 2001, the Company recognized an out-of-market, net stranded cost liability for its gas and electric import contracts and district heating commitments. At such time, the Company recorded a corresponding asset of equal amount for the indemnification of this obligation from REPGB's former shareholders and the Dutch government, as applicable. As of December 31, 2001, the Company has recorded a liability of $369 million for its stranded cost gas and electric commitments in non-trading derivative liabilities and a liability of $206 million for its district heating commitments in current and non-current other liabilities. As of September 30, 2002, the Company has recorded a liability of $141 million for its stranded cost gas contract in non-trading derivative liabilities, an asset of $9 million for its amended power contracts in trading and marketing assets, and a liability of $229 million for its district heating commitments in current and non-current other liabilities. As of December 31, 2001 and September 30, 2002, the Company has recorded an indemnification receivable for the district heating stranded cost liability of $206 million and $229 million, respectively. Pursuant to SFAS No. 133, the Company marks-to-market the stranded cost gas contract (see Note 4). Prior to the amendments to the remaining power contacts, pursuant to SFAS No. 133, the power contracts were marked-to-market. Subsequent to amending the remaining power contracts, the power contracts are marked-to-market as a part of the Company's energy trading activities. Pursuant to SFAS No. 133, during the nine months ended September 30, 2002, the Company recognized a $16 million gain recorded in fuel expense related to changes in the valuation of the stranded cost contracts, excluding the effects of the gain related to amending the two power contracts discussed above and net of derivative transactions entered into to economically hedge the stranded cost gas contract. NorNed Project. NEA entered into commitments with certain Norwegian counterparties (the Norwegian Counterparties) for the construction of a grid interconnector cable between the Netherlands and Norway, subject to the operation of a bi-directional, long-term (25 years in duration) PEA. The PEA contemplates, among other terms, exclusive use and cost free access to the cable by NEA and the Norwegian counterparties. The PEA is subject to, among other things, clearance by the European Commission and the Dutch regulatory authorities of the terms and conditions of the PEA. In 2001, NEA and the Norwegian counterparties filed a notification request regarding the PEA with the European Commission. It is not expected that the European Commission will respond to the notification request until the third quarter of 2003. Under the Transition Act, NEA is entitled to recover the cable construction costs from TenneT, the Netherlands grid operator. However, at this early stage it is not entirely clear how NEA will receive the transport tariff funds intended to recover the construction costs of the cable, and whether the ultimate transport tariff rate approved by the Dutch power regulation (Dte) will be sufficient to cover the ultimate construction costs. However, assuming that the Transition Act is fully implemented with respect to this matter, REPGB believes that NEA will ultimately recover the cost of the cable. For additional information regarding the indemnification and settlement of stranded costs, see Note 13(f) to the Reliant Resources 10-K/A Notes. Investment in NEA. During the second quarter of 2001, the Company recorded a $51 million pre-tax gain (NLG 125 million) recorded as equity income for the preacquisition gain contingency related to the acquisition of REPGB for the value of its equity investment in NEA. This gain was based on the Company's evaluation of NEA's financial position and fair value. The fair value of the Company's investment in NEA is dependent upon the ultimate resolution of its existing contingencies and proceeds received from liquidating its remaining net assets. 42 (e) Payment to CenterPoint Energy in 2004. The Company may be required to make a payment to CenterPoint Energy in early 2004, to the extent the Company's affiliated retail electric provider's price to beat for providing retail electric service to residential and small commercial customers in CenterPoint Energy's Houston service territory during 2002 and 2003 exceeds the market price of electricity. This payment is required by the Texas electric restructuring law unless the Texas Utility Commission determines that, on or prior to January 1, 2004, 40% or more of the amount of electric power that was consumed in 2000 by residential or small commercial customers, as applicable, within CenterPoint Energy's Houston service territory is committed to be served by retail electric providers other than the Company. This amount will not exceed $150 per customer, multiplied by the number of residential or small commercial customers, as the case may be, that the Company serves on January 1, 2004 in CenterPoint Energy's Houston service territory, less the number of residential or small commercial electric customers, as the case may be, the Company serves in other areas of Texas. As of September 30, 2002, the Company had approximately 1.7 million residential and small commercial customers in CenterPoint Energy's Houston service area. In the Master Separation Agreement between the Company and Reliant Energy, the Company has agreed to make this payment, if any, to CenterPoint Energy. Currently, the Company believes it is probable that it will be required to make such payment to CenterPoint Energy related to its residential customers. As of September 30, 2002, the Company believes that the payment related to its residential customers will be in the range of $155 million to $185 million (pre-tax), with a most probable estimate of $170 million. The Company will recognize the total obligation over the period it recognizes the related revenues based on the difference between amount of the price to beat and the estimated market price of electricity multiplied by the estimated energy sold through January 1, 2004 not to exceed the maximum cap of $150 per customer. During the third quarter of 2002, the Company recognized $89 million (pre-tax) of which $27 million was associated with the revenues for the first half of 2002. The remainder of the Company's estimated obligation will be recognized during the fourth quarter of 2002 and during 2003. In the future, the Company will revise its estimates of this payment as additional information about market price of electricity and the market share that will be served by the Company and other retail electric providers on January 1, 2004 becomes available and the Company will adjust the related accrual at that time. Currently, the Company believes that the 40% test for small commercial customers will be met and the Company will not make a payment related to those customers. If the 40% test is not met related to its small commercial customers and a payment is required, the Company estimates this payment would be approximately $30 million. (f) Construction Agency Agreements and Equipment Financing Structure. In 2001, the Company, through several of its subsidiaries, entered into operative documents with special purpose entities to facilitate the development, construction, financing and leasing of several power generation projects. The special purpose entities are not consolidated by the Company. As a result of the decision to cancel one of the projects, the commitments were reallocated in June 2002 so that the special purpose entities now have an aggregate financing commitment from equity and debt participants (Investors) for three electric generating facilities of $1.9 billion of which the last $515 million is currently available only if cash collaterized. The availability of the commitment is subject to satisfaction of various conditions, including the obligation to provide cash collateral for the loans and letters of credit outstanding on November 29, 2004. The Company, through several of its subsidiaries, acts as construction agent for the special purpose entities and is responsible for completing construction of these projects by December 31, 2004. However, the Company has generally limited its risk during construction to an amount not to exceed 89.9% of costs incurred to date, except in certain events. Upon completion of an individual project and exercise of the lease option, the Company's subsidiaries will be required to make lease payments in an amount sufficient to provide a return to the Investors. If the Company does not exercise its option to lease any project upon its completion, the Company must purchase the project or remarket the project on behalf of the special purpose entities. The Company's ability to exercise the lease option is subject to certain conditions. The Company must guarantee that the Investors will receive an amount at least equal to 89.9% of their investment in the case of a remarketing sale at the end of construction. At the end of an individual project's initial operating lease term (approximately five years from construction completion), the Company's subsidiary lessees have the option to extend the lease with the approval of the Investors, purchase the project at a fixed amount equal to the original construction cost, or act as a remarketing agent and sell the project to an independent third party. If the lessees elect the remarketing option, they may be required to make a payment of an amount not to exceed 85% of the project cost, if the proceeds from remarketing are not sufficient to repay the Investors. The Company has guaranteed the performance and payment of its subsidiaries' obligations during the construction periods and, if the lease option is exercised, each lessee's obligations during the lease period. At any time during the construction period or during the 43 lease, the Company may purchase a facility by paying an amount approximately equal to the outstanding balance plus costs or the Company may purchase the facility by assuming, directly or indirectly, the obligations of the subsidiaries, in which case the guarantee must remain in place and lender consent may be required. Given general market conditions and the uncertainty surrounding accounting changes in regard to special purpose entities, the Company is considering all options, including the purchase option. As of September 30, 2002, the special purpose entities had cash of $45 million, property, plant and equipment of $1.2 billion, net other liabilities of $13 million and debt obligations of $1.1 billion. As of September 30, 2002, the special purpose entities had equity from unaffiliated third parties of $45 million. Based on current projections regarding the rate of expenditures for the three electric generating facilities, it appears likely that the full amount of non-cash collateralized commitments will have been utilized by the end of the first quarter of 2003. In order to complete the generating facilities on an uninterrupted basis, the Company is considering the following alternatives to fund the remaining $400 million obligation: (a) seek from the lenders an increase in the non-cash collateralized portion of the $1.9 billion facility; (b) invest unrestricted corporate cash into the structure with the existing Investors, or (c) exercise its purchase option and assume the debt and fund the remaining amount with cash on hand. If the Company does either of the latter two options, the Company believes that the special purpose entities will be required to be consolidated by the Company based on guidance in EITF No. 97-10, "The Effect of Lessee Involvement in Asset Construction." The Company, through its subsidiary, REPG, had entered into an agreement with a bank whereby the bank, as owner, entered into contracts for the purchase and construction of power generation equipment and REPG, or its subagent, acted as the bank's agent in connection with administering the contracts for such equipment. The agreement expired in September 2002. REPG, or its designee, had the option at any time to purchase, or, at equipment completion, subject to certain conditions, including the agreement of the bank to extend financing, to lease the equipment, or to assist in the remarketing of the equipment under terms specified in the agreement. REPG and its subagents had to cash collateralize their obligation to administer the contracts. This cash collateral was approximately equivalent to the total payments by the bank for the equipment, interest and other fees. The cash collateral was deposited by REPG or the subagent into a collateral account with the bank and earned interest at LIBOR less 0.15%. Under certain circumstances, the collateral deposit or a portion of it, would be returned to REPG or its designee. Immediately prior to the expiration of the agreement in September 2002, REPG was assigned and exercised purchase options for contracts for steam and combustion turbines and two heat recovery steam generators with an aggregate cost of $121 million under which payments and interest during construction totaling $94 million had been made. REPG used $94 million of its collateral deposits to complete the purchase. In May 2002, REPG was assigned and exercised a purchase option for a contract for an air-cooled condenser totaling $20 million under which payments and interest during construction totaling $8 million had been made. REPG used $8 million of its collateral deposits to complete the purchase. After the purchase, REPG canceled the contract and paid a cancellation payment of $1.7 million to the manufacturer. In January 2002, the bank sold to the parties to the construction agency agreements discussed above, equipment contracts with a total contractual obligation of $258 million, under which payments and interest during construction totaled $142 million. Accordingly, $142 million of collateral deposits were returned to the Company. At December 31, 2001, REPG and/or its subagent had deposits of $230 million in the collateral account. Pursuant to SFAS No. 144, the Company evaluated for impairment the steam and combustion turbines and two heat recovery steam generators purchased in September 2002 for a total of $94 million. Based on the Company's analysis, the Company determined this equipment was impaired and accordingly recognized a $37 million pre-tax impairment loss which is recorded as depreciation expense for the three and nine months ended September 30, 2002 in the Company's Statement of Consolidated Income. The fair value of the equipment and thus the impairments was determined using a combination of quoted market prices and prices for similar assets. 44 (g) REMA Sale/Leaseback Transactions. In August 2000, the Company entered into separate sale/leaseback transactions with each of the three owner-lessors for the Company's respective 16.45%, 16.67% and 100% interests in the Conemaugh, Keystone and Shawville generating stations, respectively, acquired in the REMA acquisition. The lease documents contain some restrictive covenants that restrict REMA's ability to, among other things, make dividend distributions unless REMA satisfies various conditions. As of September 30, 2002, these various conditions were satisfied by REMA. As of December 31, 2001, REMA had $167 million of restricted funds that were available for REMA's working capital needs and to make future lease payments. For additional discussion of these lease transactions, please read Notes 5(a) and 13(c) to the Reliant Resources 10-K/A Notes. (h) Reliant Energy Desert Basin Contingency. Reliant Energy Desert Basin (REDB), an indirect wholly owned subsidiary of Reliant Resources, sells power to Salt River Project (SRP) under a long-term power purchase agreement. Certain of REDB's obligations under the power purchase agreement are guaranteed by Reliant Resources. In the event Reliant Resources is downgraded to below investment grade by two major ratings agencies, SRP can request performance assurance in the form of cash or a letter of credit from REDB under the power purchase agreement and from Reliant Resources under the guaranty. Under the power purchase agreement and guaranty, the total amount of performance assurance cannot exceed $150 million. Under the terms of the power purchase agreement, REDB is required to provide performance assurance within 30 days of the receipt of a demand from SRP. Failure by REDB to provide performance assurance within the 30-day period constitutes a breach of the power purchase agreement. The guaranty requires Reliant Resources to provide performance assurance within 3 business days of receipt of a notice from SRP indicating that REDB has failed to comply with its obligations under the power purchase agreement to provide performance assurance. If Reliant Resources fails to comply with this obligation, SRP may sue for damages. The power purchase agreement allows REDB 30 days from the date of receipt of notice of a breach to cure. If REDB fails to cure the breach within 30 days of receipt of notice, an event of default has occurred. Upon the occurrence of an event of default, SRP has certain rights that include termination of the power purchase agreement and the right to sue for damages. On September 16, 2002, following the downgrade of Reliant Resources to below investment grade by Standard & Poor's and Moody's, SRP requested performance assurance from Reliant Resources and REDB under the guaranty and the power purchase agreement, respectively, in the total amount of $150 million. Reliant Resources and REDB replied to SRP's request on October 15, 2002, noting that the power purchase agreement does not specify the amount of performance assurance due in the event of a credit downgrade and demonstrating that under prevailing market conditions and other factors, a letter of credit in the amount of $3 million would provide commercially reasonable assurance of REDB's ability to perform its obligations under the power purchase agreement. Reliant Resources provided SRP with a $3 million letter of credit. SRP notified Reliant Resources that it deemed the amount inadequate and returned the letter of credit to Reliant Resources. On October 18, 2002, SRP sent a letter to Reliant Resources alleging that Reliant Resources had breached its duty to provide performance assurance by failing to provide the requested $150 million letter of credit. Reliant Resources and REDB maintain that provision of a $3 million letter of credit fulfills their responsibilities under the power purchase agreement to provide performance assurance and that SRP would be in breach of the power purchase agreement, and therefore liable to REDB for damages, if it were to terminate the power purchase agreement based on the failure of Reliant Resources and REDB to provide performance assurance in the amount of $150 million. (i) Tolling Agreement for Liberty Electric Generating Station. The output of the Liberty Electric Generating Station (the Liberty Station) is contracted under a tolling agreement between LEP and PG&E Energy Trading-Power, L.P. (PGET) for a term of approximately 14 years, with an option to extend at the end of the term (the Tolling Agreement). Under the Tolling Agreement, PGET has the exclusive right to receive all energy, capacity and ancillary services produced by Liberty Station. PGET must pay for, and is responsible for, all fuel used by Liberty Station. Standard & Poor's and Moody's have downgraded to sub-investment grade the senior unsecured debt of PG&E National Energy Group, Inc. (NEG), one of the two guarantors of PGET's obligations under the Tolling Agreement. Because PGET did not post replacement security within the period required by the Tolling Agreement, the downgrade constitutes an event of default by PGET under the Tolling Agreement. While LEP could terminate the 45 Tolling Agreement pursuant to the terms of the Tolling Agreement as a result of said failure, there are certain limitations under the Liberty Credit Agreements on LEP's ability to take unilateral action in response to a PGET event of default. Additionally, on October 11, 2002, Standard & Poor's downgraded to sub-investment grade the senior unsecured debt of PG&E Gas Transmission, Northwest Corp. (GTN) the other guarantor of PGET's obligations under the Tolling Agreement. On October 16, 2002, Moody's also downgraded GTN's senior unsecured debt to sub-investment grade. In addition, on August 19, 2002, and September 10, 2002, PGET notified LEP that it believed LEP had violated the Tolling Agreement by not following PGET's instructions relating to the dispatch of the Liberty Station during specified periods. The September 10, 2002 letter also claims that LEP did not timely provide PGET with certain information to make a necessary FERC filing. While LEP does not agree with PGET's interpretation of the Tolling Agreement regarding the dispatch issue, LEP agreed to (a) compensate PGET approximately $17,000 for the alleged damages attributable to the claims raised in the August 19, 2002 letter and (b) treat several hours of plant outages as forced outages for purposes of the Tolling Agreement, thereby resolving the issues raised in the August 19 letter (which compensation and treatment are not believed to be material). The Tolling Agreement generally provides that covenant-related defaults must be cured within 30 business days or they will (if material) result in an event of default, entitling the non-defaulting party to terminate. PGET has extended this cure period (relating to the September 10, 2002 letter) to November 30, 2002. While there can be no assurances as to the outcome of this matter, LEP believes that it will be able to resolve the issues raised in the September 10, 2002 letter without causing an event of default under the Tolling Agreement. However, if LEP is unable to resolve said issues and PGET declares an event of default, then PGET would be in a position to terminate the Tolling Agreement. In addition to the material adverse effect such a termination would have on Liberty as discussed below, such a termination may also result in PGET drawing on the $35 million letter of credit posted on behalf of LEP under the Tolling Agreement. Under the Tolling Agreement, a non-defaulting party who terminates the Tolling Agreement is entitled to calculate its damages in accordance with specified criteria set forth therein; the non-defaulting party is the only party entitled to damages. The defaulting party would be entitled to refer such damage calculation to arbitration. The institution of any arbitration could delay the receipt of such damages for an extended period of time. In addition, if PGET is the defaulting party, the payment of said damages could be further delayed if PGET and one or more of GTN and NEG seeks protection from creditors under the bankruptcy laws. Such filings also may result in LEP receiving significantly less in damages than it might otherwise be entitled. LEP and PGET are engaged in discussions seeking to resolve the disputes and claims of both LEP and PGET under the Tolling Agreement. There is no guarantee that these discussions will be successful. Any resolution would require the approval of the parties providing the financing under the Liberty Credit Agreements. In addition, any such settlement may have a material adverse effect on LEP and Liberty. It should be noted that the termination of the Tolling Agreement for any reason most likely would have a material adverse effect on Liberty and LEP. LEP currently receives a fixed monthly payment from PGET under the Tolling Agreement. If the Tolling Agreement is terminated, then LEP would be required to either find a power purchaser or tolling customer to replace PGET or, if that effort is unsuccessful, to sell the energy and/or capacity into the merchant energy market without any assurance, in either of the foregoing cases, that LEP would be able to earn enough revenues to pay all of its expenses or to enable Liberty to make interest and scheduled principal payments under the Liberty Credit Agreements as they become due. If the Tolling Agreement is terminated, the gas transportation agreement that PGET utilizes in connection with the Tolling Agreement will revert to LEP and LEP will be required to perform the obligations currently being performed by PGET under said agreement. The termination of the Tolling Agreement may cause both Liberty and LEP to seek other alternatives, including reorganization under the bankruptcy laws. Orion Power would not be required to reorganize under the bankruptcy laws due solely to Liberty or LEP seeking to reorganize. As noted above, the Liberty Credit Agreements restrict the ability of LEP to terminate the Tolling Agreement. There is also a requirement in the Liberty Credit Agreements that Liberty, the borrower under the Liberty Credit Agreements, and LEP enforce all of their respective rights under the Tolling Agreement. Liberty and LEP have received waivers from the lenders under the Liberty Credit Agreements from the requirement that they enforce all of their respective rights under the Tolling Agreement. These waivers extend through and expire on December 8, 2002. (j) Long-Term Maintenance Agreements. 46 Several of the wholly-owned subsidiaries of the Company have entered into long-term maintenance agreements that cover certain periodic maintenance, including parts, on their respective turbines. The long-term maintenance agreements terminate over the next twelve to eighteen years based on turbine usage. As of September 30, 2002, no payments have been made under the long-term maintenance agreements. Estimated cash payments over the remainder of 2002 and the five succeeding fiscal years estimated are as follows (in millions): 2002.......................... $ 5 2003.......................... 52 2004.......................... 30 2005.......................... 31 2006.......................... 31 2007.......................... 33 ------ Total....................... $ 182 ====== (13) BENEFIT CURTAILMENT, ENHANCEMENT CHARGE AND ACCOUNTING SETTLEMENT During the three months ended March 31, 2001, the Company recognized a pre-tax, non-cash charge of $100 million relating to the redesign of some of Reliant Energy's benefit plans in anticipation of Reliant Resources' separation from CenterPoint Energy. During the three months ended September 30, 2002, the Company recognized a net pre-tax, non-cash charge of $47 million relating to the settlement of some of the Company's benefit plan obligations as further described below. Effective March 1, 2001, the Company no longer accrues benefits under a noncontributory pension plan for its domestic non-union employees (Resources Participants). Effective March 1, 2001, each non-union Resources Participant's unvested pension account balance became fully vested and a one-time benefit enhancement was provided to some qualifying participants. During the first quarter of 2001, the Company incurred a charge to earnings of $83 million (pre-tax) for a one-time benefit enhancement and a gain of $23 million (pre-tax) related to the curtailment of Reliant Energy's pension plan. In connection with the Distribution, the Company incurred a loss of $65 million (pre-tax) related to the settlement of the pension obligation. In connection with recording the accounting settlement, CenterPoint Energy contributed certain benefit plan deferred losses, net of taxes, totaling $18 million that were deemed to be associated with the Company's benefit obligation. Upon the Distribution, the Company effectively transferred to CenterPoint Energy its pension obligation. After the Distribution, each Resources Participant may elect to have his accrued benefit (a) left in the CenterPoint Energy pension plan for which CenterPoint Energy is the plan sponsor, (b) rolled over to a new Company savings plan or an individual IRA account, or (c) paid in a lump-sum or annuity distribution. Effective March 1, 2001, the Company discontinued providing subsidized postretirement benefits to its domestic non-union employees. The Company incurred a pre-tax charge of $40 million during the first quarter of 2001 related to the curtailment of the Company's postretirement obligation. In connection with the Distribution, the Company incurred a pre-tax gain of $18 million related to the accounting settlement of postretirement benefit obligations. For additional information regarding these benefit plans, see Notes 11(b) and 11(d) to the Reliant Resources 10-K/A Notes. 47 (14) PRICE TO BEAT FUEL FACTOR ADJUSTMENT The Texas Utility Commission regulations allow the Company to request an adjustment to the fuel factor in its price to beat up to twice a year for its Houston area residential and small commercial customers based on the percentage change in the price of natural gas, or increases in the price of purchased energy. The Company's price to beat fuel factor was initially set by the Texas Utility Commission in December 2001 based on an average forward 12-month natural gas price of $3.11/mmbtu. On May 2, 2002, the Company filed a request with the Texas Utility Commission to increase the price to beat fuel factor based on a 20% increase in the price of natural gas. The Company's requested increase was based on an average forward 12-month natural gas price of $3.73/mmbtu. The requested increase represents a 5.9% increase in the total bill of a residential customer using, on average, 1,000 kWh per month. On June 6, 2002 the administrative law judge recommended to the Texas Utility Commission approval of a 19.9% increase to the price to beat fuel factor based on application of the Texas Utility Commission's price to beat rule. On July 15, 2002, the Texas Utility Commission issued an order delaying the Company's request as well as the request of each of the other four affiliated retail electric providers requesting adjustments to the price to beat fuel factors and remanded the cases to the administrative law judges requesting additional information in order to validate the Texas Utility Commission's rule. On July 24, 2002, the Company filed a request in the Travis County District Court that the Court declare that the Texas Utility Commission must apply its current rules to the Company's request and grant the fuel factor adjustment in accordance with the formula in the rule that the Texas Utility Commission had already approved. The other four affiliated retail electric providers filed similar requests with the Travis County District Court. The Court issued an order on August 9, 2002 agreeing with the Company that the Texas Utility Commission must follow the existing rules that govern the adjustment of the price to beat fuel factor. On August 26, 2002, the Texas Utility Commission approved the administrative law judge's recommendation for an increase in the price to beat fuel factor. Certain consumer groups moved for rehearing of the Texas Utility Commission's August 26, 2002 Order granting the Company's requested price to beat fuel factor adjustment. On September 26, 2002, the Texas Utility Commission denied all motions for rehearing and the consumer groups have appealed the Texas Utility Commission's August 26, 2002 Order to the Travis County District Court. On August 26, 2002, the Texas Utility Commission initiated a rulemaking to determine whether the price to beat rule should be amended. A preliminary workshop was held on October 8, 2002 to address certain questions related to the current rule. Among other issues, the workshop discussion focused on the timing of price to beat fuel factor adjustment requests, the timeline for processing requests, the use of a 10-day average of gas prices to determine if an adjustment is necessary, appropriateness of an electricity index and whether an adjustment based on gas price increases should be applied to only the gas portion of the fuel factor. On November 7, 2002, the Texas Utility Commission approved for publication a revised price to beat rule. The proposed changes from the current rule relate to (a) the number of days used to calculate the natural gas price average, (b) the threshold of what constitutes a significant change in the market price of natural gas and purchased energy, (c) processing of documents, (d) encouraging the development of liquid trading hubs in Texas and (e) additional specificity as to what adjustments to the price to beat will be considered following the true-up proceedings. After interested parties file comments and reply comments, a public hearing on the proposed revisions will be held on January 7, 2003. Texas Utility Commission issued a rule for comment. The Company cannot predict what revisions, if any, the Texas Utility Commission will make to the price to beat rule or the effect that this rulemaking will have on the its business and results of operations. (15) REPORTABLE SEGMENTS The Company has the following reportable segments: Wholesale Energy, European Energy, Retail Energy and Other Operations. For descriptions of these financial reporting segments, see Note 1 to the Reliant Resources 10-K/A Notes. There were no material inter-segment revenues during the three and nine months ended September 30, 2001 and 2002. Beginning in the first quarter of 2002, the Company began to evaluate segment performance on earnings (loss) before interest expense, interest income and income taxes (EBIT). Prior to 2002, the Company evaluated performance on operating income. EBIT is not defined under accounting principles generally accepted in the United States (GAAP), and should not be considered in isolation or as a substitute for a measure of performance prepared in accordance with GAAP and is not indicative of operating income from operations as determined under GAAP. 48 Financial data for business segments are as follows: FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2001 ---------------------------------------------------- REVENUES FROM OPERATING INCOME NON-AFFILIATES (LOSS) EBIT -------------- ------ ---- (IN MILLIONS) Wholesale Energy $2,344 $ 473 $ 475 European Energy 145 (5) (4) Retail Energy .. 43 (7) (8) Other Operations 3 (36) (32) ------ ----- ----- Consolidated ... $2,535 $ 425 $ 431 ====== ===== ===== FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2002 ---------------------------------------------------- REVENUES FROM OPERATING INCOME NON-AFFILIATES (LOSS) EBIT -------------- ------ ---- (IN MILLIONS) Wholesale Energy $3,502 $ 100 $ 108 European Energy 148 (16) (13) Retail Energy .. 1,694 237 235 Other Operations -- (50) (50) ----- ----- Consolidated ... $5,344 $ 271 $ 280 ====== ===== ===== Reconciliation of Operating Income to EBIT and EBIT to Net Income: FOR THE THREE MONTHS ENDED SEPTEMBER 30, ----------------------- 2001 2002 ----- ----- (IN MILLIONS) Operating income ............................ $ 425 $ 271 Gains (losses) from investments, net ........ 4 (2) Income of equity investment of unconsolidated subsidiaries .............................. 2 1 Other income, net ........................... -- 10 ----- EBIT ........................................ 431 280 Interest expense ............................ (8) (103) Interest income ............................. 3 11 Interest income - affiliated companies ...... 11 1 ----- ----- Income before income taxes .................. 437 189 Income tax expense .......................... 175 138 ----- ----- Net income .................................. $ 262 $ 51 ===== ===== FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2001 AS OF ----------------------------------------------- DECEMBER 31, 2001 OPERATING ----------------- REVENUES INCOME (LOSS) EBIT TOTAL ASSETS -------- ------------- ---- ----------------- (IN MILLIONS) Wholesale Energy ...... $5,111 $ 950 $ 967 $ 8,290 European Energy ....... 478 23 80 3,380 Retail Energy ......... 107 (13) (13) 391 Other Operations ...... 8 (163) (148) 599 Reconciling Elimination -- -- -- (368) ------ ----- ----- -------- Consolidated .......... $5,704 $ 797 $ 886 $ 12,292 ====== ===== ===== ======== 49 FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2002 AS OF ------------------------------------------------- SEPTEMBER 30, 2002 REVENUES FROM OPERATING ------------------- NON-AFFILIATES INCOME (LOSS) EBIT TOTAL ASSETS -------------- ------------- ---- ------------------- (IN MILLIONS) Wholesale Energy ...... $5,668 $ 225 $ 248 $ 14,057 European Energy ....... 457 103 110 3,172 Retail Energy ......... 3,368 491 489 1,494 Other Operations ...... 2 (54) (55) 1,355 Reconciling Elimination -- -- -- (399) ------ ----- ----- -------- Consolidated .......... $9,495 $ 765 $ 792 $ 19,679 ====== ===== ===== ======== Reconciliation of Operating Income to EBIT and EBIT to Net Income: FOR THE NINE MONTHS ENDED SEPTEMBER 30, --------------------------------------- 2001 2002 ----- ----- (IN MILLIONS) Operating income ..................................................... $ 797 $ 765 Gains from investments, net .......................................... 15 3 Income of equity investment of unconsolidated subsidiaries ........... 67 10 Other income, net .................................................... 7 14 ----- ----- EBIT ................................................................. 886 792 Interest expense ..................................................... (52) (209) Interest income ...................................................... 18 19 Interest income - affiliated companies ............................... 8 5 ----- ----- Income before income taxes and cumulative effect of accounting changes 860 607 Income tax expense ................................................... 314 284 Cumulative effect of accounting changes .............................. 3 (234) ----- ----- Net income ........................................................... $ 549 $ 89 ===== ===== (16) SUBSEQUENT EVENTS (a) Default Under the Receivable Facility. On October 21, 2002, the Company notified a financial institution under the Receivables Facility of a violation of a certain compliance ratio test that is considered an amortization event whereby the financial institution has the right to liquidate the receivables it owns to collect the total amount outstanding under the terms of the Receivable Facility. The past due ratio (billed receivables over 90 days past due divided by total billed receivables) has increased in excess of the 5% compliance limit due to a regulatory change. The Company has received a waiver from the financial institution. (b) Orion Power's Subsidiaries Amended and Restated Credit Facilities. During October 2002, the Company restructured the Orion Power revolving senior credit facility, the Orion MidWest credit facility and the Orion NY credit facility. As part of this restructuring, the Orion Power revolving credit facility was terminated, and the Orion MidWest and Orion NY credit facilities were extended until October 2005. The amended and restated Orion MidWest credit facility includes an acquisition term loan of approximately $974 million, and a $75 million revolving working capital facility. The amended and restated Orion NY credit facility includes an acquisition term loan of approximately $353 million, and a $30 million revolving working capital facility. The loans under each facility bear interest at LIBOR plus a margin or at a base rate plus a margin. The LIBOR margin is 2.50% during the first twelve months, 2.75% during the next six months, 3.25% for the next six months, and 3.75% thereafter. The base rate margin is 1.50% during the first twelve months, 1.75% for the next six months, 2.25% for the next six months and 2.75% thereafter. The amended and restated Orion NY credit facility is secured by a first lien on substantially all of the assets of Orion NY and its subsidiaries (excluding certain plant assets) and a second lien on substantially all of the assets of Orion MidWest and its subsidiary; the amended and restated Orion MidWest credit facility is, in turn, secured by a first lien on substantially all of the assets of Orion MidWest and its subsidiary and a second lien on substantially all of the assets of Orion NY and its subsidiaries (excluding certain plant assets). Both the Orion MidWest and Orion NY credit facilities contain certain covenants and negative pledges that must be met by each borrower under its respective facility to borrow funds or obtain letters of credit, and which require Orion MidWest and Orion NY to maintain a combined debt service coverage ratio of 50 1.5 to 1.0. These covenants are not anticipated to materially restrict either borrower's ability to borrow funds or obtain letters of credit under its respective credit facility. These covenants do, however, increase the loan compliance burden on the Company and increase the risk of default under the respective credit facilities. The restructured facilities also provide for any available cash under one facility to be made available to the other borrower to meet shortfalls in the other borrower's ability to make certain payments, including operating costs. Although cash sufficient to make the November and December 2002 payments on Orion Power's 12% senior notes and 4.5% convertible senior notes was provided in connection with the restructuring, the ability of the borrowers to make subsequent dividends to Orion Power for such interest payments or otherwise is subject to certain requirements that are likely to restrict such dividends. (c) Price to Beat Fuel Factor Adjustment. On November 13, 2002, the Company filed a request with the Texas Utility Commission to increase the price to beat fuel factor for residential and small commercial customers based on a 7.7% increase in the price of natural gas from its previous request in May 2002. The Company's requested increase was based on a 10 trading day, average forward 12-month natural gas price of $4.02/mmbtu. The requested increase represents a 2.6% increase in the total bill of a residential customer using, on average, 1,000 kWh per month. If no hearing is requested, the earliest the new price to beat could go into effect would be December 3, 2002. For additional information regarding the current price to beat fuel factor, see Note 14. (d) Liquidation of Interest Rate Swaps In November, 2002, the Company liquidated $500 million of the forward-starting interest rate swaps that were entered into in January 2002. The liquidation of these hedges resulted in a loss of $52 million, which was recorded in other comprehensive income and will be amortized into interest expense in the same period during which the forecasted interest payment affects earnings. Should the forecasted interest payment be no longer probable, any remaining deferred amount will be recognized immediately as an expense. 51 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS EFFECTS OF RESTATEMENT ON THE INTERIM FINANCIAL STATEMENTS Restatement. Subsequent to the issuance of our financial statements for 2001, we identified four natural gas financial swap transactions that should not have been recorded in our records. We have concluded, based on the offsetting nature of the transactions and manner in which the transactions were documented, that none of the transactions should have been given accounting recognition. We previously accounted for these transactions in our financial statements as a reduction in revenues in December 2000 and an increase in revenues in January 2001, with the effect of decreasing net income in the fourth quarter of 2000 and increasing net income in the first quarter of 2001, in each case by $20.0 million pre-tax ($12.7 million after-tax) and the effect of increasing basic and diluted earnings per share by $0.05 in the first quarter of 2001. There were no cash flows associated with the transactions. Also, subsequent to the issuance of our financial statements for 2001 and for the first three quarters of 2002, we determined that we incorrectly calculated the amount of hedge ineffectiveness for 2001 and the first three quarters of 2002 for hedging instruments entered into prior to the adoption of Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended (SFAS No. 133). These hedging instruments included long-term forward contracts for the sale of power in the California market through December 2006. The amount of hedge ineffectiveness for these forward contracts was calculated using the trade date. However, the proper date for the hedge ineffectiveness calculation is hedge inception, which for these contracts was deemed to be January 1, 2001, concurrent with the adoption of SFAS No. 133. In addition, we did not record the amount of ineffectiveness for any hedging instruments during the first three quarters of 2001. These errors in accounting for hedge ineffectiveness resulted in an understatement of revenues of $57.3 million ($37.1 million after-tax) and earnings per share of $0.14 in the first nine months of 2001. These errors in accounting for hedge ineffectiveness resulted in an overstatement of revenues of $16.5 million ($10.7 million after-tax) and earnings per share of $0.04 in the first nine months of 2002. As more fully described in Note 1 to the interim financial statements, the statements of consolidated operations for the three and nine months ended September 30, 2001 and 2002 have been restated from amounts previously reported to remove the effects of the four natural gas swap transactions from the first quarter of 2001 and to correctly account for the amount of hedge ineffectiveness in the first three quarters of 2001 and 2002. The restatement had no impact on previously reported consolidated operating, investing and financing cash flows for the first three quarters of 2001 or 2002. A summary of the principal effects of the restatement for the quarters ended March 31, 2001 and 2002, June 30, 2001 and 2002, and September 30, 2001 and 2002 are set forth in Note 1 to our consolidated financial statements. The following discussion and analysis has been modified for the restatement. OVERVIEW The following discussion and analysis should be read in combination with our Interim Financial Statements contained in this Form 10-Q/A. We provide electricity and energy services with a focus on the competitive wholesale and retail segments of the electric power industry in the United States. We acquire, develop and operate electric power generating facilities that are not subject to traditional cost-based regulation and therefore can generally sell power at prices determined by the market. We also trade and market power, natural gas and other energy-related commodities and provide related risk management services. In this section we discuss our results of operations on a consolidated basis and individually for each of our business segments. We also discuss our liquidity and capital resources. Our financial reporting segments include Wholesale Energy, European Energy, Retail Energy and Other Operations. For segment reporting information, please read Note 15 to our Interim Financial Statements. On February 19, 2002, we acquired all of the outstanding shares of common stock of Orion Power Holdings, Inc. (Orion Power) for $26.80 per share in cash for an aggregate purchase price of $2.9 billion. As of February 19, 2002, Orion Power's debt obligations were $2.4 billion ($2.1 billion net of restricted cash pursuant to debt covenants). For additional information regarding our acquisition of Orion Power, please read Note 6 to our Interim Financial Statements. 52 In May 2001, we offered 59.8 million shares of our common stock to the public at an initial public offering (IPO) price of $30 per share and received net proceeds of $1.7 billion. Pursuant to the master separation agreement between Reliant Resources and Reliant Energy (Master Separation Agreement), we used $147 million of the net proceeds to repay certain indebtedness owed to Reliant Energy. On September 30, 2002, CenterPoint Energy distributed all of the 240 million shares of Reliant Resources common stock it owned to its common shareholders of record as of the close of business on September 20, 2002 (Distribution). The Distribution completed the separation of Reliant Resources and CenterPoint Energy into two separate publicly held companies. We may experience changes in our cost structure, funding and operations as a result of our separation from CenterPoint Energy, including increased costs associated with reduced economies of scale, and increased costs associated with being a publicly traded, independent company. We cannot currently predict, with any certainty, the actual amount of increased costs we may incur, if any. During 2002, weaker pricing for capacity, ancillary services and power coupled with a narrowing of the spread between power prices and natural gas fuel costs (spark spread) in the United States as well as the effects of market contraction, reduced volatility and reduced liquidity in the United States and Northwest Europe power trading markets; and downgrades in our credit ratings to below investment grade by each of the major rating agencies has negatively impacted us, among other factors. We expect this trend to continue in 2003. However, in the long-term we anticipate that supply surpluses will tighten, regulatory intervention will be more balanced, prices will improve for capacity, ancillary services and power and spark spreads will widen. This view is consistent with our fundamental belief that long run market prices must reach levels sufficient to support an adequate rate of return on the construction of new generation. However, if in the long term the current weak environment persists, we could have significant impairments of our property and equipment and goodwill. The following table provides summary data regarding our consolidated results of operations for the three and nine months ended September 30, 2001 and 2002. CONSOLIDATED RESULTS OF OPERATIONS THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30, -------------------------------- ------------------------------- 2001 2002 2001 2002 ------- ------- ------- ------- (IN MILLIONS) Operating Revenues (1) ................. $ 2,535 $ 5,344 $ 5,704 $ 9,495 Operating Expenses ..................... 2,110 5,073 4,907 8,730 ------- ------- ------- ------- Operating Income ....................... 425 271 797 765 Other Income (Expense), net ............ 12 (82) 63 (158) Income Tax Expense ..................... (175) (138) (314) (284) ------- ------- ------- ------- Income Before Cumulative Effect of Accounting Change .................... 262 51 546 323 Cumulative Effect of Accounting Changes, net of tax ........................... -- -- 3 (234) ------- ------- ------- ------- Net Income ............................. $ 262 $ 51 $ 549 $ 89 ======= ======= ======= ======= Basic Earnings Per Share ............... 0.87 0.17 2.01 0.31 ======= ======= ======= ======= Diluted Earnings Per Share ............. 0.87 0.17 2.01 0.30 ======= ======= ======= ======= ------------- (1)Operating revenues reflect trading activities on a net basis as described in Note 3 to our Interim Financial Statements. Three months ended September 30, 2001 compared to three months ended September 30, 2002 Net Income. We reported consolidated net income of $51 million ($0.17 per diluted share) for the three months ended September 30, 2002 compared to $262 million ($0.87 per diluted share) for the three months ended September 30, 2001. The decrease in earnings was primarily due to the following: - a $367 million decrease in earnings before interest and income taxes (EBIT) from our Wholesale Energy segment; - a $97 million increase in net interest expense; and 53 - changes in the effective tax rate which are further described below. The above items were partially offset by a $243 million increase in EBIT from our Retail Energy segment. Earnings before Interest and Income Taxes. For an explanation of changes in EBIT, please read the discussion below under " - Earnings Before Interest and Income Taxes by Business Segment." Interest Expense. We incurred net interest expense of $91 million during the three months ended September 30, 2002 compared to net interest income of $6 million in the same period of 2001. The increase in net interest expense of $97 million in 2002 as compared to 2001 resulted primarily from a $95 million increase in interest expense to third parties, net of interest expense capitalized on projects, primarily as a result of higher levels of borrowings related to the acquisition of Orion Power in February 2002 and a $10 million decrease in interest income from affiliated companies as a result of decreased excess cash being invested with a subsidiary of CenterPoint Energy during the three months ended September 30, 2002 as compared to the same period in 2001. This was partially offset by an increase in interest income from third parties of $8 million primarily due to the investment on a short-term basis of cash on hand during the three months ended September 30, 2002 compared to the same period in 2001. Income Tax Expense. During the three months ended September 30, 2001 and 2002, our effective tax rate was 40.2% and 73.3%, respectively. Our reconciling items from the federal statutory rate of 35% to the effective tax rate totaled $72 million for the three months ended September 30, 2002. During the three months ended September 30, 2002, we accrued a $45 million United States federal tax provision for future cash distributions from our equity investment in NEA, the former coordinating body for the Dutch electric generating sector prior to Wholesale competition, which is held by our European Energy segment. Based on our current tax position, during the third quarter of 2002, we determined that we would be obligated to pay United States taxes on future cash distributions from NEA in excess of our tax basis. As of September 30, 2002, our investment in NEA was $192 million. For further discussion of our investment in NEA, please read Note 13(f) to the Reliant Resources Form 10-K/A and Note 12(d) to our Interim Financial Statements. In addition, we had increased reconciling items from state income taxes and valuation allowances partially offset by the effect of the cessation of goodwill amortization. During the third quarter of 2002, our state income taxes increased primarily due to Texas franchise tax associated with our Retail Energy operations. Our valuation allowances increased primarily due to losses incurred by our European Energy trading and origination operations during the third quarter of 2002. Our reconciling items from the federal statutory rate of 35% to the effective tax rate totaled $23 million for the three months ended September 30, 2001. These items primarily related to nondeductible goodwill, state income taxes and valuation allowances partially offset by income earned by REPGB. In 2001, the earnings of REPGB were subject to a zero percent Dutch corporate income tax rate as result of the Dutch tax holiday related to the Dutch electricity industry. In 2002, European Energy's earnings in the Netherlands are subject to the standard Dutch corporate income tax rate, which is currently 34.5%. Nine months ended September 30, 2001 compared to nine months ended September 30, 2002 Net Income. We reported consolidated net income of $89 million ($0.30 per diluted share) for the nine months ended September 30, 2002 compared to $549 million ($2.01 per share) for the nine months ended September 30, 2001. The 2001 results included a cumulative effect of accounting change of $3 million, net of tax, related to the adoption of SFAS No. 133. For additional discussion of the adoption of SFAS No. 133, please read Note 6 to the Reliant Resources 10-K/A Notes. The 2002 results included a cumulative effect of accounting change of $234 million, related to the adoption of SFAS No. 142 "Goodwill and Other Intangible Assets" (SFAS No. 142). For additional discussion of the adoption of SFAS No. 142, please read Note 7 to our Interim Financial Statements. The decrease in earnings was primarily due to the following: - a $719 million decrease in EBIT from our Wholesale Energy segment; and - a $159 million increase in net interest expense. The above items were partially offset by: - a $502 million increase in EBIT from our Retail Energy segment; - a $30 million increase in EBIT from our European Energy segment; 54 - a $53 million decrease in charges incurred relating to the redesign and settlement of some of Reliant Energy's benefit plans related to our separation from CenterPoint Energy; - $33 million in pre-tax disposal charges and impairments of goodwill and fixed assets related to exiting our Communications business recorded in the third quarter of 2001 by our Other Operations segment; and - changes in our effective tax rate which are further discussed below. Earnings before Interest and Income Taxes. For an explanation of changes in EBIT, please read the discussion below under " - Earnings Before Interest and Income Taxes by Business Segment." Interest Expense. We incurred net interest expense of $185 million during the nine months ended September 30, 2002 compared to $26 million in the same period of 2001. The increase in net interest expense of $159 million in 2002 as compared to 2001 resulted primarily from a $157 million increase in interest expense to third parties, net of interest expense capitalized on projects, primarily as a result of higher levels of borrowings related to the acquisition of Orion Power in February 2002. Interest income on net advances to affiliated companies in the first nine months of 2002 as compared to the first nine months of 2001, decreased $3 million. This decrease resulted primarily from decreased net advancements of excess cash to a subsidiary of CenterPoint Energy during the nine months ended September 30, 2002 partially offset by interest expense incurred prior to the conversion into equity of $1.7 billion of debt owed to CenterPoint Energy and its subsidiaries in connection with the completion of the IPO in 2001. Income Tax Expense. During the nine months ended September 30, 2001 and 2002, our effective tax rate was 36.5% and 46.9%, respectively. Our reconciling items from the federal statutory rate of 35% to the effective tax rate totaled $72 million for the nine months ended September 30, 2002. Our reconciling items from the federal statutory rate of 35% to the effective tax rate totaled $13 million for the nine months ended September 30, 2001. The items impacting the effective tax rate for the nine months ended September 30, 2001 and 2002 are primarily consistent with those impacting the three months ended September 30, 2001 and 2002 discussed above. EARNINGS BEFORE INTEREST AND INCOME TAXES BY BUSINESS SEGMENT The following table presents EBIT for each of our business segments for the three and nine months ended September 30, 2001 and 2002. EBIT represents earnings (loss) before interest expense, interest income and income taxes. EBIT, as defined, is shown because it is a widely accepted measure of financial performance used by some analysts and investors to analyze and compare companies on the basis of operating performance. It is not defined under accounting principles generally accepted in the United States of America (GAAP), and should not be considered in isolation or as a substitute for a measure of performance prepared in accordance with GAAP and is not indicative of operating income from operations as determined under GAAP. Additionally, our computation of EBIT may not be comparable to other similarly titled measures computed by other companies, because all companies do not calculate it in the same fashion. For a reconciliation of our operating income to EBIT and EBIT to net income, please read Note 15 to our Interim Financial Statements. THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ----------------------- ----------------------- 2001 2002 2001 2002 ----- ----- ----- ----- (IN MILLIONS) Wholesale Energy ....... $ 475 $ 108 $ 967 $ 248 European Energy ........ (4) (13) 80 110 Retail Energy .......... (8) 235 (13) 489 Other Operations ....... (32) (50) (148) (55) ----- ----- ----- ----- Total Consolidated $ 431 $ 280 $ 886 $ 792 ===== ===== ===== ===== WHOLESALE ENERGY Wholesale Energy includes our non-regulated power generation operations in the United States and our wholesale energy trading, marketing, origination and risk management operations in North America. Wholesale Energy's activities include purchasing fuel to supply existing generation assets, selling electricity produced by these assets, purchasing natural gas for resale to customers, managing the day-to-day trading, scheduling of power and natural gas, and dispatching of the generation portfolios. 55 During 2002, we have evaluated our trading, marketing, power origination and risk management services strategies. In the third quarter of 2002, we began to reduce our trading, marketing and power origination activities in order to significantly reduce collateral usage and focus commercial organization on the highest return activities primarily around our core asset positions. In addition, trading activity across the industry has decreased dramatically. The restructuring of our commercial and support groups resulted in severance costs of $6 million in the third quarter of 2002. Both commercial margins and general and administrative costs are expected to be lower going forward. During 2002, weaker pricing for capacity, ancillary services and power coupled with a narrowing of the spread between power prices and natural gas fuel costs (spark spread) negatively impacted the Wholesale Energy segment. In addition, the effects of market contraction, reduced volatility and reduced liquidity in the United States power trading markets have also negatively impacted the Wholesale Energy segment. We expect this trend to continue in 2003. However, in the long-term we anticipate that supply surpluses will tighten, regulatory intervention will be more balanced, prices will improve for capacity, ancillary services and power and spark spreads will widen. This view is consistent with our fundamental belief that long run market prices must reach levels sufficient to support an adequate rate of return on the construction of new generation. However, if in the long term the current weak environment persists the Wholesale Energy segment could have significant impairments of its property and equipment and goodwill. We have identified certain non-strategic domestic generating assets for potential sale to enhance our liquidity position. To date, we have not reached an agreement to dispose of any material assets nor have we contemplated any proceeds from asset sales in our current liquidity plan. Due to unfavorable market conditions in the wholesale power markets, there can be no assurance that we will be successful in disposing of domestic generating assets at reasonable prices or on a timely basis. Specific plans to dispose of assets could result in impairment losses in property and equipment. SFAS No. 142 requires goodwill to be tested annually and between annual tests if events occur or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. We have elected to perform our annual test for indications of goodwill impairment as of November 1, in conjunction with our annual planning process. We anticipate finalizing our annual impairment test during the fourth quarter of 2002 and currently cannot estimate the outcome. As of September 30, 2002, the Wholesale Energy segment has goodwill of $1.6 billion. For additional information regarding factors that may affect the future results of operations of Wholesale Energy, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations - Certain Factors Affecting Our Future Earnings - Factors Affecting the Results of Our Wholesale Energy Operations" in the Reliant Resources Form 10-K/A. 56 The following table provides summary data, including EBIT, of Wholesale Energy for the three and nine months ended September 30, 2001 and 2002. WHOLESALE ENERGY ----------------------------------------------------------------------- THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30, -------------------------------- ------------------------------- 2001 2002 2001 2002 ------- -------- -------- -------- (IN MILLIONS) Revenues .................................... $ 2,300 $ 3,468 $ 4,835 $ 5,537 Trading Margins ............................. 44 34 276 131 ------- -------- -------- -------- Total Operating Revenues .................. 2,344 3,502 5,111 5,668 Operating Expenses: Fuel and Cost of Gas Sold ................. 385 428 1,451 829 Purchased Power ........................... 1,298 2,606 2,174 3,686 Operation and Maintenance ................. 87 167 243 412 General, Administrative and Development ... 73 86 203 268 Depreciation and Amortization ............. 28 115 90 248 ------- -------- -------- -------- Total Operating Expenses ................ 1,871 3,402 4,161 5,443 ------- -------- -------- -------- Operating Income ............................ 473 100 950 225 ------- -------- -------- -------- Other Income: Income of equity investment of unconsolidated subsidiaries .............................. 2 1 16 11 Other, net .................................. -- 7 1 12 ------- -------- -------- -------- Earnings Before Interest and Income Taxes ... $ 475 $ 108 $ 967 $ 248 ======= ======== ======== ======== Margins: Power generation (1) ...................... $ 617 $ 434 $ 1,210 $ 1,022 Trading ................................... 44 34 276 131 ------- -------- -------- -------- Total ................................... $ 661 $ 468 $ 1,486 $ 1,153 ======= ======== ======== ======== Operations Data: Physical Wholesale Power Generation Sales (in thousand MWh (2)(4)) ................ 20,107 60,544 48,974 105,852 Trading Power Volumes (4) ................. 59,936 123,310 145,548 244,332 Trading Natural Gas Sales (in Bcf (3))(4) . 880 897 2,324 2,925 -------------- (1) Revenues less fuel and cost of gas sold and purchased power. (2) Megawatt hours. (3) Billion cubic feet. (4) Includes physically delivered volumes, physical transactions that are settled prior to delivery and hedge activity related to our power generation portfolio. Wholesale Energy's EBIT decreased by $367 million for the three months ended September 30, 2002 compared to the same period in 2001. Wholesale Energy's EBIT decreased by $719 million for the nine months ended September 30, 2002 compared to the same period in 2001. The decline in EBIT is primarily due to decreases in gross margin from our power generation operations and decreases in trading margin, partially offset by the effect of the acquisition of Orion Power which closed in February 2002. In addition to the various market-related reasons for changes in Wholesale Energy's EBIT in 2002, EBIT has been impacted by Federal Energy Regulatory Commission (FERC) staff interpretations of a May 15, 2002 FERC order revising the methodology for calculating refunds of California energy sales. In the third quarter of 2002, Wholesale Energy recorded an additional reserve of $21 million for potential refunds owed by the Company. For the nine months ended September 30, 2002, we have recorded a reserve of $55 million for such potential refunds. The Company's inception-to-date reserve for such refunds totals $70 million as of September 30, 2002. We estimate the range of our refund obligations for California energy sales to be $70 million to $190 million. Wholesale Energy's EBIT was also impacted by changes to the credit reserve for California receivable balances. The changes in the credit reserves resulted from the FERC refunds described above, collections during the period as well as a determination that credit risk had been reduced on certain outstanding receivables following payments made by one creditor to the California Power Exchange. Accordingly, the credit reserve was reduced by $6 million and $44 million in the three and nine months ended September 30, 2002, respectively. The credit reserve increased 57 by $33 million for the nine months ended September 30, 2001. During the three months ended September 30, 2001, the credit reserve was not adjusted. For information regarding the reserves against receivables, FERC refund methodology and uncertainties in the California wholesale energy market, please read Notes 12(a) and 12(c) to our Interim Financial Statements. Wholesale Energy's gross margin from power generation operations decreased by $183 million in the three months ended September 30, 2002 compared to the same period in 2001. This decrease was primarily due to a $289 million decline in 2002 margin caused by deterioration in favorable conditions that existed in the West in 2001 and by increased refund requirements discussed above. In addition, the Mid-Atlantic region experienced an $85 million decrease in gross margin in 2002 due to a 28% decline in prices for power sales and reduced capacity as a result of the expiration of a capacity contract. The gross margin for this period benefited by $263 million from the Orion acquisition in February 2002 and by $35 million in gross margin from new plants that became commercially operational in the second half of 2001. Included in this gross margin variance is a $95 million decrease due to the ineffectiveness of cash flow hedges from a $73 million gain in 2001, primarily related to the California market, to a $22 million loss in 2002. Wholesale Energy's gross margin from power generation operations is comprised of revenues less fuel and cost of gas sold and purchased power. Revenues increased by $1.2 billion (51%) in the three months ended September 30, 2002 compared to the same period in 2001. The major components of this increase are $421 million in revenues from Orion Power, which we acquired in February 2002, and $2.0 billion in revenues from the Mid-Atlantic region due to favorable hedging, marketing and operating results. These were offset by a reduction in hedging, marketing and operating results of the California region of $1.6 billion. Wholesale Energy's revenues and gross margin for the three months ended September 30, 2001 benefited from favorable conditions in the West caused by a combination of factors including reduction in available hydroelectric generation resources, increased demand, and decreased electric imports. Wholesale Energy's fuel and cost of gas sold and purchased power increased by $1.4 billion in the three months ended September 30, 2002. The major components of this increase are due to increased hedging and marketing activities in the Mid-Atlantic region ($2.1 billion) partially offset by a reduction in the hedging and marketing results in the California region ($1.2 billion) coupled with increased fuel expense due to a 79% increase in power generation sales volumes, excluding hedging activity, largely due to the Orion Power acquisition that closed in February 2002. Trading gross margins decreased $10 million in the three months ended September 30, 2002 compared to the same period in 2001, primarily due to changes in our physical gas businesses that had been profitable but were creating high collateral demands. Also during the third quarter 2002, Wholesale Energy reduced trading activities not associated with our core generation asset positions. For the nine-month period ending September 30, 2002, Wholesale Energy's gross margin from power generation operations decreased by $188 million compared to the same period in 2001. The decline in favorable conditions that existed in the West region in 2001 coupled with the increased refund requirements discussed above caused an unfavorable variance in the West region of $614 million. In addition, the Mid-Atlantic region experienced a $108 million decrease in gross margin in 2002 due to a 20% decline in prices for power sales and reduced capacity as a result of the expiration of a capacity contract. This unfavorable variance was offset by $526 million in gross margin from the Orion Power acquisition that closed in February 2002 and by $76 million in gross margin from new plants that became commercially operational in the second half of 2001. Included in this gross margin variance is a $73 million decrease due to the ineffectiveness of cash flow hedges from a $57 million gain in 2001, primarily related to the California market, to a $16 million loss in 2002. Wholesale Energy's revenues increased by $702 million (15%) in the nine months ended September 30, 2002 compared to the same period in 2001. The major components of this increase are $2.4 billion in the Mid-Atlantic region as a result of favorable hedging, marketing and operating results and $824 million in revenues contributed by Orion Power. These increased revenues were offset by a decline of $2.8 billion in California revenues for this period. Wholesale Energy's fuel and cost of gas sold and purchased power increased by $891 million in the nine months ended September 30, 2002 due primarily to $2.5 billion in the Mid-Atlantic region as a result of hedging and marketing activities and an increase of $298 million due to Orion Power. This partially was offset by a reduction of hedging and marketing activities in the California region of $2.2 billion. Trading gross margins decreased $145 million primarily as a result of lower commodity volatility and decreased trading activity across the industry including the reduction in trading activity associated with our core generation asset positions. 58 Operation and maintenance expenses for Wholesale Energy increased $80 million in the three months ended September 30, 2002 compared to the same period in 2001. This was primarily due to $90 million of operation and maintenance expenses of our Orion Power generating plants acquired in February 2002 partially offset by savings generated from a cost reduction program. General, administrative and development expenses increased $13 million in the three months ended September 30, 2002 compared to the same period in 2001, primarily due to higher administrative costs and corporate overhead allocations to support wholesale commercial activities, which included the integration of Orion Power, and $6 million in severance expense incurred in the three months ended September 30, 2002 for staff reductions related to the reduction of our trading and marketing activities. Operation and maintenance expenses for Wholesale Energy increased $169 million in the nine months ended September 30, 2002 compared to the same period in 2001. This was primarily due to $185 million of operation and maintenance expenses of our Orion Power generating plants acquired in February 2002 partially offset by savings generated from a cost reduction program. General, administrative and development expenses increased $65 million in the nine months ended September 30, 2002 compared to the same period in 2001, primarily due to higher administrative costs and corporate overhead allocations to support wholesale commercial activities, including the integration of Orion Power, and $12 million of severance expense as discussed above. In addition, during the nine months ended September 30, 2002, Wholesale Energy incurred increased expenses related to development activities of $28 million, which includes write-offs of $17 million in previously capitalized costs related to projects that have been terminated. Depreciation and amortization expense increased by $87 million in the three months ended September 30, 2002 compared to the same period in 2001 primarily as a result of $46 million in depreciation expense related to our Orion Power plants and other generating plants placed into service after the third quarter of 2001 and a $37 million impairment charge on turbines and generators. For the three months ended September 30, 2001, Wholesale Energy recorded $2 million in amortization expense related to goodwill. Depreciation and amortization expense increased by $158 million in the nine months ended September 30, 2002 compared to the same period in 2001 primarily as a result of $116 million in depreciation expense related to our Orion Power plants and other generating plants placed into service after the third quarter of 2001, a $15 million write-off for the closure of a plant, and a $37 million equipment impairment related to turbines and generators. These were partially offset by lower amortization of air emission allowances of $21 million primarily related to our California power generation operations. For the nine months ended September 30, 2001, Wholesale Energy recorded $4 million in amortization expense related to goodwill. For information regarding the cessation of goodwill amortization, please read Note 2(q) to the Reliant Resources 10-K/A Notes and Note 7 to our Interim Financial Statements. Our Wholesale Energy segment reported income from equity investments for the three and nine months ended September 30, 2002 of $1 million and $11 million, respectively, compared to $2 million and $16 million in the same periods in 2001, respectively. The equity income in both periods primarily resulted from an investment in an electric generation plant in Boulder City, Nevada. The equity income related to our investment in the plant decreased during the nine months ended September 30, 2002 compared to the same period in 2001, primarily due to decreases in margins due to lower prices realized in 2002, partially offset by the receipt of business interruption and other insurance claims totaling $12 million. EUROPEAN ENERGY European Energy generates and sells power from its generation facilities in the Netherlands and participates in the emerging wholesale energy trading and power origination industry in Northwest Europe. In September 2002, we concluded a comprehensive evaluation of our European Energy segment's businesses and it was decided that proprietary trading would be significantly reduced in order to focus on optimization of our power generation assets in the Netherlands. Accordingly, on September 25, 2002, we announced the closure of our London-based natural gas and electricity trading operations. In addition, we are in the process of consolidating facilities, centralizing activities and reducing personnel in other operating centers. As a result, European Energy recorded a $8 million reorganization charge, primarily related to severance, in operating and maintenance and general and administrative expenses as discussed below. 59 During the third quarter of 2002, we completed the transitional impairment test for the adoption of SFAS No. 142, including the review of goodwill for impairment. Based on this impairment test, we recorded an impairment of European Energy segment's goodwill of $234 million. This impairment loss was recorded retroactively as a cumulative effect of a change in accounting principle for the quarter ended March 31, 2002. Our measurement of the fair value of European Energy was based on both an income approach, using future discounted cash flows, and a market approach, using acquisition multiples, including price per Megawatt, based on publicly available data for recently completed European transactions. For further discussion of the impairment, please read Note 7 to our Interim Financial Statements. The circumstances leading to the impairment of our European Energy segment's goodwill included a significant decline in electric margins attributable to the deregulation of the European electricity market in 2001, lack of growth in the wholesale energy trading markets in Northwest Europe and continued regulation of the European fuel markets. We anticipate that power prices will continue to be depressed throughout 2003, but we believe that prices will improve over the long-term. If prices do not improve or there are additional declines in prices, the European Energy segment could have significant impairments of its property and equipment and goodwill. SFAS No. 142 requires goodwill to be tested annually and between annual tests if events occur or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. We have elected to perform our annual test for indications of goodwill impairment as of November 1, in conjunction with our annual planning process. We anticipate finalizing our annual impairment test during the fourth quarter of 2002 and currently cannot estimate the outcome. As of September 30, 2002, the European Energy segment has goodwill of $492 million. For additional information regarding factors that may affect the future results of operations of European Energy, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations - Certain Factors Affecting Our Future Earnings - Factors Affecting the Results of Our European Energy Operations" in the Reliant Resources Form 10-K/A. 60 The following table provides summary data, including EBIT, of European Energy for the three and nine months ended September 30, 2001 and 2002. EUROPEAN ENERGY ---------------------------------------------------------- THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------------- ------------------------ 2001 2002 2001 2002 -------- -------- -------- -------- (IN MILLIONS) Revenues ....................................... $ 142 $ 145 $ 472 $ 447 Trading Margins ................................ 3 3 6 10 -------- -------- -------- -------- Total Operating Revenues ..................... 145 148 478 457 Operating Expenses: Fuel ......................................... 91 67 294 254 Purchased Power .............................. 9 38 15 (55) Operation and Maintenance .................... 17 25 56 87 General, Administrative and Development ...... 13 18 33 26 Depreciation and Amortization ................ 20 16 57 42 -------- -------- -------- -------- Total Operating Expenses ................... 150 164 455 354 -------- -------- -------- -------- Operating (Loss) Income ........................ (5) (16) 23 103 -------- -------- -------- -------- Other Income: Income of equity investment of unconsolidated subsidiaries ................................. -- -- 51 -- Other, net ..................................... 1 3 6 7 -------- -------- -------- -------- (Loss) Earnings Before Interest and Income Taxes $ (4) $ (13) $ 80 $ 110 ======== ======== ======== ======== Margins: Power Generation (1) ......................... $ 42 $ 40 $ 163 $ 248 Trading ...................................... 3 3 6 10 -------- -------- -------- -------- Total ...................................... $ 45 $ 43 $ 169 $ 258 ======== ======== ======== ======== Electricity (in thousand MWh): Power Generation Sales ....................... 4,013 4,257 11,885 13,198 Trading Sales ................................ 5,687 17,883 14,641 52,436 ----------- (1) Revenues less fuel and purchased power. European Energy's EBIT decreased $9 million and increased $30 million for the three and nine months ended September 30, 2002 compared to the same periods in 2001 due to changes in gross margins (revenues less fuel and purchased power) as explained below. During the nine months ended September 30, 2002, European Energy recognized a one-time $109 million gain resulting from the amendment of our stranded cost electricity supply contracts which is recorded as a reduction in purchase power expense and is included in gross margins. For additional discussion regarding the amendment of these contracts please read Note 12(d) to our Interim Financial Statements. European Energy's revenues increased $3 million for the three months ended September 30, 2002 compared to the same period in 2001, while trading margins remained flat. Driving the increase in revenues was an increase in the volume of electricity sales and higher average sales prices realized in 2002, compared to the third quarter of 2001. Trading margins remained flat, despite substantially higher settlement volumes, as margins have declined from 2001 levels due to credit and liquidity concerns which continue to impact the European power and gas markets. European Energy's revenues decreased $25 million for the nine months ended September 30, 2002 compared to the same period in 2001, while trading margins increased by $4 million. While electricity sales increased by $32 million, period on period, ancillary services and district heating revenues decreased by a combined total of $11 million. Also contributing to the decline from 2001 was a non-recurring efficiency and energy payment of $30 million received during the second quarter of 2001 from NEA, which was the coordinating body for the Dutch electric generating sector prior to wholesale competition. Trading margins increased $4 million for the nine months ended September 30, 2002 compared to 2001 primarily due to an increase in power trading volumes and trading origination transactions. However, there has been a significant decrease in overall market liquidity from prior year levels and we have ceased trading on a proprietary basis during the third quarter of 2002. In addition, the overall decrease in total operating revenues was impacted by an unfavorable foreign exchange effect of $16 million. 61 Fuel and purchased power costs increased $5 million for the three months ended September 30, 2002 compared to the same period in 2001 primarily due to higher volumes of purchased power and higher consumption of natural gas partially offset by lower consumption of coal in the third quarter of 2002 relative to the third quarter of 2001. During the third quarter of 2002, we consumed comparatively less coal, a less expensive fuel than natural gas, due to planned maintenance of a coal burning unit. Also, the comparatively higher level of electricity sales during the third quarter of 2002, in combination with our fuels optimization strategy, have led to higher levels of purchased power. This overall increase in fuel cost was impacted by a favorable foreign exchange effect of $4 million. Fuel and purchased power costs decreased $110 million for the nine months ending September 30, 2002 compared to the same period in 2001 primarily due to a one-time $109 million gain as discussed above and a net $16 million gain related to changes in the valuation of certain out-of-market contracts in the first half of 2002. In addition, higher electricity sales levels have driven comparatively higher levels of fuel consumption and purchased power during the nine months ended September 30, 2002 as compared to the same period in 2001. For further discussion of these out-of-market contracts, please read Notes 6 and 13(f) to the Reliant Resources 10-K/A Notes and Note 12(d) to our Interim Financial Statements. Gross margin decreased $2 million for the three months ended September 30, 2002 compared to the same period in 2001 primarily due to our power generation operations discussed above. Gross margin increased $89 million for the nine months ended September 30, 2002 compared to the same period in 2001 primarily due to (a) the one-time $109 million gain discussed above, (b) the $16 million net gain recognized in fuel expense discussed above and (c) a $4 million increase in trading margin due to a increase in power trading volumes and trading origination transactions. Partially offsetting these increases were the $30 million payment received during the second quarter of 2001 from NEA, and decreased margins on ancillary services and district heating of $6 million. Further offsetting the increase in gross margin were unscheduled plant outages at certain of our electric generating facilities in the first half of 2002. We estimate that these unplanned outages resulted in a net decrease in gross margin of approximately $7 million. We also estimate that planned outages of certain facilities further negatively impacted margins by approximately $3 million during the third quarter of 2002. Operation and maintenance and general and administrative expenses increased by $13 million for the three months ended September 30, 2002 compared to the same period in 2001. The increase was primarily attributable to $8 million in reorganization and severance charges associated with our business restructuring as discussed above. Also contributing to the increase were increased consulting fees and employee benefit expenses, as well as increased expenses associated with the trading business. Operation and maintenance and general and administrative expenses increased by $24 million for the nine months ended September 30, 2002 compared to the same period in 2001. The increase was primarily attributable to the reasons discussed above plus increased environmental expenditures of $2 million, and reversal of a reserve for environmental tax subsidies receivable in 2001 of $4 million. Depreciation and amortization expenses decreased $4 million during the third quarter of 2002 compared to the same period in 2001 primarily due to the cessation of goodwill amortization effective January 1, 2002. During the three months ended September 30, 2001, European Energy recorded $6 million in amortization expense related to goodwill. For additional discussion regarding the cessation of goodwill amortization, please read Note 2(q) to Reliant Resources Form 10-K/A Notes and Note 7 to our Interim Financial Statements. This decrease was partially offset by an increase of $1 million in depreciation expense during the same period as a result of capital expenditures in late 2001 associated with our trading business. Depreciation and amortization expenses decreased $15 million for the nine months ended September 30, 2002 compared to the same period in 2001 primarily due to the cessation of goodwill amortization effective January 1, 2002. During the nine months ended September 30, 2001, European Energy recorded $19 million in amortization expense related to goodwill. This decrease was partially offset by an increase of $3 million in depreciation expense during the same period as a result of capital expenditures in late 2001 associated with our trading business. Other non-operating income increased $2 million during the three months ended September 30, 2002 compared to the same period in 2001 due to investment income and lease income. Other non-operating income decreased $50 million during the nine months ended September 30, 2002 compared to the same period in 2001 primarily due to a $51 million gain recorded in the second quarter of 2001, as equity income for the preacquisition gain contingency 62 related to the acquisition of REPGB for the value of its equity investment in NEA. For further discussion of this gain, please read Note 13(f) to the Reliant Resources 10-K/A Notes and Note 12(d) to our Interim Financial Statements. RETAIL ENERGY Our Retail Energy segment provides electricity products and services to end-use customers, ranging from residential and small commercial customers to large commercial, industrial and institutional customers. In addition, this segment manages the procurement of electricity supply for these customers. For further information regarding our contract to purchase supply from Texas Genco, please read Note 5 to our Interim Financial Statements. Retail Energy provided billing, customer service, credit and collection and remittance services to CenterPoint Energy's regulated electric utility and two of its natural gas distribution divisions. The service agreement governing these services terminated on December 31, 2001. Retail Energy charged the regulated electric and natural gas utilities for these services at cost. We received approximately 1.7 million electric customers in the Houston metropolitan area when the Texas market opened to full competition in January 2002. During the first nine months of 2002, the Retail Energy segment was largely focused on the extensive efforts necessary to transition customers from the utilities to the affiliated retail electric providers. We recently began marketing efforts outside of the Houston metropolitan area, primarily in the Dallas/Fort Worth area. The Electric Reliability Council of Texas (ERCOT) independent system operator (ERCOT ISO) is responsible for ensuring that information relating to a customer's choice of retail electric provider is conveyed in a timely manner. Problems in the flow of information between the ERCOT ISO, the transmission and distribution utility and the retail electric providers have resulted in delays in enrolling and billing customers. While the flow of information is improving, operational problems in the new systems and processes are still being worked out. We depend on the local transmission and distribution utilities to read our customers' electric meters. We are required to rely on the local utility or, in some cases, the independent transmission system operator, to provide us with our customers' information regarding electricity usage, such as historical usage patterns, and we may be limited in our ability to confirm the accuracy of the information. The provision of inaccurate information or delayed provision of such information by the local utilities or system operators could have a material negative impact on our business, results of operations and cash flows. The Company records its electricity sales and services to retail customers under the accrual method and these revenues generally are recognized upon delivery, except for sales to large commercial, industrial and institutional customers under contract. Contracted electricity sales to large commercial, industrial and institutional customers are currently accounted for under the mark-to-market method of accounting, and are presented net in trading margins. Historically, these energy contracts are recorded at fair value in trading margins upon contract execution. The net changes in their market values are recognized in the income statement in trading margins in the period of the change. Realized gains and losses are recognized in trading margins on a net basis in the results of operations. Electricity sales and services related to retail customers not billed are recognized based upon estimated electricity and services delivered. At September 30, 2002, the amount not billed is $372 million, including approximately $77 million related to delayed billings. Problems or delays in the flow of information between the ERCOT ISO, the transmission and distribution utility and the retail electric providers and operational problems with our new systems and processes could impact our ability to accurately estimate the amount not billed at September 30, 2002. In addition, we must bill the customer within six months of delivering the electricity. Any electricity that cannot accurately be billed within that time frame cannot be billed or collected. At September 30, 2002, the amount of electricity that cannot be billed does not have a material impact on our results of operations or cash flows. The ERCOT ISO is responsible for maintaining reliable operations of the bulk electric power supply system in the ERCOT market. The ERCOT ISO is also responsible for handling scheduling and settlement for all electricity supply volumes in the Texas deregulated electricity market. As part of settlement, the ERCOT ISO communicates the actual volumes delivered compared to the volumes scheduled. The ERCOT ISO calculates an additional charge or credit based on the difference between the actual and scheduled volumes, based on a market clearing price. Settlement charges also include allocated costs such as unaccounted-for energy. Preliminary settlement information is due from ERCOT within two months after electricity is delivered. Final settlement information is due from ERCOT within twelve months after electricity is delivered. As a result, we record our estimated supply costs using scheduled supply volumes and adjust those costs upon receipt of settlement and consumption information. The ERCOT settlement process was delayed due to operational problems between the ERCOT ISO, the transmission and distribution utility and the retail electric providers. During the third quarter of 2002, the ERCOT ISO began issuing 63 final settlements for the pilot time period of July 31, 2001 to December 31, 2001. Currently, the final settlements are being received within the 12 month time frame. The delay in the ERCOT settlement process could impact our ability to accurately reflect our supply costs. The Company records its transmission and distribution charges using the same method detailed above for its electricity sales and services to retail customers. At September 30, 2002 the transmission and distribution charges not billed by the transmission and distribution utilities to us totaled $54 million. Delays or inaccurate billings from the transmission and distribution utilities could impact our ability to accurately reflect our transmission and distribution costs. For additional information regarding factors that may affect the future results of operations of Retail Energy, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations - Certain Factors Affecting Our Future Earnings - Factors Affecting the Results of Our Retail Energy Operations" in the Reliant Resources Form 10-K/A. The following table provides summary data, including EBIT, of Retail Energy for the three and nine months ended September 30, 2001 and 2002. RETAIL ENERGY -------------------------------------------------- THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ---------------------- ---------------------- 2001 2002 2001 2002 -------- -------- -------- -------- (IN MILLIONS) Electricity Sales and Services ........................................ $ 28 $ 1,196 $ 78 $ 2,487 Hedging Revenues ...................................................... -- 416 -- 731 Trading Margins ....................................................... 15 82 29 150 -------- -------- -------- -------- Operating Revenues .................................................. 43 1,694 107 3,368 Operating Expenses: Purchased Power ..................................................... 2 1,220 2 2,430 Accrual for Payment to CenterPoint Energy, Inc. ..................... -- 89 -- 89 Operation and Maintenance ........................................... 29 67 71 172 General and Administrative .......................................... 16 74 40 167 Depreciation and Amortization ....................................... 3 7 7 19 -------- -------- -------- -------- Total Operating Expenses .......................................... 50 1,457 120 2,877 -------- -------- -------- -------- Operating (Loss) Income ............................................... (7) 237 (13) 491 -------- -------- -------- -------- Other Loss, net ....................................................... (1) (2) -- (2) -------- -------- -------- -------- (Loss) Earnings Before Interest and Income Taxes ...................... $ (8) $ 235 $ (13) $ 489 ======== ======== ======== ======== Operations Data: Energy Sales (gigawatt-hours (GWh)): Residential ....................................................... 8,606 17,055 Small commercial .................................................. 3,986 10,026 Large commercial, industrial and institutional .................... 6,465 17,740 -------- -------- Total ........................................................... 19,057 44,821 ======== ======== Customers as of September 30, 2002 (in thousands, metered locations): Residential ....................................................... 1,469 Small commercial .................................................. 219 Large commercial, industrial and institutional .................... 22 -------- Total ........................................................... 1,710 ======== Our Retail Energy segment's EBIT increased $243 million and $502 million in the three and nine months ended September 30, 2002, respectively, compared to the same period in 2001. The increase in EBIT was primarily due to increased gross margins (revenues less purchased power) related to retail electric sales to residential, small commercial and large commercial, industrial and institutional customers resulting from full competition. The increases in gross margins were partially offset by increased operating expenses as further discussed below. Electric sales and services increased $1.2 billion and $2.4 billion in the three and nine months ended September 30, 2002, respectively, compared to the same periods in 2001, due primarily to retail electric sales in the Texas retail 64 market to residential and small commercial customers and large commercial, industrial and institutional customers that did not sign contracts. Revenues related to the hedging, managing and optimizing of our electric energy supply contributed approximately $416 million and $731 million, respectively, of the increase in revenues for the three and nine months ended September 30, 2002 compared to the same periods in 2001. Purchased power expense increased $1.2 billion and $2.4 billion, respectively, for the three and nine months ended September 30, 2002 due to costs of approximately $829 million and $1.8 billion, respectively, associated with retail electric sales and $389 million and $656 million, respectively, associated with hedging, managing and optimizing of our electric energy supply. Our Retail Energy segment's gross margins increased $433 million and $833 million in the three and nine months ended September 30, 2002, respectively, compared to the same periods in 2001 primarily due to increased margins of $462 million and $895 million, respectively, from retail electric sales of which $67 million and $121 million, respectively, was increased gross margin for electric sales to contracted energy sales to large commercial, industrial and institutional customers due primarily to the opening of the Texas market to full competition in January 2002, as discussed above. The increase in our price to beat fuel factor occurring in August 2002 contributed approximately $35 million of this increase in retail electric sales margins for the three and nine months ended September 30, 2002. During the three and nine months ended September 30, 2002, the Retail Energy segment recognized $82 million and $150 million, respectively, of gross margins related to commercial, industrial and institutional electricity contracts compared to $15 million and $29 million in the same periods in 2001, respectively. Included in these margins are unrealized gains related to these contracts which were $38 million and $30 million in the three and nine months ended September 30, 2002, respectively, compared to unrealized gains of $15 million and $29 million, respectively, in the same periods in 2001. For additional information regarding the price to beat fuel factor increase, please read Note 14(a). For information regarding the accounting for contracted electricity sales to large commercial, industrial and institutional customers, please read Note 2(d) and Note 6 to the Reliant Resources 10-K/A Notes. In addition, in the three and nine months ended September 30, 2001, $14 million and $37 million, respectively, of revenues were recorded for billing, customer service, credit and collection and remittance services charged to Reliant Energy's regulated electric utility and two of its natural gas distribution divisions. The associated costs are included in operation expenses and general and administrative expenses. The service agreement governing these services terminated on December 31, 2001. To the extent that our price for providing retail electric service to residential and small commercial customers in CenterPoint Energy's Houston service territory during 2002 and 2003, which price is mandated by the Texas electric restructuring law, exceeds the market price of electricity, we may be required to make a payment to CenterPoint Energy in early 2004 unless the Texas Utility Commission determines that, on or prior to January 1, 2004, 40% or more of the amount of electric power that was consumed in 2000 by residential or small commercial customers, as applicable, within CenterPoint Energy's Houston service territory as of January 1, 2002 is committed to be served by retail electric providers other than us. Currently, we believe it is probable that we will be required to make such payment to CenterPoint Energy related to our residential customers up to the cap amount. Our estimate for the payment related to residential customers is between $155 million and $185 million (pre-tax), with a most probable estimate of $170 million. We will recognize the total obligation over the period we recognized the related revenues. During the third quarter of 2002, we recognized $89 million (pre-tax) of which $27 million was associated with the revenues for the first half of 2002. The remainder of our estimated obligation will be recognized during the fourth quarter of 2002 and during 2003. For further discussion of this payment to CenterPoint Energy and the related accounting, please read Note 13(f) to the Reliant Resources 10-K/A Notes and Note 12(e) to our Interim Financial Statements. Operations and maintenance expenses and general and administrative expenses increased $96 million and $228 million in the three and nine months ended September 30, 2002 compared to the same periods in 2001, respectively, primarily due to (a) increased gross receipts taxes of $31 million and $64 million, respectively, (b) personnel and employee related costs and other administrative costs (including allocated corporate overhead) of $45 million and $128 million, respectively, primarily due to the Texas retail market opening to full competition in January 2002, (c) increased bad debt reserves of $23 million and $46 million, respectively, associated with increased retail electric sales and (d) increased marketing costs of $5 million and $15 million, respectively, primarily due to the Texas retail market opening to full competition. Depreciation and amortization expense increased $4 million and $12 million in the three and nine months ended September 30, 2002, respectively, compared to the same periods in 2001 primarily due to depreciation of information systems developed and placed in service to meet the needs of our retail businesses. In addition, for the 65 three and nine months ended September 30, 2001, Retail Energy recorded $1 million and $2 million for the three and nine months ended September 30, 2001 for amortization expense related to goodwill. For information regarding the cessation of goodwill amortization, please read Note 2(q) to the Reliant Resources 10-K/A Notes and Note 7 to our Interim Financial Statements. On November 13, 2002, we filed a request with the Texas Utility Commission to increase the price to beat fuel factor for residential and small commercial customers based on a 7.7% increase in the price of natural gas from our previous request in May 2002. Our requested increase was based on a 10 trading day, average forward 12-month natural gas price of $4.02/mmbtu. The requested increase represents a 2.6% increase in the total bill of a residential customer using, on average, 1,000 kWh per month. If no hearing is requested, the earliest the new price to beat could go into effect would be December 3, 2002. For additional information regarding the current price to beat fuel factor, please read Note 14 to our Interim Financial Statements. OTHER OPERATIONS Our Other Operations segment includes the operations of our venture capital and Communications businesses, and unallocated corporate costs. During the third quarter of 2001, we decided to exit our Communications business. The business served as a facility-based competitive local exchange carrier and Internet services provider and owned network operations centers and managed data centers in Houston and Austin. Our exit plan was substantially completed in the first quarter of 2002. The following table provides summary data regarding the results of operations of Other Operations for the three and nine months ended September 30, 2001 and 2002. OTHER OPERATIONS -------------------------------------- THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ---------------- ---------------- 2001 2002 2001 2002 ----- ----- ----- ----- (IN MILLIONS) Operating Revenues ...................... $ 3 $ -- $ 8 $ 2 Operating Expenses: Operation and Maintenance ............. 6 -- 15 3 General, Administrative and Development 12 46 131 43 Depreciation and Amortization ......... 21 4 25 10 ----- ----- ----- ----- Total Operating Expenses ............ 39 50 171 56 ----- ----- ----- ----- Operating Loss .......................... (36) (50) (163) (54) ----- ----- ----- ----- Other Income (Expense): Gain from Investments, net ............ 5 -- 16 4 Other, net ............................ (1) -- (1) (5) ----- ----- ----- ----- Loss Before Interest and Income Taxes ... $ (32) $ (50) $(148) $ (55) ===== ===== ===== ===== Other Operations' loss before interest and income taxes increased by $18 million and declined by $93 million for the three and nine months ended September 30, 2002, respectively, compared to the same periods in 2001. For the three months ended September 30, 2002, the increase in loss before interest and taxes is primarily due to a net pre-tax, non-cash $47 million charge relating to the accounting settlement of certain benefit obligations associated with our separation from CenterPoint Energy partially offset by $14 million in restructuring charges and $19 million of goodwill impairment related to the exiting of our Communications business recognized during the third quarter of 2001 and $4 million in decreased operating losses from our Communications business. In addition, during the three months ended September 30, 2002, gains from investments decreased $5 million and depreciation expense related to corporate assets increased $3 million. For the nine months ended September 30, 2002, the decline in loss before interest and income taxes is primarily due to (a) a pre-tax, non-cash charge of $100 million recorded in the first quarter of 2001 relating to the redesign of some of Reliant Energy's benefit plans in anticipation of our separation from CenterPoint Energy, (b) decreased operating losses of $15 million related to our Communications business, and (c) $14 million in restructuring charges and $19 million of goodwill impairment related to the exiting of our Communications business recognized during third quarter of 2001. Partially offsetting these items are a net pre-tax, non-cash accounting settlement charge of 66 $47 million recognized during the third quarter of 2002 as discussed above and increased depreciation expense related to corporate assets of $8 million. In addition, other income decreased $16 million during the nine months ended September 30, 2002 compared to the same period in 2001, primarily due to a decrease in gains from investments of $12 million coupled with a $6 million accrual for investment bank services recorded during the first quarter of 2002. Gains from investments decreased due to an impairment of an investment in an internet company in 2002 and decreased gains from other investments. For additional information about the benefit charges noted above, please read Note 13 to our Interim Financial Statements. TRADING AND MARKETING OPERATIONS We trade and market power, natural gas and other energy-related commodities and provide related risk management services to our businesses and our customers. Historically, we apply mark-to-market accounting for all of our energy trading, marketing, power origination and risk management services activities. For information regarding mark-to-market accounting, please read Notes 2(d) and 6(a) to the Reliant Resources 10-K/A Notes and Notes 1 and 3 to our Interim Financial Statements. These trading activities consist of: - the domestic energy trading, marketing, power origination and risk management services operations of our Wholesale Energy segment; - the European energy trading and power origination operations of our European Energy segment; and - the large commercial, industrial and institutional customers under retail electricity contracts of our Retail Energy segment. Our domestic and European energy trading and marketing operations enter into derivative transactions with goals of optimizing our current power generation asset position and taking a market position. During 2002, we have evaluated our trading, marketing, power origination and risk management services strategies. In the third quarter of 2002, we began to reduce our Wholesale Energy segment's trading, marketing and power origination activities due to liquidity concerns and in order to significantly reduce collateral usage and focus on our commercial organization on the highest return activities primarily around our core asset positions. In September 2002, we concluded a comprehensive evaluation of our European Energy segment's businesses and it was decided that proprietary trading would be significantly reduced in order to focus on optimization of our generation assets in the Netherlands. Our realized and unrealized trading, marketing and risk management services margins are as follows: THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, -------------------------- ------------------------- 2001 2002 2001 2002 ----- ----- ----- ----- (IN MILLIONS) Realized ............ $ 132 $ 87 $ 262 $ 278 Unrealized .......... (70) 32 49 13 ----- ----- ----- ----- Total .............. $ 62 $ 119 $ 311 $ 291 ===== ===== ===== ===== Below is an analysis of our net trading and marketing assets and liabilities for 2002 (in millions): Fair value of contracts outstanding at December 31, 2001 ............................. $ 218 Fair value of new contracts when entered into during the period ...................... 54 Contracts realized or settled during the period ...................................... (278) Changes in fair values attributable to changes in valuation techniques and assumptions 31 Changes in fair value attributable to market price and other market changes .......... 200 ----- Fair value of contracts outstanding at September 30, 2002 .......................... $ 225 ===== During the nine months ended September 30, 2002, our Retail Energy segment entered into electric sales contracts with large commercial, industrial and institutional customers ranging from one-half to four years in duration. These contracts had an aggregate fair value of $42 million at the contract inception dates. We have entered into energy supply contracts to substantially economically hedge these contracts. The fair value of these Retail Energy electric sales contracts to large commercial, industrial and institutional customers was determined by 67 comparing the contract price to an estimate of the market cost of delivered retail energy and applying the estimated volumes under the provisions of these contracts. The calculation of the estimated cost of delivered retail energy involves estimating the customer's anticipated load volume, and using the forward ERCOT over-the-counter (OTC) commodity prices, adjusted for the customer's anticipated load characteristics. Load characteristics in the valuation model include: the customer's expected hourly electricity usage profile, the potential variability in the electricity usage profile (due to weather or operational uncertainties), and the electricity usage limits included in the customer's contract. In addition, estimates include anticipated delivery costs, such as electric line losses, ERCOT system operator administrative fees and other market interaction charges, estimated credit risk and administrative costs to serve, and may include estimated transmission and distribution fees. The remaining weighted-average duration of these contracts is approximately eighteen months. Our Retail Energy segment also enters into supply contracts to substantially economically hedge the sales contracts entered into with large commercial, industrial and institutional customers. During the nine months ended September 30, 2002, these contracts had an aggregate fair value of $6 million at the contract inception dates. The fair values of these contracts are estimated using ERCOT OTC forward price and volatility curves and correlation among power and fuel prices specific to ERCOT, net of credit risk. A significant portion of the value of these contracts required utilization of internal models that yield similar results to externally developed standard industry models. For the contracts extending beyond September 30, 2002, the remaining weighted-average duration of these contracts, based on volumes, is less than two years. The remaining fair value of new contracts recorded at inception of $6 million primarily relates to natural gas transportation contracts entered into by the Wholesale Energy segment. The fair values of these Wholesale Energy contracts at inception require the utilization of a spread option model and are estimated using OTC forward price and volatility curves and correlation among natural gas prices at differing locations, net of estimated credit risk. For the contracts extending beyond September 30, 2002, the remaining weighted-average duration of these contracts, based on volumes, is less than five years. During the third quarter of 2002, our Retail Energy segment eliminated one valuation factor adjustment and added another to its fair value calculation. Retail Energy eliminated a valuation factor for potential claims for delays in switching under the liquidated damage clauses in contracts. Retail Energy eliminated this valuation factor because there is now enough data to substantiate that these claims will not be submitted. This change in methodology reduced credit reserves by $5 million. Retail Energy added a valuation factor adjustment to capture the potential earnings loss associated with customers terminating contracts due to a provision in some of its contracts that allows customers to terminate their contracts if our unsecured debt ratings fall below investment grade or if our ratings are withdrawn entirely by a rating agency. During the third quarter of 2002, each of the major rating agencies downgraded our credit ratings to sub-investment grade. We performed an analysis at the customer level to estimate our exposure for these provisions. To date, no customers have terminated according to this provision. This change in methodology increased credit reserves by $1 million. Retail Energy also changed the methodology related to recording its estimate of unaccounted for energy (UFE). Retail Energy changed its UFE factor from 1.6% to zero. The reason for the change is that Retail Energy believes the UFE is included in its volatility valuation factor and its results from energy sales in 2001 were not negatively impacted by the UFE. This change in methodology reduced credit reserves by $9 million. During the second quarter of 2002, we changed our methodology for allocating credit reserves between our trading and non-trading portfolios. Total credit reserves calculated for both the trading and non-trading portfolios, which are less than the sum of the independently calculated credit reserves for each portfolio due to common counterparties between the portfolios, are allocated to the trading and non-trading portfolios based upon the independently calculated trading and non-trading credit reserves. Previously, credit reserves were independently calculated for the trading portfolio while credit reserves for the non-trading portfolio were calculated by deducting the trading credit reserves from the total credit reserves calculated for both portfolios. This change in methodology reduced credit reserves relating to the trading portfolio by $18 million. 68 Below are the maturities of our contracts related to our trading and marketing assets and liabilities as of September 30, 2002 (in millions): FAIR VALUE OF CONTRACTS AT SEPTEMBER 30, 2002 -------------------------------------------------------------------------------------- 2007 AND TOTAL SOURCE OF FAIR VALUE 2003 (1) 2003 (2) 2004 2005 2006 THEREAFTER FAIR VALUE -------------------- -------- -------- ---- ---- ---- ---------- ---------- Prices actively quoted ... $ 6 $ 16 $ (10) $ -- $ -- $ -- $ 12 Prices provided by other external sources ....... 120 30 12 1 12 19 194 Prices based on models and other valuation methods (15) 12 13 3 (4) 10 19 ----- ----- ----- ----- ----- ----- ----- Total .................... $ 111 $ 58 $ 15 $ 4 $ 8 $ 29 $ 225 ===== ===== ===== ===== ===== ===== ===== ------------ (1) Twelve months ended September 30, 2003 (2) The fourth quarter of 2003 The "prices actively quoted" category represents our New York Mercantile Exchange (NYMEX) futures positions in natural gas and crude oil. NYMEX had quoted prices for natural gas and crude oil for the next 72 and 30 months, respectively. The "prices provided by other external sources" category represents our forward positions in natural gas and power at points for which OTC broker quotes are available. On average, OTC quotes for natural gas and power extend 72 and 36 months into the future, respectively. We value these positions against internally developed forward market price curves that are constantly validated and recalibrated against OTC broker quotes. This category also includes some transactions whose prices are obtained from external sources and then modeled to hourly, daily or monthly prices, as appropriate. The "prices based on models and other valuation methods" category contains (a) the value of our valuation adjustments for liquidity, credit and administrative costs, (b) the value of options not quoted by an exchange or OTC broker, (c) the value of transactions for which an internally developed price curve was constructed as a result of the long-dated nature of the transaction or the illiquidity of the market point, and (d) the value of structured transactions. In certain instances structured transactions can be composed and modeled by us as simple forwards and options based on prices actively quoted. Options are typically valued using Black-Scholes option valuation models. Although the valuation of the simple structures might not be different from the valuation of contracts in other categories, the effective model price for any given period is a combination of prices from two or more different instruments and therefore has been included in this category due to the complex nature of these transactions. The fair values in the above table are subject to significant changes based on fluctuating market prices and conditions. Changes in the assets and liabilities from trading, marketing, power origination and price risk management services result primarily from changes in the valuation of the portfolio of contracts, newly originated transactions and the timing of settlements. The most significant parameters impacting the value of our portfolio of contracts include natural gas and power forward market prices, volatility and credit risk. For the Retail Energy sales discussed above, significant variables affecting contract values also include the variability in electricity consumption patterns due to weather and operational uncertainties (within contract parameters). Market prices assume a normal functioning market with an adequate number of buyers and sellers providing market liquidity. Insufficient market liquidity could significantly affect the values that could be obtained for these contracts, as well as the costs at which these contracts could be hedged. Please read "Quantitative and Qualitative Disclosures About Market Risk" in Item 7A of the Reliant Resources Form 10-K/A for further discussion and measurement of the market exposure in the trading and marketing businesses and discussion of credit risk management. 69 The following table presents the distribution by credit ratings of our total non-trading derivatives and trading and marketing assets as of September 30, 2002, after taking into consideration netting and set-off agreements with counterparties within each balance sheet caption (in millions). PERCENTAGE OF COLLATERAL EXPOSURE NET OF EXPOSURE NET OF CREDIT RATING EQUIVALENT EXPOSURE HELD (3) COLLATERAL COLLATERAL ------------------------ -------- -------- ---------- ---------- AAA/Aaa ....................... $ 1 $ -- $ 1 0% AA/Aa2 ........................ 239 -- 239 10% A/A2 .......................... 631 -- 631 25% BBB/Baa2 ...................... 1,173 (95) 1,078 44% BB/Ba2 or lower ............... 570 (65) 505 20% Unrated (1)(2) ................ 22 (8) 14 1% ------- ------- ------- ------- 2,636 (168) 2,468 100% Less: Credit and other reserves (66) -- (66) ------- ------- ------- $ 2,570 $ (168) $ 2,402 ======= ======= ======= ---------- (1) For unrated counterparties, we perform financial statement analysis, considering contractual rights and restrictions, and collateral, to create a synthetic credit rating. (2) In lieu of making an individual assessment of the credit of unrated counterparties, we may make a determination that the collateral held in respect of such obligations is sufficient to cover a substantial portion of our exposure. In making this determination, we take into account various factors, including market volatility. (3) Collateral consists of cash and standby letters of credit. For additional information, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations - Certain Factors Affecting Our Future Earnings - Factors Affecting the Results of Our Wholesale Energy Operations - Price Volatility," and " - Risks Associated with Our Hedging and Risk Management Activities" in Item 7 of the Reliant Resources Form 10-K/A. For a description of accounting policies for our trading and marketing activities, please read Notes 2(d) and 6 to the Reliant Resources 10-K/A Notes. We seek to monitor and control our trading risk exposures through a variety of processes and committees. For additional information, please read "Quantitative and Qualitative Disclosures About Market Risk - Risk Management Structure" in Item 7A of the Reliant Resources Form 10-K/A. CERTAIN FACTORS AFFECTING OUR FUTURE EARNINGS For information on other developments, factors and trends that may have an impact on our future earnings, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations - Certain Factors Affecting Our Future Earnings" in the Reliant Resources Form 10-K/A. For additional information regarding (a) the California wholesale market and related litigation, please read Notes 12(a) and 12(c) to our Interim Financial Statements, and (b) Dutch stranded costs, please read Note 12(d) to our Interim Financial Statements. FERC Notice of Proposed Rulemaking. On July 31, 2002, FERC issued a Notice of Proposed Rulemaking proposing requirements for standardization of basic market rules in the wholesale electricity markets. The stated intent of FERC's proposal is to implement standard rules that will provide for more equal access to electricity markets and more predictability and uniformity in the operation of wholesale electricity markets in the various parts of the country. The proposal includes provisions for capacity commitments, price mitigation, independent market monitoring, transmission and congestion revenue rights, and operation of transmission systems by independent entities that satisfy specified governance provisions. The new requirements are not scheduled to be fully implemented until at least Fall 2004. We cannot predict at this time the final form of this rulemaking or the effect that this rulemaking will have on our business and results of operations. 70 FINANCIAL CONDITION The following table summarizes the net cash provided by (used in) operating, investing and financing activities for the nine months ended September 30, 2001 and 2002. NINE MONTHS ENDED SEPTEMBER 30, ----------------------- 2001 2002 ------- ------- (IN MILLIONS) Cash provided by (used in): Operating activities ......... $ 262 $ 319 Investing activities ......... (709) (3,301) Financing activities ......... 635 4,301 Net cash provided by operating activities during the nine months ended September 30, 2002 increased by $57 million compared to the same period 2001. This increase was primarily due to (a) cash flows provided by our Retail Energy segment for retail sales in the first nine months of 2002 due to the Texas retail market opening to full competition in January 2002, (b) $250 million net proceeds related to an arrangement with a financial institution to sell an undivided interest in accounts receivable from residential and small commercial retail electric customers (please see Note 9 to our Interim Financial Statements), (c) $136 million of net collateral deposits related to an equipment financing structure returned to us in 2002 coupled with collateral deposits paid in 2001 (please see Note 12(f) to our Interim Financial Statements), (d) reduced lease prepayments related to the REMA sale-leaseback agreements (please read Note 12(g) to our Interim Financial Statements) and (e) $96 million related to the settlement of four structured transactions in 2002 (please read Note 4 to our Interim Financial Statements). These items were partially offset by (a) decreased operating cash flows from our Wholesale Energy segment; (b) a $100 million settlement payment related to certain stranded costs contracts (please read Note 12(d) to our Interim Financial Statements), (c) settlement of hedges of our net investment in foreign subsidiaries totaling $156 million, (d) cash flows for margin deposits related to our trading and hedging activities and (e) other changes in working capital. Net cash used in investing activities during the nine months ended September 30, 2002 increased $2.6 billion compared to the same period in 2001, primarily due to funding the acquisition of Orion Power for $2.9 billion on February 19, 2002, partially offset by a decrease in capital expenditures related to the construction of domestic power generation projects during the nine months ended September 30, 2002 as compared to the same period in 2001 and a $137 million cash dividend from our European Energy segment's equity investment in NEA (please see Note 12(d) to our Interim Financial Statements). Cash flows provided by financing activities during the nine months ended September 30, 2002 increased $3.7 billion compared to the same period in 2001, primarily due to an increase in short-term borrowings used to fund the acquisition of Orion Power and other working capital requirements and due to increased working capital to meet future obligations, decreased investments of excess cash in an affiliate of CenterPoint Energy, partially offset by $1.7 billion in net proceeds from our IPO in 2001. Acquisition of Orion Power Holdings, Inc. On February 19, 2002, we acquired all of the outstanding shares of common stock of Orion Power for $26.80 per share in cash for an aggregate purchase price of $2.9 billion. As of February 19, 2002, Orion Power's debt obligations were $2.4 billion ($2.1 billion net of restricted cash pursuant to debt covenants). We funded the purchase of Orion Power with a $2.9 billion credit facility and $41 million of cash on hand. This basis of accounting in our Interim Financial Statements contemplates the recovery of our assets and the satisfaction of our liabilities in the normal course of conducting business, which in turn is dependent upon our ability to successfully execute our refinancing plans. We expect to successfully execute our refinancing plans; accordingly, management believes we will be able to meet our obligations in a manner consistent with this accounting treatment. However, there can be no assurance that we will be successful in executing our refinancing plans. If we are unable to complete the necessary future refinancings on acceptable terms and conditions, given the magnitude of the refinancings we may be forced to consider a reorganization under the protection of bankruptcy laws. For discussion of our refinancing plans, please read Note 2 to our Interim Financial Statements. 71 FUTURE SOURCES OF CASH FLOWS For a discussion of factors affecting our sources of cash and liquidity, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources" in the Reliant Resources Form 10-K/A and Notes 2, 9, 12(h), 12(i), 16(a) and 16(b) to our Interim Financial Statements. Credit Facilities. As of September 30, 2002, we had $8.1 billion in committed credit facilities of which $365 million remained unused. Credit facilities aggregating $5.3 billion were unsecured. As of September 30, 2002, letters of credit outstanding under these facilities aggregated $597 million. As of September 30, 2002, borrowings of $7.1 billion were outstanding under these facilities. As of September 30, 2002, we have $6.6 billion of committed credit facilities which will expire by September 30, 2003 of which $1.7 billion will expire by December 31, 2002. For a discussion of the repayment, refinancing and/or amendment of certain of these committed credit facilities and our liquidity concerns, please read Notes 2 and 9 to our Interim Financial Statements. Credit Ratings. Credit ratings impact our ability to obtain short- and long-term financing, the cost of such financing and the execution of our commercial strategies. For a discussion of our credit ratings and the related factors affecting our future financial position, results of operations and cash flows, please read Note 2 to our Interim Financial Statements. Orion Power and its Subsidiaries Credit Facilities Covenant Waivers. For a discussion of Orion Power and its subsidiaries covenant waivers during the third quarter of 2002, please read Note 9 to our Interim Financial Statements. For additional information regarding Orion Power and its subsidiaries' debt obligations, please read Notes 2 and 9 to our Interim Financial Statements. Receivable Facility Covenant Violation. For a discussion of a covenant violation under the Receivable Facility, please read Note 16(a) to our Interim Financial Statements. California Trade Receivables. As of September 30, 2002, the Company was owed a total of $233 million, net of a $70 million reserve for refund, by the Cal ISO, the Cal PX, the DWR, and California Energy Resources Scheduling for energy sales in the California wholesale market during the fourth quarter of 2000 through September 30, 2002. From September 30, 2002 through November 8, 2002, the Company has collected $9 million of these receivable balances. As of September 30, 2002, we had a pre-tax credit provision of $24 million against these receivable balances. For additional information regarding uncertainties in the California wholesale market, please read Notes 12(a) and 12(c) to our Interim Financial Statements and Notes 13(e) and 13(i) to the Reliant Resources 10-K/A Notes. FUTURE USES OF CASH FLOWS For a discussion of items impacting our liquidity and uses of cash, including the impact of our downgrade to sub-investment grade, commercial obligations related to our wholesale and retail operations, various collateral requirements and capital obligations, please read Notes 2, 9, 12(h), 12(i) and 16(a) to our Interim Financial Statements. Generating Projects. As of September 30, 2002, we had one generating facility under construction. Total estimated costs of constructing this facility is $498 million. As of September 30, 2002, we had incurred $280 million of the total projected costs of this project, which was funded primarily from equity and a debt facility. In addition to this generating facility, we are constructing facilities as construction agents under construction agency agreements, which permit us to lease or buy each of these facilities at the conclusion of their construction. In connection with the acquisition of Orion Power, we acquired contracts to purchase additional power generation equipment, consisting of steam and combustion turbines and heat recovery steam generators. As of September 30, 2002, we have cancelled all but one contract, having determined the equipment is in excess of our current needs. We plan to pay an additional $1 million in early 2003 to cancel the remaining contract. Construction Agency Agreement and Equipment Financing Structure. In 2001, we, through several of our subsidiaries, entered into operative documents with special purpose entities to facilitate the development, construction, financing and leasing of several power generation projects. These special purpose entities are not 72 consolidated by us. In addition, we, through our subsidiary, REPG, entered into an agreement, which was terminated in September 2002, with a bank whereby the bank, as owner, entered or would enter into contracts for the purchase and construction of power generation equipment and REPG, or its subagent, would act as the bank's agent in connection with administering the contracts for such equipment. For information regarding these transactions, please read Note 12(f) to our Interim Financial Statements. Payment to CenterPoint Energy. To the extent that our price for providing retail electric service to residential and small commercial customers in CenterPoint Energy's Houston service territory during 2002 and 2003, which price is mandated by the Texas electric restructuring law, exceeds the market price of electricity, we may be required to make a payment to CenterPoint Energy in early 2004 unless the Texas Utility Commission determines that, on or prior to January 1, 2004, 40% or more of the amount of electric power that was consumed in 2000 by residential or small commercial customers, as applicable, within CenterPoint Energy's Houston service territory as of January 1, 2002 is committed to be served by retail electric providers other than us. As of September 30, 2002, our estimate for the payment related to residential customers is between $155 million and $185 million (pre-tax), with a most probable estimate of $170 million. For additional information regarding this payment, please read Note 12(e) to our Interim Financial Statements. Restricted Cash. All of our operations are conducted by our subsidiaries. Our cash flow and our ability to service parent-level indebtedness when due is dependent upon our receipt of cash dividends, distributions or other transfers from our subsidiaries. The terms of some of our subsidiaries' indebtedness restrict their ability to pay dividends or make restricted payments to us in some circumstances. Under the restructured credit facilities of Orion NY and Orion MidWest, these subsidiaries are restricted from distributing cash to Orion Power. In addition, the 12% senior notes of Orion Power restrict its ability to pay dividends to us unless Orion Power meets certain conditions, including the ability to incur additional indebtedness without violating the required fixed charge coverage ratio of 2.0 to 1.0. As of September 30, 2002, we had restricted cash totaling $380 million related to Orion Power and its subsidiaries. In addition, the ability of REMA, our subsidiary that owns some of the power generation facilities in our Northeast regional portfolio, to pay dividends or make payments to us is restricted under the terms of three lease agreements under which we lease all or an undivided interest in these generating facilities. These agreements allow REMA to pay dividends or make restricted payments only if specified conditions are satisfied, including maintaining specified fixed charge coverage ratios. As of September 30, 2002, the specified conditions were satisfied. In addition, the terms of two of our subsidiaries' indebtedness restrict their ability to pay dividends or make restricted payments to us in some circumstances. Specifically, our subsidiary which owns an electric power generation facility in Channelview, Texas (Channelview) and our subsidiary which holds an equity investment in the entity owning and operating an electric power generation facility in Nevada (El Dorado) are each party to credit agreements used to finance construction of their generating plants. Both the Channelview credit agreement and the El Dorado credit agreement allow the respective subsidiary to pay dividends or make restricted payments only if specified conditions are satisfied, including maintaining specified debt service coverage ratios and debt service reserve account balances. In both cases, the amount of the dividends or restricted payments that may be paid if the conditions are met is limited to a specified level and may be paid only from a particular account. As of September 30, 2002, we had restricted cash of $7 million related to Channelview. Counterparty Credit Risk. We are exposed to the risk that counterparties who owe us money or physical commodities, such as energy or gas, as a result of market transactions fail to perform their obligations. Should the counterparties to these arrangements fail to perform, we might incur losses if we are forced to acquire alternative hedging arrangements or replace the underlying commitment at then-current market prices. In addition, we might incur additional losses to the extent of amounts, if any, already paid to the defaulting counterparties. Liberty Electric Generating Station Contingency. The output of the Liberty Station is contracted under a tolling agreement between Liberty Electric Power, LLC, a wholly owned subsidiary of Orion Power, and PG&E Energy Trading-Power, LP for a term of approximately 14 years, with an option to extend at the end of the term (Tolling Agreement). For information regarding the Tolling Agreement, issues related to the financing of the Liberty Station and other related contingencies, please read Note 12(i). Reliant Energy Desert Basin Contingency. Reliant Energy Desert Basin (REDB), an indirect wholly owned subsidiary of Reliant Resources, sells power to Salt River Project (SRP) under a long-term power purchase 73 agreement. Certain of REDB's obligations under the power purchase agreement are guaranteed by Reliant Resources. In the event Reliant Resources is downgraded to below investment grade by two major ratings agencies, SRP can request performance assurance in the form of cash or a letter of credit from REDB under the power purchase agreement and from Reliant Resources under the guaranty. Under the power purchase agreement and guaranty, the total amount of performance assurance cannot exceed $150 million. For information regarding the REDB's obligations, Reliant Resources related guarantee and other related contingencies, please read Note 12(h). Generating Capacity Auction Letter of Credit. Effective October 1, 2002, Texas Genco, LP, a subsidiary of CenterPoint Energy, entered into a Master Power Purchase and Sale Agreement with Reliant Energy Electric Solutions LLC, guaranteed by certain of the indirect retail energy subsidiaries of the Company, which provides a basis for purchasing power to serve the Company's Texas retail electric customers for a primary term ending December 31, 2003. The Company does not anticipate that it will be required to post any collateral to secure payment for its purchases under such agreement. Please read Note 2 to our Interim Financial Statements for additional information on this agreement. Treasury Stock Purchases. On December 6, 2001, our Board of Directors authorized us to purchase up to 10 million additional shares of our common stock through June 2003. Purchases will be made on a discretionary basis in the open market or otherwise at times and in amounts as determined by management subject to market conditions, legal requirements and other factors. Since the date of this authorization through November 8, 2002, we have not purchased any shares of our common stock under this program. Other Sources/Uses of Cash. Our liquidity and capital requirements are affected primarily by the results of operations, capital expenditures, debt service requirements, working capital needs and collateral requirements. We expect to complete the construction of new generation facilities that are in progress; however, we do not anticipate the construction of any new generation facilities in the near future. We will evaluate opportunities to enter retail electric markets for large commercial, industrial and institutional customers, in particular, in regions in which we have electric generating facilities and capacity. We expect our capital requirements to be met with cash flows from operations, and proceeds from debt and equity offerings, project financings, securitization of assets, other borrowings and off-balance sheet financings. Additional capital expenditures, some of which may be substantial, depend to a large extent upon the nature and extent of future project commitments, which are discretionary. We believe that our current level of cash and borrowing capability, along with our future anticipated cash flows from operations and assuming successful refinancings of credit facilities as they mature, will be sufficient to meet the existing operational and collateral needs of our business for the next 12 months. If cash generated from operations is insufficient to satisfy our liquidity requirements, we may seek to sell assets or obtain additional credit facilities or financings from financial institutions. If we are unable to complete the necessary future refinancings on acceptable terms and conditions, given the magnitude of the refinancings we may be forced to consider a reorganization under the protection of bankruptcy laws. For additional discussion regarding our capital commitments, please read Note 2 to our Interim Financial Statements. NEW ACCOUNTING PRONOUNCEMENTS AND CRITICAL ACCOUNTING POLICIES New Accounting Pronouncements. In July 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 141 "Business Combinations" (SFAS No. 141). SFAS No. 141 requires business combinations initiated after June 30, 2001 to be accounted for using the purchase method of accounting and broadens the criteria for recording intangible assets separate from goodwill. Recorded goodwill and intangibles will be evaluated against these new criteria and may result in certain intangibles being transferred to goodwill, or alternatively, amounts initially recorded as goodwill may be separately identified and recognized apart from goodwill. We adopted the provisions of the statement which apply to goodwill and intangible assets acquired prior to June 30, 2001 on January 1, 2002. The adoption of SFAS No. 141 did not have a material impact on our historical results of operations or financial position. In August 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS No. 143). SFAS No. 143 requires the fair value of a liability for an asset retirement legal obligation to be recognized in the period in which it is incurred. When the liability is initially recorded, associated costs are capitalized by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. SFAS No. 143 requires entities to record a cumulative effect of change in accounting principle in the income statement in the period of adoption. We 74 plan to adopt SFAS No. 143 on January 1, 2003, and are in the process of determining the effect of adoption on our consolidated financial statements. In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144). SFAS No. 144 provides new guidance on the recognition of impairment losses on long-lived assets to be held and used or to be disposed of and also broadens the definition of what constitutes a discontinued operation and how the results of a discontinued operation are to be measured and presented. SFAS No. 144 supercedes SFAS No. 121 "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" and Accounting Principles Board Opinion No. 30, "Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions," while retaining many of the requirements of these two statements. Under SFAS No. 144, assets held for sale that are a component of an entity will be included in discontinued operations if the operations and cash flows will be or have been eliminated from the ongoing operations of the entity and the entity will not have any significant continuing involvement in the operations prospectively. SFAS No. 144 did not materially change the methods used by us to measure impairment losses on long-lived assets, but may result in additional future dispositions being reported as discontinued operations. We adopted SFAS No. 144 on January 1, 2002. In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections" (SFAS No. 145). SFAS No. 145 eliminates the current requirement that gains and losses on debt extinguishment must be classified as extraordinary items in the income statement. Instead, such gains and losses will be classified as extraordinary items only if they are deemed to be unusual and infrequent. SFAS No. 145 also requires sale-leaseback accounting for certain lease modifications that have economic effects that are similar to sale-leaseback transactions. The changes related to debt extinguishment will be effective for fiscal years beginning after May 15, 2002, and the changes related to lease accounting will be effective for transactions occurring after May 15, 2002. We will apply this guidance prospectively. In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities" (SFAS No. 146). SFAS No. 146 nullifies EITF No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)" (EITF No. 94-3). The principal difference between SFAS No. 146 and EITF No. 94-3 relates to the requirements for recognition of a liability for cost associated with an exit or disposal activity. SFAS No. 146 requires that a liability be recognized for a cost associated with an exit or disposal activity when it is incurred. A liability is incurred when a transaction or event occurs that leaves an entity little or no discretion to avoid the future transfer or use of assets to settle the liability. Under EITF No. 94-3, a liability for an exit cost was recognized at the date of an entity's commitment to an exit plan. In addition, SFAS No. 146 also requires that a liability for a cost associated with an exit or disposal activity be recognized at its fair value when it is incurred. SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002 with early application encouraged. We will apply the provisions of SFAS No. 146 to all exit or disposal activities initiated after December 31, 2002. See Note 4 for a discussion regarding our adoption of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended (SFAS No. 133) on January 1, 2001 and adoption of subsequent cleared guidance. See Note 7 for a discussion regarding our adoption of SFAS No. 142 "Goodwill and Other Intangible Assets" (SFAS No. 142) on January 1, 2002. In June 2002, the EITF reached a consensus that all mark-to-market gains and losses on energy trading contracts should be shown net in the income statement whether or not settled physically. In October 2002, the EITF issued a consensus that superceded the June 2002 consensus. The October 2002 consensus required, among other things, that energy derivatives held for trading purposes be shown net in the income statement. This new consensus is effective for fiscal periods beginning after December 15, 2002. However, consistent with the new consensus and as allowed under EITF No. 98-10 "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (EITF No. 98-10), beginning with the quarter ended September 30, 2002, we now report all energy trading and marketing activities on a net basis in the Statements of Consolidated Income. Comparative financial statements for prior periods have been reclassified to conform to this presentation. 75 FOR THE THREE FOR THE NINE FOR THE SIX MONTHS ENDED MONTHS ENDED MONTHS ENDED SEPTEMBER 30, 2001 SEPTEMBER 30, 2001 JUNE 30, 2002 ------------------ ------------------ ------------- Revenues ....................... $ 6,278 $19,687 $11,434 Fuel and cost of gas sold ...... 2,471 11,011 6,142 Purchased power ................ 3,807 8,676 5,292 ------- ------- ------- Net impact on margins ..... $ -- $ -- $ -- ======= ======= ======= Furthermore, in October 2002, under EITF No. 02-03, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (EITF No. 02-03) the EITF reached a consensus to rescind EITF No. 98-10. All new contracts that would have been accounted for under EITF No. 98-10, and that do not fall within the scope of SFAS No. 133, should no longer be marked-to-market through earnings beginning October 25, 2002. In addition, inventories used in the trading and marketing operations should no longer be marked-to-market through earnings. This transition is effective for us for the first quarter of 2003. A cumulative effect of a change in accounting principle should be recorded effective January 1, 2003 related to all contracts and inventories that will no longer be recorded at fair value that were entered into or held, as applicable, prior to October 25, 2002. We are in process of determining the effect of adoption on our consolidated financial statements. Finally, the EITF has not reached a consensus on whether recognition of dealer profit, or unrealized gains and losses at inception of an energy trading contract is appropriate in the absence of quoted market prices or current market transactions for contracts with similar terms. In the June 2002 EITF meeting and again in the October 2002 EITF meeting, the FASB staff indicated that until such time as a consensus is reached, the FASB staff will continue to hold the view that previous EITF consensus does not allow for recognition of dealer profit, unless evidenced by quoted market prices or other current market transactions for energy trading contracts with similar terms and counterparties. During the three and nine months ended September 30, 2002, we recorded $8 million and $54 million, respectively, of fair value at the contract inception related to trading and marketing activities. We believe that any material inception gains recorded subsequent to the FASB staff comment regarding this issue were evidenced by quoted market prices and other current market transactions for energy trading contracts with similar terms and counterparties. During the first quarter of 2002, the FASB considered proposed approaches related to identifying and accounting for special-purpose entities. The current proposal being considered by the FASB would limit special purpose entities used by a company for financing and other purpose not being consolidated with its results of operations. One criterion being considered is to require consolidation of a special purpose entity if the equity investments held by third-party owners in the special purpose entity is less than 10% of capitalization. The FASB likely will not grandfather special purpose entities existing at the date the final interpretation is issued. Special purpose entities in existence at the date of adoption of this interpretation will likely be consolidated by the primary beneficiary. For information regarding special purpose entities affiliated with us, please read Notes 12(f) and 12(g) to our Interim Financial Statements. Critical Accounting Policies. A critical accounting policy is one that is both important to the portrayal of our financial condition and results of operations and requires management to make difficult, subjective or complex judgments. The circumstances that make these judgments difficult, subjective and/or complex have to do with the need to make estimates about the effect of matters that are inherently uncertain. Estimates and assumptions about future events and their effects cannot be made with certainty. We base our estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments. These estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. We believe the following are the most significant estimates used in the preparation of our consolidated financial statements. - determination of fair value of trading and marketing assets and liabilities for our energy trading, marketing and price risk management services operations, and non-trading derivative assets and liabilities, including stranded costs obligations related to our European Energy operations (please read "Management's Discussion and Analysis of Financial Condition and Results of Operations - Trading and Marketing Operations" and "Quantitative and Qualitative Disclosures About Market Risk" in the Reliant Resources 76 Form 10-K/A, Notes 2(d) and 6 to the Reliant Resources 10-K/A Notes and Notes 1 and 4 to our Interim Financial Statements); - determination of impairment of long-lived assets and intangibles (please read "Management's Discussion and Analysis of Financial Condition and Results of Operations - European Energy" in the Reliant Resources Form 10-K/A, Note 2(f) and Note 2(q) to the Reliant Resources 10-K/A Notes, Note 7 to our Interim Financial Statements, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Earnings Before Interest and Taxes by Business Segment - Wholesale Energy" and "Management's Discussion and Analysis of Financial Condition and Results of Operations - Earnings Before Interest and Taxes by Business Segment - European Energy" within this Form 10-Q/A); - estimation of revenues for delivered energy sales and services to retail customers and the related supply costs (please read "Management's Discussion and Analysis of Financial Condition and Results of Operations - Retail Energy" and "Management's Discussion and Analysis of Financial Condition and Results of Operations - Certain Factors Affecting Our Future Earnings - Factors Affecting the Results of Our Retail Energy Operations" in the Reliant Resources Form 10-K/A and "Management's Discussion and Analysis of Financial Condition and Results of Operations - Earnings Before Interest and Taxes by Business Segment - Retail Energy" within this Form 10-Q/A); and - estimation of credit provisions for uncollectible receivables and potential refunds related to energy sales in the California market (please read Notes 12(a) and 12(c) to our Interim Financial Statements). For a description of all significant accounting policies, please read Note 2 to the Reliant Resources 10-K/A Notes. 77 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK COMMODITY PRICE RISK We assess the risk of our non-trading derivatives (Energy Derivatives) using a sensitivity analysis method, and we assess the risk of our trading derivatives (Trading Derivatives) using the value-at-risk (VAR) method, in order to maintain our total exposure within management-prescribed limits. The sensitivity analysis performed on our Energy Derivatives measures the potential loss based on a hypothetical 10% movement in energy prices. An increase of 10% in the market prices of energy commodities from their September 30, 2002 levels would have decreased the fair value of our Energy Derivatives from their levels on those respective dates by $64 million, excluding non-trading derivative liabilities associated with our European Energy segment's stranded cost gas contract. Our European Energy segment's stranded cost gas contract has exposure to commodity price movements. For information regarding this contract, please read Notes 4 and 12(d) to our Interim Financial Statements. A decrease of 10% in market prices of energy commodities from their September 30, 2002 levels would result in a loss of earnings of $9 million. We utilize the variance/covariance model of VAR, which is a probabilistic model that measures the estimated risk of loss to earnings in market sensitive instruments based on historical experience. With respect to trading and marketing activities, our highest, lowest and average daily VAR were $21 million, $15 million and $18 million, respectively, during the third quarter of 2002 and $29 million, $13 million and $18 million, respectively, during the first nine months of 2002 based on a 95% confidence level and primarily a one-day holding period. During the third quarter of 2001, our highest, lowest and average daily VAR were $11 million, $3 million and $5 million, respectively, and during the first nine months of 2001, our highest, lowest and average monthly VAR were $18 million, $3 million and $7 million, respectively, based on a 95% confidence level and primarily a one-day holding period. We cannot assure you that market volatility, failure of counterparties to meet their contractual obligations, transactions entered into after the date of the original filed Form 10-Q or a failure of risk controls will not lead to significant losses from our trading, marketing and risk management activities. INTEREST RATE RISK We have issued long-term debt and have obligations under bank facilities which subject us to the risk of loss associated with movements in market interest rates. Our floating-rate obligations borrowed from third parties aggregated $6.9 billion at September 30, 2002. If the floating rates were to increase by 10% from September 30, 2002 rates, our combined interest expense to third parties would increase by a total of $2 million each month in which such increase continued. We have entered into interest rate swap contracts with an aggregate notional amount of $1.2 billion that fix the interest rate applicable to floating rate short-term debt and floating rate long-term debt. At September 30, 2002, the swaps relating to short-term and long-term debt, could be terminated at a cost of $63 million. The swaps relating to both short-term and long-term debt qualify for hedge accounting under SFAS No. 133 and the periodic settlements are recognized as an adjustment to interest expense in the Statements of Consolidated Income over the term of the swap agreement. A decrease of 10% in the September 30, 2002 level of interest rates would increase the cost of terminating the swaps related to short-term debt and long-term debt outstanding at September 30, 2002 by $10 million. In addition, during 2002, we entered into forward-starting interest rate swaps having an aggregate notional amount of $500 million to hedge the interest rate on a future offering of long-term fixed-rate notes. At September 30, 2002, these swaps could be liquidated at a cost of $51 million. These swaps qualify as cash flow hedges under SFAS No. 133. In November 2002, we liquidated these swaps at a cost of $52 million. For further discussion of the liquidation of these swaps, please read Note 16 (d) to our Interim Financial Statements. For information regarding the accounting for these interest rate swaps, please read Note 4 to our Interim Financial Statements. 78 At September 30, 2002, we had issued fixed-rate debt aggregating $812 million. As of September 30, 2002, fair values were estimated to be equivalent to the carrying amounts of these instruments. These instruments are fixed-rate and, therefore, do not expose us to the risk of loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase by $48 million if interest rates were to decline by 10% from their rates at September 30, 2002. FOREIGN CURRENCY EXCHANGE RATE RISK As of September 30, 2002, we have entered into foreign currency option contracts and have issued Euro-denominated debt to hedge our entire net investment in our European Energy segment against a material decline of the Euro. Changes in the value of the options and debt are recorded as foreign currency translation adjustments as a component of accumulated other comprehensive income (loss) in stockholders' equity. As of September 30, 2002, we have recorded a $34 million loss in cumulative net translation adjustments. The cumulative translation adjustments will be realized in earnings and cash flows only upon the disposition of the related investments. As of September 30, 2002, our European Energy segment had entered into transactions to purchase approximately $150 million at fixed exchange rates in order to hedge future fuel purchases payable in U.S. dollars. As of September 30, 2002, the fair value of these financial instruments was a $6 million liability. An increase in the value of the Euro of 10% compared to the U.S. dollar from its September 30, 2002 level would result in a loss in the fair value of these foreign currency financial instruments of $15 million. For information regarding the accounting for these financial instruments, see Note 6(b) to the Reliant Resources 10-K/A Notes. Our European Energy segment's stranded cost gas contract has foreign currency exposure. A decrease of 10% in the U.S. dollar relative to the Euro from their September 30, 2002 levels would result in a loss of earnings of $13 million. EQUITY MARKET VALUE RISK We have an investment in Itron, Inc. (Itron), which is classified as "available-for-sale" under SFAS No. 115. As of September 30, 2002, the value of the Itron investment was $3 million. The Itron investment exposes us to losses in the fair value of Itron common stock. A 10% decline in the market value per share of Itron common stock from the September 30, 2002 level would decrease the fair value by less than $1 million. 79 CONTROLS AND PROCEDURES EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES The Company's Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the Company's disclosure controls and procedures (as such term is defined in Rules 13a-14(c) and 15d-14(c) under the Securities Exchange Act of 1934, as amended (the Exchange Act) as of a date within 90 days prior to the filing date of this quarterly report (the Evaluation Date). Based on such evaluation, such officers have concluded that, as of the Evaluation Date, the Company's disclosure controls and procedures are effective in alerting them on a timely basis to material information relating to the Company (including its consolidated subsidiaries) required to be included in the Company's reports filed or submitted under the Exchange Act. It should be noted that the design of any system of controls is based, in part, upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will be successful in achieving its stated goal under all potential future conditions, regardless of how remote. CHANGES IN INTERNAL CONTROLS Since the Evaluation Date, there have not been any significant changes in the Company's internal controls or in other factors that could significantly affect such controls. 80 PART II. OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS. For a description of legal proceedings affecting Reliant Resources, please read Note 12 to our Interim Financial Statements, and the discussion under "Our Business - Environmental Matters" and "Legal Proceedings" in the Reliant Resources Form 10-K/A and Notes 13 and 17 to the Reliant Resources 10-K/A Notes. ITEM 5. OTHER INFORMATION. From time to time, Reliant Resources makes statements concerning its expectations, beliefs, plans, objectives, goals, strategies, future events or performance and underlying assumptions and other statements, which are not historical facts. These statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Although Reliant Resources believes that the expectations and the underlying assumptions reflected in its forward-looking statements are reasonable, it cannot assure you that these expectations will prove to be correct. Forward-looking statements involve a number of risks and uncertainties, and actual results may differ materially from the results discussed in the forward-looking statements. The following are some of the factors that could cause actual results to differ materially from those expressed or implied in forward-looking statements: - state, federal and international legislative and regulatory developments, including deregulation, re-regulation and restructuring of the electric utility industry and changes in or application of environmental and other laws and regulations to which we are subject, and changes in or application of laws or regulations applicable to other aspects of our business, such as commodities trading and hedging activities, - the outcome of pending lawsuits, governmental proceedings and investigations, - the effects of competition, including the extent and timing of the entry of additional competitors in our markets, - liquidity concerns in our markets, - the degree to which we successfully integrate the operations and assets of Orion Power Holdings, Inc. into our Wholesale Energy segment, - the successful and timely completion of our construction projects, as well as the successful start-up of completed projects, - any reduction in our trading, marketing and origination activities, - our pursuit of potential business strategies, including acquisitions or dispositions of assets or the development of additional power generation facilities, - the timing and extent of changes in commodity prices and interest rates, - the availability of adequate supplies of fuel, water, and associated transportation necessary to operate our generation portfolio, - weather variations and other natural phenomena, which can effect the demand for power from or our ability to produce power at, our generating facilities, - financial market conditions, our access to capital and the results of our financing and refinancing efforts, including availability of funds in the debt/capital markets for merchant generation companies, - the credit worthiness or bankruptcy or other financial distress of our counterparties, - actions by rating agencies with respect to us or our competitors, - acts of terrorism or war, - the availability and price of insurance, - the reliability of the systems, procedures and other infrastructure necessary to operate our retail electric business, including the systems owned and operated by the independent system operator in the Electric Reliability Council of Texas, - political, legal, regulatory and economic conditions and developments in the United States and in foreign countries in which we operate, including the effects of fluctuations in foreign currency exchange rates, - the successful operation of deregulating power markets, - the resolution of the refusal by California market participants to pay our receivables balances, and o other factors affecting Reliant Resources discussed in the Reliant Resources Form 10-K/A, including those outlined and in "Management's Discussion and Analysis of Financial Condition and Results of Operations - Certain Factors Affecting Our Future Earnings." 81 When used in Reliant Resources' documents or oral presentations, the words "anticipate," "estimate," "believes," "continues," "could," "intends," "may," "plans," "potential," "should," "will," "expect," "objective," "projection," "forecast," "goal," "guidance," "outlook" and similar words are intended to identify forward-looking statements. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K. (a) Exhibits. SEC FILE OR EXHIBIT REPORT OR REGISTRATION EXHIBIT NUMBER DOCUMENT DESCRIPTION REGISTRATION STATEMENT NUMBER REFERENCE ------ -------------------- ---------------------- ------ --------- * 10.1 Separation Agreement dated July 2, 2002 Reliant Resources, Inc. 1-3187 10.1 between Reliant Resources, Inc. and Joe Bob Quarterly Report on Form Perkins 10-Q for the Quarterly Period Ended September 30, 2002 * 10.2 Employment Agreement effective July 29, Reliant Resources, Inc. 1-3187 10.2 2002 between Reliant Resources, Inc. and Quarterly Report on Form Mark M. Jacobs 10-Q for the Quarterly Period Ended September 30, 2002 + 99.1 Certification of Chairman and Chief Executive Officer of Reliant Resources, Inc. Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) + 99.2 Certification of Executive Vice President and Chief Financial Officer of Reliant Resources, Inc. Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) (b) Reports on Form 8-K. - Current Report on Form 8-K dated July 5, 2002, as filed with the SEC on July 5, 2002 (Item 5). - Current Report on Form 8-K dated July 25, 2002, as filed with the SEC on July 25, 2002 (Items 5, 7 and 9). - Current Report on Form 8-K dated July 31, 2002, as filed with the SEC on August 1, 2002 (Items 5, 7 and 9). - Current Report on Form 8-K/A dated February 19, 2002, as filed with the SEC on August 2, 2002 (Item 7). - Current Report on Form 8-K dated August 14, 2002, as filed with the SEC on August 14, 2002 (Items 7 and 9). - Current Report on Form 8-K dated September 5, 2002, as filed with the SEC on September 9, 2002 (Items 5 and 7). - Current Report on Form 8-K dated September 13, 2002, as filed with the SEC on September 13, 2002 (Items 5 and 7). - Current Report on Form 8-K dated September 18, 2002, as filed with the SEC on September 18, 2002 (Items 5 and 7). - Current Report on Form 8-K dated September 30, 2002, as filed with the SEC on September 30, 2002 (Items 5 and 7). -------- * Management contract or compensatory plan or arrangement. + Filed herewith. 82 SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this Amendment No. 1 to Quarterly Report on Form 10-Q/A to be signed on its behalf by the undersigned thereunto duly authorized. RELIANT RESOURCES, INC. (Registrant) By: /s/ Thomas C. Livengood ------------------------------ Thomas C. Livengood Vice President and Controller (Principal Accounting Officer) Date: April 23, 2003 83 CERTIFICATIONS I, Joel V. Staff, certify that: 1. I have reviewed this quarterly report on Form 10-Q/A of Reliant Resources, Inc.; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: April 23, 2003 /s/ Joel V. Staff ---------------------------------- Joel V. Staff Chairman and Chief Executive Officer 84 CERTIFICATIONS I, Mark M. Jacobs, certify that: 1. I have reviewed this quarterly report on Form 10-Q/A of Reliant Resources, Inc.; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: April 23, 2003 /s/ Mark M. Jacobs ---------------------------------- Mark M. Jacobs Executive Vice President and Chief Financial Officer 85 Exhibit Index SEC FILE OR EXHIBIT REPORT OR REGISTRATION EXHIBIT NUMBER DOCUMENT DESCRIPTION REGISTRATION STATEMENT NUMBER REFERENCE ------ -------------------- ---------------------- ------ --------- * 10.1 Separation Agreement dated July 2, 2002 Reliant Resources, Inc. 1-3187 10.1 between Reliant Resources, Inc. and Joe Bob Quarterly Report on Form Perkins 10-Q for the Quarterly Period Ended September 30, 2002 * 10.2 Employment Agreement effective July 29, Reliant Resources, Inc. 1-3187 10.2 2002 between Reliant Resources, Inc. and Quarterly Report on Form Mark M. Jacobs 10-Q for the Quarterly Period Ended September 30, 2002 + 99.1 Certification of Chairman and Chief Executive Officer of Reliant Resources, Inc. Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) + 99.2 Certification of Executive Vice President and Chief Financial Officer of Reliant Resources, Inc. Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) * Management contract or compensatory plan or arrangement. + Filed herewith. 86