-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, A/KsCE/zzS712aQjK7y3z41Zst7V4/tqwuHZBpOfxZ8UKG6Rndr5wT8sohhcE1fM /WNWsdCiHl/SX1oU47+FGg== 0000950129-01-503901.txt : 20020410 0000950129-01-503901.hdr.sgml : 20020410 ACCESSION NUMBER: 0000950129-01-503901 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 20010930 FILED AS OF DATE: 20011113 FILER: COMPANY DATA: COMPANY CONFORMED NAME: RELIANT ENERGY RESOURCES CORP CENTRAL INDEX KEY: 0001042773 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 760511406 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-13265 FILM NUMBER: 1781144 BUSINESS ADDRESS: STREET 1: 1111 LOUISIANA ST CITY: HOUSTON STATE: TX ZIP: 77002 BUSINESS PHONE: 7132073000 FORMER COMPANY: FORMER CONFORMED NAME: HI MERGER INC DATE OF NAME CHANGE: 19970721 FORMER COMPANY: FORMER CONFORMED NAME: NORAM ENERGY CORP/ DATE OF NAME CHANGE: 19970808 FILER: COMPANY DATA: COMPANY CONFORMED NAME: RELIANT ENERGY INC CENTRAL INDEX KEY: 0000048732 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 740694415 STATE OF INCORPORATION: TX FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-03187 FILM NUMBER: 1781143 BUSINESS ADDRESS: STREET 1: 1111 LOUISIANA CITY: HOUSTON STATE: TX ZIP: 77002 BUSINESS PHONE: 7132073000 MAIL ADDRESS: STREET 1: 611 WALKER CITY: HOUSTON STATE: TX ZIP: 77002 FORMER COMPANY: FORMER CONFORMED NAME: HOUSTON INDUSTRIES INC DATE OF NAME CHANGE: 19970807 FORMER COMPANY: FORMER CONFORMED NAME: HOUSTON LIGHTING & POWER CO DATE OF NAME CHANGE: 19920703 10-Q 1 h92033e10-q.txt RELIANT ENERGY INCORPORATED - SEPTEMBER 30 2001 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q (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, 2001 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 1-3187 RELIANT ENERGY, INCORPORATED (Exact name of registrant as specified in its charter) Texas 74-0694415 (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) 207-3000 (Registrant's telephone number, including area code) Commission file number 1-13265 RELIANT ENERGY RESOURCES CORP. (Exact name of registrant as specified in its charter) Delaware 76-0511406 (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) 207-3000 (Registrant's telephone number, including area code) ---------- RELIANT ENERGY RESOURCES CORP. MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION H(1)(a) AND (b) OF FORM 10-Q AND IS THEREFORE FILING THIS FORM 10-Q WITH THE REDUCED DISCLOSURE FORMAT. Indicate by check mark whether the registrants: (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding twelve months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes X No As of November 7, 2001, Reliant Energy, Incorporated had 298,149,968 shares of common stock outstanding, including 7,298,389 ESOP shares not deemed outstanding for financial statement purposes and excluding 4,511,691 shares held as treasury stock. As of November 7, 2001, all 1,000 shares of Reliant Energy Resources Corp. common stock were held by Reliant Energy, Incorporated. THIS COMBINED QUARTERLY REPORT ON FORM 10-Q IS SEPARATELY FILED BY RELIANT ENERGY, INCORPORATED (RELIANT ENERGY) AND RELIANT ENERGY RESOURCES CORP. (RERC CORP). INFORMATION CONTAINED HEREIN RELATING TO RERC CORP. IS FILED BY RELIANT ENERGY AND SEPARATELY BY RERC CORP. ON ITS OWN BEHALF. RERC CORP. MAKES NO REPRESENTATION AS TO INFORMATION RELATING TO RELIANT ENERGY OR ANY OTHER AFFILIATE OR SUBSIDIARY OF RELIANT ENERGY (EXCEPT AS IT MAY RELATE TO RERC CORP. AND ITS SUBSIDIARIES). RELIANT ENERGY, INCORPORATED AND RELIANT ENERGY RESOURCES CORP. QUARTERLY REPORT ON FORM 10-Q FOR THE QUARTER ENDED SEPTEMBER 30, 2001 TABLE OF CONTENTS PART I. FINANCIAL INFORMATION Reliant Energy: Item 1. Financial Statements.................................................................1 Statements of Consolidated Income Three and Nine Months Ended September 30, 2000 and 2001 (unaudited)......................1 Consolidated Balance Sheets December 31, 2000 and September 30, 2001 (unaudited).....................................2 Statements of Consolidated Cash Flows Nine Months Ended September 30, 2000 and 2001 (unaudited)................................4 Notes to Unaudited Consolidated Financial Statements.....................................5 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations of Reliant Energy and Subsidiaries...........................................23 Item 3. Quantitative and Qualitative Disclosures About Market Risk..........................38 RERC Corp.: Item 1. Financial Statements................................................................41 Statements of Consolidated Operations Three and Nine Months Ended September 30, 2000 and 2001 (unaudited).....................41 Consolidated Balance Sheets December 31, 2000 and September 30, 2001 (unaudited)....................................42 Statements of Consolidated Cash Flows Nine Months Ended September 30, 2000 and 2001 (unaudited)...............................44 Notes to Unaudited Consolidated Financial Statements....................................45 Item 2. Management's Narrative Analysis of the Results of Operations of RERC Corp. and Subsidiaries............................................................................52 PART II. OTHER INFORMATION Item 1. Legal Proceedings...................................................................56 Item 5. Other Information...................................................................56 Item 6. Exhibits and Reports on Form 8-K....................................................57
PART I. FINANCIAL INFORMATION RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED INCOME (THOUSANDS OF DOLLARS, EXCEPT PER SHARE AMOUNTS) (UNAUDITED)
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30, -------------------------------- ------------------------------ 2000 2001 2000 2001 -------------- --------------- ------------- ------------- REVENUES ......................................................... $ 9,501,786 $ 12,466,991 $ 19,469,961 $ 37,725,663 EXPENSES: Fuel and cost of gas sold ...................................... 3,894,701 4,018,175 9,149,210 17,074,186 Purchased power ................................................ 3,807,911 6,695,007 5,998,790 15,879,299 Operation and maintenance ...................................... 585,172 674,234 1,614,779 2,008,830 Taxes other than income taxes .................................. 144,322 147,335 369,932 429,149 Depreciation and amortization .................................. 293,422 286,475 706,157 706,240 ------------- -------------- ------------- ------------- Total ...................................................... 8,725,528 11,821,226 17,838,868 36,097,704 ------------- -------------- ------------- ------------- OPERATING INCOME ................................................. 776,258 645,765 1,631,093 1,627,959 ------------- -------------- ------------- ------------- OTHER (EXPENSE) INCOME: Unrealized gain (loss) on AOL Time Warner investment ........... 40,000 (512,447) 242,928 (44,464) Unrealized (loss) gain on indexed debt securities .............. (40,000) 503,077 (242,870) 38,845 Income from equity investments in unconsolidated subsidiaries .. 27,142 2,132 33,108 66,482 Interest expense ............................................... (186,303) (138,275) (533,066) (466,520) Distribution on trust preferred securities ..................... (13,754) (13,900) (40,458) (41,699) Minority interest .............................................. 161 (25,717) 676 (48,908) Other, net ..................................................... 14,070 26,528 61,068 96,348 ------------- -------------- ------------- ------------- Total ...................................................... (158,684) (158,602) (478,614) (399,916) ------------- -------------- ------------- ------------- INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES, EXTRAORDINARY ITEM, CUMULATIVE EFFECT OF ACCOUNTING CHANGE AND PREFERRED DIVIDENDS ............................................ 617,574 487,163 1,152,479 1,228,043 Income Tax Expense ............................................. 221,807 196,863 386,963 455,780 ------------- -------------- ------------- ------------- INCOME FROM CONTINUING OPERATIONS BEFORE EXTRAORDINARY ITEM, CUMULATIVE EFFECT OF ACCOUNTING CHANGE AND PREFERRED DIVIDENDS ...................................................... 395,767 290,300 765,516 772,263 Loss from Discontinued Operations, net of tax of $(3,829) and $(2,015) ..................................................... (6,704) -- (26,814) -- Loss on Disposal of Discontinued Operations, net of tax of $(1,640) ..................................................... -- -- -- (7,294) ------------- -------------- ------------- ------------- INCOME BEFORE EXTRAORDINARY ITEM, CUMULATIVE EFFECT OF ACCOUNTING CHANGE AND PREFERRED DIVIDENDS ...................... 389,063 290,300 738,702 764,969 Extraordinary Item ............................................. -- -- 7,445 -- ------------- -------------- ------------- ------------- INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE AND PREFERRED DIVIDENDS ............................................ 389,063 290,300 746,147 764,969 Cumulative Effect of Accounting Change, net of tax of $33,205 .. -- -- -- 61,619 ------------- -------------- ------------- ------------- INCOME BEFORE PREFERRED DIVIDENDS ................................ 389,063 290,300 746,147 826,588 Preferred Dividends ............................................ 97 97 292 292 ------------- -------------- ------------- ------------- NET INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS ................... $ 388,966 $ 290,203 $ 745,855 $ 826,296 ============= ============== ============= ============= BASIC EARNINGS PER SHARE: Income from Continuing Operations .............................. $ 1.38 $ 1.00 $ 2.68 $ 2.67 Loss from Discontinued Operations, net of tax .................. (0.02) -- (0.09) -- Loss on Disposal of Discontinued Operations, net of tax ........ -- -- -- (0.03) Extraordinary Item ............................................. -- -- 0.03 -- Cumulative Effect of Accounting Change, net of tax ............. -- -- -- 0.22 ------------- -------------- ------------- ------------- Net Income Attributable to Common Stockholders ................. $ 1.36 $ 1.00 $ 2.62 $ 2.86 ============= ============== ============= ============= DILUTED EARNINGS PER SHARE: Income from Continuing Operations .............................. $ 1.36 $ 0.99 $ 2.66 $ 2.65 Loss from Discontinued Operations, net of tax .................. (0.02) -- (0.09) -- Loss on Disposal of Discontinued Operations, net of tax ........ -- -- -- (0.03) Extraordinary Item ............................................. -- -- 0.03 -- Cumulative Effect of Accounting Change, net of tax ............. -- -- -- 0.21 ------------- -------------- ------------- ------------- Net Income Attributable to Common Stockholders ................. $ 1.34 $ 0.99 $ 2.60 $ 2.83 ============= ============== ============= =============
See Notes to the Company's Interim Financial Statements 1 RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (THOUSANDS OF DOLLARS) (UNAUDITED) ASSETS
DECEMBER 31, SEPTEMBER 30, 2000 2001 ------------- ------------- CURRENT ASSETS: Cash and cash equivalents ............................ $ 175,972 $ 294,816 Investment in AOL Time Warner common stock ........... 896,824 852,361 Accounts receivable, net ............................. 2,623,492 1,840,682 Accrued unbilled revenues ............................ 592,618 264,724 Fuel stock and petroleum products .................... 213,484 327,811 Materials and supplies ............................... 269,729 264,215 Price risk management assets ......................... 4,290,803 2,128,025 Non-trading derivative assets ........................ -- 1,425,211 Margin deposits on energy trading activities ......... 521,004 351,756 Other ................................................ 253,335 172,876 ------------- ------------- Total current assets ............................... 9,837,261 7,922,477 ------------- ------------- Property, plant and equipment ........................... 22,391,874 23,732,570 Less accumulated depreciation and amortization .......... (7,131,698) (7,389,815) ------------- ------------- Property, plant and equipment, net ................... 15,260,176 16,342,755 ------------- ------------- OTHER ASSETS: Goodwill and other intangibles, net .................. 3,080,686 2,986,762 Regulatory assets .................................... 1,926,103 1,374,418 Price risk management assets ......................... 544,909 689,983 Non-trading derivative assets ........................ -- 630,326 Equity investments in unconsolidated subsidiaries .... 108,727 141,633 Stranded costs indemnification receivable ............ -- 353,000 Net assets of discontinued operations ................ 194,858 118,097 Other ................................................ 746,709 949,742 ------------- ------------- Total other assets ................................. 6,601,992 7,243,961 ------------- ------------- TOTAL ASSETS ..................................... $ 31,699,429 $ 31,509,193 ============= =============
See Notes to the Company's Interim Financial Statements 2 RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS - (CONTINUED) (THOUSANDS OF DOLLARS) (UNAUDITED) LIABILITIES AND STOCKHOLDERS' EQUITY
DECEMBER 31, SEPTEMBER 30, 2000 2001 ------------- ------------- CURRENT LIABILITIES: Short-term borrowings ................................................... $ 5,004,494 $ 3,015,490 Current portion of long-term debt ....................................... 1,623,202 571,079 Indexed debt securities derivative ...................................... -- 749,413 Accounts payable ........................................................ 3,057,948 1,518,245 Taxes accrued ........................................................... 172,449 801,100 Interest accrued ........................................................ 103,489 126,702 Dividends declared ...................................................... 110,893 112,057 Price risk management liabilities ....................................... 4,272,771 2,156,798 Non-trading derivative liabilities ...................................... -- 1,415,196 Margin deposits from customers on energy trading activities ............. 284,603 239,350 Accumulated deferred income taxes ....................................... 309,008 376,140 Other ................................................................... 630,357 596,409 ------------- ------------- Total current liabilities ............................................. 15,569,214 11,677,979 ------------- ------------- OTHER LIABILITIES: Accumulated deferred income taxes ....................................... 2,548,891 2,497,178 Unamortized investment tax credits ...................................... 265,737 251,989 Price risk management liabilities ....................................... 530,263 730,859 Non-trading derivative liabilities ...................................... -- 578,921 Benefit obligations ..................................................... 491,964 550,815 Other ................................................................... 1,100,505 1,180,689 ------------- ------------- Total other liabilities ............................................... 4,937,360 5,790,451 ------------- ------------- LONG-TERM DEBT ............................................................. 4,996,095 5,400,854 ------------- ------------- COMMITMENTS AND CONTINGENCIES (NOTES 1 AND 12) MINORITY INTEREST IN CONSOLIDATED SUBSIDIARIES ............................. 9,345 1,226,844 ------------- ------------- COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUSTS HOLDING SOLELY JUNIOR SUBORDINATED DEBENTURES OF THE COMPANY ................................................................. 705,355 705,680 ------------- ------------- STOCKHOLDERS' EQUITY: Cumulative preferred stock .............................................. 9,740 9,740 Common stock ............................................................ 3,257,190 3,887,007 Treasury stock .......................................................... (120,856) (113,336) Unearned ESOP stock ..................................................... (161,158) (137,907) Retained earnings ....................................................... 2,520,350 3,020,515 Accumulated other comprehensive (loss) income ........................... (23,206) 41,366 ------------- ------------- Total stockholders' equity ............................................ 5,482,060 6,707,385 ------------- ------------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY .......................... $ 31,699,429 $ 31,509,193 ============= =============
See Notes to the Company's Interim Financial Statements 3 RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED CASH FLOWS (THOUSANDS OF DOLLARS) (UNAUDITED)
NINE MONTHS ENDED SEPTEMBER 30, ------------------------------- 2000 2001 ------------ ------------ CASH FLOWS FROM OPERATING ACTIVITIES: Net income attributable to common stockholders .......................... $ 745,855 $ 826,296 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization ......................................... 706,157 706,240 Deferred income taxes ................................................. (131,299) (169,898) Investment tax credits ................................................ (13,748) (13,748) Cumulative effect of accounting change, net ........................... -- (61,619) Unrealized (gain) loss on AOL Time Warner investment .................. (242,928) 44,464 Unrealized loss (gain) on indexed debt securities ..................... 242,870 (38,845) Undistributed earnings of unconsolidated subsidiaries ................. (33,108) (31,884) Proceeds from sale of debt securities ................................. 123,428 -- Impairment of marketable equity securities ............................ 26,504 -- Extraordinary item .................................................... (7,445) -- Net cash provided by discontinued operations .......................... 26,180 87,140 Minority interest ..................................................... (676) 48,908 Changes in other assets and liabilities: Accounts receivable, net ............................................ (651,019) 1,166,205 Inventory ........................................................... (101,734) (102,096) Accounts payable .................................................... 599,033 (1,541,046) Federal tax refund .................................................. 52,817 -- Fuel cost under-recovery/surcharge .................................. (506,439) 169,265 Net price risk management assets and liabilities .................... (24,436) 102,269 Margin deposits on energy trading activities, net ................... (62,755) 123,995 Prepaid lease obligation ............................................ -- (195,239) Interest and taxes accrued .......................................... 291,143 641,660 Other current assets ................................................ (56,290) 99,156 Other current liabilities ........................................... 258,624 (36,006) Other assets ........................................................ (156,320) (53,779) Other liabilities ................................................... 4,225 65,897 Other, net ............................................................ (14,313) 131,113 ------------ ------------ Net cash provided by operating activities ......................... 1,074,326 1,968,448 ------------ ------------ CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures .................................................... (1,237,814) (1,543,193) Business acquisitions, net of cash acquired ............................. (2,119,667) -- Proceeds from sale-leaseback transactions ............................... 1,000,000 -- Payment of business purchase obligation ................................. (981,789) -- Investments in unconsolidated subsidiaries .............................. (5,196) -- Net cash used in discontinued operations ................................ (38,099) (10,397) Other, net .............................................................. 81,130 (38,117) ------------ ------------ Net cash used in investing activities ............................. (3,301,435) (1,591,707) ------------ ------------ CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from long-term debt, net ....................................... 467,285 544,632 Increase (decrease) in short-term borrowing, net ........................ 2,819,479 (1,824,195) Payments of long-term debt .............................................. (645,081) (408,398) Payment of common stock dividends ....................................... (319,467) (324,956) Proceeds from issuance of stock ......................................... 39,742 91,798 Proceeds from subsidiary issuance of stock .............................. -- 1,697,848 Purchase of treasury stock by subsidiary ................................ -- (20,420) Purchase of treasury stock .............................................. (27,561) -- Net cash provided by discontinued operations ............................ 45,813 -- Other, net .............................................................. 1,990 (8,341) ------------ ------------ Net cash provided by (used in) financing activities ................. 2,382,200 (252,032) ------------ ------------ EFFECT OF EXCHANGE RATE CHANGES ON CASH ................................... 9,681 (5,865) ------------ ------------ NET INCREASE IN CASH AND CASH EQUIVALENTS ................................. 164,772 118,844 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD .......................... 80,767 175,972 ------------ ------------ CASH AND CASH EQUIVALENTS AT END OF PERIOD ................................ $ 245,539 $ 294,816 ============ ============ SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash Payments: Interest (net of amounts capitalized) ................................... $ 560,922 $ 466,296 Income taxes ............................................................ 266,841 118,672
See Notes to the Company's Interim Financial Statements 4 RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (1) BASIS OF PRESENTATION Included in this combined Quarterly Report on Form 10-Q (Form 10-Q) for Reliant Energy, Incorporated (Reliant Energy), together with its subsidiaries (the Company), and for Reliant Energy Resources Corp. (RERC Corp.) and its subsidiaries (collectively, RERC) are Reliant Energy's and RERC Corp.'s consolidated interim financial statements and notes (Interim Financial Statements), including these companies' wholly owned and majority owned subsidiaries. The Interim Financial Statements are unaudited, omit certain financial statement disclosures and should be read with the combined Annual Report on Form 10-K of Reliant Energy (Reliant Energy Form 10-K) and RERC Corp. (RERC Corp. Form 10-K) for the year ended December 31, 2000 and the Quarterly Reports on Form 10-Q of Reliant Energy (Reliant Energy First Quarter 10-Q) and RERC Corp. (RERC Corp. First Quarter 10-Q) for the quarter ended March 31, 2001 and the Quarterly Reports on Form 10-Q of Reliant Energy (Reliant Energy Second Quarter 10-Q) and RERC Corp. (RERC Corp. Second Quarter 10-Q) for the quarter ended June 30, 2001. The preparation of financial statements in conformity with generally accepted accounting principles 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. 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 for the respective periods. Amounts reported in the Company's 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 fluctuations in demand for energy and energy services, (b) changes in energy commodity prices, (c) timing of maintenance and other expenditures and (d) acquisitions and dispositions of businesses, assets and other interests. In addition, certain amounts from the prior year have been reclassified to conform to the Company's presentation of financial statements in the current year. These reclassifications do not affect the earnings of the Company. The following notes to the consolidated financial statements in the Reliant Energy Form 10-K relate to certain contingencies. These notes, as updated herein, are incorporated herein by reference: Notes to Consolidated Financial Statements of Reliant Energy (Reliant Energy 10-K Notes): Note 2(f) (Summary of Significant Accounting Policies -- Regulatory Assets), Note 3 (Business Acquisitions), Note 4 (Regulatory Matters), Note 5 (Derivative Financial Instruments), Note 8 (Indexed Debt Securities (ACES and ZENS) and AOL Time Warner Securities), Note 14 (Commitments and Contingencies) and Note 20 (Subsequent Events). For information regarding certain legal, tax and regulatory proceedings and environmental matters, see Note 12. In September 2001, the Company announced that it is evaluating strategic alternatives for its European Energy segment, including the possible sale, in order to pursue business opportunities that are more in line with its domestic wholesale energy strategies. (2) NEW ACCOUNTING PRONOUNCEMENTS In July 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 141 "Business Combinations" (SFAS No. 141) and SFAS No. 142 "Goodwill and Other Intangible Assets" (SFAS No. 142). 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. SFAS No. 142 provides for a nonamortization approach, whereby 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 5 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 provisions of each statement which apply to goodwill and intangible assets acquired prior to June 30, 2001 will be adopted by the Company on January 1, 2002. The Company is in the process of determining the effect of adoption of SFAS No. 141 and SFAS No. 142 on its consolidated financial statements. 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 (APB Opinion No. 30), 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 is effective for fiscal years beginning after December 15, 2001, with early adoption encouraged. SFAS No. 144 is not expected to 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 than is currently permitted. The Company plans to adopt SFAS No. 144 on January 1, 2002. (3) DERIVATIVE FINANCIAL INSTRUMENTS Adoption of SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities" as amended (SFAS No. 133) on January 1, 2001 resulted in an after-tax increase in net income of $61 million and a cumulative after-tax increase in accumulated other comprehensive loss of $252 million. The adoption also increased current assets, long-term assets, current liabilities and long-term liabilities by $703 million, $252 million, $805 million and $340 million, respectively, in the Company's Consolidated Balance Sheet. Due to the adoption, the Company also reclassified $788 million related to the Company's Zero-Premium Exchangeable Subordinated Notes (ZENS) from the current portion of long-term debt to indexed debt securities derivative. During the nine months ended September 30, 2001, losses of $145 million of the initial transition adjustment recognized in other comprehensive income were realized in net income. For additional information regarding the adoption of SFAS No. 133 and the Company's accounting policies for derivative financial instruments, see Note 2 of Reliant Energy First Quarter 10-Q, which note is incorporated by reference herein. 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. One criteria of this previously approved guidance was revised in October 2001 and will become effective on January 1, 2002. The Company is currently in the process of determining the effect of adoption of the revised guidance. 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 is April 1, 2002. The Company is currently assessing the impact of this recently cleared issue and does not believe it will have a material impact on the Company's consolidated financial statements. Cash Flow Hedges. During the nine months ended September 30, 2001, the amount of hedge ineffectiveness recognized in earnings from derivatives that are designated and qualify as cash flow hedges was immaterial. No component of the derivative instruments' gain or loss was excluded from the assessment of effectiveness. During the 6 nine months ended September 30, 2001, there were no deferred gains or losses 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, 2001, current non-trading derivative assets and liabilities and corresponding amounts in accumulated other comprehensive income are expected to be reclassified into net income during the next twelve months. Hedge of Net Investment in Foreign Subsidiaries. The Company has substantially hedged its net investment in its European Energy segment through a combination of Euro-denominated borrowings, foreign currency swaps and foreign currency forward contracts. These are designed to reduce the Company's exposure to changes in foreign currency rates. During the nine months ended September 30, 2001, the derivative and non-derivative instruments designated as hedging the net investment in the Company's European Energy segment resulted in a loss of $3 million, which is included in the balance of the cumulative translation adjustment. Other Derivatives. Upon adoption of SFAS No. 133 effective January 1, 2001, the Company's indexed debt securities obligations related to its ZENS obligation were bifurcated into a debt component valued at $122 million and an embedded derivative component valued at $788 million. Changes in the fair value of the derivative component are recorded in the Company's Statements of Consolidated Income. During the nine months ended September 30, 2001, the Company recorded a $39 million gain associated with the fair value of the derivative component of the indexed debt securities obligations. During the nine months ended September 30, 2001, the Company recorded a $44 million loss on the Company's investment in AOL Time Warner Inc. common stock. Changes in the fair value of the Company's Investment in AOL Time Warner Inc. common stock should substantially offset changes in the fair value of the derivative component of the ZENS. In December 2000, the Dutch parliament adopted legislation allocating to the Dutch generation sector, including an indirect Dutch generating subsidiary of the Company, Reliant Energy Power Generation Benelux N.V. (REPGB), previously named N.V. UNA (UNA), financial responsibility for various stranded costs 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 electricity and gas under a gas supply contract and three electricity contracts. These contracts are derivatives pursuant to SFAS No. 133. As of September 30, 2001, the Company has recognized $138 million in short-term and long-term non-trading derivative liabilities for REPGB's portion of these stranded costs contracts. For additional information regarding REPGB's stranded costs and the related indemnification by former shareholders of these stranded costs, see Note 12(e). (4) ACQUISITIONS (a) Reliant Energy Mid-Atlantic Power Holdings, LLC. On May 12, 2000, an indirect subsidiary of the Company purchased entities owning electric power generating assets and development sites located in Pennsylvania, New Jersey and Maryland having an aggregate net generating capacity of approximately 4,262 megawatts (MW). With the exception of development entities that were sold to another subsidiary of the Company in July 2000, the assets of the entities acquired are held by Reliant Energy Mid-Atlantic Power Holdings, LLC (REMA). The purchase price for the May 2000 transaction was $2.1 billion, subject to post-closing adjustments which management does not believe will be material. The Company accounted for the acquisition as a purchase with assets and liabilities of REMA reflected at their estimated fair values. The Company's fair value adjustments related to the acquisition primarily included adjustments in property, plant and equipment, air emissions regulatory allowances, materials and supplies inventory, environmental reserves and related deferred taxes. The Company finalized these fair value adjustments in May 2001. There were no additional material modifications to the preliminary adjustments from December 31, 2000. For additional information regarding the acquisition of REMA, see Note 3(a) to Reliant Energy 10-K Notes. The Company's results of operations include the results of REMA only for the period beginning May 12, 2000. The following table presents selected actual financial information and pro forma information for the three and nine months ended September 30, 2000, as if the acquisition had occurred on January 1, 2000. Pro forma amounts also give effect to the sale and leaseback of interests in three of the REMA generating plants, consummated in August 2000. For additional information regarding sale and leaseback transactions, see Note 14(c) to Reliant Energy 10-K Notes. 7
THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, 2000 SEPTEMBER 30, 2000 ------------------------------- ------------------------------- ACTUAL PRO FORMA ACTUAL PRO FORMA --------------- --------------- --------------- --------------- (IN MILLIONS, EXCEPT PER SHARE AMOUNTS) Revenues............................................ $ 9,502 $ 9,502 $ 19,470 $ 19,636 Income from continuing operations................... 396 400 766 745 Net income attributable to common stockholders...... 389 393 746 725 Basic earnings per share............................ $ 1.36 $ 1.38 $ 2.62 $ 2.55 Diluted earnings per share.......................... $ 1.34 $ 1.36 $ 2.60 $ 2.53
These 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 the REMA entities had occurred on January 1, 2000. Purchase-related adjustments to the results of operations include the effects on depreciation and amortization, interest expense and income taxes. (b) Orion Power Holdings, Inc. In September 2001, Reliant Resources and Orion Power Holdings, Inc. (Orion Power) entered into a definitive merger agreement, under which Reliant Resources agreed to acquire all of the outstanding shares of Orion Power for $26.80 per share in cash in a transaction valued at approximately $2.9 billion. In the merger, Reliant Resources will also assume approximately $1.8 billion of Orion Power's net debt obligations. Orion Power is an independent electric power generating company formed in March 1998 to acquire, develop, own and operate power-generating facilities in the newly deregulated wholesale markets throughout North America. Orion Power has 81 power plants currently in operation with a total capacity of 5,644 MW and an additional 2,855 MW in construction and various stages of development. The merger is conditioned upon approval by Orion Power's shareholders and the receipt of certain regulatory approvals including the Federal Trade Commission, the New York Public Service Commission and Federal Energy Regulatory Commission (FERC). (5) DISCONTINUED OPERATIONS Effective December 1, 2000, Reliant Energy's Board of Directors approved a plan to dispose of the Company's Latin American segment through sales of its assets. Accordingly, the Company is reporting the results of its Latin American segment as discontinued operations for all periods presented in the Interim Financial Statements in accordance with APB Opinion No. 30. During the three months ended March 31, 2001, the Company recorded an additional loss on disposal of $7 million (after-tax) related to its Latin American segment. No additional loss was recorded during the three months ended June 30, 2001 or September 30, 2001. (6) DEPRECIATION AND AMORTIZATION The Company's depreciation expense for the quarter and nine months ended September 30, 2000 was $105 million and $291 million, respectively, compared to $107 million and $307 million for the same periods in 2001. Goodwill amortization related to acquisitions was $19 million and $61 million for the quarter and nine months ended September 30, 2000, respectively, compared to $39 million and $81 million for the same periods in 2001. Other amortization expense, including amortization of regulatory assets, was $169 million and $354 million for the quarter and nine months ended September 30, 2000, respectively, compared to $140 million and $318 million for the same periods in 2001. In the third quarter of 2001, the Company accelerated amortization of $19 million of certain regulatory assets related to energy conservation management as required by a Public Utility Commission of Texas (Texas Utility Commission) order dated October 3, 2001. In June 1998, the Texas Utility Commission issued an order approving a transition to competition plan (Transition Plan) filed by Reliant Energy HL&P in December 1997. For information regarding the additional depreciation of electric utility generating assets and the redirection of transmission and distribution (T&D) depreciation to generation assets under the Transition Plan, see Note 2(g) to Reliant Energy 10-K Notes. In June 1999, the Texas legislature adopted the Texas Electric Choice Plan (Legislation), which substantially amended the regulatory structure governing electric utilities in Texas in order to allow retail electric competition beginning on January 1, 2002. The Legislation provides that depreciation expense for T&D related assets may be redirected to generation assets from 1999 through 2001 for regulatory purposes. Because the electric generation operations portion of Reliant Energy HL&P discontinued application of SFAS No. 71 effective June 30, 1999, such operations can no longer record additional or redirected depreciation for financial reporting purposes. However, for regulatory purposes, the Company continues to redirect T&D depreciation to generation assets. As of December 31, 2000 and 8 September 30, 2001, the cumulative amount of redirected depreciation for regulatory purposes was $611 million and $783 million, respectively. In 1999, the Company determined that approximately $800 million of Reliant Energy HL&P's electric generation assets were impaired. The Legislation provides for recovery of this impairment through regulated cash flows. Therefore, a regulatory asset was recorded for an amount equal to the impairment in the Company's Consolidated Balance Sheets. The Company amortizes this regulatory asset as it is recovered from regulated cash flows. Amortization expense related to the recoverable impaired plant costs was $135 million and $282 million for the quarter and nine months ended September 30, 2000, respectively, compared to $98 million and $221 million for the same periods in 2001. For additional information regarding redirected and accelerated depreciation, please read Note 12(f). (7) COMPREHENSIVE INCOME The following table summarizes the components of total comprehensive income:
FOR THE THREE MONTHS ENDED FOR THE NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, --------------------------- --------------------------- 2000 2001 2000 2001 ----------- ----------- ----------- ----------- (IN MILLIONS) Net income attributable to common stockholders ..... $ 389 $ 290 $ 746 $ 826 Other comprehensive income (loss): Foreign currency translation adjustments from continuing operations .......................... (5) (79) (10) (74) Foreign currency translation adjustments from discontinued operations ........................ (10) -- (33) -- Additional minimum non-qualified pension liability adjustment ........................... -- (3) -- (2) Cumulative effect of adoption of SFAS No. 133 .... -- -- -- (252) Net deferred (loss) gain from cash flow hedges ... -- (21) -- 427 Reclassification of net deferred gain from cash flow hedges realized in net income ............. -- (127) -- (44) Unrealized (loss) gain on available-for-sale securities ..................................... (2) (3) -- 10 Reclassification adjustment for impairment loss on available-for-sale securities realized in net income ..................................... 3 -- 17 -- ----------- ----------- ----------- ----------- Comprehensive income ............................... $ 375 $ 57 $ 720 $ 891 =========== =========== =========== ===========
(8) SHORT-TERM BORROWINGS As of September 30, 2001, the Company had credit facilities, which included the facilities of various financing subsidiaries, Reliant Resources, REPGB and RERC Corp., with financial institutions which provide for an aggregate of $8.7 billion in committed credit, of which $4.1 billion was unused. As of September 30, 2001, borrowings of $3.9 billion were outstanding or supported under these credit facilities of which $0.9 billion were classified as long-term debt, based on availability of committed credit with expiration dates exceeding one year and management's intention to maintain these borrowings in excess of one year. Various credit facilities aggregating $2.3 billion may be used for letters of credit of which $0.7 billion were outstanding as of September 30, 2001. Interest rates on borrowings are based on the London interbank offered rate (LIBOR) plus a margin, Euro interbank deposits plus a margin, a base rate or a rate determined through a bidding process. Credit facilities aggregating $3.1 billion are unsecured. The credit facilities contain covenants and requirements that must be met to borrow funds and obtain letters of credit, as applicable. Such covenants are not anticipated to materially restrict the borrowers from borrowing funds or obtaining letters of credit, as applicable, under such facilities. As of September 30, 2001, the borrowers are in compliance with the covenants under all of these credit agreements. 9 (9) EARNINGS PER SHARE The following table presents Reliant Energy's basic and diluted earnings per share (EPS) calculation:
FOR THE THREE MONTHS ENDED FOR THE NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------------------- ------------------------------- 2000 2001 2000 2001 ------------- ------------- ------------- ------------- (IN MILLIONS, EXCEPT SHARE AND PER SHARE AMOUNTS) Basic EPS Calculation: Income from continuing operations .................... $ 396 $ 290 $ 766 $ 772 Loss from discontinued operations, net of tax ........ (7) -- (27) -- Loss on disposal of discontinued operations, net of tax ............................................. -- -- -- (7) Extraordinary item ................................... -- -- 7 -- Cumulative effect of accounting change, net of tax ... -- -- -- 61 ------------- ------------- ------------- ------------- Net income attributable to common stockholders ....... $ 389 $ 290 $ 746 $ 826 ============= ============= ============= ============= Weighted average shares outstanding .................... 285,183,000 290,318,000 284,170,000 289,143,000 ============= ============= ============= ============= Basic EPS: Income from continuing operations .................... $ 1.38 $ 1.00 $ 2.68 $ 2.67 Loss from discontinued operations, net of tax ........ (0.02) -- (0.09) -- Loss on disposal of discontinued operations, net of tax ............................................. -- -- -- (0.03) Extraordinary item ................................... -- -- 0.03 -- Cumulative effect of accounting change, net of tax ... -- -- -- 0.22 ------------- ------------- ------------- ------------- Net income attributable to common stockholders ....... $ 1.36 $ 1.00 $ 2.62 $ 2.86 ============= ============= ============= ============= Diluted EPS Calculation: Net income attributable to common stockholders ....... $ 389 $ 290 $ 746 $ 826 Plus: Income impact of assumed conversions: Interest on 61/4% convertible trust preferred securities ......................................... -- -- -- -- ------------- ------------- ------------- ------------- Total earnings effect assuming dilution .............. $ 389 $ 290 $ 746 $ 826 ============= ============= ============= ============= Weighted average shares outstanding .................... 285,183,000 290,318,000 284,170,000 289,143,000 Plus: Incremental shares from assumed conversions(1): Stock options ...................................... 3,595,000 1,147,000 1,837,000 1,942,000 Restricted stock ................................... 807,000 733,000 807,000 733,000 6 1/4% convertible trust preferred securities ...... 14,000 14,000 14,000 14,000 ------------- ------------- ------------- ------------- Weighted average shares assuming dilution ............ 289,599,000 292,212,000 286,828,000 291,832,000 ============= ============= ============= ============= Diluted EPS: Income from continuing operations .................... $ 1.36 $ 0.99 $ 2.66 $ 2.65 Loss from discontinued operations, net of tax ........ (0.02) -- (0.09) -- Loss on disposal of discontinued operations, net of tax ............................................. -- -- -- (0.03) Extraordinary item ................................... -- -- 0.03 -- Cumulative effect of accounting change, net of tax ... -- -- -- 0.21 ------------- ------------- ------------- ------------- Net income attributable to common stockholders ....... $ 1.34 $ 0.99 $ 2.60 $ 2.83 ============= ============= ============= =============
- ---------- (1) For the three months ended September 30, 2001, the computation of diluted EPS excludes 2,319,488 purchase options for shares of common stock that have exercise prices (ranging from $31.73 to $50.00 per share) greater than the per share average market price for the period and would thus be anti-dilutive if exercised. For the nine months ended September 30, 2000 and 2001, the computation of diluted EPS excludes 485,119 and 2,005,338 purchase options, respectively, for shares of common stock that have exercise prices (ranging from $28.72 to $32.22 per share and $39.53 to $50.00 per share for the first nine months of 2000 and 2001, respectively) greater than the per share average market price for the period and would thus be anti-dilutive if exercised. (10) CAPITAL STOCK Common Stock. Reliant Energy has 700,000,000 authorized shares of common stock. At December 31, 2000, 299,914,791 shares of Reliant Energy common stock were issued and 286,464,709 shares of Reliant Energy 10 common stock were outstanding. At September 30, 2001, 302,533,344 shares of Reliant Energy common stock were issued and 290,723,264 shares of Reliant Energy common stock were outstanding. Outstanding common shares exclude (a) shares pledged to secure a loan to Reliant Energy's Employee Stock Ownership Plan (8,638,889 and 7,298,389 at December 31, 2000 and September 30, 2001, respectively) and (b) treasury shares (4,811,193 and 4,511,691 at December 31, 2000 and September 30, 2001, respectively). Reliant Energy declared dividends of $0.375 per share in the third quarter of 2000 and 2001 and $1.125 per share in the first nine months of 2000 and 2001. During the nine months ended September 30, 2001, Reliant Energy issued 300,000 shares of Reliant Energy common stock out of its treasury stock. As of September 30, 2001, Reliant Energy was authorized to purchase up to $271 million of Reliant Energy common stock under its stock repurchase program. (11) TRUST PREFERRED SECURITIES (a) Reliant Energy. Statutory business trusts created by Reliant Energy have issued trust preferred securities, the terms of which, and the related series of junior subordinated debentures, are described below (in millions):
AGGREGATE LIQUIDATION AMOUNT ---------------------------- MANDATORY DECEMBER 31, SEPTEMBER 30, DISTRIBUTION RATE/ REDEMPTION DATE/ JUNIOR SUBORDINATED TRUST 2000 2001 INTEREST RATE MATURITY DATE DEBENTURES - ---------------------- ------------ ------------- ------------------ -------------- ----------------------------- REI Trust I $ 375 $ 375 7.20% March 2048 7.20% Junior Subordinated Debentures due 2048 HL&P Capital Trust I $ 250 $ 250 8.125% March 2046 8.125% Junior Subordinated Deferrable Interest Debentures Series A HL&P Capital Trust II $ 100 $ 100 8.257% February 2037 8.257% Junior Subordinated Deferrable Interest Debentures Series B
For additional information regarding the $625 million of preferred securities and the $100 million of capital securities, see Note 11 to Reliant Energy 10-K Notes. The sole asset of each trust consists of junior subordinated debentures of Reliant Energy having interest rates and maturity dates corresponding to each issue of preferred or capital securities, and the principal amounts corresponding to the common and preferred or capital securities issued by that trust. (b) RERC Corp. A statutory business trust created by RERC Corp. has issued convertible trust preferred securities, the terms of which, and the related series of convertible junior subordinated debentures, are described below (in millions):
AGGREGATE LIQUIDATION AMOUNT ---------------------------- MANDATORY DECEMBER 31, SEPTEMBER 30, DISTRIBUTION RATE/ REDEMPTION DATE/ JUNIOR SUBORDINATED TRUST 2000 2001 INTEREST RATE MATURITY DATE DEBENTURES - ---------------------- ------------ ------------- ------------------ ---------------- ----------------------------- Resources Trust $ 1 $ 1 6.25% June 2026 6.25% Convertible Junior Subordinated Debentures due 2026
For additional information regarding the convertible preferred securities, see Note 11 to Reliant Energy 10-K Notes and Note 6 to RERC Corp. 10-K Notes. The sole asset of the trust consists of convertible junior subordinated debentures of RERC Corp. having an interest rate and maturity date corresponding to the convertible preferred securities, and the principal amount corresponding to the common and convertible preferred securities issued by the trust. 11 (12) COMMITMENTS, CONTINGENCIES AND REGULATORY MATTERS (a) Legal Matters. Reliant Energy HL&P Municipal Franchise Fee Lawsuits. In February 1996, the cities of Wharton, Galveston and Pasadena filed suit, for themselves and a proposed class of all similarly situated cities in Reliant Energy HL&P's service area, against Reliant Energy and Houston Industries Finance, Inc. (formerly a wholly owned subsidiary of Reliant Energy) alleging underpayment of municipal franchise fees. Plaintiffs claim that they are entitled to 4% of all receipts of any kind for business conducted within these cities over the previous four decades. Because the franchise ordinances at issue affecting Reliant Energy HL&P expressly impose fees only on its own receipts and only from sales of electricity for consumption within a city, the Company regards all of plaintiffs' allegations as spurious and is vigorously contesting the case. The plaintiffs' pleadings asserted that their damages exceeded $250 million. The 269th Judicial District Court for Harris County granted partial summary judgment in favor of Reliant Energy dismissing all claims for franchise fees based on sales tax collections. Other motions for partial summary judgment were denied. A six-week jury trial of the original claimant cities (but not the class of cities) ended on April 4, 2000 (Three Cities case). Although the jury found for Reliant Energy on many issues, they found in favor of the original claimant cities on three issues, and assessed a total of $4 million in actual and $30 million in punitive damages. However, the jury also found in favor of Reliant Energy on the affirmative defense of laches, a defense similar to a statute of limitations defense, due to the original claimant cities having unreasonably delayed bringing their claims during the 43 years since the alleged wrongs began. The trial court in the Three Cities case granted most of Reliant Energy's motions to disregard the jury's findings. The trial court's rulings reduced the judgment to $1.7 million, including interest, plus an award of $13.7 million in legal fees. In addition, the trial court granted Reliant Energy's motion to decertify the class and vacated its prior orders certifying a class. Following this ruling, 45 cities filed individual suits against Reliant Energy in the District Court of Harris County. The extent to which issues in the Three Cities case may affect the claims of the other cities served by Reliant Energy HL&P cannot be assessed until judgments are final and no longer subject to appeal. However, the trial court's rulings disregarding most of the jury's findings are consistent with Texas Supreme Court opinions over the past decade. The Company estimates the range of possible outcomes for the plaintiffs to be between zero and $17 million inclusive of interest and attorneys' fees. The Three Cities case has been appealed. The Company believes that the $1.7 million damage award resulted from serious errors of law and that it will be set aside by the Texas appellate courts. In addition, the Company believes that because of an agreement between the parties limiting fees to a percentage of the damages, reversal of the award of $13.7 million in attorneys' fees in the Three Cities case is probable. California Wholesale Market. Reliant Energy, Reliant Energy Services, Inc. (a wholly owned subsidiary of Reliant Resources), Reliant Energy Power Generation, Inc. (a wholly owned subsidiary of Reliant Resources) and several other subsidiaries of Reliant Resources, as well as three officers of some of these companies, 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. Pursuant to the terms of the master separation agreement between Reliant Energy and Reliant Resources (see Note 4(b) to Reliant Energy 10-K Notes), Reliant Resources has agreed to indemnify Reliant Energy for any damages arising under these lawsuits and may elect to defend these lawsuits at Reliant Resources' own expense. 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 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. In one of the cases, the plaintiffs allege aggregate damages of over $4 billion. Although defendants removed all of these cases to federal court, five of the six cases were remanded back to state court and the parties stipulated to remanding the sixth case. 12 In August 2001, plaintiffs and defendants filed petitions to coordinate the remanded state court cases with plaintiffs seeking coordination in San Francisco Superior Court and defendants seeking coordination in San Diego Superior Court. On September 21, 2001, pursuant to a stipulated briefing schedule, defendants served plaintiffs with their joint demurrer, motion to stay and motion to strike, which are premised in part on federal preemption and the filed rate doctrine (the filed rate doctrine bars all claims, both state and federal, that attempt to challenge a rate that a federal agency has reviewed and approved). On October 12, 2001, San Diego Superior Court Judge Janis Sammartino, the judge assigned to hear the coordination petitions, stayed all the actions pending a decision on coordination. Plaintiffs have voluntarily dismissed Reliant Energy from two of the three class actions in which it was named as a defendant. Plaintiffs have also voluntarily dismissed RERC Corp. from the one action in which it was named as a defendant. The ultimate outcome of the lawsuits cannot be predicted with any degree of certainty at this time. However, the Company believes, based on its analysis to date of the claims asserted in these lawsuits and the underlying facts, that resolution of these lawsuits will not have a material adverse effect on the Company's financial condition, results of operations or cash flows. (b) Environmental Matters. Clean Air Standards. The Company has participated in a lawsuit against the Texas Natural Resource Conservation Commission (TNRCC) regarding the limitation of the emission of oxides of nitrogen (NOx) in the Houston area. A settlement of the lawsuit was reached with the TNRCC in the second quarter of 2001 and revised emissions limitations were adopted by the TNRCC in the third quarter of 2001. The revised limitations provide for an increase in allowable NOx emissions, compared to the original TNRCC requirements, through 2004. Further emission reduction requirements may or may not be required through 2007, depending upon the outcome of further investigations of regional air quality issues. To achieve the TNRCC NOx reduction requirements, the Company anticipates investing up to $738 million in capital and other special project expenditures by 2004, and potentially up to an additional $93 million between 2004 and 2007. The Texas electric restructuring law provides for stranded cost recovery for expenditures incurred before May 1, 2003 to achieve the NOx reduction requirements. Manufactured Gas Plant Sites. RERC and its predecessors operated a manufactured gas plant (MGP) adjacent to the Mississippi River in Minnesota, formerly known as Minneapolis Gas Works (MGW) until 1960. RERC has substantially completed remediation of the main site other than ongoing water monitoring and treatment. The manufactured gas was stored in separate holders. RERC is negotiating clean-up of one such holder. There are six other former MGP sites in the Minnesota service territory. Remediation has been completed on one site. Of the remaining five sites, RERC believes that two were neither owned nor operated by RERC. RERC believes it has no liability with respect to the sites it neither owned nor operated. At September 30, 2001, RERC had accrued $17 million for remediation of the Minnesota sites. At September 30, 2001, the estimated range of possible remediation costs was $8 million to $36 million. The cost estimates of the MGW site are based on studies of that site. The remediation costs for the other sites are based on industry average costs for remediation of sites of similar size. The actual remediation costs will be dependent upon the number of sites remediated, the participation of other potentially responsible parties, if any, and the remediation methods used. Issues relating to the identification and remediation of MGPs are common in the natural gas distribution industry. RERC has received notices from the United States Environmental Protection Agency and others regarding its status as a potentially responsible party (PRP) for other sites. Based on current information, RERC has not been able to quantify a range of environmental expenditures for potential remediation expenditures with respect to other MGP sites. Other Minnesota Matters. At September 30, 2001, RERC had recorded accruals of $4 million (with a maximum estimated exposure of approximately $17 million at September 30, 2001) for other environmental matters in Minnesota for which remediation may be required. Mercury Contamination. The Company's pipeline and distribution operations have in the past employed elemental mercury in measuring and regulating equipment. It is possible that small amounts of mercury may have been spilled in the course of normal maintenance and replacement operations and that these spills may have contaminated the immediate area with elemental mercury. The Company has found this type of contamination at some sites in the past, and the Company has conducted remediation at these sites. It is possible that other contaminated sites may exist and that remediation costs may be incurred for these sites. Although the total amount of these costs cannot be known at this time, based on experience of the Company and that of others in the natural gas industry to date and on the current regulations regarding remediation of these sites, the Company believes that the 13 costs of any remediation of these sites will not be material to the Company's financial condition, results of operations or cash flows. REMA Ash Disposal Site Closures and Site Contaminations. Under the agreement to acquire REMA (see Note 3(a) to Reliant Energy 10-K 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 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, 2001, REMA has liabilities associated with six ash disposal site closures and six site investigations and environmental remediations. The Company has recorded its estimate of these environmental liabilities in the amount of $36 million as of September 30, 2001. The Company expects approximately $13 million will be paid over the next five years. REPGB Asbestos Abatement and Soil Remediation. Prior to the Company's acquisition of REPGB (see Note 3(b) to Reliant Energy 10-K 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 expected to be fully completed by 2005. As of September 30, 2001, the estimated undiscounted liability for this asbestos abatement and soil remediation was $20 million. Other. From time to time, the Company has received notices from regulatory authorities or others regarding its status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. In addition, the Company has been named as a defendant in litigation related to such sites and in recent years has been named, along with numerous others, as a defendant in several lawsuits filed by a large number of individuals who claim injury due to exposure to asbestos while working at sites along the Texas Gulf Coast. Most of these claimants have been workers who participated in construction of various industrial facilities, including power plants, and some of the claimants have worked at locations owned by the Company. The Company anticipates that additional claims like those received may be asserted in the future and intends to continue vigorously contesting claims that it does not consider to have merit. Although their ultimate outcome cannot be predicted at this time, the Company does not believe, based on its experience to date, that these matters, either individually or in the aggregate, will have a material adverse effect on the Company's financial condition, results of operations or cash flows. (c) Other Legal and Environmental Matters. The Company is involved in other legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. Some of these proceedings 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. The Company's management believes that the disposition of these matters will not have a material adverse effect on the Company's financial condition, results of operations or cash flows. (d) California Wholesale Market Uncertainty. Receivables. During the summer and fall of 2000, and continuing into early 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, structural market flaws including over-reliance on the electric spot market, and limitations on supply as a result of maintenance and other outages. Although wholesale prices increased, California's deregulation legislation kept retail rates frozen below 1996 levels 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 two of California's public utilities, Pacific Gas and Electric (PG&E) and Southern California Edison Company (SCE), have fallen 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 therefore cannot directly purchase power from third-party suppliers through the California Independent System Operator (Cal ISO) to serve their short load. Pursuant to emergency legislation enacted by the California Legislature, the California Department of Water Resources (CDWR) has 14 negotiated and purchased power through short- and long-term contracts on behalf of PG&E and SCE to meet their net short loads. However, the CDWR disputes its direct liability for some of the power obtained from third-party suppliers including the Company to serve the utilities' net short load. Also, the CDWR has not been billed by, nor made payments to, the Cal ISO for real-time transactions. The issue of CDWR's liability for amounts supplied to cover the utilities' short load, as well as the issue of the Cal ISO's compliance with certain FERC orders are currently before the FERC. Pursuant to the April 26, 2001 FERC order described below, generators in California are required to offer all their available capacity for sale in the real-time market. These types of sales have thus far been nominal and have not materially increased the Company's receivables balances. However, these sales to the Cal ISO are being made without adequate assurance of a creditworthy counterparty despite numerous FERC orders requiring such. The Company and other parties have filed with the FERC seeking to compel enforcement of these orders and the Cal ISO tariff. On November 7, 2001, the FERC issued an order finding that the Cal ISO is in violation of its tariff and the creditworthiness orders previously issued by the FERC. The FERC ordered the Cal ISO to enforce the creditworthiness requirements in its tariff and to invoice the CDWR within 15 days for the purchases made to meet the net short position of PG&E and SCE. If the Cal ISO does not comply with this order, the FERC stated it would seek an injunction to enforce its creditworthiness orders. In addition, certain contracts intended to serve as collateral for sales to the California Power Exchange (Cal PX) were seized by California Governor Gray Davis on February 2 and 5, 2001. The Ninth Circuit Court of Appeals subsequently ruled that Governor Davis' seizure of these contracts was wrongful. The Company has filed a lawsuit, currently pending in California, to require the State of California to compensate it for the seizure of these contracts. If successful in this action, the Company (either directly or through the Cal PX) would realize money from these contracts that could reduce, or perhaps eliminate, the level of receivables due to the Company from the Cal PX. However, the timing and ultimate resolution of these claims is uncertain at this time. 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 purports to 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 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 this year 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. The stipulated judgment includes no provision relating to payments to SCE's creditors, although SCE has stated its intention to use the settlement to fund the repayment of its creditors. As of December 31, 2000, the Company was owed a total of $282 million by the Cal PX and the Cal ISO. As of September 30, 2001, the Company was owed a total of $338 million by the Cal ISO, the Cal PX, the CDWR, and California Energy Resources Scheduling for energy sales in the California wholesale market during the fourth quarter of 2000 through September 30, 2001. As of September 30, 2001, the Company had a pre-tax provision of $75 million against receivable balances related to energy sales in the California market, including $36 million recorded in the first nine months of 2001. 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, the FERC initiated a staff investigation and issued a number of orders from December 15, 2000, through April 26, 2001 implementing a series of wholesale market reforms. Under these orders, 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 were identified as being subject to possible refunds. This amount is subject to review and adjustment based on the pending refund proceeding described below. During the second quarter of 2001, the Company accrued refunds of $15 million, $3 million of which had been previously reserved in the first quarter of 2001. See "--FERC Refunds" below. On April 26, 2001, the FERC issued an order replacing the previous price review procedures and establishing a market monitoring and mitigation plan, effective on May 29, 2001, for the California markets. The plan retains a "breakpoint" approach to price mitigation, for bids in the real-time market during periods when power reserves fall below 7.5% (i.e., Stages 1, 2 and 3 emergencies in the Cal ISO). The Cal ISO is instructed to use data submitted 15 confidentially by gas-fired generators in California and daily indices of natural gas and emissions allowance costs to establish the market-clearing price in real-time based on the marginal cost of the highest-cost generator called to run. The plan also requires generators in California to offer all their available capacity for sale in the real-time market, and conditions sellers' market-based rate authority such that sellers violating certain conditions on their bids will be subject to increased scrutiny by the FERC, potential refunds and even revocation of their market-based rate authority. On June 19, 2001, the FERC issued an order modifying the market monitoring and mitigation plan adopted in its April 26 order, to apply price controls to all hours, instead of just hours of low operating reserve, and to extend the mitigation measures to other Western states (Arizona, Colorado, Idaho, Montana, Nevada, New Mexico, Oregon, Utah, Washington and Wyoming) in addition to California. The proxy market clearing price calculated by the Cal ISO will apply during reserve deficiencies to all sales in the Cal ISO and Western spot markets. In non-emergency hours in California, the maximum price in California and the other Western states will be capped at 85% of the highest Cal ISO hourly market clearing price established during the hours when the last Stage 1 emergency was in effect. Sellers other than marketers will be allowed to bid higher than the maximum prices, but such bids are subject to justification and potential refund. Justification of higher prices is limited to establishing higher actual gas costs than the proxy calculation averages if conditions or natural gas markets change significantly. The modified monitoring and mitigation plan went into effect June 20, 2001, and will terminate on September 30, 2002, covering two summer peak seasons, or approximately 16 months. The Company believes that while the mitigation plan will reduce volatility in the market, assuming the credit issues described above are addressed, the Company will nevertheless be able to profitably operate its facilities in the West because the proxy market clearing price is based on the heat rate of the least efficient unit on-line during each hour. Additionally, as noted above, the mitigation plan allows sellers, such as the Company, to justify prices above the proxy price. Finally, any adverse impacts of the mitigation plan on the Company's operations would be mitigated, in part, by the Company's forward hedging activities. The FERC set July 2, 2001 as the refund effective date for sales subject to the price mitigation plan throughout the West. This means that transactions after that date may be subject to refund if found to be unjust or unreasonable. FERC Refunds. The FERC issued an order on July 25, 2001 adopting a refund methodology and initiating an expedited hearing schedule to determine (1) retroactive mitigated prices for each hour from October 2, 2000 through June 20, 2001; (2) the amount owed in refunds by each supplier according to the methodology (these amounts may be in addition to or in place of the refund amounts previously determined under the March 9, 2001 order); and (3) the amount currently owed to each supplier. The amounts of any refunds will be determined by the end of the expedited hearing process, which is scheduled to result in a recommendation to the FERC commissioners by the Administrative Law Judge assigned to the case by March 8, 2002. The Company has not reserved any amounts for potential future refunds under the July 25, 2001 order, nor can it currently predict the amount of these potential refunds, if any, because the methodology used to calculate these refunds is dependent on information that is currently unknown and still subject to review and challenge in the hearing process. Any refunds that are determined in the FERC proceeding will be offset against unpaid amounts owed to the Company for its prior sales. 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. Neither of these investigations has been completed and no findings have been made in connection with either of them. However, 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. Legislative Efforts. Since the inception of the California energy crisis, various pieces of legislation have been introduced in the U.S. 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. To date, only a few energy-related bills have passed and the Company does not believe that the legislation that has been enacted to date on these issues will have a material adverse effect on the Company. However, it is possible that legislation could be enacted on 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. 16 (e) Indemnification of Dutch Stranded Costs. In January 2001, the Dutch Electricity Production Sector Transitional Arrangements Act (Transition Act) became effective. The Transition Act, among other things, allocated to REPGB and the three other Dutch generation companies, a share of the assets, liabilities and stranded cost commitments of BV Nederlands Elektriciteit Administratiekantoor (formerly, N.V. Samenwerkende elecktriciteits-produktiebedrijven (SEP)). Prior to the enactment of the Transition Act, SEP acted as the national electricity pooling and coordinating body for the generation output of REPGB and the three other national Dutch generation companies. REPGB and the three other Dutch generation companies are shareholders of SEP. The Transition Act and related agreements specify that REPGB has a 22.5% share of SEP's assets, liabilities and stranded cost commitments. SEP's stranded cost commitments consisted primarily of various uneconomical or stranded costs investments and long-term gas supply and power contracts entered into prior to the liberalization of the Dutch wholesale electricity market. SEP's primary asset is its ownership interest in the Dutch national grid company, which was sold to the Dutch government on October 25, 2001 for approximately NLG 2.6 billion (approximately $1.1 billion based on an exchange rate of 2.42 NLG per U.S. dollar as of September 30, 2001). Under the Transition Act, REPGB can either assume its 22.5% allocated interest in the contracts or, subject to the terms of the contracts, sell its interests to third parties. The Transition Act, as enacted, 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 certain liabilities associated with long-term district heating contracts entered into by the generation companies with various municipalities. 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. However, at this point, it is unclear what the timing of this compensation will be or what form it will take. To the extent that this compensation is not ultimately provided to the generation companies by the Dutch government, REPGB will collect its compensation directly from the former shareholders as further discussed below. The former shareholders have agreed pursuant to a share purchase agreement to indemnify REPGB for up to NLG 1.9 billion in stranded cost liabilities (approximately $785 million based on an exchange rate of 2.42 NLG per U.S. dollar as of September 30, 2001). The indemnity obligation of the former shareholders and various provincial and municipal entities (including the city of Amsterdam), is secured by a NLG 900 million escrow account (approximately $372 million based on an exchange rate of 2.42 NLG per U.S. dollar as of September 30, 2001). Pursuant to SFAS No. 133, the gas and electric contracts are marked to market. As of September 30, 2001, the Company has recorded a liability of $362 million for its stranded cost gas and electric and district heating commitments. In addition, the Company recorded a corresponding asset of equal amount for the indemnification of this obligation from REPGB's former shareholders and the Dutch government. The estimate of stranded cost liability is based on a number of assumptions, many of which are contingent upon the outcome of future events, such as fuel and energy prices, that are not known at this time. The actual amount of the ultimate stranded cost liability may be greater or smaller depending on the outcome of these assumptions. To date, the Company has filed indemnity claims totaling of NLG 95 million (approximately $39 million at an exchange rate of 2.42 NLG per U.S. dollar as of September 30, 2001) for stranded cost liabilities associated with the district heating and gas and electricity contract losses incurred during the first and second quarters of 2001. The former shareholders have so far rejected REPGB's indemnity claims and in response, the Company has initiated arbitration proceedings against the former shareholders. The Company believes that the rejection of its indemnity claims is without merit and intends to vigorously pursue its claims against the former shareholders. 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 SEP. This gain was based on the Company's evaluation of SEP's financial position and fair value. Pursuant to the purchase agreement of REPGB, as amended, REPGB is entitled to a NLG 125 million (approximately $51 million) dividend from SEP with any remainder owing to the former shareholders. (f) Reliant Energy HL&P Rate Matters. The Texas Utility Commission issued a final order on October 3, 2001 that establishes the rates that will become effective when retail choice begins in 2002. In this final order, Reliant Energy HL&P is required to reverse the amount of redirected depreciation and accelerated depreciation allowed under the Transition Plan and the 17 Legislation. The Texas Utility Commission determined that the utility had overmitigated its stranded costs. The Company disagrees with certain positions prescribed in the order by the Texas Utility Commission. Motions for Rehearing were filed by the Company with the Texas Utility Commission on October 23, 2001 and the Company will determine future action based on the Texas Utility Commission's response to these motions. Reliant Energy HL&P also filed an amicus brief on September 24, 2001 at the Texas Supreme Court supporting Texas Utilities Company's Petition for Writ of Mandamus challenging these same issues. At September 30, 2001, cumulative redirected depreciation and cumulative accelerated depreciation for regulatory purposes totaled $783 million and approximately $1.1 billion, respectively. Implementing the reversal of redirected depreciation would result in lower rates for the transmission and distribution utility, and the accelerated depreciation being returned through credits over seven years would serve as reductions to the transmission and distribution utility's non-bypassable charges. The annual impact to earnings for the reversal of redirected depreciation would be approximately $36 million after-tax, while the return of accelerated depreciation is not expected to impact earnings. The annual cash flow impact would be approximately $225 million. The credits related to accelerated depreciation will become effective beginning with retail choice. For information regarding redirected depreciation and accelerated depreciation, see Note 4(a) to Reliant Energy 10-K Notes. (g) Construction Agency Agreement. In April 2001, Reliant Resources, 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 have an aggregate financing commitment from equity and debt participants (Investors) of $2.5 billion. The availability of the commitment is subject to satisfaction of various conditions. Reliant Resources, through several of its subsidiaries, acts as construction agent for the special purpose entities and is responsible for completing construction of these projects by August 31, 2004, but has generally limited its risk related to construction completion to 89.9% of costs incurred to date, except in certain events. Upon completion of an individual project and exercise of the lease option, Reliant Resources' subsidiaries will be required to make lease payments in an amount sufficient to provide a return to the Investors. If Reliant Resources does not exercise its option to lease any project upon its completion, Reliant Resources must purchase the project or remarket the project on behalf of the special purpose entities. Reliant Resources must guarantee that the Investors will receive at least 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), Reliant Resources' subsidiary lessees have the option to extend the lease with the approval of 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 up to 85% of the project cost if the proceeds from remarketing are not sufficient to repay the Investors. Reliant Resources 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. (h) 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, 2001, REMA had $143 million of restricted funds that are available for REMA's working capital needs and to make future lease payments, including a lease payment of $55 million in January 2002. For additional discussion of these lease transactions, please read Note 3(a) and 14(c) to Reliant Energy 10-K Notes. (13) INITIAL PUBLIC OFFERING OF RELIANT RESOURCES On July 27, 2000, Reliant Energy announced its intention to form Reliant Resources to own and operate a substantial portion of Reliant Energy's unregulated operations, and to offer no more than 20% of the common stock of Reliant Resources in an initial public offering (Offering) in connection with the Company's business separation plan. In May 2001, Reliant Resources completed its initial public offering of 59.8 million shares of its common stock and received net proceeds of $1.7 billion. Pursuant to the terms of the master separation agreement, Reliant Resources used $147 million of the net proceeds to repay certain indebtedness owed to Reliant Energy. Reliant Resources used the remainder of net proceeds to increase its working capital. Reliant Energy expects the Offering to be followed by a distribution of the remaining common stock of Reliant Resources owned by Reliant Energy to Reliant Energy's or its successor's shareholders within twelve months of the Offering (Distribution). As a result of the Offering, the Company recorded directly into stockholders' equity as a component of common stock a $509 18 million gain on the sale of its subsidiary's stock. For additional information regarding the Company's business separation plan, see Note 4(b) to Reliant Energy 10-K Notes. The Reliant Resources common stock issued in the Offering has been reflected as minority interest in consolidated subsidiaries in the Company's Consolidated Balance Sheet as of September 30, 2001. The Distribution is subject to further corporate approvals, market and other conditions, and government actions, including receipt of a favorable Internal Revenue Service ruling that the Distribution would be tax-free to Reliant Energy or its successor and its shareholders for U.S. federal income tax purposes, as applicable. There can be no assurance that the Distribution will be completed as described or within the time periods outlined above. During the third quarter of 2001, Reliant Resources purchased 1,000,000 shares of its common stock at an average price of $20.42 per share, or an aggregate purchase price of $20.4 million. These shares were purchased in anticipation of funding benefit plan obligations of Reliant Resources expected to be funded prior to the Distribution. The master separation agreement between Reliant Resources and Reliant Energy restricts the ability of Reliant Resources to issue shares of its common stock prior to the separation of the two companies without the prior consent of Reliant Energy. On September 18, 2001, Reliant Resources' Board of Directors authorized Reliant Resources to purchase up to 10 million additional shares of its common stock through February 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. (14) BENEFIT CURTAILMENT AND ENHANCEMENT CHARGE During the first quarter of 2001, the Company recognized a pre-tax, non-cash charge of $101 million relating to the redesign of some of Reliant Energy's benefit plans in anticipation of distributing to Reliant Energy's or its successor's shareholders the remaining common stock of its unregulated subsidiary, Reliant Resources. For information regarding this anticipated transaction, see Note 4(b) to Reliant Energy 10-K Notes. Effective March 1, 2001, the Company no longer accrues benefits under a noncontributory pension plan for its domestic non-union employees of Reliant Resources and Reliant Energy Tegco, Inc. (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 $84 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. Effective March 1, 2001, the Company discontinued providing subsidized postretirement benefits to its domestic non-union employees of Reliant Resources and its participating subsidiaries and Reliant Energy Tegco, Inc. 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. For additional information regarding these benefit plans, see Notes 12(b) and 12(d) to Reliant Energy 10-K Notes. 19 (15) REPORTABLE SEGMENTS The Company's determination of reportable segments considers the strategic operating units under which the Company manages sales, allocates resources and assesses performance of various products and services to wholesale or retail customers in differing regulatory environments. The Company has identified the following reportable segments: Electric Operations, Natural Gas Distribution, Pipelines and Gathering, Wholesale Energy, European Energy, Retail Energy and Other Operations. Prior to July 1, 2001, Retail Energy has been reported in the Other Operations segment. Reportable segments from previous interim periods and the prior year have been restated to conform to the current presentation. Retail Energy provides energy products and services to end-use customers, ranging from residential and small commercial customers to large commercial, institutional and industrial customers. For descriptions of the other reporting segments, see Note 1 to Reliant Energy 10-K Notes. Financial data for the business segments are as follows:
AS OF DECEMBER 31, FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2000 2000 ----------------------------------------------- --------------- NET REVENUES FROM INTERSEGMENT OPERATING NON-AFFILIATES REVENUES INCOME (LOSS) TOTAL ASSETS --------------- --------------- --------------- --------------- (IN MILLIONS) Electric Operations ............... $ 1,827 $ -- $ 500 $ 10,691 Natural Gas Distribution .......... 863 7 (42) 4,547 Pipelines and Gathering ........... 42 51 33 2,358 Wholesale Energy .................. 6,622 112 314 10,866 European Energy ................... 129 -- 15 2,521 Retail Energy ..................... 15 6 (19) 151 Other Operations .................. 4 -- (25) 1,482 Discontinued Operations (1) ....... -- -- -- 195 Reconciling Elimination ........... -- (176) -- (1,112) --------------- --------------- --------------- --------------- Consolidated ...................... $ 9,502 $ -- $ 776 $ 31,699 =============== =============== =============== ===============
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2000 ----------------------------------------------------- NET REVENUES FROM INTERSEGMENT OPERATING NON-AFFILIATES REVENUES INCOME (LOSS) -------------- -------------- -------------- (IN MILLIONS) Electric Operations .......... $ 4,195 $ -- $ 1,027 Natural Gas Distribution ..... 2,690 24 51 Pipelines and Gathering ...... 128 146 99 Wholesale Energy ............. 11,990 352 464 European Energy .............. 415 -- 72 Retail Energy ................ 42 17 (40) Other Operations ............. 10 -- (42) Reconciling Elimination ...... -- (539) -- -------------- -------------- -------------- Consolidated ................. $ 19,470 $ -- $ 1,631 ============== ============== ==============
20
AS OF SEPTEMBER 30, FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2001 2001 ----------------------------------------------------- -------------- NET REVENUES FROM INTERSEGMENT OPERATING TOTAL NON-AFFILIATES REVENUES INCOME (LOSS) ASSETS -------------- -------------- -------------- -------------- (IN MILLIONS) Electric Operations ............. $ 1,608 $ -- $ 436 $ 10,950 Natural Gas Distribution ........ 602 6 (25) 3,630 Pipelines and Gathering ......... 52 40 34 2,334 Wholesale Energy ................ 9,891 96 266 10,486 European Energy ................. 275 -- (5) 3,451 Retail Energy ................... 35 17 (7) 256 Other Operations ................ 4 1 (53) 1,301 Discontinued Operations (1) ..... -- -- -- 118 Reconciling Elimination ......... -- (160) -- (1,017) -------------- -------------- -------------- -------------- Consolidated .................... $ 12,467 $ -- $ 646 $ 31,509 ============== ============== ============== ==============
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2001 ----------------------------------------------------- NET REVENUES FROM INTERSEGMENT OPERATING NON-AFFILIATES REVENUES INCOME (LOSS) -------------- -------------- -------------- (IN MILLIONS) Electric Operations .......... $ 4,521 $ -- $ 964 Natural Gas Distribution ..... 3,727 92 62 Pipelines and Gathering ...... 177 141 106 Wholesale Energy ............. 28,415 530 687 European Energy .............. 799 -- 23 Retail Energy ................ 74 41 (13) Other Operations ............. 13 1 (201) Reconciling Elimination ...... -- (805) -- -------------- -------------- -------------- Consolidated ................. $ 37,726 $ -- $ 1,628 ============== ============== ==============
- ---------- (1) Effective December 1, 2000, Reliant Energy's Board of Directors approved a plan to dispose of its Latin American segment, through sales of its assets. For more information regarding the Company's discontinued operations, see Note 5. Reconciliation of Operating Income to Net Income Attributable to Common Stockholders:
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30, -------------------------------- -------------------------------- 2000 2001 2000 2001 ------------- ------------- ------------- ------------- (IN MILLIONS) Operating Income ....................................... $ 776 $ 646 $ 1,631 $ 1,628 Other Expense .......................................... (158) (159) (478) (400) Income Tax Expense ..................................... (222) (197) (387) (456) Loss from Discontinued Operations, net of tax .......... (7) -- (27) -- Loss on Disposal of Discontinued Operations, net of tax ............................................... -- -- -- (7) Extraordinary Item ..................................... -- -- 7 -- Cumulative Effect of Accounting Change, net of tax ..... -- -- -- 61 ------------- ------------- ------------- ------------- Net Income Attributable to Common Stockholders ......... $ 389 $ 290 $ 746 $ 826 ============= ============= ============= =============
(16) RELIANT ENERGY COMMUNICATIONS During the third quarter of 2001, management decided to exit the Company's Communications business which serves as a facility-based competitive local exchange carrier and Internet services provider and owns network operations centers and managed data centers in Houston and Austin. Consequently, the Company determined the goodwill associated with the Communications business was impaired. The Company recorded $33 million of pre-tax disposal charges in the third quarter of 2001. These charges included the write-off of goodwill of $19 million and 21 fixed asset write-downs, severance reserves and other incremental costs associated with exiting the Communications business, totaling $14 million. (17) SUBSEQUENT EVENTS. (a) Securitization Financing. On October 24, 2001, Reliant Energy Transition Bond Company LLC (Bond Company), a Delaware limited liability company and direct wholly owned subsidiary of Reliant Energy, issued $749 million aggregate principal amount of its Series 2001-1 Transition Bonds pursuant to a financing order of the Texas Utility Commission. Classes of the bonds mature on September 15, 2007, September 15, 2009, September 15, 2011 and September 15, 2015, and bear interest at rates of 3.84%, 4.76%, 5.16% and 5.63%, respectively. Net proceeds to the Bond Company from the issuance were $738 million. The Bond Company paid Reliant Energy $738 million for all of Reliant Energy's interest in the financing order. The Company used the net proceeds for general corporate purposes, including the repayment of indebtedness. The Transition Bonds are secured primarily by the "transition property," which includes the irrevocable right to recover, through nonbypassable transition charges payable by certain retail electric customers, the qualified costs of Reliant Energy authorized by the financing order of the Texas Utility Commission. The holders of the Bond Company's bonds have no recourse to any assets or revenues of Reliant Energy, and the creditors of Reliant Energy have no recourse to any assets or revenues (including, without limitation, the transition charges) of the Bond Company. Reliant Energy has no payment obligations with respect to the Transition Bonds except to remit collections of transition charges as set forth in a servicing agreement between Reliant Energy and the Bond Company and in an intercreditor agreement among Reliant Energy, the Bond Company and other parties. (b) Purchase of Treasury Stock by Subsidiary. From October 1, 2001 through November 8, 2001, Reliant Resources purchased 7,628,200 shares of its common stock at an average price of $16.69 per share, or an aggregate purchase price of $127 million. These shares were purchased pursuant to Reliant Resources' Board of Directors authorization as discussed in Note 13. 22 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF RELIANT ENERGY AND SUBSIDIARIES The following discussion and analysis should be read in combination with our Interim Financial Statements contained in this Form 10-Q. We are a diversified international energy services and energy delivery company that provides energy and energy services in North America and Europe. We operate one of the nation's largest electric utilities in terms of kilowatt-hour (KWh) sales, and our three natural gas distribution divisions together form one of the United States' largest natural gas distribution operations in terms of customers served. We invest in the acquisition, development and operation of domestic and international non-rate regulated power generation facilities. We own two interstate natural gas pipelines that provide gas transportation, supply, gathering and storage services, and we also engage in wholesale energy marketing and trading. 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 Electric Operations, Natural Gas Distribution, Pipelines and Gathering, Wholesale Energy, European Energy, Retail Energy and Other Operations. Historically, Retail Energy has been reported in the Other Operations segment. For segment reporting information, please read Note 15 to our Interim Financial Statements. Effective December 1, 2000, our Board of Directors approved a plan to dispose of our Latin American business segment and sell its assets. Accordingly, we are reporting the results of our Latin American business segment as discontinued operations for all periods presented in our Interim Financial Statements in accordance with Accounting Principles Board Opinion No. 30 (APB Opinion No. 30). For additional information regarding the disposal of our Latin American business segment, please read Note 19 to Reliant Energy 10-K Notes. In 2000, we submitted a business separation plan to the Texas Utility Commission that was later amended during the year to restructure our businesses into two separate publicly traded companies in order to separate our unregulated businesses from our regulated businesses. In December 2000, the plan was substantially approved by the Texas Utility Commission in its entirety and a final order was issued on April 10, 2001. For additional information regarding our business separation plan, please read Note 4(b) to Reliant Energy 10-K Notes. Reliant Energy filed an amendment to its business separation plan with the Texas Utility Commission on October 15, 2001 to delay full implementation of the restructuring until all regulatory approvals have been received. As part of the separation, Reliant Energy will undergo a restructuring of its corporate organization to achieve a new holding company structure. The new holding company will hold our regulated businesses and will be named CenterPoint Energy, Inc. In connection with the formation of the new holding company, the Company has filed an application with the SEC requesting an exemption from the registration requirements of the Public Utility Holding Company Act of 1935 (1935 Act). The restructuring will require approval of the SEC, certain of the affected state commissions and the Nuclear Regulatory Commission. On October 22, 2001, the Board of Directors of Reliant Energy announced that a special meeting of shareholders of Reliant Energy will be held on December 17, 2001. At the special meeting, shareholders of record as of the close of business on November 1, 2001 will be asked to approve the merger whereby CenterPoint Energy, Inc. will become the new holding company. Reliant Energy expects to begin mailing a joint proxy statement/prospectus relating to the special meeting to its shareholders on or about November 12, 2001. In order to satisfy requirements for maintaining the exemption from the registration requirements of the 1935 Act, Reliant Energy expects to separate its three gas distribution divisions into three separate corporate entities within two years of the SEC's exemption order. The separation of these businesses will require additional regulatory approvals from the state utility regulators in five of the six states where the Company currently operates gas distribution businesses and may require waivers, consents and/or modifications to certain RERC agreements, including credit facilities and other financing arrangements. In connection with our business separation plan, we formed Reliant Resources, which owns and operates a substantial portion of our unregulated operations. In May 2001, Reliant Resources offered 59.8 million shares of its common stock to the public at an initial public offering (Offering) price of $30 per share and received net proceeds from the Offering of $1.7 billion. Pursuant to the master separation agreement, Reliant Resources used $147 million of the net proceeds to repay certain indebtedness owed to Reliant Energy. Reliant Energy expects to distribute the 23 remaining common stock of Reliant Resources it owns to Reliant Energy's or its successor's shareholders within twelve months of the closing of the Reliant Resources initial public offering. On May 12, 2000, one of our subsidiaries purchased entities owning electric power generating assets and development sites located in Pennsylvania, New Jersey, and Maryland having an aggregate net generating capacity of approximately 4,262 MW. The purchase price for the May 2000 transaction was $2.1 billion. We accounted for the acquisition as a purchase, and accordingly, our results of operations include the results of operations for REMA only for the period after the acquisition date. For additional information about this acquisition, including our accounting treatment of the acquisition, please read Note 3(a) to Reliant Energy 10-K Notes and Note 4 to our Interim Financial Statements. In September 2001, we announced that we are evaluating strategic alternatives for our European Energy segment, including the possible sale, in order to pursue business opportunities that are more in line with our domestic wholesale energy strategies. During the third quarter of 2001, management decided to exit our Communications business which serves as a facility-based competitive local exchange carrier and Internet services provider and owns network operations centers and managed data centers in Houston and Austin. For additional information about our Communications business, please read Note 16 to our Interim Financial Statements. CONSOLIDATED RESULTS OF OPERATIONS
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30, -------------------------------- ------------------------------- 2000 2001 2000 2001 ------------- ------------- ------------- ------------- (IN MILLIONS, EXCEPT PER SHARE DATA) Revenues ................................................ $ 9,502 $ 12,467 $ 19,470 $ 37,726 Operating Expenses ...................................... (8,726) (11,821) (17,839) (36,098) ------------- ------------- ------------- ------------- Operating Income ........................................ 776 646 1,631 1,628 Income from Equity Investments in Unconsolidated Subsidiaries .......................................... 27 2 33 66 Interest Expense ........................................ (186) (138) (533) (466) Distribution on Trust Preferred Securities .............. (14) (14) (40) (42) Minority Interest ....................................... -- (26) 1 (49) Other Income ............................................ 15 17 61 91 Income Tax Expense ...................................... (222) (197) (387) (456) Loss from Discontinued Operations, net of tax ........... (7) -- (27) -- Loss on Disposal of Discontinued Operations, net of tax ................................................ -- -- -- (7) Extraordinary Item ...................................... -- -- 7 -- Cumulative Effect of Accounting Change, net of tax ...... -- -- -- 61 ------------- ------------- ------------- ------------- Net Income Attributable to Common Stockholders .......... $ 389 $ 290 $ 746 $ 826 ============= ============= ============= ============= Basic Earnings Per Share ................................ $ 1.36 $ 1.00 $ 2.62 $ 2.86 Diluted Earnings Per Share .............................. $ 1.34 $ 0.99 $ 2.60 $ 2.83
Three months ended September 30, 2000 compared to three months ended September 30, 2001 We reported consolidated net income of $389 million ($1.34 per diluted share) for the three months ended September 30, 2000 compared to $290 million ($0.99 per diluted share) for the three months ended September 30, 2001. The 2000 results include a $7 million after-tax loss from discontinued operations in Latin America. The 2001 results include a $22 million after-tax charge, including the effect of minority interest, for the disposal of our Communications business. Our consolidated net income, after adjusting for the items described above, was $396 million ($1.37 per diluted share) for the three months ended September 30, 2000 compared to $312 million ($1.07 per diluted share) for the three months ended September 30, 2001. The decrease in adjusted net income was primarily due to decreased revenues from reduced customer usage due to milder weather in our Electric Operations segment and increased expenses in our Wholesale Energy segment, partially offset by decreased interest expense. 24 For an explanation of changes in operating income for the third quarter of 2000 versus 2001, see the discussion below of operating income (loss) by segment. Equity income from unconsolidated subsidiaries decreased by $25 million during the third quarter of 2001 compared to 2000 primarily due to decreased earnings from unconsolidated subsidiaries of our Wholesale Energy segment due to decreased power prices in the three months ended September 30, 2001 compared to the same period in 2000. We incurred charges for interest expense and distribution on trust preferred securities of $200 million and $152 million for the third quarters of 2000 and 2001, respectively. The decrease resulted from a combination of lower levels of both short-term borrowings and long-term debt and lower interest rates in the third quarter of 2001 compared to the same period in 2000. During 2001, short-term borrowings decreased primarily from the reduction in commercial paper with the proceeds from the Reliant Resources Offering. Other income includes an additional impairment loss of $4 million pre-tax on marketable equity securities classified as "available-for-sale" recorded during the three months ended September 30, 2000. During the third quarter of 2001, we recorded minority interest expense of $26 million primarily related to the minority interest in Reliant Resources. The effective tax rate for the third quarter of 2000 and 2001 was 36% and 40%, respectively. The increase in effective tax rate was primarily a result of decreased earnings of REPGB, increased state income taxes and the write-off of goodwill associated with our Communications business. In 2001 and prior years, the earnings of REPGB were subject to a zero percent Dutch corporate income tax rate as a result of the Dutch tax holiday related to the Dutch electricity industry. In 2002, all of European Energy's earnings in the Netherlands will be subject to the standard Dutch corporate income tax rate, which is currently 35%. Nine months ended September 30, 2000 compared to nine months ended September 30, 2001 We reported consolidated net income of $746 million ($2.60 per diluted share) for the nine months ended September 30, 2000 compared to $826 million ($2.83 per diluted share) for the nine months ended September 30, 2001. The 2000 results include a $27 million after-tax loss from discontinued operations in Latin America and an extraordinary gain of $7 million related to the early extinguishment of long-term debt. The 2001 results reflect a $7 million after-tax loss on the disposal of discontinued operations in Latin America, a $61 million after-tax cumulative effect of an accounting change from the adoption of SFAS No. 133, a $65 million after-tax non-cash charge relating to the redesign of the company's benefit plans for employees of our unregulated businesses and a $33 million after-tax gain recorded in equity income related to a preacquisition contingency for the value of SEP, the coordinating body for the Dutch electricity generating sector, offset by related minority interest of $6 million and a $28 million after-tax charge for the disposal of our Communications business offset by related minority interest of $6 million. Our consolidated net income, after adjusting for the items described above, was $765 million ($2.67 per diluted share) for the first nine months of 2000 compared to $833 million ($2.86 per diluted share) for the first nine months of 2001. The increase in adjusted earnings for this period was largely driven by improved performance from our Wholesale Energy segment, partially offset by a decline in operating results from our Electric Operations and European Energy segments. A decline in interest expense also contributed to the increase in net income. For information regarding the adoption of SFAS No. 133, the discontinuance of our Latin American segment, the gain related to the preacquisition contingency, the benefit charge incurred in the first quarter of 2001 and the Communications business disposal charge, see Notes 3, 5, 12(e), 14 and 16 to our Interim Financial Statements. For an explanation of changes in operating income for the first nine months of 2000 versus 2001, see the discussion below of operating income (loss) by segment. Equity income from unconsolidated subsidiaries increased by $33 million during the first nine months of 2001 compared to 2000 primarily due to the pre-tax gain of $51 million ($33 million after-tax) related to a preacquisition contingency recorded by our European Energy segment, as discussed above. Our Wholesale Energy segment reported income from equity investments for the nine months ended September 30, 2000 of $33 million compared to $15 million in the same period in 2001 primarily due to decreased earnings from unconsolidated subsidiaries as a 25 result of a plant outage at one of our equity investments and decreased power prices in the nine months ended September 30, 2001 compared to the same period in 2000. We incurred charges for interest expense and distribution on trust preferred securities of $573 million and $508 million for the first nine months of 2000 and 2001, respectively. The decrease resulted from a combination of lower levels of both short-term borrowings and long-term debt and lower interest rates in the first nine months of 2001 compared to the same period in 2000. During 2001, short-term borrowings decreased primarily from the reduction in commercial paper with the proceeds from the Reliant Resources Offering. Other income increased by $30 million during the first nine months of 2001 compared to 2000 primarily due to increased interest income from our Electric Operations and Wholesale Energy segments and a pre-tax impairment loss of $27 million recorded in 2000 related to certain marketable securities, partially offset by a $15 million gain related to the sale of a development-stage project in 2000 and a federal tax refund in 2000. For additional information regarding our investment equity securities noted above, see Note 2(l) to Reliant Energy 10-K Notes. During the nine months ended September 30, 2001, we recorded minority interest expense of $49 million primarily related to the minority interest in Reliant Resources. The effective tax rate for the first nine months of 2000 and 2001 was 34% and 37%, respectively. The increase in the effective tax rate was primarily due to the same factors as discussed above in the quarterly results of operations. As discussed in Note 12(e) to our Interim Financial Statements, the Transition Act allocated to the Dutch generation sector, including REPGB, financial responsibility for SEP's obligations to purchase electricity and gas under a gas supply contract and three electricity contracts. As a result of the above, we recorded an out-of-market, net stranded cost liability of $138 million and a related deferred tax asset of $48 million at September 30, 2001 for our statutorily allocated share of these gas supply and electricity contracts. We believe that the costs incurred by REPGB subsequent to the tax holiday ending in 2001 related to these contracts will be deductible for Dutch tax purposes. However, due to the uncertainties related to the deductibility of these costs, we have recorded a reserve in other liabilities in our Interim Financial Statements of $48 million as of September 30, 2001. RESULTS OF OPERATIONS BY BUSINESS SEGMENT The table below shows operating income (loss) by segment:
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30, -------------------------------- ------------------------------ 2000 2001 2000 2001 ------------ ------------ ------------ ------------ (IN MILLIONS) Electric Operations ............... $ 500 $ 436 $ 1,027 $ 964 Natural Gas Distribution .......... (42) (25) 51 62 Pipelines and Gathering ........... 33 34 99 106 Wholesale Energy .................. 314 266 464 687 European Energy ................... 15 (5) 72 23 Retail Energy ..................... (19) (7) (40) (13) Other Operations .................. (25) (53) (42) (201) ------------ ------------ ------------ ------------ Total Consolidated .......... $ 776 $ 646 $ 1,631 $ 1,628 ============ ============ ============ ============
ELECTRIC OPERATIONS Our Electric Operations segment conducts operations under the name "Reliant Energy HL&P," an unincorporated division of Reliant Energy. Our Electric Operations segment generates, purchases, transmits and distributes electricity to approximately 1.7 million customers in a 5,000 square mile area on the Texas Gulf Coast, including Houston, Texas. For information on other developments, factors and trends that may have an impact on the future earnings of our Electric Operations segment, please read Note 12(f) to our Interim Financial Statements and "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Certain Factors Affecting Our Future Earnings -- Electric Operations". 26
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30, -------------------------------- ------------------------------- 2000 2001 2000 2001 ------------- ------------- ------------- ------------- (IN MILLIONS) Operating Revenues: Base Revenues ...................................... $ 1,041 $ 981 $ 2,477 $ 2,414 Reconcilable Fuel Revenues ......................... 786 627 1,718 2,107 ------------- ------------- ------------- ------------- Total Operating Revenues ......................... 1,827 1,608 4,195 4,521 ------------- ------------- ------------- ------------- Operating Expenses: Fuel and Purchased Power ........................... 804 641 1,763 2,148 Operation and Maintenance .......................... 230 255 696 727 Depreciation and Amortization ...................... 177 161 420 369 Other Operating Expenses ........................... 116 115 289 313 ------------- ------------- ------------- ------------- Total Operating Expenses ......................... 1,327 1,172 3,168 3,557 ------------- ------------- ------------- ------------- Operating Income ..................................... $ 500 $ 436 $ 1,027 $ 964 ============= ============= ============= ============= Electric Sales Including Unbilled (in GWh(1)): Residential ........................................ 8,534 7,710 17,967 17,445 Commercial ......................................... 5,291 5,232 13,526 13,741 Industrial ......................................... 6,847 6,539 21,132 21,047 Industrial - Interruptible ......................... 1,550 1,369 4,232 2,806 Other .............................................. 381 99 1,407 777 ------------- ------------- ------------- ------------- Total Sales Including Unbilled ..................... 22,603 20,949 58,264 55,816 ============= ============= ============= ============= Average Cost of Fuel (in Cents/MMBtu(2)) ............. 288.8 233.3 254.1 269.0
- -------------- (1) Gigawatt hours (2) Million British thermal units Our Electric Operations segment's operating income for the three months ended September 30, 2001 decreased $64 million compared to the three months ended September 30, 2000. The decrease was primarily due to decreased revenues from reduced customer usage related to milder weather, customer conservation and reduced rates for certain governmental agencies as mandated by Texas electric deregulation legislation, and higher transmission cost of service expense. These decreases were partially offset by lower amortization expense. Our Electric Operations segment's operating income for the nine months ended September 30, 2001 decreased $63 million compared to the nine months ended September 30, 2000. The decrease was primarily due to decreased revenues from reduced customer usage related to milder weather, reduced rates for certain governmental agencies as mandated by Texas deregulation legislation, increased tax expenses and higher benefit expenses, partially offset by lower amortization expense and increased customer growth. Base revenues decreased $60 million and $63 million for the quarter and nine months ended September 30, 2001, respectively, primarily due to milder weather compared to the prior year and a reduction in revenues due to reduced rates for certain governmental agencies as mandated by Texas deregulation legislation. In addition, during the third quarter of 2001 compared to the same period in 2000, revenues declined due to decreased customer usage. Reconcilable fuel revenues and fuel and purchased power expenses for the quarter ended September 30, 2001 decreased as a result of a decrease in the price of natural gas ($4.40 and $3.32 per MMBtu in the third quarters of 2000 and 2001, respectively). Reconcilable fuel revenues and fuel and purchased power expenses for the nine months ended September 30, 2001 increased as a result of purchased power volumes and an increase in the price of natural gas ($3.71 and $4.52 per MMBtu for the first nine months of 2000 and 2001, respectively). Operation and maintenance expenses and other operating expenses for the quarter ended September 30, 2001 increased by $25 million and decreased by $1 million, respectively, when compared to the same period in 2000. The increase in operation and maintenance expenses is largely due to higher benefit costs and transmission cost of service expense. Operation and maintenance expenses and other operating expenses for the first nine months of 2001 increased by $31 million and $24 million, respectively, when compared to the same period in 2000. The increase in operation and maintenance expense is primarily due to higher benefit costs partially offset by decreased legal fees. The 27 increase in other operating expenses is primarily due to an increase in franchise tax requirements resulting from increased revenues. Depreciation and amortization expense for the quarter and nine months ended September 30, 2001 decreased $16 million and $51 million, respectively, compared to the same periods in 2000. The decrease for the quarter was primarily due to a decrease in amortization of the book impairment regulatory asset recorded in June 1999, partially offset by accelerated amortization of certain regulatory assets related to energy conservation management as required by the Texas Utility Commission. The decrease for the nine months was primarily due to a decrease in amortization of the book impairment regulatory asset recorded in June 1999 and decreased amortization expense due to regulatory assets related to cancelled projects being fully amortized in June 2000 partially offset by accelerated amortization of certain regulatory assets related to energy conservation management as required by the Texas Utility Commission. For information regarding items that affect depreciation and amortization expense of Electric Operations pursuant to the Legislation and the Transition Plan, see Notes 2(g) and 4(a) to Reliant Energy 10-K Notes and Note 6 to our Interim Financial Statements. NATURAL GAS DISTRIBUTION Our Natural Gas Distribution segment's operations consist of intrastate natural gas sales to, and natural gas transportation for residential, commercial and industrial customers in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas and some non-rate regulated retail marketing of natural gas.
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30, -------------------------------- ------------------------------- 2000 2001 2000 2001 ------------- ------------- ------------- ------------- (IN MILLIONS) Operating Revenues ..................... $ 870 $ 608 $ 2,714 $ 3,819 Operating Expenses: Natural Gas .......................... 705 437 2,085 3,139 Operation and Maintenance ............ 149 139 399 420 Depreciation and Amortization ........ 38 37 111 110 Other Operating Expenses ............. 20 20 68 88 ------------- ------------- ------------- ------------- Total Operating Expenses ........... 912 633 2,663 3,757 ------------- ------------- ------------- ------------- Operating (Loss) Income ................ $ (42) $ (25) $ 51 $ 62 ============= ============= ============= ============= Throughput Data (in Bcf (1)): Residential and Commercial Sales ..... 34 36 194 225 Industrial Sales ..................... 12 13 50 36 Transportation ....................... 11 10 38 36 Retail ............................... 130 100 411 339 ------------- ------------- ------------- ------------- Total Throughput ................... 187 159 693 636 ============= ============= ============= =============
- ---------- (1) Billion cubic feet. Our Natural Gas Distribution segment's operating loss decreased $17 million and operating income increased $11 million for the quarter and nine months ended September 30, 2001, respectively, as compared to the same periods in 2000. Operating results for 2000 reflect expenses incurred in connection with exiting certain non-rate regulated natural gas business activities outside our established market areas. Increases in employee benefits and bad debt expenses during the third quarter of 2001 were partially offset by increased customer usage. The increase in income for the first nine months in 2001 compared to the same period in 2000 is primarily due to the expenses reflected in 2000 as noted above and improved margins from colder weather and increased customer growth and usage, partially offset by increased bad debt expense in addition to changes in estimates of unbilled revenues and recoverability of deferred gas accounts and other items. 28 PIPELINES AND GATHERING Our Pipelines and Gathering segment operates two interstate natural gas pipelines and provides gathering and pipeline services.
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30, -------------------------------- -------------------------------- 2000 2001 2000 2001 ------------- ------------- ------------- ------------- (IN MILLIONS) Operating Revenues ................... $ 93 $ 92 $ 274 $ 318 Operating Expenses: Natural Gas ........................ 19 7 50 65 Operation and Maintenance .......... 22 31 71 90 Depreciation and Amortization ...... 14 15 42 44 Other Operating Expenses ........... 5 5 12 13 ------------- ------------- ------------- ------------- Total Operating Expenses ......... 60 58 175 212 ------------- ------------- ------------- ------------- Operating Income ..................... $ 33 $ 34 $ 99 $ 106 ============= ============= ============= ============= Throughput Data (in MMBtu): Natural Gas Sales .................. 4 2 11 11 Transportation ..................... 181 174 651 613 Gathering .......................... 72 76 213 223 Elimination (1) .................... (3) (1) (9) (2) ------------- ------------- ------------- ------------- Total Throughput ..................... 254 251 866 845 ============= ============= ============= =============
- ---------- (1) Elimination of volumes both transported and sold. Our Pipelines and Gathering segment's operating income for the quarter and nine months ended September 30, 2001 increased $1 million and $7 million, respectively, compared to the same periods in 2000. Increased operating margins (revenues less natural gas costs) for our gas gathering business were partially offset by costs related to a pipeline rate case which began in the third quarter of 2001 and other operating expenses. Improved operating margins from both the pipelines and gas gathering businesses, partially offset by increased operating expenses, contributed to the increase for the first nine months of 2001. WHOLESALE ENERGY Our Wholesale Energy segment includes our non-rate regulated power generation operations in the United States and our wholesale energy trading, marketing, power origination and risk management operations in North America. Trading and marketing purchases fuel to supply existing generation assets, sells the electricity produced by these assets, and manages the day-to-day trading and dispatch associated with these portfolios. As a result, we have made, and expect to continue to make, significant investments in developing the trading and marketing infrastructure including software, trading and risk control resources. 29
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30, -------------------------------- ------------------------------- 2000 2001 2000 2001 ------------- ------------- ------------- ------------- (IN MILLIONS) Operating Revenues ................... $ 6,734 $ 9,987 $ 12,342 $ 28,945 Operating Expenses: Fuel and Cost of Gas Sold .......... 2,698 3,207 6,061 13,195 Purchased Power .................... 3,575 6,326 5,506 14,527 Operation and Maintenance .......... 98 155 231 434 Depreciation and Amortization ...... 45 28 70 90 Other Operating Expenses ........... 4 5 10 12 ------------- ------------- ------------- ------------- Total Operating Expenses ......... 6,420 9,721 11,878 28,258 ------------- ------------- ------------- ------------- Operating Income ..................... $ 314 $ 266 $ 464 $ 687 ============= ============= ============= ============= Operations Data: Electricity Wholesale Power Sales (in MMWH (1)) .................... 68 108 132 270 Natural Gas Sales (in Bcf) ......... 625 1,097 1,707 2,723
- ---------- (1) Million megawatt hours. Our Wholesale Energy segment's operating income decreased $48 million for the third quarter of 2001 compared to the same period in 2000. The decline was primarily due to decreased gross margins (revenues less fuel and cost of gas sold and purchased power) resulting from lower gas and power unit margins in 2001 and favorable hedging activities in the Pennsylvania-New Jersey-Maryland market in 2000, increased operation and maintenance expenses from facilities in the West and Mid-Atlantic regions, higher legal and regulatory expenses related to Western markets and higher general and administrative expenses to support expanded commercial activities and operations. These costs were partially offset by decreased amortization expense related to air emissions regulatory allowances. Our Wholesale Energy segment's operating revenues increased $3.3 billion for the third quarter of 2001 compared to the same period in 2000. The increased revenues during the third quarter of 2001 compared to the same period in 2000 were primarily due to increased volumes for natural gas and power sales partially offset by decreased prices for natural gas sales. Our Wholesale Energy segment's fuel and gas costs and purchased power increased $3.3 billion in the third quarter of 2001 compared to the same period in 2000 primarily due to the same reasons as the increase in revenues. Operation and maintenance expenses for our Wholesale Energy segment increased $57 million in the third quarter of 2001 compared to the same period in 2000, primarily due to costs associated with the operation and maintenance of generating plants in the West region, higher lease expense associated with the Mid-Atlantic generating facilities' sale/leaseback transactions that were entered into in August 2000, higher administrative costs to support growing wholesale commercial activities and operations and higher legal and regulatory expenses related to Western markets, partially offset by decreased development expenses. The higher lease expense associated with the Mid-Atlantic generating facilities was offset by lower interest expense in the consolidated results of operations in the third quarter of 2001 compared to the same period in 2000. Depreciation and amortization expense for the third quarter of 2001 compared to the same period in 2000 decreased by $17 million primarily due to changes in expense related to the amortization of our air emissions regulatory allowances, primarily in California. Our Wholesale Energy segment's operating income increased $223 million for the first nine months of 2001 compared to the same period in 2000. The increase was primarily due to increased gross margins. Gross margins for our Wholesale Energy segment increased by $448 million primarily due to increased revenues from energy and ancillary services, increased volumes and higher margins from its trading and marketing activities and the addition of our Mid-Atlantic assets and strong commercial and operational performance in other regions. These results were partially offset by higher operation and maintenance expenses from facilities in the West and Mid-Atlantic regions, increased depreciation and amortization expense, and a $36 million provision and a $12 million net write-off against receivable balances related to energy sales in the West region. Our Wholesale Energy segment's operating revenues increased $16.6 billion for the first nine months of 2001 compared to the same period in 2000. The increased revenues were primarily due to increased volumes for natural gas and power 30 sales and to a lesser extent increased prices for natural gas and power sales. Our Wholesale Energy segment's fuel and gas costs and purchased power increased $16.2 billion in the first nine months of 2001 compared to the same period in 2000. Increased fuel and gas costs and purchased power were primarily due to increased purchased volumes for natural gas and power sales and to a lesser extent increases in plant output and increased prices for natural gas and power purchases. Operation and maintenance expenses for our Wholesale Energy segment increased $203 million in the first nine months of 2001 compared to the same period in 2000, primarily due to costs associated with the operation and maintenance of generating plants from facilities in the West and Mid-Atlantic regions, higher lease expense associated with the Mid-Atlantic generating facilities' sale/leaseback transactions and due to the other reasons for the increase in the third quarter of 2001, as discussed above. The higher lease expense associated with the Mid-Atlantic generating facilities was offset by lower interest expense in the consolidated results of operations in the first nine months of 2001 compared to the same period in 2000. Depreciation and amortization expense during the first nine months of 2001 compared to the same period in 2000 increased by $20 million as a result of higher expense related to the depreciation of our Mid-Atlantic plants, which were acquired in May 2000 and increased amortization of air emissions regulatory allowances. On June 19, 2001, the FERC issued an order modifying the market monitoring and mitigation plan it had previously adopted on April 26, 2001. This modification to the mitigation plan extends the hours to which the price controls are applied, as well as the states in which the price controls will be in effect. Additionally, the FERC issued an order on July 25, 2001, which ordered among other items, a methodology for calculating possible refunds by sellers of electricity in the West region. We, however, believe that while the mitigation plan will reduce volatility in the market, we will nevertheless be able to profitably operate our facilities in the West because the proxy market clearing price is based on the heat rate of the least efficient unit on-line during each hour. Additionally, as noted above, the mitigation plan allows sellers, such as us, to justify prices above the proxy price. Finally, any adverse impacts of the mitigation plan on our operations would be mitigated, in part, by our forward hedging activities. The amounts of any refunds will be determined by the end of an expedited hearing process which is scheduled to conclude March 8, 2002. We have not reserved any amounts for potential future refunds, nor can we currently predict the amount of these potential refunds, if any, because the methodology used to calculate these refunds is dependent on information that is currently unknown to us and still subject to review and challenge in the hearing process. For information regarding the reserve against receivables and uncertainties in the California wholesale energy market, please read Notes 12(a) and 12(d) to our Interim Financial Statements. EUROPEAN ENERGY Our European Energy segment includes the operations of REPGB and its subsidiaries and our European trading, marketing and risk management operations. Our European Energy segment generates and sells power from its generation facilities in the Netherlands and participates in the emerging wholesale energy trading and marketing industry in Europe. In September 2001, we announced that we are evaluating strategic alternatives for our European Energy segment, including the possible sale, in order to pursue business opportunities that are more in line with our domestic wholesale energy strategies. Beginning January 1, 2001, the Dutch wholesale electric market was completely opened to competition. Consistent with our expectations at the time that we made the acquisition, REPGB has experienced a significant decline in electric margins in 2001 attributable to the deregulation of the market. For additional information regarding these and other factors that may affect the future results of operations of our European Energy segment, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations - Certain Factors Affecting Our Future Earnings - Competitive, Regulatory and Other Factors Affecting Our European Energy Operations" in the Reliant Energy Form 10-K, which information is incorporated herein by reference. 31
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30, ------------------------------- ------------------------------- 2000 2001 2000 2001 ------------- ------------- ------------- ------------- (IN MILLIONS) Operating Revenues ........................ $ 129 $ 275 $ 415 $ 799 Operating Expenses: Fuel and Purchased Power ................ 68 229 199 629 Operation and Maintenance and Other ..... 31 31 90 90 Depreciation and Amortization ........... 15 20 54 57 ------------- ------------- ------------- ------------- Total Operating Expenses ............. 114 280 343 776 ------------- ------------- ------------- ------------- Operating Income (Loss) ................... $ 15 $ (5) $ 72 $ 23 ============= ============= ============= ============= Electricity (in MMWH): Wholesale Sales ......................... 2.8 4.6 8.7 11.9 Trading Sales ........................... 0.2 5.7 0.3 14.6
Our European Energy segment's operating income decreased $20 million and $49 million for the third quarter and the first nine months of 2001 compared to the same periods in 2000. These decreases were primarily due to a decrease in margins (revenues less fuel and purchased power), as the Dutch electric market was completely opened to wholesale competition on January 1, 2001. Increased margins from ancillary services and trading activities partially offset this decline. In the first half of 2001, efficiency and energy payments from SEP totaling $30 million and increased district heating sales partially offset the decline for the nine months ended September 30, 2001 compared to the same period in 2000. Our European Energy segment's operating revenues increased $146 million and $384 million for the third quarter and the first nine months of 2001 compared to the same periods in 2000. The increases were primarily due to increased trading revenues associated with our participation in the Dutch and German power markets. Fuel and purchased power costs increased $161 million and $430 million in the third quarter and the first nine months of 2001 compared to the same periods in 2000 primarily due to increased purchased power for trading activities, and to a lesser extent, increased cost of natural gas and other fuels due to increased output from our generating facilities. RETAIL ENERGY Our Retail Energy segment provides energy products and services to end-use customers, ranging from residential and small commercial customers to large commercial, institutional and industrial customers. In addition, our Retail Energy segment includes billing and remittance services provided to the Electric Operations segment and two of our natural gas distribution divisions. Retail Energy charges the regulated electric and gas utilities for these services at cost. Retail Energy is expected to succeed to Electric Operations' electric retail customer base in the Houston metropolitan area when the Texas market opens to competition in January 2002. Our Retail Energy segment has historically been reported in our Other Operations segment. As a result of the Texas Electric Choice pilot program which began in August 2001, these operations are being reported and evaluated as a separate segment by management. Accordingly, we are reporting the results of our retail operations as a separate segment for all periods presented. The Texas electric restructuring law calls for the commencement of retail competition beginning on January 1, 2002. This law authorizes the Texas Utility Commission to delay the date which the retail electric market is opened to competition in any power region in Texas if it is determined that the region is unable to offer fair competition and reliable service to all retail customer classes on that date. We anticipate retail competition will commence on January 1, 2002. If retail competition is delayed, our Retail Energy segment's results of operations and cash flows could be materially affected depending on the length of the delay. 32
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30, -------------------------------- -------------------------------- 2000 2001 2000 2001 ------------- ------------- ------------- ------------- (IN MILLIONS) Operating Revenues .................... $ 21 $ 52 $ 59 $ 115 Operating Expenses: Natural Gas ........................ -- 8 -- 8 Operation and Maintenance ........... 39 48 97 113 Depreciation and Amortization ....... 1 3 2 7 ------------- ------------- ------------- ------------- Total Operating Expenses ......... 40 59 99 128 ------------- ------------- ------------- ------------- Operating Loss ........................ $ (19) $ (7) $ (40) $ (13) ============= ============= ============= =============
Our Retail Energy segment's operating loss decreased $12 million and $27 million, respectively, in the third quarter and the first nine months of 2001 compared to the same periods in 2000. The operating loss reduction was primarily due to increased sales of energy and energy services to commercial and industrial customers from our Reliant Energy Solutions unit and energy sales and services for certain Texas governmental agencies under a program mandated by the Texas electric deregulation legislation. Operating revenues increased $31 million and $56 million, respectively, in the third quarter and the first nine months of 2001 compared to the same periods in 2000, due to revenues from sales of energy and energy services to commercial and industrial customers, energy sales and services for certain Texas governmental agencies, as well as increased revenues for the billing and remittance services provided to Reliant Energy. Operations and maintenance expenses increased $9 million and $16 million, respectively, in the third quarter and the first nine months of 2001 compared to the same periods in 2000, primarily due to increased personnel and employee related costs, costs related to building an infrastructure necessary to prepare for competition in the retail electric market in Texas and advertising costs. OTHER OPERATIONS Our Other Operations segment includes the operations of our eBusiness, Communications and venture capital businesses, non-operating investments, certain real estate holdings and unallocated corporate costs. Historically, our Other Operations segment has included the operations of our Communications business. For additional information about our exiting of our Communications business, please read Note 16 to our Interim Financial Statements. Our Other Operations segment's operating loss increased $28 million and $159 million, respectively, for the quarter and nine months ended September 30, 2001 compared to the same periods in 2000. The increased loss in the third quarter was primarily a result of a $33 million pre-tax charge related to the disposal of our Communications business. The increased loss for the nine months was primarily due to a $101 million pre-tax, non-cash charge related to the redesign of certain of our benefit plans in anticipation of the separation of our regulated and our unregulated businesses and the $33 million pre-tax disposal charge incurred in the third quarter as discussed above. For information regarding the benefit charge incurred in the first quarter of 2001, please read Note 14 to our Interim Financial Statements. CERTAIN FACTORS AFFECTING OUR FUTURE EARNINGS GENERAL 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 Energy Form 10-K, which is incorporated herein by reference. For additional information regarding the California wholesale market and related litigation, please read Notes 12(a) and 12(d) to our Interim Financial Statements. ELECTRIC OPERATIONS In contemplation of open competition, our Electric Operations segment has been allowed since 1998 under our Transition Plan approved by the Texas Utility Commission and the Legislation to earn base revenues which produced earnings in excess of traditional regulated levels. These excess earnings have been utilized to mitigate stranded cost of generation plants by accelerating the depreciation of these assets for regulatory purposes. 33 This transition to competition period is scheduled to end on December 31, 2001. At that time, and in accordance with the Legislation, we expect our Electric Operations segment will be unbundled pursuant to our business separation plan (please read Notes 4(a) and 4(b) to Reliant Energy 10-K Notes) into three distinct businesses: a transmission and distribution company, a power generation company and a retail company. New rates based on the allowed invested capital, or "rate base", of the transmission and distribution business will be implemented beginning on January 1, 2002. For more information regarding the final rulings in the rate case for the transmission and distribution company, please read Note 12(f) to our Interim Financial Statements. The retail business will be conducted by a subsidiary of Reliant Resources. The generation business will sell power via capacity auctions at market rates, which began in September 2001. However, the Legislation provides that during 2004 (please read Note 4(a) to Reliant Energy 10-K Notes), a true-up amount will be calculated which will be recovered from or returned to customers to adjust the market revenues earned from the capacity auctions to a level that should approximate a regulated return on the invested capital of the generation business. Thus, beginning in 2002, earnings of our Electric Operations segment will be reduced to near traditional regulated returns exclusive of any additional positive or negative cash flows that may result from implementation of competitive transition charges received from customers or other credits to customers, as applicable. The underlying assumptions for the true-up calculation have not been finalized. Accordingly, the results of operations of the unbundled components of our Electric Operations segment post-competition will significantly decline. 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, 2000 and 2001.
NINE MONTHS ENDED SEPTEMBER 30, ------------------------------------ 2000 2001 --------------- --------------- (IN MILLIONS) Cash provided by (used in): Operating activities ........... $ 1,074 $ 1,968 Investing activities ........... (3,301) (1,592) Financing activities ........... 2,382 (252)
Net cash provided by operating activities during the nine months ended September 30, 2001 increased $894 million compared to the same period in 2000 primarily due to improved operating cash flows from Wholesale Energy and a decrease in margin deposits on energy trading activities partially offset by a prepayment of a lease obligation related to the REMA sale/leaseback transactions and other changes in working capital. Net cash used in investing activities decreased $1.7 billion during the nine months ended September 30, 2001 compared to the same period in 2000 primarily due to the funding of the remaining purchase obligation for REPGB for $982 million on March 1, 2000 and the acquisition of REMA for $2.1 billion on May 12, 2000, partially offset by proceeds from REMA sale-leaseback transactions of $1 billion as well as an increase in capital expenditures related to the construction of domestic power generation projects during the nine months ended September 30, 2001. Cash flows from financing activities decreased $2.6 billion during the nine months ended September 30, 2001 compared to the same period in 2000 primarily due to financings in 2000 used to fund acquisitions. During the nine months ended September 30, 2001, a portion of the $1.7 billion in net proceeds from the initial public offering of Reliant Resources were used to pay down commercial paper. FUTURE SOURCES AND USES OF CASH FLOWS Credit Facilities. As of September 30, 2001, we had credit facilities in effect, including facilities of various financing subsidiaries and operating subsidiaries, which provided for an aggregate of $8.7 billion in committed credit. As of September 30, 2001, $4.6 billion was outstanding under these facilities including borrowings of $3.9 billion and letters of credit of $0.7 billion. The remaining unused credit facilities totaled $4.1 billion. Of the $8.7 billion of committed credit facilities described above, $6.0 billion will expire by September 30, 2002, including $978 million related to Reliant Resources and its subsidiaries. To the extent that we continue to need access to this amount of committed credit, we expect to extend or replace these facilities on normal commercial terms on a timely basis. 34 As of September 30, 2001, Reliant Resources had loaned $892 million to subsidiaries of Reliant Energy that are not subsidiaries of Reliant Resources. If any of these loans are outstanding at the Distribution, such loans must be repaid prior to the Distribution. Reliant Energy plans to repay these amounts, if any, through borrowings under existing credit facilities or commercial paper supported by such credit facilities. Shelf Registrations. At September 30, 2001, Reliant Energy had shelf registration statements providing for the issuance of $230 million aggregate liquidation value of our preferred stock, $580 million aggregate principal amount of our debt securities and $125 million of trust preferred securities and related junior subordinated debt securities. In addition, Reliant Energy had a shelf registration for 15 million shares of its common stock, which would have been worth $395 million as of September 30, 2001 based on the closing price of its common stock as of that date. In January 2001, RERC Corp. filed a shelf registration statement for $600 million of unsecured unsubordinated debt securities of which $550 million was issued in February 2001. Securitization. On October 24, 2001, Reliant Energy Transition Bond Company LLC (Bond Company), a Delaware limited liability company and direct wholly owned subsidiary of Reliant Energy, issued $749 million aggregate principal amount of its Series 2001-1 Transition Bonds pursuant to a financing order of the Texas Utility Commission. Classes of the bonds mature on September 15, 2007, September 15, 2009, September 15, 2011 and September 15, 2015, and bear interest at rates of 3.84%, 4.76%, 5.16% and 5.63%, respectively. Net proceeds to the Bond Company from the issuance were $738 million. The Bond Company paid Reliant Energy $738 million for all of Reliant Energy's interest in the financing order. We used the net proceeds for general corporate purposes, including the repayment of indebtedness. Preferred Stock Redemption. Reliant Energy has 97,397 shares of preferred stock outstanding, designated as $4 Preferred Stock. In connection with the formation of our new holding company, we plan to redeem the preferred stock prior to the special shareholder meeting to be held on December 17, 2001, at an aggregate redemption price of approximately $10.2 million plus accrued and unpaid dividends to the date fixed for redemption. The record date for the preferred stock redemption was November 6, 2001, and redemption notices were mailed on November 7, 2001. Fuel Filing. As of September 30, 2001, Reliant Energy HL&P was under-collected on fuel recovery by approximately $444 million. In two separate filings with the Texas Utility Commission in 2000, Reliant Energy HL&P received approval to implement fuel surcharges to collect the under-recovery of fuel expenses, as well as to adjust the fuel factor to compensate for significant increases in the price of natural gas. On March 15, 2001, Reliant Energy HL&P filed with the Texas Utility Commission to revise its fuel factor and address its undercollected fuel costs of $389 million, which is the accumulated amount from September 2000 through February 2001, plus estimates for March and April 2001. Reliant Energy HL&P requested to revise its fixed fuel factor to be implemented with the May 2001 billing cycle and proposed to defer the collection of the $389 million until the 2004 stranded costs true-up proceeding. On April 16, 2001, the Texas Utility Commission issued an order approving interim rates effective with the May 2001 billing cycle. On June 21, 2001, Reliant Energy HL&P filed with the Texas Utility Commission to terminate the interim factor and return to the prior fuel factor due to the forecasted decline in natural gas prices. On July 20, 2001, the Texas Utility Commission issued an order of dismissal approving Reliant Energy HL&P's request that the interim rates approved on April 16, 2001, effective with Reliant Energy HL&P's May billing month, be terminated and Reliant Energy HL&P prospectively bill its customers using the prior fuel factor established in a previous order beginning with Reliant Energy HL&P's August billing month. The Texas Utility Commission also granted Reliant Energy HL&P a good cause exception in that Reliant Energy HL&P will not be required to refund amounts collected through the interim rates. Reliant Energy HL&P did not waive its right to collect any final fuel balance. The final fuel balance is subject to review, and the amount to be included in the 2004 stranded cost true-up will be determined during the final fuel reconciliation. The Texas Utility Commission currently has scheduled Reliant Energy HL&P to file its final fuel reconciliation in July 2002. For additional information regarding this matter, please read Note 4(a) to Reliant Energy 10-K Notes. Initial Public Offering of Reliant Resources. On July 27, 2000, Reliant Energy announced its intention to form Reliant Resources to own and operate a substantial portion of Reliant Energy's unregulated operations, and to offer no more than 20% of the common stock of Reliant Resources in the Offering in connection with our business separation plan. In May 2001, Reliant Resources completed its initial public offering of 59.8 million shares of its common stock and received net proceeds of $1.7 billion. Pursuant to the terms of the master separation agreement, Reliant Resources used $147 million of the net proceeds to repay certain indebtedness owed to Reliant Energy. 35 Reliant Resources used the remainder of the net proceeds of the Offering for repayment of third party borrowings, capital expenditures, repurchases of common stock and to increase its working capital. Reliant Energy expects the Offering to be followed by a distribution of the remaining common stock of Reliant Resources owned by Reliant Energy to Reliant Energy's or its successor's shareholders within twelve months of the Offering. For additional information regarding our business separation plan, please read Note 4(b) to Reliant Energy 10-K Notes. Reliant Resources Stock Repurchase. In July 2001, Reliant Resources' Board of Directors authorized Reliant Resources to purchase up to one million shares of its common stock in anticipation of funding of its benefit plan obligations expected to be funded prior to Distribution. During the third quarter of 2001, Reliant Resources purchased 1,000,000 shares of its common stock at an average price of $20.42 per share, or an aggregate purchase price of $20.4 million. In addition, on September 18, 2001, Reliant Resources' Board of Directors authorized Reliant Resources to purchase up to 10 million additional shares of its common stock through February 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. From October 1, 2001 through November 8, 2001, Reliant Resources purchased 7,628,200 shares of its common stock at an average price of $16.69 per share. Acquisition of Mid-Atlantic Assets. On May 12, 2000, we completed the acquisition of our Mid-Atlantic assets from Sithe Energies, Inc. for an aggregate purchase price of $2.1 billion. The acquisition was originally financed through commercial paper borrowings by one of our financing subsidiaries. In August 2000, we entered into separate sale/leaseback transactions with each of the three owner-lessors for our respective 16.45%, 16.67% and 100% interests in the Conemaugh, Keystone and Shawville generating stations, respectively, which we acquired as part of the Mid-Atlantic acquisition. For additional discussion of these lease transactions, please read Notes 3(a) and 14(c) to Reliant Energy 10-K Notes. As consideration for the sale of our interest in the facilities, we received a total of $1.0 billion in cash that was used to repay commercial paper borrowings at one of our financing subsidiaries. We will continue to make lease payments through 2029. The lease terms expire in 2034. Acquisition of Orion Power Holdings, Inc. In September 2001, Reliant Resources entered into a definitive merger agreement with Orion Power Holdings, Inc. (Orion Power), under which Reliant Resources agreed to acquire all of the outstanding shares of Orion Power for $26.80 per share in cash in a transaction valued at approximately $2.9 billion. In the merger, Reliant Resources will also assume approximately $1.8 billion of Orion Power's net debt obligations. Orion Power is an independent electric power generating company formed in March 1998 to acquire, develop, own and operate power-generating facilities in the newly deregulated wholesale markets throughout North America. Orion Power has 81 power plants currently in operation with a total capacity of 5,644 MW and an additional 2,855 MW in construction and various stages of development. The merger is conditioned upon approval by Orion Power's shareholders and receipt of certain regulatory approvals including the Federal Trade Commission, New York Public Service Commission and the FERC. Reliant Resources expects to finance the purchase price with existing cash balances, existing credit facilities and new financing, which will be in place at or prior to closing. Generating Projects. As of September 30, 2001, we had four non-rate regulated generating facilities under construction. Total estimated costs of constructing these facilities are $1.4 billion, including $365 million in commitments for the purchase of combustion turbines. As of September 30, 2001, we had incurred $917 million of the total projected costs of these projects, which were funded primarily from borrowings and equity. We believe that our level of cash, our borrowing capability and proceeds from the offering of Reliant Resources as discussed above will be sufficient to fund these commitments. In addition, we have options to purchase additional combustion turbines for a total estimated cost of $112 million for future generation projects, which we are actively trying to remarket. We believe that our current level of cash, our borrowing capability and proceeds from the Reliant Resources Offering will be sufficient to fund these options should we choose to exercise them. Construction Agency Agreement. In April 2001, Reliant Resources, 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 have an aggregate financing commitment from equity and debt participants (Investors) of $2.5 billion. The availability of the commitment is subject to satisfaction of various conditions. Reliant Resources, through several of its subsidiaries, acts as construction agent for the special purpose entities and is responsible for completing construction of these projects by August 31, 2004, but has generally limited its risk related to construction completion to 89.9% of costs incurred to date, except in certain events. Upon completion of an individual project and exercise of the lease option, Reliant Resources' subsidiaries will be required to make lease payments in an amount sufficient to provide a return to the Investors. If Reliant Resources does not exercise its option to lease any project upon its completion, Reliant Resources must 36 purchase the project or remarket the project on behalf of the special purpose entities. Reliant Resources must guarantee that the Investors will receive at least 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), Reliant Resources' subsidiary lessees have the option to extend the lease with the approval of 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 up to 85% of the project cost if the proceeds from remarketing are not sufficient to repay the Investors. Reliant Resources 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. California Trade Receivables. During the summer and fall of 2000, and continuing into early 2001, prices for wholesale electricity in California increased dramatically as a result of a combination of factors, including higher natural gas prices and emissions allowance costs, reduction in available hydroelectric generation resources, increased demand, decreases in net electric imports, structural market flaws including over-reliance on the spot market, and limitations on supply as a result of maintenance and other outages. Although wholesale prices increased, California's deregulation legislation kept retail rates frozen below 1996 levels until rates were raised by the CPUC early this year. This caused two of California's public utilities, which are our customers based on our deliveries to the Cal PX and the Cal ISO, to accrue billions of dollars of unrecovered wholesale power costs and ultimately default in January and February 2001 on payments owed for wholesale power purchased through the Cal PX and from the Cal ISO, and in the case of PG&E, to file a voluntary petition for bankruptcy. As of September 30, 2001, we were owed $338 million by the Cal ISO, the Cal PX, the CDWR and California Energy Resource Scheduling for energy sales in the California wholesale market during the fourth quarter of 2000 through September 30, 2001 and have recorded an allowance against such receivables of $75 million. From October 1, 2001 through November 8, 2001, we have collected $3.2 million of these receivable balances. For additional information regarding uncertainties in the California wholesale market, please read Notes 12(a) and 12(d) to our Interim Financial Statements and Notes 14(g) and 14(h) to Reliant Energy 10-K Notes. Reliant Energy HL&P Rate Matters. The Texas Utility Commission issued a final order on October 3, 2001 that establishes the rates that will become effective when retail choice begins in 2002. In this final order, Reliant Energy HL&P is required to reverse the amount of redirected depreciation and accelerated depreciation allowed under the Transition Plan and the Legislation. The Texas Utility Commission determined that the utility had overmitigated its stranded costs. The Company disagrees with certain positions prescribed in the order by the Texas Utility Commission. Motions for Rehearing were filed by the Company with the Texas Utility Commission on October 23, 2001 and the Company will determine future action based on the Texas Utility Commission's response to these motions. Reliant Energy HL&P also filed an amicus brief on September 24, 2001 at the Texas Supreme Court supporting Texas Utilities Company's Petition for Writ of Mandamus challenging these same issues. At September 30, 2001, cumulative redirected depreciation and cumulative accelerated depreciation for regulatory purposes totaled $783 million and approximately $1.1 billion, respectively. Implementing the reversal of redirected depreciation would result in lower rates for the transmission and distribution utility, and the accelerated depreciation being returned through credits over seven years would serve as reductions to the transmission and distribution utility's non-bypassable charges. The annual impact to earnings for the reversal of redirected depreciation would be approximately $36 million after-tax, while the return of accelerated depreciation is not expected to impact earnings. The annual cash flow impact would be approximately $225 million. The credits related to accelerated depreciation will become effective beginning with retail choice. For additional information regarding redirected depreciation and accelerated depreciation, see Note 4(a) to Reliant Energy 10-K Notes. Other Sources/Uses of Cash. Our liquidity and capital requirements are affected primarily by capital expenditures, debt service requirements and various working capital needs. We expect to continue to bid on future acquisitions of independent power projects and privatizations of generation facilities. We expect any resulting capital requirements to be met with excess cash flows from operations, as well as proceeds from debt and equity offerings, project financings and other borrowings. We also expect Reliant Resources to establish a commercial paper program in late 2001 or the first half of 2002. Additional capital expenditures depend upon the nature and extent of future project commitments, some of which may be substantial. We believe that our current level of cash, our borrowing capability and proceeds from the Reliant Resources initial public offering discussed above, along with future cash flows from operations, will be sufficient to meet the existing operational needs of our businesses for the next twelve months. 37 NEW ACCOUNTING PRONOUNCEMENTS In July 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 141 "Business Combinations" (SFAS No. 141) and SFAS No. 142 "Goodwill and Other Intangible Assets" (SFAS No. 142). 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. SFAS No. 142 provides for a nonamortization approach, whereby 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. We will adopt the provisions of each statement which apply to goodwill and intangible assets acquired prior to June 30, 2001 on January 1, 2002. We are in the process of determining the effect of adoption of SFAS No. 141 and SFAS No. 142 on our consolidated financial statements. 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 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 APB Opinion No. 30, 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 is effective for fiscal years beginning after December 15, 2001, with early adoption encouraged. SFAS No. 144 is not expected to materially change the methods we use to measure impairment losses on long-lived assets, but may result in additional future dispositions being reported as discontinued operations than is currently permitted. We plan to adopt SFAS No. 144 on January 1, 2002. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK INTEREST RATE RISK At September 30, 2001, we had issued fixed-rate debt and Trust Preferred Securities aggregating $5.4 billion in principal amount having a fair value of $5.5 billion. The fair value of these instruments would increase by approximately $635 million if interest rates were to decline by 10% from their levels at September 30, 2001. Our floating-rate obligations aggregated $4.3 billion at September 30, 2001 (please read Note 10 to Reliant Energy 10-K Notes) inclusive of (a) amounts borrowed under our short-term and long-term credit facilities (including the issuance of commercial paper supported by these facilities), (b) borrowings under a receivables facility and (c) amounts subject to a master leasing agreement under which lease payments vary depending on short-term interest rates. If the floating rates were to increase by 10% from September 30, 2001 levels, our consolidated interest expense and expense under operating leases would increase by a total of approximately $1.5 million each month in which such an increase continued. 38 In November 1998, RERC Corp. sold $500 million aggregate principal amount of its 6 3/8% Term Enhanced Remarketable Securities (TERM Notes) which included an embedded option to remarket the securities. The option is expected to be exercised in the event that the ten year Treasury rate in 2003 is below 5.66%. At September 30, 2001, we could terminate the option at a cost of $33 million. A decrease of 10% in the September 30, 2001 level of interest rates would increase the cost of termination of the option by approximately $13 million. As discussed in Note 8(c) to Reliant Energy 10-K Notes, upon adoption of SFAS No. 133 effective January 1, 2001, the ZENS obligation was bifurcated into a debt component of $122 million and a derivative component of $788 million. Changes in the fair value of the derivative component are recorded in our Statements of Consolidated Income; therefore, we are exposed to changes in the fair value of the derivative component as a result of changes in the underlying risk-free interest rate. If the risk-free interest rate were to increase by 10% from September 30, 2001 levels, the fair value of the derivative component would increase by approximately $10 million, which would be recorded as a loss in our Statements of Consolidated Income. During the nine months ended September 30, 2001, we entered into interest rate swaps for the purpose of decreasing the amount of debt subject to interest rate fluctuations. At September 30, 2001, these interest rate swaps had an aggregate notional amount of $1.6 billion and a nominal fair value. At September 30, 2001, we could terminate these interest rate swaps at a cost of $14 million. A decrease of 10% in the September 30, 2001 level of interest rates would not increase the cost of termination of the swaps by a material amount. For information regarding the accounting for these interest rate swaps, see Note 3 to our Interim Financial Statements. EQUITY MARKET RISK As discussed in Note 8 to Reliant Energy 10-K Notes, we own approximately 26 million shares of AOL Time Warner Inc. common stock (AOL TW Common), which we hold to facilitate our ability to meet our obligations under the ZENS. Please read Note 8 to Reliant Energy 10-K Notes for a discussion of the effect of adoption of SFAS No. 133 on our ZENS obligation and our historical accounting treatment of our ZENS obligation. Subsequent to adoption of SFAS No. 133, a decrease of 10% from the September 30, 2001 market value of AOL TW Common would result in a loss of approximately $4 million, which would be recorded as a loss in our Statements of Consolidated Income. FOREIGN CURRENCY EXCHANGE RATE RISK As of September 30, 2001, we have entered into foreign currency swaps and foreign exchange forward contracts and have issued Euro-denominated debt to hedge our net investment in our European Energy segment. Changes in the value of the swaps, forwards 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, 2001, we have recorded a $76 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, 2001, our European Energy segment had entered into transactions to purchase approximately $123 million at fixed exchange rates in order to hedge future fuel purchases payable in U.S. dollars. As of September 30, 2001, the fair value of these financial instruments was a $4 million liability. An increase in the value of the Euro of 10% compared to the U.S. dollar from its September 30, 2001 level would result in an additional loss in the fair value of these foreign currency financial instruments of $12 million. For information regarding the accounting for these financial instruments, see Note 3 to our Interim Financial Statements and Note 2 of the Reliant Energy First Quarter 10-Q, which note is incorporated by reference herein. 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 in earnings based on a hypothetical 10% movement in energy prices. An increase of 10% in the market prices of energy commodities from their September 30, 2001 levels would have decreased the fair value of our Energy Derivatives from their levels on those respective dates by $1 million. 39 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 Derivatives, our highest, lowest and average monthly VAR were $6 million, $4 million and $5 million, respectively, during the third quarter of 2001 and $12 million, $4 million and $6 million, respectively, during the first nine months of 2001 based on a 95% confidence level and a one day holding period. During the third quarter of 2000, our highest, lowest and average monthly VAR were $12 million, $4 million and $7 million, respectively, and during the first nine months of 2000, our highest, lowest and average monthly VAR were $12 million, $1 million and $5 million, respectively, based on a 95% confidence level and 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 this Form 10-Q or a failure of risk controls will not lead to significant losses from our marketing and risk management activities. 40 RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES (A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED) STATEMENTS OF CONSOLIDATED OPERATIONS (THOUSANDS OF DOLLARS) (UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------------------ ------------------------------ 2000 2001 2000 2001 ------------ ------------ ------------ ------------ REVENUES ............................................. $ 7,265,045 $ 668,903 $ 14,368,967 $ 4,051,754 EXPENSES: Natural gas and purchased power .................... 6,968,565 414,217 13,408,344 3,118,665 Operation and maintenance .......................... 204,721 173,520 537,035 514,094 Depreciation and amortization ...................... 58,552 51,996 164,000 154,837 Taxes other than income taxes ...................... 24,471 23,694 79,960 100,830 ------------ ------------ ------------ ------------ Total .......................................... 7,256,309 663,427 14,189,339 3,888,426 ------------ ------------ ------------ ------------ OPERATING INCOME ..................................... 8,736 5,476 179,628 163,328 ------------ ------------ ------------ ------------ OTHER (EXPENSE) INCOME: Interest expense, net .............................. (38,959) (40,080) (100,100) (118,700) Distribution on trust preferred securities ......... (7) (7) (22) (21) Other, net ......................................... 5,732 1,323 (7,401) 13,293 ------------ ------------ ------------ ------------ Total .......................................... (33,234) (38,764) (107,523) (105,428) ------------ ------------ ------------ ------------ (LOSS) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES ....................................... (24,498) (33,288) 72,105 57,900 Income Tax (Benefit) Expense ....................... (5,577) (5,997) 41,119 38,448 ------------ ------------ ------------ ------------ (LOSS) INCOME FROM CONTINUING OPERATIONS ............. (18,921) (27,291) 30,986 19,452 Loss from Discontinued Operations, net of tax of zero ............................................. (7,957) -- (16,225) -- ------------ ------------ ------------ ------------ NET (LOSS) INCOME .................................... $ (26,878) $ (27,291) $ 14,761 $ 19,452 ============ ============ ============ ============
See Notes to RERC's Interim Financial Statements 41 RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES (A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED) CONSOLIDATED BALANCE SHEETS (THOUSANDS OF DOLLARS) (UNAUDITED) ASSETS
DECEMBER 31, SEPTEMBER 30, 2000 2001 ------------ ------------- CURRENT ASSETS: Cash and cash equivalents ................................... $ 22,576 $ 6,152 Accounts and notes receivable, principally customer, net .... 794,904 370,574 Accrued unbilled revenue .................................... 550,183 110,162 Fuel and petroleum products ................................. 82,707 151,476 Materials and supplies ...................................... 33,394 32,758 Non-trading derivative assets ............................... -- 9,143 Taxes receivable ............................................ -- 3,248 Accumulated deferred income taxes ........................... -- 35,115 Other ....................................................... 45,926 20,216 ------------ ------------ Total current assets ...................................... 1,529,690 738,844 ------------ ------------ PROPERTY, PLANT AND EQUIPMENT: Property, plant and equipment ............................... 3,429,304 3,605,238 Less accumulated depreciation ............................... (399,947) (475,975) ------------ ------------ Property, plant and equipment, net ........................ 3,029,357 3,129,263 ------------ ------------ OTHER ASSETS: Goodwill, net ............................................... 1,787,015 1,734,097 Prepaid pension asset ....................................... 141,882 55,601 Non-trading derivative assets ............................... -- 2,795 Other ....................................................... 87,821 103,719 ------------ ------------ Total other assets ........................................ 2,016,718 1,896,212 ------------ ------------ TOTAL ASSETS .................................................. $ 6,575,765 $ 5,764,319 ============ ============
See Notes to RERC's Interim Financial Statements 42 RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES (A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED) CONSOLIDATED BALANCE SHEETS (THOUSANDS OF DOLLARS) -- (CONTINUED) (UNAUDITED) LIABILITIES AND STOCKHOLDER'S EQUITY
DECEMBER 31, SEPTEMBER 30, 2000 2001 ------------- ------------- CURRENT LIABILITIES: Short-term borrowings .................................................... $ 635,000 $ 283,308 Current portion of long-term debt ........................................ 146,252 -- Accounts payable ......................................................... 704,524 222,501 Accounts and notes payable - affiliated companies, net ................... 134,707 27,942 Taxes accrued ............................................................ 69,877 -- Interest accrued ......................................................... 35,725 33,915 Customer deposits ........................................................ 33,357 39,106 Non-trading derivative liabilities ....................................... -- 102,207 Other .................................................................... 96,375 77,920 ------------- ------------- Total current liabilities .......................................... 1,855,817 786,899 ------------- ------------- OTHER LIABILITIES: Accumulated deferred income taxes ........................................ 583,857 528,588 Benefit obligations ...................................................... 175,144 196,091 Non-trading derivative liabilities ....................................... -- 14,788 Notes payable - affiliated companies, net ................................ 21,718 26,682 Other .................................................................... 144,853 148,498 ------------- ------------- Total other liabilities .............................................. 925,572 914,647 ------------- ------------- LONG-TERM DEBT ............................................................. 1,392,798 1,927,779 ------------- ------------- COMMITMENTS AND CONTINGENCIES (NOTES 1 AND 10) RERC OBLIGATED MANDATORILY REDEEMABLE CONVERTIBLE PREFERRED SECURITIES OF SUBSIDIARY TRUST HOLDING SOLELY JUNIOR SUBORDINATED DEBENTURES OF RERC ...................................................... 608 601 ------------- ------------- STOCKHOLDER'S EQUITY: Common stock ............................................................. 1 1 Paid-in capital .......................................................... 2,410,716 2,255,396 Accumulated deficit ...................................................... -- (45,955) Accumulated other comprehensive loss ..................................... (9,747) (75,049) ------------- ------------- Total stockholder's equity ........................................... 2,400,970 2,134,393 ------------- ------------- TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY .............................. $ 6,575,765 $ 5,764,319 ============= =============
See Notes to RERC's Interim Financial Statements 43 RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES (A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED) STATEMENTS OF CONSOLIDATED CASH FLOWS (THOUSANDS OF DOLLARS) (UNAUDITED)
NINE MONTHS ENDED SEPTEMBER 30, -------------------------------- 2000 2001 ------------- ------------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income ............................................................. $ 14,761 $ 19,452 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization ........................................ 164,000 154,837 Deferred income taxes ................................................ 9,093 (8,618) Net cash used in discontinued operations ............................. (1,182) -- Impairment of marketable equity securities ........................... 26,504 -- Changes in other assets and liabilities: Accounts and notes receivable ...................................... (563,958) 821,084 Accounts receivable/payable, affiliates ............................ 34,666 (40,694) Inventory .......................................................... (71,626) (61,813) Accounts payable ................................................... 472,360 (482,023) Fuel cost (under) recovery ......................................... (7,374) 53,741 Interest and taxes accrued ......................................... 368 (110,050) Net price risk management assets ................................... (24,436) -- Margin deposits on energy trading activities, net .................. (62,755) -- Other assets ....................................................... (69,742) (2,782) Other liabilities .................................................. 99,225 16,905 Other, net ........................................................... (418) 60,065 ------------- ------------- Net cash provided by operating activities ........................ 19,486 420,104 ------------- ------------- CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures ................................................... (197,703) (199,092) Net cash used in discontinued operations ............................... (2,800) -- Other, net ............................................................. (15,855) (45,784) ------------- ------------- Net cash used in investing activities ............................ (216,358) (244,876) ------------- ------------- CASH FLOWS FROM FINANCING ACTIVITIES: Payments of long-term debt ............................................. (200,000) (155,455) Proceeds from long-term debt ........................................... 322,400 544,632 Increase (decrease) in short-term borrowings, net ...................... 100,416 (351,692) Decrease in notes with affiliates, net ................................. (81,484) (61,107) Dividend paid .......................................................... -- (400,000) Capital contribution from Reliant Energy ............................... -- 236,000 Other, net ............................................................. (359) (4,030) ------------- ------------- Net cash provided by (used in) financing activities .............. 140,973 (191,652) ------------- ------------- NET DECREASE IN CASH AND CASH EQUIVALENTS ................................. (55,899) (16,424) CASH AND CASH EQUIVALENTS AT BEGINNING OF THE PERIOD ...................... 80,127 22,576 ------------- ------------- CASH AND CASH EQUIVALENTS AT END OF THE PERIOD ............................ $ 24,228 $ 6,152 ============= ============= SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash Payments: Interest (net of amounts capitalized) .................................. $ 101,165 $ 121,026 Income taxes ........................................................... 54,328 116,237
See Notes to RERC's Interim Financial Statements 44 RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (1) BASIS OF PRESENTATION See Note 1 to Reliant Energy's Interim Financial Statements. The preparation of financial statements in conformity with generally accepted accounting principles 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. RERC's 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 for the respective periods. Amounts reported in RERC's Statements of Consolidated Operations are not necessarily indicative of amounts expected for a full year period due to the effects of, among other things, (a) seasonal variations in energy consumption, (b) timing of maintenance and other expenditures and (c) acquisitions and dispositions of assets and other interests. In addition, certain amounts from the prior year have been reclassified to conform to RERC's presentation of financial statements in the current year. These reclassifications do not affect earnings of RERC. RERC's Interim Financial Statements are unaudited, omit certain financial statement disclosures and should be read with the combined Annual Report on Form 10-K of Reliant Energy (Reliant Energy Form 10-K) and RERC Corp. (RERC Corp. Form 10-K) for the year ended December 31, 2000, and the Quarterly Reports on Form 10-Q of Reliant Energy (Reliant Energy First Quarter 10-Q) and RERC Corp. (RERC Corp. First Quarter 10-Q) for the quarter ended March 31, 2001 and the Quarterly Reports on Form 10-Q of Reliant Energy (Reliant Energy Second Quarter 10-Q) and RERC Corp. (RERC Corp. Second Quarter 10-Q) for the quarter ended June 30, 2001. The following notes to the financial statements in the RERC Corp. Form 10-K relate to certain contingencies. These notes, as updated herein, are incorporated herein by reference: Notes to Consolidated Financial Statements (RERC Corp. 10-K Notes): Note 2(f) (Regulatory Assets), Note 4 (Derivative Financial Instruments) and Note 9 (Commitments and Contingencies). For information regarding environmental matters and legal proceedings, see Note 10 to RERC's Interim Financial Statements. (2) NEW ACCOUNTING PRONOUNCEMENTS In July 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 141 "Business Combinations" (SFAS No. 141) and SFAS No. 142 "Goodwill and Other Intangible Assets " (SFAS No. 142). 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. SFAS No. 142 provides for a nonamortization approach, whereby 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 provisions of each statement which apply to goodwill and intangible assets acquired prior to June 30, 2001 will be adopted by RERC on January 1, 2002. RERC is in the process of determining the effect of adoption of SFAS No. 141 and SFAS No. 142 on its consolidated financial statements. 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 45 adoption. RERC 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 (APB Opinion No. 30), 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 is effective for fiscal years beginning after December 15, 2001, with early adoption encouraged. SFAS No. 144 is not expected to materially change the methods used by RERC to measure impairment losses on long-lived assets, but may result in additional future dispositions being reported as discontinued operations than is currently permitted. RERC plans to adopt SFAS No. 144 on January 1, 2002. (3) DERIVATIVE FINANCIAL INSTRUMENTS Adoption of SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities" as amended (SFAS No. 133) on January 1, 2001 resulted in a cumulative after-tax decrease in accumulated other comprehensive loss of $38 million. The adoption also increased current assets, long-term assets, current liabilities and long-term liabilities by $88 million, $5 million, $53 million and $2 million, respectively, in RERC's Consolidated Balance Sheet. During the nine months ended September 30, 2001, losses of $31 million of the initial transition adjustment recognized in other comprehensive loss were realized in net income. 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 is April 1, 2002. RERC is currently assessing the impact of this recently cleared issue and does not believe it will have a material impact on RERC's consolidated financial statements. Cash Flow Hedges. During the nine months ended September 30, 2001, the amount of hedge ineffectiveness recognized in earnings from derivatives that are designated and qualify as cash flow hedges was immaterial. No component of the derivative instruments' gain or loss was excluded from the assessment of effectiveness. During the nine months ended September 30, 2001, there were no deferred gains or losses 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, 2001, current non-trading derivative assets and liabilities and corresponding amounts in accumulated other comprehensive loss are expected to be reclassified into net income during the next twelve months. (4) RELIANT ENERGY'S SEPARATION PLAN In 2000, Reliant Energy announced its intention to divide into two publicly traded companies in order to separate its unregulated businesses from its regulated businesses. In August 2000, Reliant Energy formed Reliant Resources to own and operate a substantial portion of Reliant Energy's unregulated operations and to offer no more than 20% of Reliant Resources' common stock in an initial public offering. In May 2001, Reliant Resources offered 59.8 million shares of its common stock to the public in an initial public offering and received net proceeds of $1.7 billion. Reliant Energy expects to distribute the remaining common stock of Reliant Resources it owns to Reliant Energy's or its successor's shareholders within twelve months after the completion of Reliant Resources' initial public offering. As part of the separation, Reliant Energy will undergo a restructuring of its corporate organization to achieve a new holding company structure. The new holding company will hold Reliant Energy's regulated businesses and will be named CenterPoint Energy, Inc. In connection with the formation of the new holding company, Reliant Energy has filed an application with the SEC requesting an exemption from the registration requirements of the Public Utility Holding Company Act of 1935 (1935 Act). The restructuring will require approval of the SEC, certain of the affected state commissions and the Nuclear Regulatory Commission. On October 22, 2001, the Board of Directors of Reliant Energy announced that a special meeting of shareholders of Reliant Energy will be held on December 17, 2001. At the special meeting, shareholders of record as of the close of business on November 1, 2001 46 will be asked to approve the merger whereby CenterPoint Energy, Inc. will become the new holding company. Reliant Energy expects to begin mailing a joint proxy statement/prospectus relating to the special meeting to its shareholders on or about November 12, 2001. In order to satisfy requirements for maintaining the exemption from the registration requirements of the 1935 Act, RERC expects to separate its three gas distribution divisions into three separate corporate entities within two years of the SEC's exemption order. The separation of these businesses will require additional regulatory approvals from the state utility regulators in five of the six states where RERC currently operates gas distribution businesses and may require waivers, consents and/or modifications to certain RERC agreements, including credit facilities and other financing arrangements. On December 31, 2000, RERC Corp. transferred all of the outstanding stock of Reliant Energy Services International, Inc. (RESI), Arkla Finance Corporation (Arkla Finance) and Reliant Energy Europe Trading & Marketing, Inc. (RE Europe Trading), all wholly owned subsidiaries of RERC Corp., to Reliant Resources (collectively, the Stock Transfer). Both RERC Corp. and Reliant Resources are subsidiaries of Reliant Energy. As a result of the Stock Transfer, RESI, Arkla Finance and RE Europe Trading each became a wholly owned subsidiary of Reliant Resources. Also, on December 31, 2000, a wholly owned subsidiary of Reliant Resources merged with and into Reliant Energy Services, Inc. (Reliant Energy Services), a wholly owned subsidiary of RERC Corp., with Reliant Energy Services as the surviving corporation (Merger). As a result of the Merger, Reliant Energy Services became a wholly owned subsidiary of Reliant Resources. As consideration for the Merger, Reliant Resources paid $94 million to RERC Corp. Prior to January 1, 2001, Reliant Energy Services, RESI and RE Europe Trading conducted the trading, marketing, power origination and risk management business and operations of RERC. Arkla Finance is a company that holds an investment in marketable equity securities. The Stock Transfer and the Merger are part of Reliant Energy's previously announced restructuring. RERC is reporting the results of RE Europe Trading as discontinued operations for all periods presented in RERC's Interim Financial Statements in accordance with APB Opinion No. 30. (5) DISCONTINUED OPERATIONS As discussed in Note 4, on December 31, 2000, RERC transferred all of the outstanding stock of RE Europe Trading to Reliant Resources. As a result of the transfer, RERC is reporting the results of RE Europe Trading as discontinued operations for all periods presented in RERC's Interim Financial Statements in accordance with APB Opinion No. 30. Below is a table of the operating results of RE Europe Trading for the three and nine months ended September 30, 2000.
THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, 2000 SEPTEMBER 30, 2000 ------------------ ------------------ (IN MILLIONS) Revenues ................ $ 8 $ 13 Operating expenses ...... 16 29 Operating loss .......... (8) (16) Net loss ................ (8) (16)
In addition to RE Europe Trading, RERC transferred its interests in RESI, Arkla Finance and Reliant Energy Services to Reliant Resources as described in Note 4. The transfer of these operations did not result in the disposal of a segment of business as defined under APB Opinion No. 30. Revenues and net income for these operations were $6 billion and $9 million, respectively, for the three months ended September 30, 2000 and revenues and net loss were $12 billion and $4 million, respectively, for the nine months ended September 30, 2000. (6) DEPRECIATION AND AMORTIZATION RERC's depreciation expense for the quarter and nine months ended September 30, 2000 was $43 million and $118 million, respectively, compared to $37 million and $109 million for the same periods in 2001. Amortization 47 expense, primarily relating to goodwill amortization, for the quarter and nine months ended September 30, 2000 was $16 million and $46 million, respectively, compared to $15 million and $46 million for the same periods in 2001. (7) RERC OBLIGATED MANDATORILY REDEEMABLE CONVERTIBLE PREFERRED SECURITIES OF SUBSIDIARY TRUSTS HOLDING SOLELY JUNIOR SUBORDINATED DEBENTURES OF RERC -- see Note 11 to Reliant Energy's Interim Financial Statements. (8) COMPREHENSIVE INCOME The following table summarizes the components of total comprehensive (loss) income.
THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ----------------------------- ---------------------------- 2000 2001 2000 2001 ------------ ------------ ------------ ------------ (IN MILLIONS) Net (loss) income .................................... $ (27) $ (27) $ 15 $ 19 Other comprehensive income: Additional minimum non-qualified pension liability adjustment ............................. -- (3) -- 1 Cumulative effect of adoption of SFAS No. 133 ...... -- -- -- 38 Net deferred loss from cash flow hedges ............ -- (7) -- (66) Reclassification of net deferred gains from cash flow hedges realized in net income ............... -- (23) -- (38) Unrealized loss on available-for-sale securities .. (2) -- -- -- Reclassification adjustment for impairment loss on available-for-sale securities realized in net income ....................................... 3 -- 17 -- ------------ ------------ ------------ ------------ Comprehensive (loss) income .......................... $ (26) $ (60) $ 32 $ (46) ============ ============ ============ ============
(9) RELATED PARTY TRANSACTIONS From time to time, RERC has advanced to or borrowed money from Reliant Energy or its subsidiaries. As of December 31, 2000, included in accounts and notes payable-affiliated companies, RERC had net short term borrowings of $59 million and net accounts payable of $76 million. As of September 30, 2001, included in accounts and notes payable-affiliated companies, RERC had net short term notes receivable of $7 million, offset by net accounts payable of $35 million. As of December 31, 2000 and September 30, 2001, RERC had net long term borrowings, included in notes payable-affiliated companies, totaling $22 million and $27 million, respectively. For the three and nine months ended September 30, 2000, RERC had net interest income of $1 million and $3 million, respectively. For the three and nine months ended September 30, 2001, RERC had net interest income of $0.5 million and $5 million, respectively. In 2000, Reliant Energy Services supplied natural gas to, purchased electricity for resale from, and provided marketing and risk management services to, unregulated power plants in deregulated markets acquired or operated by Reliant Energy Power Generation, Inc., an indirect subsidiary of Reliant Energy, or its subsidiaries. In 2001, RERC supplies natural gas to Reliant Energy Services, now a subsidiary of Reliant Resources (see Note 4). For the three and nine months ended September 30, 2000, the sales and services to Reliant Energy and its affiliates totaled $268 million and $452 million, respectively. For the three and nine months ended September 30, 2001, the sales and services to Reliant Energy and its affiliates totaled $15 million and $148 million, respectively. Purchases from Reliant Energy and its affiliates were $192 million and $318 million for the three and nine months ended September 30, 2000, respectively, and $85 million and $516 million for the three and nine months ended September 30, 2001, respectively. Reliant Energy provides some corporate services to RERC, 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 services have been directly charged or allocated to RERC 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 48 allocations are not necessarily indicative of what would have been incurred had RERC been a separate entity. Amounts charged and allocated to RERC for these services were $9 million and $23 million for the three and nine months ended September 30, 2000, respectively, and $7 million and $22 million for the three and nine months ended September 30, 2001, respectively, and are included primarily in operation and maintenance expenses. In May 2001, Reliant Energy made a $236 million capital contribution to RERC Corp. and RERC Corp. subsequently advanced the $236 million to a financing subsidiary of Reliant Energy, which is not a subsidiary of RERC. (10) ENVIRONMENTAL MATTERS AND LEGAL PROCEEDINGS (a) Environmental Matters. Manufactured Gas Plant Sites. RERC and its predecessors operated a manufactured gas plant (MGP) adjacent to the Mississippi River in Minnesota formerly known as Minneapolis Gas Works (MGW) until 1960. RERC has substantially completed remediation of the main site other than ongoing water monitoring and treatment. The manufactured gas was stored in separate holders. RERC is negotiating cleanup of one such holder. There are six other former MGP sites in the Minnesota service territory. Remediation has been completed on one site. Of the remaining five sites, RERC believes that two were neither owned nor operated by RERC. RERC believes it has no liability with respect to the sites it neither owned nor operated. At September 30, 2001, RERC had accrued $17 million for remediation of the Minnesota sites. At September 30, 2001, the estimated range of possible remediation costs was $8 million to $36 million. The cost estimates of the MGW site are based on studies of that site. The remediation costs for the other sites are based on industry average costs for remediation of sites of similar size. The actual remediation costs will be dependent upon the number of sites remediated, the participation of other potentially responsible parties, if any, and the remediation methods used. Issues relating to the identification and remediation of MGPs are common in the natural gas distribution industry. RERC has received notices from the United States Environmental Protection Agency and others regarding its status as a potentially responsible party (PRP) for other sites. Based on current information, RERC has not been able to quantify a range of environmental expenditures for potential remediation expenditures with respect to other MGP sites. Other Minnesota Matters. At September 30, 2001, RERC had recorded accruals of $4 million (with a maximum estimated exposure for these accruals of approximately $17 million at September 30, 2001) for other environmental matters in Minnesota for which remediation may be required. Mercury Contamination. RERC's pipeline and distribution operations have in the past employed elemental mercury in measuring and regulating equipment. It is possible that small amounts of mercury may have been spilled in the course of normal maintenance and replacement operations and that these spills may have contaminated the immediate area with elemental mercury. This type of contamination has been found by RERC at some sites in the past, and RERC has conducted remediation at these sites. It is possible that other contaminated sites may exist and that remediation costs may be incurred for these sites. Although the total amount of these costs cannot be known at this time, based on experience of RERC and that of others in the natural gas industry to date and on the current regulations regarding remediation of these sites, RERC believes that the costs of any remediation of these sites will not be material to RERC's financial condition, results of operations or cash flows. Potentially Responsible Party Notifications. From time to time, RERC has received notices from regulatory authorities or others regarding its status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. Considering the information currently known about such sites and the involvement of RERC in activities at these sites, RERC does not believe that these matters will have a material adverse effect on RERC's financial condition, results of operations or cash flows. (b) Other Legal Matters. California Wholesale Market. Reliant Energy, Reliant Energy Services, Inc. (a wholly owned subsidiary of Reliant Resources), Reliant Energy Power Generation, Inc. (a wholly owned subsidiary of Reliant Resources) and several other subsidiaries of Reliant Resources, as well as three officers of some of these companies, have been named as defendants in class action lawsuits and other lawsuits filed against a number of companies that own 49 generation plants in California and other sellers of electricity in California markets. RERC had also been named as a defendant in one of these actions. Plaintiffs have voluntarily dismissed Reliant Energy from two of the three class actions in which it was named as a defendant. Plaintiffs have also voluntarily dismissed RERC from the one action in which it was named as a defendant. Other. RERC is a party to litigation (other than that specifically noted) which arises in the normal course of business. Management regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. Management believes that the effects, if any, from the disposition of these matters will not have a material adverse effect on RERC's financial condition, results of operations or cash flows. (11) TRANSFER OF BENEFIT ASSETS AND LIABILITIES During the first quarter of 2001, RERC Corp. had net distributions to Reliant Energy related to benefit assets and obligations, net of deferred taxes, of $62 million. (12) REPORTABLE SEGMENTS Because RERC Corp. is a wholly owned subsidiary of Reliant Energy, RERC's determination of reportable segments considers the strategic operating units under which Reliant Energy manages sales, allocates resources and assesses performance of various products and services to wholesale or retail customers in differing regulatory environments. Segment financial data includes information for Reliant Energy and RERC on a combined basis, except for Reliant Energy segments that have no RERC operations in the applicable period. Reconciling items included under the caption "Elimination of Non-RERC Operations" reduce the consolidated Reliant Energy amounts by those operations not conducted within the RERC legal entity. Operations not owned or operated by RERC, but included in segment information before elimination include primarily the operations and assets of Reliant Energy's non-rate regulated power generation business in 2000 and Reliant Energy's investment in AOL Time Warner securities, and non-RERC corporate expenses in 2000 and 2001. Reliant Energy has identified the following reportable segments in which RERC has operations: Wholesale Energy (prior to January 1, 2001), Natural Gas Distribution, Pipelines and Gathering and Other Operations. For descriptions of the financial reporting segments, see Note 12 to RERC Corp. 10-K Notes. The following table summarizes financial data for the business segments:
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2000 ------------------------------------------------- AS OF NET DECEMBER 31, 2000 REVENUES FROM INTERSEGMENT OPERATING ----------------- NON-AFFILIATES REVENUES INCOME (LOSS) TOTAL ASSETS -------------- ------------- ------------- ------------- (IN MILLIONS) Wholesale Energy ..................... $ 6,622 $ 112 $ 314 $ 10,866 Natural Gas Distribution ............. 863 7 (42) 4,547 Pipelines and Gathering .............. 42 51 33 2,358 Other Operations ..................... 4 -- (25) 1,482 Reconciling Elimination .............. -- (170) -- (1,112) Elimination of Non-RERC Operations ... (266) -- (271) (11,565) ------------- ------------- ------------- ------------- Consolidated ......................... $ 7,265 $ -- $ 9 $ 6,576 ============= ============= ============= =============
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2000 ----------------------------------------------------- NET REVENUES FROM INTERSEGMENT OPERATING NON-AFFILIATES REVENUES INCOME (LOSS) -------------- ------------- ------------- (IN MILLIONS) Wholesale Energy ....................... $ 11,990 $ 352 $ 464 Natural Gas Distribution ............... 2,690 24 51 Pipelines and Gathering ................ 128 146 99 Other Operations ....................... 10 -- (42) Reconciling Elimination ................ -- (522) -- Elimination of Non-RERC Operations ..... (449) -- (392) ------------- ------------- ------------- Consolidated ........................... $ 14,369 $ -- $ 180 ============= ============= =============
50
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2001 ------------------------------------------------------ AS OF NET SEPTEMBER 30, 2000 REVENUES FROM INTERSEGMENT OPERATING ------------------ NON-AFFILIATES REVENUES INCOME (LOSS) TOTAL ASSETS -------------- ------------- ------------- ------------- ( IN MILLIONS) Natural Gas Distribution ............... $ 602 $ 6 $ (25) $ 3,630 Pipelines and Gathering ................ 52 40 34 2,334 Other Operations ....................... 4 1 (53) 1,301 Reconciling Elimination ................ -- (47) -- (1,017) Elimination of Non-RERC Operations ..... (4) -- 49 (484) Sales to Non-RERC Affiliates ........... 15 -- -- -- ------------- ------------- ------------- ------------- Consolidated ........................... $ 669 $ -- $ 5 $ 5,764 ============= ============= ============= =============
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2001 ------------------------------------------------------- NET REVENUES FROM INTERSEGMENT OPERATING NON-AFFILIATES REVENUES INCOME (LOSS) -------------- -------------- -------------- ( IN MILLIONS) Natural Gas Distribution ............... $ 3,727 $ 92 $ 62 Pipelines and Gathering ................ 177 141 106 Other Operations ....................... 13 1 (201) Reconciling Elimination ................ -- (234) -- Elimination of Non-RERC Operations ..... (13) -- 196 Sales to Non-RERC Affiliates ........... 148 -- -- -------------- -------------- -------------- Consolidated ........................... $ 4,052 $ -- $ 163 ============== ============== ==============
51 MANAGEMENT'S NARRATIVE ANALYSIS OF THE RESULTS OF OPERATIONS OF RERC CORP. AND SUBSIDIARIES The following narrative analysis should be read in combination with RERC Corp.'s Interim Financial Statements and notes contained in this Form 10-Q. RERC Corp. meets the conditions specified in General Instruction H(1)(a) and (b) to Form 10-Q and is therefore permitted to use the reduced disclosure format for wholly owned subsidiaries of reporting companies. Accordingly, RERC Corp. has omitted from this report the information called for by Item 3 (Quantitative and Qualitative Disclosures About Market Risk) of Part I and the following Part II items of Form 10-Q: Item 2 (Changes in Securities and Use of Proceeds), Item 3 (Defaults Upon Senior Securities) and Item 4 (Submission of Matters to a Vote of Security Holders). The following discussion explains material changes in the amount of revenue and expense items of RERC between the quarter and nine months ended September 30, 2001 and the quarter and nine months ended September 30, 2000. Reference is made to Management's Narrative Analysis of the Results of Operations in Item 7 of the RERC Corp. Form 10-K, the RERC Corp. 10-K Notes and RERC Corp. First and Second Quarter 10-Q referred to herein. On July 27, 2000, Reliant Energy announced its intention to form Reliant Resources to own and operate a substantial portion of Reliant Energy's unregulated operations, and to offer no more than 20% of the common stock of Reliant Resources in an initial public offering (Offering) in connection with Reliant Energy's business separation plan. In May 2001, Reliant Resources completed its initial public offering of 59.8 million shares of its common stock and received net proceeds of $1.7 billion. Reliant Energy expects the Offering to be followed by a distribution of the remaining common stock of Reliant Resources owned by Reliant Energy to Reliant Energy's or its successor's shareholders within twelve months of the Offering (Distribution). As part of the separation, Reliant Energy will undergo a restructuring of its corporate organization to achieve a new holding company structure. The new holding company will hold Reliant Energy's regulated businesses and will be named CenterPoint Energy, Inc. In connection with the formation of the new holding company, Reliant Energy has filed an application with the SEC requesting an exemption from the registration requirements of the Public Utility Holding Company Act of 1935 (1935 Act). The restructuring will require approval of the SEC, certain of the affected state commissions and the Nuclear Regulatory Commission. On October 22, 2001, the Board of Directors of Reliant Energy announced that a special meeting of shareholders of Reliant Energy will be held on December 17, 2001. At the special meeting, shareholders of record as of the close of business on November 1, 2001 will be asked to approve the merger whereby CenterPoint Energy, Inc. will become the new holding company. Reliant Energy expects to begin mailing a joint proxy statement/prospectus relating to the special meeting to its shareholders on or about November 12, 2001. In order to satisfy requirements for maintaining the exemption from the registration requirements of the 1935 Act, RERC expects to separate its three gas distribution divisions into three separate corporate entities within two years of the SEC's exemption order. The separation of these businesses will require additional regulatory approvals from the state utility regulators in five of the six states where RERC currently operates gas distribution businesses and may require waivers, consents and/or modifications to certain RERC agreements, including credit facilities and other financing arrangements. The Distribution is subject to further corporate approvals, market and other conditions, and government actions, including receipt of a favorable Internal Revenue Service ruling that the Distribution would be tax-free to Reliant Energy or its successor and its shareholders for U.S. federal income tax purposes, as applicable. There can be no assurance that the Distribution will be completed as described or within the time periods outlined above. On December 31, 2000, RERC Corp. transferred all of the outstanding stock of RESI, Arkla Finance and RE Europe Trading, all wholly owned subsidiaries of RERC Corp., to Reliant Resources (Stock Transfer). Both RERC Corp. and Reliant Resources are subsidiaries of Reliant Energy. As a result of the Stock Transfer, RESI, Arkla Finance and RE Europe Trading each became a wholly owned subsidiary of Reliant Resources. Also, on December 31, 2000, a wholly owned subsidiary of Reliant Resources merged with and into Reliant Energy Services, a wholly owned subsidiary of RERC Corp., with Reliant Energy Services as the surviving corporation (Merger). As a result of the Merger, Reliant Energy Services became a wholly owned subsidiary of Reliant Resources. As consideration of the Merger, Reliant Resources paid $94 million to RERC Corp. 52 Reliant Energy Services, together with RESI and RE Europe Trading, conduct the trading, marketing, power origination and risk management business and operations of Reliant Energy. Arkla Finance is a company that held an investment in marketable equity securities. The Stock Transfer and the Merger are part of Reliant Energy's previously announced restructuring. RERC is reporting the results of RE Europe Trading as discontinued operations for all periods presented in the consolidated financial statements in accordance with Accounting Principles Board Opinion No. 30. CONSOLIDATED RESULTS OF OPERATIONS
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30, --------------------------------- --------------------------------- 2000 2001 2000 2001 ------------- ------------- ------------- ------------- ( IN MILLIONS) Revenues ......................................... $ 7,265 $ 669 $ 14,369 $ 4,052 Operating Expenses ............................... (7,256) (664) (14,189) (3,889) ------------- ------------- ------------- ------------- Operating Income ................................. 9 5 180 163 Interest Expense, net ............................ (39) (40) (100) (119) Other Income (Expense), net ...................... 5 2 (8) 13 Income Tax Benefit (Expense) ..................... 6 6 (41) (38) ------------- ------------- ------------- ------------- (Loss) Income From Continuing Operations ......... (19) (27) 31 19 Loss From Discontinued Operations, net of tax .... (8) -- (16) -- ------------- ------------- ------------- ------------- Net (Loss) Income .............................. $ (27) $ (27) $ 15 $ 19 ============= ============= ============= =============
For the third quarter 2001 and 2000, RERC's net loss was $27 million. For the first nine months of 2001, RERC's net income was $19 million compared to net income of $15 million for the same period in 2000. The $4 million increase was primarily due to: o the effects of colder weather, increased customer growth and usage and reduced operating expenses due to exiting certain non-rate regulated retail gas markets outside of RERC's established areas during 2000 in our Natural Gas Distribution segment, o improved operating margins (revenues less natural gas costs) from both pipelines and gas gathering businesses partially offset by increased operating expenses, o an after-tax impairment loss of $17 million on marketable equity securities classified as "available-for-sale" incurred during the first nine months of 2000, and o start-up costs of the RE Europe Trading operations in 2000 included in loss from discontinued operations. The above items were partially offset by the following: o an increase in the Natural Gas Distribution segment's bad debt expense and changes in estimates of unbilled revenues and recoverability of deferred gas accounts and other items, o an increase in third-party interest primarily resulting from higher levels of long-term debt during the nine months ended September 30, 2001 compared to the same period in 2000, and o during the first nine months of 2000, RERC's results of operations included the trading and marketing results of Reliant Energy Services, as discussed above. During the nine months ended September 30, 2000, RERC incurred a pre-tax impairment loss of $27 million on marketable equity securities classified as "available-for-sale" by its Other Operations segment. Management's determination to recognize this impairment resulted from a combination of events occurring in 2000 related to this investment. For additional information regarding this impairment loss, see Note 2(l) to RERC Corp. 10-K Notes. 53 This investment is held by Arkla Finance and was transferred to a wholly owned subsidiary of Reliant Resources effective December 31, 2000. RERC's operating revenues decreased $6.6 billion and $10.3 billion for the quarter and nine months ended September 30, 2001, respectively, compared to the same periods in 2000. The decrease for both periods was primarily due to the transfer of Reliant Energy Services to Reliant Resources pursuant to the Merger discussed above. These decreases were partially offset by an increase in revenues related to the Natural Gas Distribution and Pipelines and Gathering segments resulting from an increase in the costs of natural gas and to a lesser extent the effect of cooler weather on the operations of the Natural Gas Distribution segment. Total operating expenses decreased by $6.6 billion and $10.3 billion for the quarter and nine months ended September 30, 2001, respectively, as compared to the same periods in 2000. These decreases were primarily due to the same reasons for the decreases in revenues discussed above. RERC's effective tax rate for the first nine months of 2000 and 2001 was 57% and 66%, respectively, primarily due to the effect of the permanent difference related to goodwill on lower pre-tax income. RERC is reporting the results of RE Europe Trading as discontinued operations for all periods presented in RERC's consolidated financial statements in accordance with APB No. 30. For additional information regarding the operating results of the other entities transferred to Reliant Resources, please read Note 13 to RERC Corp. 10-K Notes and Notes 4 and 5 to RERC's Interim Financial Statements. Seasonality and Other Factors. RERC's results of operations are affected by seasonal fluctuations in the demand for and, to a lesser extent, the price of natural gas. RERC's results of operations are also affected by, among other things, the actions of various federal and state governmental authorities having jurisdiction over rates charged by RERC, competition in RERC's various business operations, debt service costs and income tax expense. For a discussion of certain other factors that may affect RERC's future earnings please read "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Certain Factors Affecting Our Future Earnings -- Competitive and Other Factors Affecting RERC Operations" "--Environmental Expenditures" and "-- Other Contingencies" in the Reliant Energy Form 10-K. NEW ACCOUNTING PRONOUNCEMENTS In July 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 141 "Business Combinations" (SFAS No. 141) and SFAS No. 142 "Goodwill and Other Intangible Assets" (SFAS No. 142). SFAS No. 141 requires business combinations initiated after September 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. SFAS No. 142 provides for a nonamortization approach, whereby 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. We will adopt the provisions of each statement which apply to goodwill and intangible assets acquired prior to June 30, 2001 on January 1, 2002. We are in the process of determining the effect of adoption of SFAS No. 141 and SFAS No. 142 on our consolidated financial statements. 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 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- 54 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 APB Opinion No. 30, 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 is effective for fiscal years beginning after December 15, 2001, with early adoption encouraged. SFAS No. 144 is not expected to materially change the methods we use to measure impairment losses on long-lived assets, but may result in additional future dispositions being reported as discontinued operations than is currently permitted. We plan to adopt SFAS No. 144 on January 1, 2002. 55 PART II. OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS. Reliant Energy: For a description of legal proceedings affecting Reliant Energy, please read Note 12 to Reliant Energy's Interim Financial Statements, Item 3 of the Reliant Energy Form 10-K and Notes 4 and 14 to Reliant Energy 10-K Notes, all of which are incorporated herein by reference. RERC Corp.: For a description of legal proceedings affecting RERC, please review Note 10 to RERC's Interim Financial Statements, Item 3 of the RERC Corp. Form 10-K and Note 9 to RERC Corp. 10-K Notes, which are incorporated herein by reference. ITEM 5. OTHER INFORMATION. Forward-Looking Statements. From time to time, Reliant Energy and RERC Corp. make statements concerning their respective 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 Energy and RERC Corp. believe that the expectations and the underlying assumptions reflected in their respective forward-looking statements are reasonable, they 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: o 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, o the timing of the implementation of our business separation plan, o the effects of competition, including the extent and timing of the entry of additional competitors in our markets, o industrial, commercial and residential growth in our service territories, o our pursuit of potential business strategies, including acquisitions or dispositions of assets or the development of additional power generation facilities, o state, federal and other rate regulations in the United States and in foreign countries in which we operate or into which we might expand our operations, o the timing and extent of changes in commodity prices and interest rates, o weather variations and other natural phenomena, o political, legal and economic conditions and developments in the United States and in foreign countries in which we operate or into which we might expand our operations, including the effects of fluctuations in foreign currency exchange rates, o financial market conditions and the results of our financing efforts, o the performance of our projects, and 56 o other factors we discuss in this and other filings by Reliant Energy and RERC Corp. with the Securities and Exchange Commission. When used in Reliant Energy's or RERC Corp.'s documents or oral presentations, the words "anticipate," "estimate," "believe," "continue," "could," "intend," "may," "plan," "potential," "predict," "should," "will," "expect," "objective," "projection," "forecast," "goal" and similar words are intended to identify forward-looking statements. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K. (a) Exhibits. Reliant Energy: Exhibit 2(a) Agreement and Plan of Merger dated as of September 26, 2001 by and among Reliant Resources, Inc., Reliant Energy Power Generation Merger Sub, Inc. and Orion Power Holdings, Inc. (incorporated by reference from Reliant Energy's Current Report on Form 8-K dated September 27, 2001), Exhibit 2.1, SEC File No. 1-3187 Exhibit 99(a) Items incorporated by reference from the Reliant Energy Form 10-K: Item 3 "Legal Proceedings," Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations - Certain Factors Affecting Our Future Earnings" and Notes 2(f) (Summary of Significant Accounting Policies - Regulatory Assets), 3 (Business Acquisitions), 4 (Regulatory Matters), 5 (Derivative Financial Instruments), 8 (Indexed Debt Securities (ACES and ZENS) and AOL Time Warner Securities), 14 (Commitments and Contingencies) and 20 (Subsequent Events) of the Reliant Energy 10-K Notes. Exhibit 99(b) Items incorporated by reference from Reliant Energy March 31, 2001 Form 10-Q: Note 2 (Derivative Financial Instruments). RERC Corp.: Exhibit 99 Items incorporated by reference from the Reliant Energy Form 10-K: Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations - Certain Factors Affecting Our Future Earnings." Items incorporated by reference from the RERC Corp. Form 10-K: Item 3 "Legal Proceedings," Item 7 "Management's Narrative Analysis of the Results of Operations of RERC and its Consolidated Subsidiaries" and Notes 2(f) (Regulatory Assets), 4 (Derivative Financial Instruments) and 9 (Commitments and Contingencies) of the RERC Corp. 10-K Notes. (b) Reports on Form 8-K. Reliant Energy: On September 12, 2001 a report on Form 8-K dated August 28, 2001 was filed containing unaudited pro forma financial statements reflecting the effects of the Distribution and other events. On September 27, 2001, a report on Form 8-K was filed reporting the planned acquisition of Orion Power Holdings, Inc. by Reliant Resources, Inc. RERC Corp.: None. 57 SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. RELIANT ENERGY, INCORPORATED (Registrant) By: /s/ Mary P. Ricciardello --------------------------------------------- Mary P. Ricciardello Senior Vice President and Chief Accounting Officer Date: November 9, 2001 58 SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. RELIANT ENERGY RESOURCES CORP. (Registrant) By: /s/ Mary P. Ricciardello ---------------------------------- Mary P. Ricciardello Senior Vice President Date: November 9, 2001 59 EXHIBIT INDEX Reliant Energy: Exhibit 2(a) Agreement and Plan of Merger dated as of September 26, 2001 by and among Reliant Resources, Inc., Reliant Energy Power Generation Merger Sub, Inc. and Orion Power Holdings, Inc. (incorporated by reference from Reliant Energy's Current Report on Form 8-K dated September 27, 2001), Exhibit 2.1, SEC File No. 1-3187 Exhibit 99(a) Items incorporated by reference from the Reliant Energy Form 10-K: Item 3 "Legal Proceedings," Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations - Certain Factors Affecting Our Future Earnings" and Notes 2(f) (Summary of Significant Accounting Policies - Regulatory Assets), 3 (Business Acquisitions), 4 (Regulatory Matters), 5 (Derivative Financial Instruments), 8 (Indexed Debt Securities (ACES and ZENS) and AOL Time Warner Securities), 14 (Commitments and Contingencies) and 20 (Subsequent Events) of the Reliant Energy 10-K Notes. Exhibit 99(b) Items incorporated by reference from Reliant Energy March 31, 2001 Form 10-Q: Note 2 (Derivative Financial Instruments). RERC Corp.: Exhibit 99 Items incorporated by reference from the Reliant Energy Form 10-K: Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations - Certain Factors Affecting Our Future Earnings." Items incorporated by reference from the RERC Corp. Form 10-K: Item 3 "Legal Proceedings," Item 7 "Management's Narrative Analysis of the Results of Operations of RERC and its Consolidated Subsidiaries" and Notes 2(f) (Regulatory Assets), 4 (Derivative Financial Instruments) and 9 (Commitments and Contingencies) of the RERC Corp. 10-K Notes. EX-99.A 3 h92033ex99-a.txt ITEMS FROM RELIANT ENERGY FORM 10-K EXHIBIT 99(a).REI RELIANT ENERGY, INCORPORATED ITEMS INCORPORATED BY REFERENCE ITEMS INCORPORATED BY REFERENCE FROM THE RELIANT ENERGY FORM 10-K o ITEM 3. LEGAL PROCEEDINGS. (a) RELIANT ENERGY. For a description of certain legal and regulatory proceedings affecting Reliant Energy, see Notes 4, 14(g), 14(h) and 14(i) to our consolidated financial statements, which notes are incorporated herein by reference. o ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- CERTAIN FACTORS AFFECTING OUR FUTURE EARNINGS Our earnings for the past three years are not necessarily indicative of our future earnings and results. The level of our future earnings depends on numerous factors including: - state and federal legislative, as well as international 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, - the timing of the implementation of our Business Separation Plan, - industrial, commercial and residential growth in our service territories, - our pursuit of potential business strategies, including acquisitions or dispositions of assets or the development of additional power generation facilities, - state, federal and other rate regulations in the United States and in foreign countries in which we operate or into which we might expand our operations, - the timing and extent of changes in commodity prices and interest rates, - weather variations and other natural phenomena, - our ability to cost-effectively finance and refinance, - the determination of the amount of our Texas generating assets' stranded costs and the recovery of these costs, - the ability to consummate and the timing of the consummation of acquisitions and dispositions, - the performance of our generation projects undertaken, - the successful operation of deregulating power markets, including the resolution of the crisis in the California market, and - risks incidental to our overseas operations, including the effects of fluctuations in foreign currency exchange rates. In order to adapt to the increasingly competitive environment, we continue to evaluate a wide array of potential business strategies, including business combinations or acquisitions involving other utility or non-utility businesses or properties, dispositions of currently owned businesses, as well as developing new generation projects, products, services and customer strategies. 1 BUSINESS SEPARATION AND RESTRUCTURING In anticipation of electric deregulation in Texas, and pursuant to the Legislation, we submitted a business separation plan in January 2000 to the Texas Utility Commission. Pursuant to the Business Separation Plan, we will restructure our businesses into two separate publicly traded companies in order to separate our unregulated businesses from our rate-regulated businesses. Reliant Resources holds substantially all of our unregulated businesses. We expect Reliant Resources will conduct the Offering in 2001. Also, we anticipate that the Regulated Holding Company will conduct the Distribution within 12 months of the completion of the Offering, subject to receipt of a favorable tax ruling and other regulatory approvals. For additional information regarding the Business Separation Plan and the Restructuring, please read "Business -- Our Business -- Restructuring" in Item 1 of this Form 10-K and Note 4(b) to our consolidated financial statements. We have sought a ruling from the Internal Revenue Service that the Distribution will be tax-free to the Regulated Holding Company and its shareholders. At this time, we do not have a ruling from the Internal Revenue Service regarding the tax treatment of the Distribution. If we do not obtain a favorable tax ruling, the Distribution is not likely to be made in the expected time frame or, perhaps, at all. In order for the Distribution to be tax-free, various requirements must be met, including ownership by its parent of at least 80% of all classes of Reliant Resources' outstanding capital stock at the time of the Distribution. Additionally, in connection with the Distribution, Reliant Energy plans to restructure its remaining businesses to achieve a public utility holding company structure and to register the Regulated Holding Company as a public utility holding company under the 1935 Act. Creation of the Regulated Holding Company will require the approval of Reliant Energy's shareholders. For additional information regarding the Regulated Holding Company, please read "Business -- Our Business -- Restructuring" in Item 1 of this Form 10-K and Note 4(b) to our consolidated financial statements. The Restructuring will also require the approval of the Louisiana Public Service Commission and the Nuclear Regulatory Commission. We cannot assure you that those approvals will be obtained. After the Restructuring, the Regulated Holding Company will become a registered public utility holding company under the 1935 Act. COMPETITIVE, REGULATORY AND OTHER FACTORS AFFECTING OUR ELECTRIC OPERATIONS Competition and Deregulation. In June 1999, the Texas legislature adopted the Legislation, which substantially amended the regulatory structure governing electric utilities in Texas in order to allow retail competition. Retail pilot projects for up to 5% of each utility's load in all customer classes will begin in June 2001 and retail electric competition for all other customers will begin on January 1, 2002. Our retail operations will be conducted by indirect wholly owned subsidiaries of Reliant Resources. Under the market framework established by the Legislation, we will initially be required to sell electricity to Houston area residential and small commercial customers at a specified price, which is referred to in the Legislation as the "price to beat," whereas other retail electric providers will be allowed to sell electricity to these same customers at any price. We will not be permitted to offer electricity to these customers at a price other than the price to beat until January 1, 2005, unless before that date the Texas Utility Commission determines that 40% or more of the amount of electric power that was consumed in 2000 by residential or small commercial customers, as applicable, within the affiliated transmission and distribution utility's certificated service territory, as of January 1, 2002, is committed to be served by other retail electric providers. In addition, as long as we continue to provide retail service, the Legislation requires us to make the price to beat available to residential and small commercial customers in Reliant Energy HL&P's service territory through January 1, 2007. Because we will not be able to compete for residential and small commercial customers on the basis of price in Reliant Energy HL&P's service area, and because we expect that the retail market framework established by the Legislation will encourage competition from new retail electric providers, we could lose a significant number of these customers to other providers. When the pilot projects begin in June 2001, and until full retail electric competition begins, the Legislation provides that 5% of our customers may elect to purchase electricity from other retail electric providers. Our affiliated retail electric providers cannot participate in the pilot projects in Reliant Energy HL&P's service area. Reliant Energy HL&P will collect from retail electric providers the rates approved from its Wires Case to cover the cost of providing transmission and distribution service and any other non-bypassable charges. 2 Generally, retail electric providers will procure or buy electricity from the wholesale generators at unregulated rates, sell electricity at retail to their customers and pay the transmission and distribution utility a regulated tariffed rate for delivering the electricity to their customers. The results of our retail electric operations will be largely dependent upon the amount of gross margin, or "headroom," available in the "price to beat." The available headroom will equal the difference between the price to beat and the sum of the charges, fees and transmission and distribution utility rate approved by the Texas Utility Commission and the price we pay for power to meet our price to beat load. The larger the amount of headroom, the more incentive new market entrants should have to provide retail electric services in Reliant Energy HL&P's service territory. The Texas Utility Commission's regulations allow us to adjust our price to beat fuel factor based on the percentage change in the price of natural gas. In addition, we may also request an adjustment as a result of changes in our price of purchased energy. In such a request, we may adjust the fuel factor to the extent necessary to restore the amount of headroom that existed at the time our initial price to beat fuel factor was set by the Texas Utility Commission. We may not request that our price to beat be adjusted more than twice a year. Currently, we do not know nor can we estimate the amount of headroom in our initial price to beat or in the initial price to beat for the affiliated retail electric provider in each other Texas retail electric market. Similarly, we cannot estimate with any certainty the magnitude and frequency of the adjustments required, if any, and the eventual impact of such adjustments on the amount of headroom. In preparation for this competition, we expect to make significant changes in the electric utility operations currently conducted through Reliant Energy HL&P. For additional information regarding these changes, the Legislation, retail competition, its application to our Electric Operations segment and the "price to beat," please read "Business -- Our Business -- Deregulation and Competition," "-- Restructuring," "-- Electric Operations" and "Business -- Regulation -- State and Local Regulations -- Texas -- Electric Operations -- The Legislation" in Item 1 of this Form 10-K and Note 4 to our consolidated financial statements. Also, market volatility in the price of fuel for our generation operations, as well as in the price of purchased power, could have an effect on our cost to generate or acquire power. For additional information regarding commodity prices and supplies, please read "-- Competitive, Regulatory and Other Factors Affecting Our Wholesale Energy Operations -- Price Volatility." Other Regulatory Factors. Pursuant to the Legislation, Reliant Energy HL&P will be entitled to recover its stranded costs (i.e., the excess of net book value of generation assets, as defined by the Legislation, over the market value of those assets) and its regulatory assets related to generation. The Legislation prescribes specific methods for determining the amount of stranded costs and the details for their recovery. However, during the base rate freeze period from 1999 through 2001, earnings above the utility's authorized rate of return formula may be applied in a manner to accelerate depreciation of generation related plant assets for regulatory purposes. In addition, depreciation expense for transmission and distribution related assets may be redirected to generation assets for regulatory purposes during that period. The Legislation also provides for Reliant Energy HL&P, or a special purpose entity, to issue securitization bonds for the recovery of generation related regulatory assets and a portion of stranded costs. Any stranded costs not recovered through the sale of securitization bonds may be recovered through a non-bypassable charge to transmission and distribution customers. For additional information regarding these securitization bonds, please read "-- Liquidity and Capital Resources -- Future Sources and Uses of Cash -- Securitization." The Texas Utility Commission recently stated on record that it would consider requiring electric utilities to reverse the amount of redirected depreciation and accelerated depreciation previously taken if in its estimation the utility has overmitigated its stranded costs. The reversal could occur through a lower rate for the transmission and distribution utility and/or through credits contained in the transmission and distribution utility's rate. Any order requiring the reversal of these amounts would likely be included in the Texas Utility Commission proceeding establishing the initial rate of the transmission and distribution utility or in the case of our Electric Operations segment, the Wires Case. We do not expect the final transmission and distribution rate in the Wires Case to be established until August 2001. For more information regarding the Wires Case, see "Business -- Regulation -- State and Local Regulations -- Texas -- Electric Operations -- Rate Case." 3 At June 30, 1999, we performed an impairment test of Reliant Energy HL&P's previously regulated electric generation assets pursuant to SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" (SFAS No. 121), on a plant specific basis. Under SFAS No. 121, an asset is considered impaired, and should be written down to fair value, if the future undiscounted net cash flows expected to be generated by the use of the asset are insufficient to recover the carrying amount of the asset. For assets that are impaired pursuant to SFAS No. 121, we determined the fair value for each generating plant by estimating the net present value of future cash inflows and outflows over the estimated life of each plant. The difference between fair value and net book value was recorded as a reduction in the current book value. We determined that $797 million of electric generation assets were impaired as of June 30, 1999. Of these amounts, $745 million related to the South Texas Project and $52 million related to two gas-fired generation plants. The Legislation provides for recovery of this impairment through regulated cash flows during the transition period and through non-bypassable charges to transmission and distribution customers. As such, a regulatory asset has been recorded for an amount equal to the impairment loss. We recorded amortization expense related to the recoverable impaired plant costs and other assets created from discontinuing regulatory accounting of $221 million in the third and fourth quarters of 1999 and $329 million in 2000. We expect to fully amortize this regulatory asset as it is recovered from regulated cash flows in 2001. The impairment analysis requires estimates of possible future market prices, load growth, competition and many other factors over the lives of the plants. The resulting impairment loss is highly dependent on these underlying assumptions. In addition, after January 10, 2004, Reliant Energy HL&P must finalize and reconcile stranded costs (as defined by the Legislation) in a filing with the Texas Utility Commission. Any positive difference between the regulatory net book value and the fair market value of the generation assets (as defined by the Legislation) will be collected through future non-bypassable charges. Any over-mitigation of stranded costs may be refunded through future non-bypassable charges. This final reconciliation allows alternative methods of third party valuation of the fair market value of these assets, including outright sale, stock valuations and asset exchanges. Because generally accepted accounting principles require us to estimate fair market values on a plant-by-plant basis in advance of the final reconciliation, the financial impacts of the Legislation with respect to the final determination of stranded costs in 2004 are subject to material changes. Factors affecting such change may include estimation risk, uncertainty of future energy and commodity prices and the economic lives of the plants. If events occur that make the recovery of all or a portion of the regulatory assets associated with the generation plant impairment loss and other assets created from discontinuance of regulatory accounting pursuant to the Legislation no longer probable, we will write off the corresponding balance of these assets as a non-cash charge against earnings. One of the results of discontinuing the application of regulatory accounting for the generation operations is the elimination of the regulatory accounting effects of excess deferred income taxes and investment tax credits related to these operations. We believe it is probable that some parties will seek to return these amounts to ratepayers and, accordingly, we have recorded an offsetting liability. In accordance with the Legislation, beginning on January 1, 2002, and ending at December 31, 2003, any difference between market power prices received in the generation capacity auction and the Texas Utility Commission's earlier estimates of those market prices will be included in the 2004 stranded costs true-up. The Texas Utility Commission's estimate serves as a preliminary identification of stranded costs for recovery through securitization. This component of the true-up is intended to ensure that neither the customers nor we are disadvantaged economically as a result of the two-year transition period by providing this pricing structure. Since the time of our original impairment calculation in June 1999 when we discontinued application of SFAS No. 71 for our generation operations, natural gas prices have risen 295% from June 1999 to December 31, 2000 resulting in increases in estimated market prices for power during 2002 and 2003. Generally, for Reliant Energy HL&P's generation portfolio, sustained increases in natural gas prices result in an increase in the fair value of Reliant Energy HL&P's generation portfolio, due to our mix of lower variable cost of electric generation. Therefore, as electric power prices increase, the amount of our estimated stranded costs decline and the estimate of our 2002 and 2003 capacity true-up amounts which may be owed to customers increases. 4 For additional information regarding the impairment of regulatory assets and electric generating plant and equipment as well as the recovery of stranded costs, please read Note 4(a) to our consolidated financial statements. For additional information regarding our filings to recover under-recovered fuel costs, please read Note 4(d) to our consolidated financial statements. Other. For additional information regarding litigation over franchise fees, please read Note 14(g) to our consolidated financial statements. COMPETITIVE, REGULATORY AND OTHER FACTORS AFFECTING OUR WHOLESALE ENERGY OPERATIONS Competition. As of December 31, 2000, our Wholesale Energy business segment owned and operated 9,231 MW of electric generation assets that serve wholesale energy markets located in the Mid-Atlantic, Southwest and Midcontinent regions of the United States and the states of Florida and Texas. Competitive factors affecting the results of operations of these generation assets include new market entrants and construction by others of more efficient generation assets. The wholesale power industry has numerous competitors, some of which may have more operating experience, more acquisition and development experience, larger staffs and/or greater financial resources than we do. Like us, many of our competitors are seeking attractive opportunities to acquire or develop power generation facilities, both in the United States and abroad. This competition may adversely affect our ability to make investments or acquisitions. Also, industry restructuring requires or encourages the disaggregation of many vertically-integrated utilities into separate generation, transmission and distribution, and retail businesses. As a result, a significant number of additional competitors could become active in the wholesale power generation segment of our industry. Furthermore, other competitors operate power generation projects in the regions where we have invested in electric generation assets. While demand for electric energy services is generally increasing throughout the United States, the rate of construction and development of new, more efficient electric generation facilities may exceed increases in demand in some regional electric markets. Although local permitting and siting issues often reduce the risk of a rapid growth in supply of generation capacity in any particular region, projects are likely to be built over time. The commencement of commercial operation of these new facilities in the regional markets where we have facilities will likely increase the competitiveness of the wholesale power market in those regions, which could have a material effect on our business and lower the value of some of our electric generation assets. Finally, our trading, marketing, power origination and risk management operations compete with other energy merchants based on the ability to aggregate supplies at competitive prices from different sources and locations and to efficiently utilize transportation from third-party pipelines and transmission from electric utilities. These operations also compete against other energy marketers on the basis of their relative skills, financial position and access to credit sources. This competitive factor reflects the tendency of energy customers, wholesale energy suppliers and transporters to seek financial guarantees and other assurances that their energy contracts will be satisfied. As pricing information becomes increasingly available in the energy trading and marketing business and as deregulation in the electricity markets continues to accelerate, we anticipate that our trading, marketing, power origination and risk management operations will experience greater competition and downward pressure on per-unit profit margins. Regulation. The regulatory environment applicable to the electric power industry has recently undergone substantial changes as a result of restructuring initiatives at both the state and federal levels. These initiatives have had a significant impact on the nature of the industry and the manner in which its participants conduct their business. Our Wholesale Energy segment has targeted the deregulating wholesale and retail segments of the electric power industry created by these initiatives. These changes are ongoing and we cannot predict the future development of deregulation in these markets or the ultimate effect that this changing regulatory environment will have on our business. 5 Moreover, existing regulations may be revised or reinterpreted, new laws and regulations may be adopted or become applicable to us or our facilities, and future changes in laws and regulations may have a detrimental effect on our business. Certain restructured markets, particularly California, have recently experienced supply problems and price volatility. These supply problems and volatility have been the subject of a significant amount of press coverage, much of which has been critical of the restructuring initiatives. In some markets, including California (please read "-- California" below), proposals have been made by governmental agencies and/or other interested parties to slow the pace of deregulation or to re-regulate areas of these markets that have previously been deregulated. If the current trend towards competitive restructuring of the wholesale and retail power markets is reversed, discontinued or delayed, the business growth prospects of our Wholesale Energy segment would be slowed and the financial outlook for our existing positions could be impacted. If RTOs are established as envisioned by FERC Order 2000, "rate pancaking," or multiple transmission charges that apply to a single point-to-point delivery of energy, will be eliminated within a region, and wholesale transactions within the region, and between regions will be facilitated. The end result could be a more competitive, transparent market for the sale of energy and a more economic and efficient use and allocation of resources. For additional information regarding FERC Order 2000 affecting these RTOs, please read "Business -- Regulation -- Federal Energy Regulatory Commission" in Item 1 of this Form 10-K. Price Volatility. Our Wholesale Energy business segment sells electricity from our non-Texas power generation facilities into the spot market or other competitive power markets or on a contractual basis. Our Wholesale Energy business segment is not guaranteed any rate of return on our capital investments through mandated rates, and our revenues and results of operations are likely to depend, in large part, upon prevailing market prices for electricity and fuel in our regional markets and other competitive markets. These market prices may fluctuate substantially over relatively short periods of time. In addition, the FERC, which has jurisdiction over wholesale power rates, as well as independent system operators that oversee some of these markets, may impose price limitations, bidding rules and other mechanisms to address some of the volatility in these markets. Most of our Wholesale Energy business segment's domestic power generation facilities purchase fuel under short-term contracts or on the spot market. Fuel prices may also be volatile, and the price we can obtain for power sales may not change at the same rate as changes in fuel costs. These factors could have an adverse impact on our revenues and results of operations. Volatility in market prices for fuel and electricity may result from: - weather conditions, - seasonality, - electricity usage, - illiquid markets, - transmission or transportation constraints or inefficiencies, - availability of competitively priced alternative energy sources, - demand for energy commodities, - natural gas, crude oil and refined products, and coal production levels, - natural disasters, wars, embargoes and other catastrophic events, and - federal, state and foreign energy and environmental regulation and legislation. Trading, Marketing, Power Origination and Risk Management Operations. To lower our Wholesale Energy business segment's financial exposure related to commodity price fluctuations, its trading, marketing, power origination and risk management operations routinely enter into contracts to hedge a portion of its purchase and sale commitments, weather positions, fuel requirements and inventories of natural gas, coal, crude oil and refined products, and other commodities. As part of this strategy, our Wholesale Energy business segment routinely utilizes fixed-price forward physical purchase and sales contracts, futures, financial swaps 6 and option contracts traded in the over-the-counter markets or on exchanges. However, our Wholesale Energy business segment does not expect to cover the entire exposure of its assets or its positions to market price volatility and the coverage will vary over time. To the extent our Wholesale Energy business segment has unhedged positions, fluctuating commodity prices can impact our financial results and financial position, either favorably or unfavorably. At times, our Wholesale Energy business segment has open trading positions in the market, within established guidelines, resulting from the management of its trading portfolio. To the extent open trading positions exist, fluctuating commodity prices can impact our financial results and financial position, either favorably or unfavorably. The risk management procedures our Wholesale Energy business segment has in place may not always be followed or may not always work as planned. As a result of these and other factors, we cannot predict with precision the impact that our risk management decisions may have on our businesses, operating results or financial position. Although our Wholesale Energy business segment devotes a considerable amount of management effort to these issues, their outcome is uncertain. Our trading, marketing, power origination and risk management operations are also exposed to the risk that counterparties who owe it money or physical commodities, such as energy or gas, as a result of market transactions will not perform their obligations. Should the counterparties to these arrangements fail to perform, our trading, marketing, power origination and risk management operations might be forced to acquire alternative hedging arrangements or replace the underlying commitment at then-current market prices. In this event, our trading, marketing, power origination and risk management operations might incur additional losses to the extent of amounts, if any, already paid to the counterparties. California. During the summer and fall of 2000, 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, decreases in net electric imports, structural market flaws including over-reliance on the electric spot market, and limitations on supply as a result of maintenance and other outages. Although wholesale prices increased, California's deregulation legislation kept retail rates frozen below 1996 levels. This caused two of California's public utilities, which are our customers based on our deliveries to the Cal PX and the Cal ISO, to amass billions of dollars of uncollected wholesale power costs and to ultimately default in January and February 2001 on payments owed for wholesale power purchased through the Cal PX and from the Cal ISO. As of December 31, 2000, we were owed $101 million by the Cal PX and $181 million by the Cal ISO. In the fourth quarter of 2000, we recorded a pre-tax provision of $39 million against receivable balances related to energy sales in the California market. From January 1, 2001 through February 28, 2001, we have collected $105 million of these receivable balances. As of March 1, 2001, we were owed a total of $358 million by the Cal ISO, the Cal PX, the CDWR and California Energy Resources Scheduling for energy sales in the California wholesale market from the fourth quarter of 2000 through February 28, 2001. Management will continue to assess the collectibility of these receivables based on further developments affecting the California electricity market and the market participants described herein. Additional provisions to the allowance may be warranted in the future. In response to the filing of a number of complaints challenging the level of wholesale prices, the FERC initiated a staff investigation and issued an order on December 15, 2000 implementing a series of wholesale market reforms, including an interim price review procedure for prices above a $150/MWh "breakpoint" on sales to the Cal ISO and through the Cal PX. The order does not prohibit sales above the "breakpoint," but the seller is subject to weekly reporting and monitoring requirements. For each reported transaction, potential refund liability extends for a period of 60 days following the date any such transaction is reported to the FERC. On March 9, 2001, the FERC issued a further order establishing a proxy market clearing price of $273/MWh for January 2001, and on March 16, 2001 the FERC issued a further order adjusting the proxy market clearing price to $430/MWh for February 2001. New market monitoring and mitigation measures to replace the $150/MWh breakpoint and reporting obligation are being developed by the FERC to take effect on May 1, 2001. 7 In the FERC's March 9 and March 16 orders, the FERC outlined criteria for determining amounts subject to possible refund based on the proxy market clearing price for January and February 2001 and indicated that approximately $12 million of the $125 million charged by us in January 2001 in California to the Cal ISO and the Cal PX and approximately $7 million of the $47 million charged by us in February 2001 in California to the Cal ISO and the Cal PX were subject to possible refunds. In the March 9 and March 16 orders, the FERC set forth procedures for challenging possible refund obligations. Because we believe that there is cost or other justification for prices charged above the proxy market clearing prices established in the March 9 and March 16 orders, we intend to pursue such a challenge with respect to our potential refund amounts identified in such orders. Any refunds we may ultimately be obligated to pay are to be credited against unpaid amounts owed to us for our sales in the Cal PX or to the Cal ISO. The December 15 order established that a refund condition would be in place for the period beginning October 2, 2000 through December 31, 2002. The December 15 order also eliminated the requirement that California's public utilities sell all of their generation into and purchase all of their power from the Cal PX and directed that the Cal PX wholesale tariffs be terminated effective April 2001. The Cal PX has since suspended its day-ahead and day-of markets and filed for bankruptcy protection on March 9, 2001. Motions for rehearing have been filed on a number of issues related to the December 15 order and such motions are still pending before the FERC. 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 Public Utilities Commission, the California Electricity Oversight Board, the California Bureau of State Audits and the California Office of the Attorney General all have separate ongoing investigations into the high prices and their causes. None of these investigations have been completed and no findings have been made in connection with any of them. Despite the market restructuring ordered under the December 15 order, the California public utilities have continued to accrue unrecovered wholesale costs. As a result, the credit ratings of two of these public utilities were severely downgraded to below investment grade in January 2001. As their credit lines became unavailable, the two utilities defaulted on payments due to the Cal PX and the Cal ISO, which operate financially as pass-through entities, coordinating payments from buyers and sellers of electricity. As a result, the Cal PX and Cal ISO were not able to pay final invoices to market participants totaling over $1 billion. The default of two of California's public utilities on amounts owed the Cal PX and the Cal ISO for purchased power has further exacerbated the current crisis in the California wholesale markets and resulted in substantial uncollected receivables owed to us by the Cal ISO and the Cal PX. The Cal PX's efforts to recover the available collateral of the utilities, in the form of block forward contracts, have been frustrated by the emergency acts of California's Governor, who seized control of the contracts upon the expiration of temporary restraining orders prohibiting such action. Although obligated to pay reasonable value for the contracts, the state of California has not yet made any payment for the contracts. Various actions have been filed challenging the Governor's ability to seize these contracts. Upon the default of the two utilities of amounts due to the Cal PX, the Cal PX issued "charge-backs" allocating the utilities' defaults to the other market participants. Proceedings were brought both in federal court and at the FERC seeking a suspension of the charge-backs and challenging the reasonableness of the Cal PX's actions. The Cal PX has since agreed to a preliminary injunction suspending any of its charge-back activities in order to allow the FERC to address the charge-back issues. Amounts owed to us were debited in invoices by the Cal PX for charge-backs in the amount of $29 million and, on February 14, 2001, we filed our own lawsuit against the Cal PX in the United States District Court for the Central District of California, seeking a recovery of those amounts and a stay of any further charge-backs by the Cal PX. The filing of bankruptcy by the Cal PX will automatically stay for some period the various court and administrative cases against the Cal PX. The two defaulting utilities have both filed lawsuits challenging the refusal of state regulators to allow wholesale power costs to be passed through to retail customers under the "filed rate doctrine." The filed rate doctrine provides that wholesale power costs approved by the FERC are entitled to be recovered through rates. 8 Additionally, to address the failing financial condition of the two defaulting utilities and the utilities' potential bankruptcy, the California Legislature passed emergency legislation, effective January 18, 2001 and February 2, 2001, appropriating funds to be used by the CDWR for the purchase of wholesale electricity on behalf of the utilities and authorizing the sale of bonds to fund future purchases under long-term power contracts with wholesale generators. The CDWR began the process of soliciting bids from generators for long-term contracts and continued the purchasing of short-term power contracts. No bonds have yet been issued by the CDWR to support long-term power purchases or to provide credit support for short-term purchases. As noted above, two of California's public utilities have defaulted in their payment obligations to the Cal PX and the Cal ISO as a result of the refusal of state regulators to allow them to recover their wholesale power costs. This refusal by state regulators has also caused the utilities to default on numerous other financial obligations, which could result in either the voluntary or involuntary bankruptcy of the utilities. While a bankruptcy filing would result in further post-petition purchases of wholesale electricity being considered administrative expenses of the debtor, a substantial delay could be experienced in the payment of pre-petition receivables pending the confirmation of a reorganization plan. The California Legislature is currently considering legislation under which a state entity would be formed to purchase and operate a substantial share of the transmission lines in California in an effort to provide cash to the utilities and thereby avoid potential bankruptcy filings by the utilities. A number of the creditors for the two California public utilities have indicated, however, that unless California moves quickly with such a plan, an involuntary bankruptcy filing may be made by one or more of such creditors. Because California's power reserves remain at low levels, in part as a result of the lack of creditworthy buyers of power given the defaults of the California utilities, the Cal ISO has relied on emergency dispatch orders requiring generators to provide at the Cal ISO's direction all power not already under contract. The power supplied to the Cal ISO has been used to meet the needs of the customers of the utilities, even though two of those utilities do not have the credit required to receive such power and may be unable to pay for it. We have contested the obligation to provide power under these circumstances. The Cal ISO sought a temporary restraining order compelling us to continue to comply with the emergency dispatch orders despite the utilities' defaults. Although the payment issue is still disputed, on February 21, 2001, we and the CDWR entered into a contract expiring March 23, 2001 for the purchase of all of our available capacity not already under contract and the litigation has been temporarily stayed. The CDWR is current in its payments under this contract, but we are still owed $108 million for power provided in compliance with the emergency dispatch orders for the six weeks prior to the agreement. Depending on the outcome of the court proceedings initiated by the Cal ISO seeking to enjoin us from ceasing power deliveries to the Cal ISO, we may be forced to continue selling power without the guarantee of payment. Additionally, we are seeking a prompt FERC determination that the Cal ISO is not complying with the credit provisions of its tariff and a related order of the FERC issued on February 14, 2001, requiring the Cal ISO not to make purchases in the real time market unless a creditworthy purchaser is responsible for such purchases. For additional information regarding the situation in California, please read "Business -- Wholesale Energy -- Power Generation Operations -- Southwest Region" and "Business -- Regulation -- State and Local Regulations -- California" in Item 1 of this Form 10-K, "-- Results of Operations by Business Segment -- Wholesale Energy -- 2000 Compared to 1999," as well as Notes 14(g) and 14(h) to our consolidated financial statements. COMPETITIVE, REGULATORY AND OTHER FACTORS AFFECTING OUR EUROPEAN ENERGY OPERATIONS Competition. The European energy market is highly competitive. In addition, over the next several years, we expect an increasing consolidation of the participants in the European generating market. Our European wholesale operations compete in the Netherlands, primarily against the three other largest Dutch generating companies, various cogenerators of electric power, various alternate sources of power and non-Dutch generators of electric power, primarily from France and Germany. In 2000, UNA and the three other largest Dutch generating companies supplied approximately 50% of the electricity consumed in the 9 Netherlands. Smaller Dutch producers supplied about 25% of the consumed electricity, and the remainder was imported. At present, the Dutch electricity system has three operational interconnection points with Germany and two interconnection points with Belgium. There are also a number of projects that are at various stages of development and that may increase the number of interconnections in the future (post 2005) including interconnections with Norway and the United Kingdom. The Belgian interconnections are used to import electricity from France, but a larger portion of Dutch electricity imports comes from Germany. Our European trading and marketing operations will also be subject to increasing levels of competition. As of December 31, 2000, there were 32 trading and marketing companies registered with the Amsterdam Power Exchange. Competition among power generators for customers is intense, and we expect competition to increase with the deregulation of the market. Please read "-- Regulation." The primary elements of competition affecting both the generation and trading and marketing operations of our European Energy business segment are price, credit support, and supply and delivery reliability. Deregulation. The Dutch electricity market was opened to limited wholesale and retail competition on January 1, 1999 as retail competition for large industrial customers began. The Dutch wholesale electric market was completely opened to competition on January 1, 2001. Consistent with our expectations at the time we made the acquisition, we anticipate that our European Energy business segment may experience a significant decline in gross margin in 2001 attributable to the deregulation of the market and termination of an agreement with the other Dutch generators and the Dutch distributors. The next customer segment, composed primarily of commercial customers, will be liberalized by 2002. The remainder of the market, mainly residential, will be open to competition by 2003. The timing of these market openings is subject to change, however, at the discretion of the Dutch Minister of Economic Affairs. In addition, the results of our European Energy segment will be negatively impacted beginning in 2002 due to the imposition of a standard Dutch corporate income tax rate, which is currently 35%, on the income of UNA. In 2000 and prior years, UNA's Dutch corporate income tax rate was zero percent. Other. Another factor that could have a significant impact on the Dutch energy industry, including the operations of our European Energy business segment, is the ultimate resolution of stranded costs issues in the Netherlands. Prior to 2001, UNA and the other Dutch generators sold their generating output through the coordinating body for the Dutch electricity generating sector, B.V. Nederlands Elektriciteit Administratiekantor (NEA). Over the years, NEA has incurred "stranded" costs as a result of, among other things, a perceived need to cover anticipated shortages in energy production supply. NEA stranded costs consist primarily of investments in alternative energy sources and fuel and power purchase contracts currently estimated to be uneconomical. Legislation has been approved by the Dutch parliament which would transfer the liability for the stranded costs from NEA to its four shareholders, one of which is UNA. For information regarding this legislation, please read Note 14(i) to our consolidated financial statements. In connection with our acquisition of UNA, the selling shareholders of UNA agreed to indemnify UNA for some stranded costs in an amount not to exceed NLG 1.4 billion ($599 million based on an exchange rate of 2.34 NLG per U.S. dollar as of December 31, 2000), which may be increased in some circumstances at our option up to NLG 1.9 billion ($812 million). Of the total consideration we paid for the shares of UNA, NLG 900 million ($385 million) has been placed by the selling shareholders under the direction of the Dutch Minister of Economic Affairs in an escrow account to secure the indemnity obligations by the former shareholders of UNA. Although our management believes that the indemnity provision will be sufficient to fully satisfy UNA's ultimate share of any stranded costs obligation, this judgment is based on numerous assumptions regarding the ultimate outcome and timing of the resolution of the stranded cost issue, the former shareholders' timely performance of their obligations under the indemnity arrangement, and the amount of stranded costs, which at present is not determinable. Any shortfall in the indemnity provision could have a material adverse effect on our results of operations. Our European operations are subject to various risks incidental to investing or operating in foreign countries. These risks include economic risks, such as fluctuations in currency exchange rates, restrictions on the repatriation of foreign earnings and/or restrictions on the conversion of local currency earnings into U.S. dollars. For example, we estimate that the impact of the devaluation of the Euro relative to the 10 U.S. dollar during 2000 negatively impacted U.S. dollar net income in the amount of approximately $8 million. Impact of Currency Fluctuations on Company Earnings. For information about our exposure through our investment in Europe to losses resulting from fluctuations in currency rates, please read "Quantitative and Qualitative Disclosures About Market Risk" in Item 7A of this Form 10-K. COMPETITIVE AND OTHER FACTORS AFFECTING RERC OPERATIONS Natural Gas Distribution. Our Natural Gas Distribution business segment competes primarily with alternate energy sources such as electricity and other fuel sources. In some areas, intrastate pipelines, other gas distributors and marketers also compete directly with our Natural Gas Distribution business segment for gas sales to end-users. In addition, as a result of federal regulatory changes affecting interstate pipelines, natural gas marketers operating on these pipelines may be able to bypass our Natural Gas Distribution business segment's facilities and market, sell and/or transport natural gas directly to commercial and industrial customers. Generally, the regulations of the states in which our Natural Gas Distribution business segment operates allow us to pass through changes in the costs of natural gas to our customers through purchased gas adjustment provisions in rates. There is, however, an inherent timing difference between our purchases of natural gas and the ultimate recovery of these costs. Consequently, we may incur additional "carrying" costs as a result of this timing difference and the resulting, temporary under-recovery of our purchased gas costs. To a large extent, these additional carrying costs are not recovered from our customers. Pipelines and Gathering. Our Pipelines and Gathering segment competes with other interstate and intrastate pipelines in the transportation and storage of natural gas. The principal elements of competition among pipelines are rates, terms of service, and flexibility and reliability of service. Our Pipelines and Gathering segment competes indirectly with other forms of energy available to its customers, including electricity, coal and fuel oils. The primary competitive factor is price. Changes in the availability of energy and pipeline capacity, the level of business activity, conservation and governmental regulations, the capability to convert to alternative fuels, and other factors, including weather, affect the demand for natural gas in areas we serve and the level of competition for transportation and storage services. Since FERC Order No. 636, REGT's and MRT's commodity sales activity has been minimal. Commodity transactions are usually related to system management activity which we have been able to manage with little exposure. We have not been nor do we anticipate to be, negatively impacted from the recent price levels and the tightening of supply. In addition, competition for our gathering operations is impacted by commodity pricing levels in its markets because these prices influence the level of drilling activity in those markets. Natural Gas Pipeline Company of America has proposed, and is soliciting customers for a 30" pipeline paralleling MRT's East Line in Illinois to a point 17 miles East of St. Louis Metro, with a proposed in-service date of June 2002. MRT has renewed or is engaged in negotiations to renew service agreements under multi-year terms, including service and potential expansion needs along MRT's existing East Line in Illinois. Our Pipelines and Gathering business segment derives approximately 14% of its revenues from its contract with Laclede, which has been under an annual evergreen term provision since 1999. In the event we are not able to renegotiate a long-term extension to the contract with Laclede, and Laclede engages another pipeline for the transportation services it currently obtains from us, the operating and financial results of our Pipelines and Gathering business segment would be materially adversely affected. FLUCTUATIONS IN COMMODITY PRICES AND DERIVATIVE INSTRUMENTS For information regarding our exposure to risk as a result of fluctuations in commodity prices and derivative instruments, please read "Quantitative and Qualitative Disclosures About Market Risk" in Item 7A of this Form 10-K. 11 INDEXED DEBT SECURITIES (ZENS) AND OUR AOL TIME WARNER INVESTMENT For information on our indexed debt securities and our investment in AOL Time Warner common stock, please read "Quantitative and Qualitative Disclosures About Market Risk" in Item 7A of this Form 10-K and Note 8 to our consolidated financial statements. ENVIRONMENTAL EXPENDITURES We are subject to numerous environmental laws and regulations, which require us to incur substantial costs to operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past operations on the environment. For additional information regarding environmental contingencies, please read Note 14(g) to our consolidated financial statements. Clean Air Act Expenditures. We expect the majority of capital expenditures associated with environmental matters to be incurred by our Electric Operations and Wholesale Energy business segments in connection with emission limitations for NOx under the Clean Air Act, or to enhance operational flexibility under Clean Air Act requirements. In 2000, emission reduction requirements for NOx were finalized for our electric generating facilities in Texas and the Mid-Atlantic region. We currently estimate that up to $534 million will be required to comply with the requirements through the end of 2003, with an estimated $215 million to be incurred in 2001. The Texas regulations require additional reductions that must be completed by March 2007. Estimates for the Texas units for the period 2004 through 2007 have not been defined, but could be up to $230 million. We are currently litigating the economic and technical viability of the Texas post-2004 reduction requirements, but cannot predict the outcome of this litigation. In addition, the Legislation created a program mandating air emissions reductions for some generating facilities of our Electric Operations segment. The Legislation provides for stranded costs recovery for costs associated with this obligation incurred before May 1, 2003. For additional information regarding the Legislation, please read Note 4(a) to our consolidated financial statements. Additional NOx emission controls for our generating units located in California may result in expenditures of up to $30 million through 2002. For additional information regarding environmental regulation of air emissions, please read "Business -- Environmental Matters -- Air Emissions" in Item 1 of this Form 10-K. Site Remediation Expenditures. From time to time we have received notices from regulatory authorities or others regarding our status as a potentially responsible party in connection with sites found to require remediation due to the presence of environmental contaminants. Based on currently available information, we believe that remediation costs will not materially affect our financial position, results of operations or cash flows. There can be no assurance, however, that future developments, including additional information about existing sites or the identification of new sites, will not require material revisions to our estimates. For information about specific sites that are the subject of remediation claims, please read Note 14(g) to our consolidated financial statements and Note 9(c) to RERC's consolidated financial statements. Water, Mercury and Other Expenditures. As discussed under "Business -- Environmental Matters -- Water Issues" in Item 1 of this Form 10-K, regulatory authorities are in the process of implementing regulations and quality standards in connection with the discharge of pollutants into waterways. Once these regulations and quality standards are enacted, we will be able to determine if our operations are in compliance, or if we will have to incur costs in order to comply with the quality standards and regulations. Until that time, however, we are not able to predict the amount of these expenditures, if any. To date, however, our expenditures associated with respect to permits, registrations and authorizations for operation of facilities under the statutes regulating the discharge of pollutants into surface water have not been material. With regard to mercury remediation and other environmental matters, such as the disposal of solid wastes, our expenditures have not been, and are not expected to be material, based on our experiences and that of others in our industries. Please read "Business -- Environmental Matters -- Mercury Contamination" and "-- Other" in Item 1 of this Form 10-K. 12 OTHER CONTINGENCIES For a description of other legal and regulatory proceedings affecting us, please read Notes 4 and 14 to our consolidated financial statements and Note 9 to RERC's consolidated financial statements. ITEMS INCORPORATED BY REFERENCE FROM THE RELIANT ENERGY 10-K NOTES o (2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (f) Regulatory Assets. The Company applies the accounting policies established in Statement of Financial Accounting Standards (SFAS) No. 71 (SFAS No. 71) to the accounts of transmission and distribution operations of Reliant Energy HL&P and the utility operations of Natural Gas Distribution and to some of the accounts of Pipelines and Gathering. For information regarding Reliant Energy HL&P's electric generation operations' discontinuance of the application of SFAS No. 71 in 1999 and the effect on its regulatory assets and the Texas Electric Choice Plan (Legislation), see Note 4(a). The following is a list of regulatory assets/liabilities reflected on the Company's Consolidated Balance Sheets as of December 31, 1999 and 2000.
DECEMBER 31, --------------- 1999 2000 ------ ------ (IN MILLIONS) Recoverable impaired plant costs, net....................... $ 587 $ 281 Recoverable electric generation related regulatory assets, net....................................................... 952 1,385 Regulatory tax liability, net............................... (45) (49) Unamortized loss on reacquired debt......................... 69 66 Other long-term assets/liabilities.......................... (14) 6 ------ ------ Total............................................. $1,549 $1,689 ====== ======
Included in the above table are $191 million and $237 million of regulatory liabilities recorded as other long-term liabilities in the Company's Consolidated Balance Sheets as of December 31, 1999 and 2000, respectively, which primarily relate to the recovery of fuel costs as of December 31, 1999, and gains on nuclear decommissioning trust funds, regulatory tax liabilities and excess deferred income taxes as of December 31, 1999 and 2000. Under a "deferred accounting" plan authorized by the Public Utility Commission of Texas (Texas Utility Commission), Electric Operations was permitted for regulatory purposes to accrue carrying costs in the form of allowance for funds used during construction (AFUDC) on its investment in the South Texas Project Electric Generating Station (South Texas Project) and to defer and capitalize depreciation and other operating costs on its investment after commercial operation until these costs were reflected in rates. In addition, the Texas Utility Commission authorized Electric Operations to defer allowable costs (including return) for future recovery. Pursuant to SFAS No. 92, "Regulated Enterprises -- Accounting for Phase-in Plans," the Company deferred these costs. These costs are included in recoverable electric generation related regulatory assets. The amortization of all deferred plant costs (which totaled $26 million for 1998) is included in the Company's Statements of Consolidated Operations as depreciation and amortization expense. Pursuant to the Legislation, see Note 4(a), the Company discontinued amortizing deferred plant costs effective January 1, 1999. In 1998, 1999 and 2000, the Company, as permitted by the 1995 rate case settlement (Rate Case Settlement), also amortized $4 million, $22 million and $11 million, respectively, of its investment in lignite reserves associated with a canceled generating station. The investment in these reserves was fully amortized during 2000. 13 For additional information regarding recoverable impaired plant costs and recoverable electric generation related assets and the related amortization during 1999 and 2000, see Notes 2(g) and 4(a). If, as a result of changes in regulation or competition, the Company's ability to recover these assets and liabilities would not be assured, then pursuant to SFAS No. 101, "Regulated Enterprises Accounting for the Discontinuation of Application of SFAS No. 71" (SFAS No. 101) and SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" (SFAS No. 121), the Company would be required to write off or write down these regulatory assets and liabilities. In addition, the Company would be required to determine any impairment to the carrying costs of plant and inventory assets. o (3) BUSINESS ACQUISITIONS (a) Reliant Energy Mid-Atlantic Power Holdings, LLC. On May 12, 2000, a subsidiary of the Company purchased entities owning electric power generating assets and development sites located in Pennsylvania, New Jersey and Maryland having an aggregate net generating capacity of approximately 4,262 megawatts (MW). With the exception of development entities that were sold to another subsidiary of the Company in July 2000, the assets of the entities acquired are held by Reliant Energy Mid-Atlantic Power Holdings, LLC (REMA). The purchase price for the May 2000 transaction was $2.1 billion, subject to post-closing adjustments which management does not believe will be material. The Company accounted for the acquisition as a purchase with assets and liabilities of REMA reflected at their estimated fair values. On a preliminary basis, the Company's fair value adjustments related to the acquisition primarily included adjustments in property, plant and equipment, air emissions regulatory allowances, materials and supplies inventory, environmental reserves and related deferred taxes. The air emissions regulatory allowances of $153 million are being amortized on a units-of-production basis as utilized. The excess of the purchase price over the fair value of net assets acquired of $7 million was recorded as goodwill and is being amortized over 35 years. The Company expects to finalize these fair value adjustments no later than May 2001, based on valuation reports of property, plant and equipment and intangible assets, and does not anticipate additional material modifications to the preliminary adjustments. Funds for the acquisition of REMA were made available through commercial paper borrowings by a finance subsidiary, which borrowings were supported by bank credit facilities. The net purchase price of REMA was allocated and the fair value adjustments to the seller's book value are as follows (in millions):
PURCHASE FAIR PRICE VALUE ALLOCATION ADJUSTMENTS ---------- ----------- Current assets.............................................. $ 75 $ (37) Property, plant and equipment............................... 1,941 670 Goodwill.................................................... 7 (144) Other intangibles........................................... 153 (10) Other assets................................................ 4 (4) Current liabilities......................................... (45) (8) Other liabilities........................................... (38) (14) ------ ----- $2,097 $ 453 ====== =====
Adjustments to property, plant and equipment, other intangibles, which includes air emissions regulatory allowances, and environmental reserves included in other liabilities are based primarily on valuation reports prepared by independent appraisers and consultants. In August 2000, the Company entered into separate sale/leaseback transactions with each of three owner-lessors for the Company's 16.45%, 16.67% and 100% interests in the Conemaugh, Keystone and Shawville generating stations, respectively, acquired as part of the REMA acquisition. As lessee, the Company leases an interest in each facility from each owner-lessor under a facility lease agreement. As consideration for 14 the sale of the Company's interest in the facilities, the Company received $1.0 billion in cash. The Company used the $1.0 billion of sale proceeds to repay commercial paper referred to above. The Company's results of operations include the results of REMA only for the period beginning May 12, 2000. Prior to November 24, 1999, the acquired entities' operations were fully integrated with, and their results of operations were consolidated into, the regulated electric utility operations of a prior owner of the facilities. In addition, prior to November 24, 1999, the electric output of the facilities was sold based on rates set by regulatory authorities and is not indicative of REMA's future results. The following table presents selected actual financial information and unaudited pro forma information for 1999 and 2000, as if the acquisition had occurred on November 24, 1999 and January 1, 2000, as applicable. Pro forma information prior to November 24, 1999 would not be meaningful since historical financial results of the business and the revenue generating activities underlying that period as described above are substantially different from the wholesale generation activities that REMA has been engaged in after November 24, 1999. Pro forma amounts also give effect to the sale and leaseback of interests in three of the REMA generating plants, which were consummated in August 2000.
YEAR ENDED DECEMBER 31, ----------------------------------------- 1999 2000 ------------------- ------------------- UNAUDITED UNAUDITED ACTUAL PRO FORMA ACTUAL PRO FORMA ------- --------- ------- --------- (IN MILLIONS, EXCEPT PER SHARE AMOUNTS) Revenues............................................. $15,223 $15,253 $29,339 $29,506 Income from continuing operations before extraordinary items................................ 1,674 1,664 771 762 Net income attributable to common stockholders....... 1,482 1,472 447 438 Basic earnings per share from continuing operations before extraordinary items......................... 5.87 5.84 2.71 2.68 Diluted earnings per share from continuing operations before extraordinary items......................... 5.85 5.82 2.68 2.65 Basic earnings per share............................. 5.20 5.16 1.57 1.54 Diluted earnings per share........................... 5.18 5.15 1.56 1.53
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 the REMA entities had occurred on November 24, 1999 and January 1, 2000, as applicable. Purchase-related adjustments to the results of operations include the effects on depreciation and amortization, interest expense and income taxes. (b) N.V. UNA. Effective October 7, 1999, the Company acquired N.V. UNA (UNA), a Dutch electric generation company, for a total net purchase price, payable in Dutch Guilders (NLG), of $1.9 billion based on an exchange rate on October 7, 1999 of 2.06 NLG per U.S. dollar. The aggregate purchase price paid in 1999 by the Company consisted of $833 million in cash. On March 1, 2000, under the terms of the acquisition agreement, the Company funded the remaining purchase obligation for $982 million. The business purchase obligation was recorded in the Company's Consolidated Balance Sheet as of December 31, 1999, based on the exchange rate on December 31, 1999, of 2.19 NLG per U.S. dollar. A portion ($596 million) of the business purchase obligation was classified as a non-current liability, as this portion of the obligation was financed with a three-year term loan facility obtained in the first quarter of 2000. The Company recorded the UNA acquisition under the purchase method of accounting, with assets and liabilities of UNA reflected at their estimated fair values. As outlined in the table below, the Company's fair value adjustments related to the acquisition of UNA primarily included increases in property, plant and equipment, long-term debt, severance liabilities, post-employment benefit liabilities and deferred foreign taxes. Additionally, a $19 million receivable was recorded in connection with the acquisition as the selling 15 shareholders agreed to reimburse UNA for some obligations incurred prior to the purchase of UNA. Adjustments to property, plant and equipment are based primarily on valuation reports prepared by independent appraisers and consultants. The excess of the purchase price over the fair value of net assets acquired of $897 million was recorded as goodwill and will be amortized on a straight-line basis over 30 years. The Company finalized these fair value adjustments during September 2000. The Company finalized a severance plan (UNA Plan) in connection with the UNA acquisition in September 2000 (commitment date) and in accordance with EITF 95-3 "Recognition of Liabilities in Connection with a Purchase Business Combination," recorded this liability of $19 million in the third quarter of 2000. Payments under the UNA Plan will be primarily made in mid-2001. In connection with the acquisition of UNA, the Company developed a comprehensive business process reengineering and employee severance plan intended to make UNA competitive in the deregulated Dutch electricity market that began January 1, 2001. The UNA Plan's initial conceptual formulation was initiated prior to the acquisition of UNA in October 1999. The finalization of the UNA Plan was approved and completed in September 2000. The Company identified 195 employees who will be involuntarily terminated in UNA's following functional areas: plant operations and maintenance, procurement, inventory, general and administrative, legal, finance and support. The Company has notified all employees identified under the severance component of the UNA Plan that they are subject to involuntary termination and that the majority of terminations will occur over a period not to exceed twelve months from the date of finalization of the UNA Plan. The termination benefits under the UNA Plan are governed by UNA's Social Plan, a collective bargaining agreement between UNA and its various representative labor unions signed in 1998. The Social Plan provides defined benefits for involuntarily severed employees, depending upon age, tenure and other factors, and was agreed to by the management of UNA as a result of the anticipated deregulation of the Dutch electricity market. The Social Plan is still in force and binding on the current management of the Company and UNA. The Company is currently executing the UNA Plan as of the date of these Consolidated Financial Statements. The net purchase price of UNA was allocated and the fair value adjustments to the seller's book value are as follows (in millions):
PURCHASE FAIR PRICE VALUE ALLOCATION ADJUSTMENTS ---------- ----------- Current assets.............................................. $ 229 $ 19 Property, plant and equipment............................... 1,899 719 Goodwill.................................................... 897 897 Current liabilities......................................... (336) -- Deferred taxes.............................................. (81) (81) Long-term debt.............................................. (422) (87) Other long-term liabilities................................. (244) (35) ------ ------ $1,942 $1,432 ====== ======
The following table presents selected actual financial information for 1998 and 1999, and unaudited pro forma information for 1998 and 1999, as if the acquisition of UNA had occurred on January 1, 1998 and 1999, respectively. The unaudited pro forma results are based on assumptions deemed appropriate by the Company's management, have been prepared for informational purposes only and are not necessarily indicative of the consolidated results that would have resulted if the acquisition of UNA had occurred on January 1, 1998 and 1999, as applicable. Purchase related adjustments to results of operations include amortization of goodwill, 16 interest expense and the effects on depreciation and amortization of the assessed fair value of some of UNA's net assets and liabilities.
YEAR ENDED DECEMBER 31, ----------------------------------------- 1998 1999 ------------------- ------------------- UNAUDITED UNAUDITED ACTUAL PRO FORMA ACTUAL PRO FORMA ------- --------- ------- --------- (IN MILLIONS, EXCEPT PER SHARE AMOUNTS) Revenues............................................. $11,230 $12,062 $15,223 $15,704 Income from continuing operations before extraordinary item................................. (278) (227) 1,674 1,648 Net (loss) income attributable to common stockholders....................................... (141) (90) 1,482 1,455 Basic earnings per share from continuing operations before extraordinary item.......................... (0.98) (0.80) 5.87 5.78 Diluted earnings per share from continuing operations before extraordinary item.......................... (0.98) (0.80) 5.85 5.76 Basic earnings per share............................. (0.50) (0.32) 5.20 5.11 Diluted earnings per share........................... (0.50) (0.32) 5.18 5.09
o (4) REGULATORY MATTERS (a) Texas Electric Choice Plan and Discontinuance of SFAS No. 71 for Electric Generation Operations. In June 1999, the Texas legislature adopted the Legislation, which substantially amended the regulatory structure governing electric utilities in Texas in order to allow retail electric competition. Retail pilot projects for up to 5% of each utility's load in all customer classes will begin in June 2001, and retail electric competition for all other customers will begin on January 1, 2002. In preparation for that competition, the Company expects to make significant changes in the electric utility operations it conducts through its electric utility division, Reliant Energy HL&P. In addition, the Legislation requires the Texas Utility Commission to issue a number of new rules and determinations in implementing the Legislation. The Legislation defines the process for competition and creates a transition period during which most utility rates are frozen at rates not in excess of their present levels. The Legislation provides for utilities to recover their generation related stranded costs and regulatory assets (as defined in the Legislation). Retail Choice. Under the Legislation, on January 1, 2002, retail customers of most investor owned electric utilities in Texas will be entitled to purchase their electricity from any of a number of "retail electric providers," which will have been certified by the Texas Utility Commission. Retail electric providers will not own or operate generation assets and their sales rates will not be subject to traditional cost-of-service rate regulation. Retail electric providers that are affiliates of electric utilities may compete substantially statewide for these sales, but rates they charge within the affiliated electric utility's traditional service territory are subject to some limitations at the outset of retail choice, as described below. The Texas Utility Commission will prescribe regulations governing quality, reliability and other aspects of service from retail electric providers. Transactions between the regulated utility and its current and future competitive affiliates are subject to regulatory scrutiny and must comply with a code of conduct established by the Texas Utility Commission. The code of conduct governs interactions among employees of regulated and current and future unregulated affiliates as well as the exchange of information between these affiliates. The Company intends to compete in the Texas retail market and, as a result, has certified two of its subsidiaries as retail electric providers. Unbundling. By January 1, 2002, electric utilities in Texas such as Reliant Energy HL&P will restructure their businesses in order to separate power generation, transmission and distribution, and retail activities into different units. Pursuant to the Legislation, the Company submitted a plan in January 2000 that was later amended to accomplish the required separation (the Business Separation Plan). For additional information regarding the Business Separation Plan, see Note 4(b). The transmission and distribution 17 business will continue to be subject to cost-of-service rate regulation and will be responsible for the delivery of electricity to retail customers. Generation. Power generators will sell electric energy to wholesale purchasers, including retail electric providers, at unregulated rates beginning January 1, 2002. To facilitate a competitive market, each power generation company affiliated with a transmission and distribution utility will be required to sell at auction 15% of the output of its installed generating capacity. The first auction will be held on or before September 1, 2001 for power delivered after January 1, 2002. This obligation continues until January 1, 2007 unless before that date the Texas Utility Commission determines at least 40% of the quantity of electric power consumed in 2000 by residential and small commercial load in the electric utility's service area is being served by retail electric providers other than the affiliated retail electric provider. See Note 4(b) for information regarding the capacity auctions and the effect of the Business Separation Plan on the Company. The Legislation also creates a program mandating air emissions reductions for non-permitted generating facilities. The Company anticipates that any stranded costs associated with this obligation incurred before May 1, 2003 will be recoverable through the stranded costs recovery mechanisms contained in the Legislation. Rates. Base rates charged by Reliant Energy HL&P on September 1, 1999 will be frozen until January 1, 2002. Pursuant to Texas Utility Commission regulations, effective January 1, 2002, retail rates charged to residential and small commercial customers by the utility's affiliated retail electric provider will be reduced by 6% from the average rates (on a bundled basis) in effect on January 1, 1999 (adjusted for fuel charges). That reduced rate will be known as the "price to beat" and will be charged by the affiliated retail electric provider to residential and small commercial customers in the utility's service area who have not elected service from another retail electric provider. The affiliated retail electric provider may not offer different rates to residential or small commercial customer classes in the utility's service area until the earlier of the date the Texas Utility Commission determines that 40% of power consumed by that class in the affiliated transmission and distribution utility's service area is being served by non-affiliated retail electric providers or January 1, 2005. In addition, the affiliated retail electric provider must make the price to beat available to eligible consumers until January 1, 2007. Stranded Costs. Reliant Energy HL&P will be entitled to recover its stranded costs (i.e., the excess of net book value of generation assets (as defined by the Legislation) over the market value of those assets) and its regulatory assets related to generation. The Legislation prescribes specific methods for determining the amount of stranded costs and the details for their recovery. However, during the base rate freeze period from 1999 through 2001, earnings above the utility's authorized return formula will be applied in a manner to accelerate depreciation of generation related plant assets for regulatory purposes. In addition, depreciation expense for transmission and distribution related assets may be redirected to generation assets for regulatory purposes during that period. The Texas Utility Commission has recently stated on record that it would consider requiring electric utilities to reverse the amount of redirected depreciation and accelerated depreciation previously taken if in its estimation the utility has overmitigated its stranded costs. The reversal could occur through a lower rate for the transmission and distribution utility and/or through credits contained in the transmission and distribution utility's rate. Any order requiring the reversal of these amounts would likely be included in the Texas Utility Commission proceeding establishing the initial rate of the transmission and distribution utility. The Company does not expect the final Reliant Energy HL&P transmission and distribution rate to be established until August 2001. For information regarding redirected depreciation, see "Accounting" in this Note 4(a). The Legislation provides for Reliant Energy HL&P, or a special purpose entity, to issue securitization bonds for the recovery of generation related regulatory assets and a portion of stranded costs. These bonds will be sold to third parties and will be amortized through non-bypassable charges to transmission and distribution customers. Any stranded costs not recovered through the securitization bonds will be recovered through a non-bypassable charge to transmission and distribution customers. Costs associated with nuclear decommissioning that have not been recovered as of January 1, 2002, will continue to be subject to cost-of-service rate regulation and will be included in a non-bypassable charge to transmission and distribution customers. For 18 further discussion of the effect of the Business Separation Plan on funding of the nuclear decommissioning trust fund, see Note 4(b). In May 2000, the Texas Utility Commission issued a financing order to the Company authorizing the issuance of transition bonds in an amount not to exceed $740 million plus actual up-front qualified costs. Payments on the transition bonds will be made out of funds derived from non-bypassable transition charges to Reliant Energy HL&P's transmission and distribution customers. The offering of the transition bonds will be registered under the Securities Act of 1933 and is expected to be consummated during 2001. Capacity Auction True-up. In accordance with the Legislation, beginning on January 1, 2002, and ending when the true-up proceeding is completed, any difference between market power prices received in the generation capacity auction and the Texas Utility Commission's earlier estimates of those market prices will be included in the 2004 stranded costs true-up, as further discussed below. This component of the true-up is intended to ensure that neither the customers nor the Company are disadvantaged economically as a result of the two-year transition period by providing this pricing structure. For information regarding the effect of the Business Separation Plan on the generation capacity auctions, see Note 4(b). Accounting. Historically, Reliant Energy HL&P has applied the accounting policies established in SFAS No. 71. In general, SFAS No. 71 permits a company with cost-based rates to defer some costs that would otherwise be expensed to the extent that it meets the following requirements: (a) its rates are regulated by a third-party; (b) its rates are cost-based; and (c) there exists a reasonable assumption that all costs will be recoverable from customers through rates. When a company determines that it no longer meets the requirements of SFAS No. 71, pursuant to SFAS No. 101 and SFAS No. 121, it is required to write off regulatory assets and liabilities unless some form of recovery continues through rates established and collected from remaining regulated operations. In addition, such company is required to determine any impairment to the carrying costs of deregulated plant and inventory assets in accordance with SFAS No. 121. In July 1997, the EITF reached a consensus on Issue No. 97-4, "Deregulation of the Pricing of Electricity -- Issues Related to the Application of FASB Statements No. 71, Accounting for the Effects of Certain Types of Regulation, and No. 101, Regulated Enterprises Accounting for the Discontinuation of Application of FASB Statement No. 71" (EITF No. 97-4). EITF No. 97-4 concluded that a company should no longer apply SFAS No. 71 to a segment which is subject to a deregulation plan at the time the deregulation legislation or enabling rate order contains sufficient detail for the utility to reasonably determine how the plan will affect the segment to be deregulated. In addition, EITF No. 97-4 requires that regulatory assets and liabilities be allocated to the applicable portion of the electric utility from which the source of the regulated cash flows will be derived. The Company believes that the Legislation provides sufficient detail regarding the deregulation of the Company's electric generation operations to require it to discontinue the use of SFAS No. 71 for those operations. Effective June 30, 1999, the Company applied SFAS No. 101 to Reliant Energy HL&P's electric generation operations. Reliant Energy HL&P's transmission and distribution operations continue to meet the criteria of SFAS No. 71. In 1999, the Company evaluated the effects that the Legislation would have on the recovery of its generation related regulatory assets and liabilities. The Company determined that a pre-tax accounting loss of $282 million existed because it believes only the economic value of its generation related regulatory assets (as defined by the Legislation) will be recovered. Therefore, the Company recorded a $183 million after-tax extraordinary loss in the fourth quarter of 1999. If events were to occur that made the recovery of some of the remaining generation related regulatory assets no longer probable, the Company would write off the remaining balance of such assets as a non-cash charge against earnings. Pursuant to EITF No. 97-4, the remaining recoverable regulatory assets will not be written off and will become associated with the transmission and distribution portion of the Company's electric utility business. For details regarding Reliant Energy HL&P's regulatory assets, see Note 2(f). At June 30, 1999, the Company performed an impairment test of its previously regulated electric generation assets pursuant to SFAS No. 121 on a plant specific basis. Under SFAS No. 121, an asset is 19 considered impaired, and should be written down to fair value, if the future undiscounted net cash flows expected to be generated by the use of the asset are insufficient to recover the carrying amount of the asset. For assets that are impaired pursuant to SFAS No. 121, the Company determined the fair value for each generating plant by estimating the net present value of future cash inflows and outflows over the estimated life of each plant. The difference between fair value and net book value was recorded as a reduction in the current book value. The Company determined that $797 million of electric generation assets were impaired as of June 30, 1999. Of these amounts, $745 million related to the South Texas Project and $52 million related to two gas-fired generation plants. The Legislation provides for recovery of this impairment through regulated cash flows during the transition period and through non-bypassable charges to transmission and distribution customers. As such, a regulatory asset has been recorded for an amount equal to the impairment loss and is included on the Company's Consolidated Balance Sheets as a regulatory asset. The Company recorded amortization expense related to the recoverable impaired plant costs and other assets created from discontinuing SFAS No. 71 of $221 million in the third and fourth quarters of 1999 and $329 million in 2000. The Company expects to fully amortize this regulatory asset as it is recovered from regulated cash flows in 2001. The impairment analysis requires estimates of possible future market prices, load growth, competition and many other factors over the lives of the plants. The resulting impairment loss is highly dependent on these underlying assumptions. In addition, after January 10, 2004, Reliant Energy HL&P must finalize and reconcile stranded costs (as defined by the Legislation) in a filing with the Texas Utility Commission. Any positive difference between the regulatory net book value and the fair market value of the generation assets (as defined by the Legislation) will be collected through future non-bypassable charges. Any over-mitigation of stranded costs may be refunded through future non-bypassable charges. This final reconciliation allows alternative methods of third party valuation of the fair market value of these assets, including outright sale, stock valuations and asset exchanges. Because generally accepted accounting principles require the Company to estimate fair market values on a plant-by-plant basis in advance of the final reconciliation, the financial impacts of the Legislation with respect to the final determination of stranded costs in 2004 are subject to material changes. Factors affecting such change may include estimation risk, uncertainty of future energy and commodity prices and the economic lives of the plants. If events occur that make the recovery of all or a portion of the regulatory assets associated with the generation plant impairment loss and other assets created from discontinuance of SFAS No. 71 pursuant to the Legislation no longer probable, the Company will write off the corresponding balance of these assets as a non-cash charge against earnings. One of the results of discontinuing the application of SFAS No. 71 for the generation operations is the elimination of the regulatory accounting effects of excess deferred income taxes and investment tax credits related to these operations. The Company believes it is probable that some parties will seek to return these amounts to ratepayers and accordingly, the Company has recorded an offsetting liability. In order to reduce potential exposure to stranded costs related to generation assets, Reliant Energy HL&P redirected $195 million and $99 million of depreciation in 1998 and for the six months ended June 30, 1999, respectively, from transmission and distribution related plant assets to generation assets for regulatory and financial reporting purposes. This redirection was in accordance with the Company's Transition Plan. See Note 4(c) for additional information regarding the Transition Plan. The Legislation provides that depreciation expense for transmission and distribution related assets may be redirected to generation assets during the base rate freeze period from 1999 through 2001. For regulatory purposes, the Company has continued to redirect transmission and distribution depreciation to generation assets. Beginning June 30, 1999, redirected depreciation expense cannot be recorded by the electric generation operations portion of Reliant Energy HL&P for financial reporting purposes as this portion of electric operations is no longer accounted for under SFAS No. 71. During the six months ended December 31, 1999 and during 2000, $99 million and $218 million in depreciation expense, respectively, has been redirected from transmission and distribution for regulatory purposes and has been established as an embedded regulatory asset included in transmission and distribution related plant and equipment balances. As of December 31, 1999 and 2000, the cumulative amount of redirected depreciation for regulatory purposes is $393 million and $611 million, respectively. 20 The Company has reviewed its long-term purchase power contracts and fuel contracts for potential loss in accordance with SFAS No. 5, "Accounting for Contingencies" and Accounting Research Bulletin No. 43, Chapter 4, "Inventory Pricing." Based on projections of future market prices for wholesale electricity, the analysis indicated no loss recognition is appropriate at this time. Other Accounting Policy Changes. As a result of discontinuing SFAS No. 71, the accounting policies discussed below related to Electric Operations' generation operations have been changed effective July 1, 1999. Allowance for funds used during construction will no longer be accrued on generation related construction projects. Instead, interest will be capitalized on these projects in accordance with SFAS No. 34, "Capitalization of Interest Cost." Previously, in accordance with SFAS No. 71, Reliant Energy HL&P deferred the premiums and expenses that arose when long-term debt was redeemed and amortized these costs over the life of the new debt. If no new debt was issued, these costs were amortized over the remaining original life of the retired debt. Effective July 1, 1999, costs resulting from the retirement of debt attributable to the generation operations of Reliant Energy HL&P will be recorded in accordance with SFAS No. 4, "Reporting Gains and Losses from Extinguishment of Debt," unless these costs will be recovered through regulated cash flows. In that case, these costs will be deferred and recorded as a regulatory asset by the entity through which the source of the regulated cash flows will be derived. (b) Business Separation Plan. General. As required by the Legislation, Reliant Energy submitted the Business Separation Plan in 2000 to the Texas Utility Commission. The Business Separation Plan was later amended to provide for the restructuring of the Company's businesses into two separate and publicly traded companies in order to separate its unregulated businesses from its regulated businesses. In December 2000, the plan was approved by the Texas Utility Commission. Reliant Resources holds Reliant Energy's unregulated businesses, including the Wholesale Energy segment, European Energy segment, communications business, eBusiness group, new ventures group and retail electric business. As further described below, Reliant Energy will undergo a restructuring of the Company's corporate organization to achieve a holding company structure. This holding company will hold primarily what are currently Reliant Energy's rate-regulated businesses. Reliant Resources expects to conduct the Offering in 2001. After the Offering, Reliant Energy will own approximately 80% of Reliant Resources common stock. Reliant Energy expects the Offering to be followed by a distribution to Reliant Energy's or its successor's shareholders of the remaining common stock of Reliant Resources within 12 months of the Offering (the Distribution Date). The Offering and the Distribution are subject to further corporate approvals, market and other conditions, and government actions, including receipt of a favorable Internal Revenue Service ruling that the Distribution would be tax-free to Reliant Energy or its successor and its shareholders for U.S. federal income tax purposes, as applicable. There can be no assurance that the Offering and the Distribution will be completed as described or within the time periods outlined above. Restructuring of Regulated Entities. Under the Business Separation Plan, Reliant Energy will restructure its regulated operations into a holding company structure in which a new corporate entity (Regulated Holding Company) will be formed as the parent with the Company's regulated businesses as subsidiaries. This Regulated Holding Company is expected to own (a) the Company's electric transmission and distribution operations, (b) its natural gas distribution businesses, (c) initially, its regulated electric generating assets in Texas, (d) its interstate pipelines, gas gathering and pipeline services operations, and (e) its interests in energy companies in Latin America until disposition of these investments (see Note 19). In these Notes, references to Reliant Energy in connection with events occurring or the performance of agreements after the restructuring generally refer to the Regulated Holding Company. In connection with the formation of the new holding company for regulated businesses, Reliant Energy expects to transfer the stock of all of its subsidiaries to the new holding company and will transfer its regulated electric generating assets in Texas to an indirect wholly owned partnership (Texas Genco) until the stranded costs associated with those assets are valued in 2004. At that time, Reliant Resources will have the right to 21 exercise an option to acquire those assets, as further discussed below. As a result of the stock and asset transfers described above, Reliant Energy will become solely a transmission and distribution company, with its other businesses becoming subsidiaries of the new holding company. Reliant Energy expects that the regulated holding company will be required to assume all of Reliant Energy's debt other than its first mortgage bonds, which would remain with Reliant Energy. The indebtedness of some wholly owned financing subsidiaries is expected to be refinanced by the regulated holding company by the end of 2002. Reliant Energy has made and will continue to make internal asset and stock transfers intended to allocate the assets and liabilities of Reliant Energy in accordance with regulatory requirements and as contemplated by the Business Separation Plan. Forms of each of the intercompany agreements described below have been prepared and will be entered into by Reliant Energy and Reliant Resources prior to the Offering. Aspects of the restructuring of Reliant Energy's regulated businesses are subject to the approval of Reliant Energy's shareholders and lenders and approvals from the SEC under the Public Utility Holding Company Act and from the United States Nuclear Regulatory Commission (NRC). There can be no assurance that the restructuring of the Company's regulated businesses will be completed as described above. Agreements Related to Texas Generating Assets. Pursuant to the Business Separation Plan, Reliant Energy expects to cause Texas Genco to either issue and sell in an initial public offering or to distribute to its shareholders no more than 20% of the common stock of Texas Genco by June 30, 2002. In connection with the separation of its unregulated businesses from its regulated businesses, Reliant Energy will grant Reliant Resources an option to purchase all of the shares of capital stock of Texas Genco that will be owned by Reliant Energy after the initial public offering or distribution. The Texas Genco option may be exercised between January 10, 2004 and January 24, 2004. The per share exercise price under the option will be the average daily closing price on the national exchange for publicly held shares of common stock of Texas Genco for the 30 consecutive trading days with the highest average closing price during the 120 trading days immediately preceding January 10, 2004, plus a control premium, up to a maximum of 10%, to the extent a control premium is included in the valuation determination made by the Texas Utility Commission relating to the market value of Texas Genco's common stock equity. The exercise price is also subject to adjustment based on the difference between the per share dividends paid during the period there is a public ownership interest in Texas Genco and Texas Genco's per share earnings during that period. If the disposition to the public of common stock of Texas Genco is by means of a primary or secondary public offering, the public offering may be of as little as 17% (rather than 19%) of Texas Genco's outstanding common stock, in which case Reliant Energy will have the right to subsequently reduce its interest to a level not less than 80%. Reliant Resources will agree that if it exercises the Texas Genco Option and purchases the shares of Texas Genco common stock, Reliant Resources will also purchase all notes and other receivables from Texas Genco then held by Reliant Energy, at their principal amount plus accrued interest. Similarly, if Texas Genco holds notes or receivables from the Company, Reliant Resources will assume those obligations in exchange for a payment to Reliant Resources by the Company of an amount equal to the principal plus accrued interest. Exercise of the Texas Genco option by Reliant Resources will be subject to various regulatory approvals, including Hart-Scott-Rodino antitrust clearance and Nuclear Regulatory Commission license transfer approval. The option will be exercisable only if Reliant Energy or its successor distributes all of the shares of Reliant Resources common stock it owns to its shareholders. The Texas Genco option agreement will require Reliant Energy to take commercially reasonable action as may be appropriate to cause Texas Genco to have a capital structure appropriate, in the judgment of Reliant Energy's Board of Directors, for the satisfactory marketing of Texas Genco common stock in an initial public offering or to establish a satisfactory trading market for Texas Genco common stock following a distribution of shares to Reliant Energy's shareholders. It also will contain covenants relating to the operation of the Texas Genco assets prior to the exercise or expiration of the option and require that Reliant Energy maintain ownership of all equity of Texas Genco until exercise or expiration of the Texas Genco option, subject to the initial public offering or distribution obligation. Reliant Resources will provide engineering and technical support services and environmental, safety and industrial health services to support the operations and maintenance of Texas Genco's facilities. Reliant 22 Resources will also provide systems, technical, programming and consulting support services and hardware maintenance (but excluding plant-specific hardware) necessary to provide dispatch planning, dispatch and settlement and communication with the independent system operator. The fees charged for these services will be designed to allow Reliant Resources to recover its fully allocated direct and indirect costs and reimbursement of out-of-pocket expenses. Expenses associated with capital investment in systems and software that benefit both the operation of Texas Genco's facilities and Reliant Resources' facilities in other regions will be allocated on an installed megawatt basis. The term of the technical services agreement will begin at the Distribution Date. The term of this agreement will end on the first to occur of (a) the closing date of the Reliant Resources' Texas Genco option, (b) Reliant Energy's sale of Texas Genco, or all or substantially all of the assets of Texas Genco, if Reliant Resources does not exercise the Texas Genco option, or (c) December 31, 2004, provided the Texas Genco option is not exercised. Texas Genco may extend the term of this agreement until December 31, 2005. Pursuant to the Legislation, Texas Genco will be required to sell at auction 15% of the output of its installed generating capacity beginning January 1, 2002. The first auction will be held on or before September 1, 2001 for power delivered after January 1, 2002. This obligation continues until January 1, 2007, unless before that date the Texas Utility Commission determines that at least 40% of the quantity of electric power consumed in 2000 by residential and small commercial customers in the Reliant Energy HL&P traditional service area is being served by retail electric providers other than subsidiaries of Reliant Resources. Texas Genco plans to auction all of its remaining output during the time period prior to Reliant Resources' exercise of the Texas Genco option. Pursuant to the Business Separation Plan, Reliant Resources is entitled to purchase, at prices established in these auctions, up to 50% of the remaining capacity, energy and ancillary services auctioned by Texas Genco. When Texas Genco is organized, it will become the beneficiary of the decommissioning trust that has been established to provide funding for decontamination and decommissioning of a nuclear electric generation station in which Reliant Energy owns a 30.8% interest (see Note 6). The master separation agreement will provide that Reliant Energy will collect through rates or other authorized charges to its electric utility customers amounts designated for funding the decommissioning trust, and will pay the amounts to Texas Genco. Texas Genco will in turn be required to deposit these amounts received from Reliant Energy into the decommissioning trust. Upon decommissioning of the facility, in the event funds from the trust are inadequate, Reliant Energy will be required to collect through rates or other authorized charges to customers as contemplated by the Texas Utilities Code all additional amounts required to fund Texas Genco's obligations relating to the decommissioning of the facility. Following the completion of the decommissioning, if surplus funds remain in the decommissioning trust, the excess will be refunded to Reliant Energy's ratepayers. Retail Agreement between Reliant Energy and Reliant Resources. Under a retail agreement, Reliant Resources will provide customer service call center operations, credit and collections and revenue reporting services for Reliant Energy's electric utility division and receiving and processing payments for the accounts of Reliant Energy's electric utility division and two of Reliant Energy's natural gas distribution divisions. Reliant Energy will provide the office space and equipment for Reliant Resources to perform these services. These services will terminate on January 1, 2002. The charges Reliant Energy will pay Reliant Resources for these services are generally intended to allow Reliant Resources to recover its fully allocated costs of providing the services, plus out-of-pocket costs and expenses. Service Agreements between Reliant Energy and Reliant Resources. Reliant Resources plans to enter into agreements with Reliant Energy under which Reliant Energy will provide Reliant Resources, on an interim basis, with various corporate support services (including accounting, finance, investor relations, planning, legal, communications, governmental and regulatory affairs and human resources), information technology services and other previously shared services such as corporate security, facilities management, accounts receivable, accounts payable and payroll, office support services and purchasing and logistics. These arrangements will continue after the Offering under a transition services agreement providing for their continuation until December 31, 2004, or, in the case of some corporate support services, until the 23 Distribution Date. The charges Reliant Resources will pay Reliant Energy for these services are generally intended to allow Reliant Energy to recover its fully allocated costs of providing the services, plus out-of-pocket costs and expenses. In each case, Reliant Resources will have the right to terminate categories of services at an earlier date. Pursuant to a lease agreement, Reliant Energy will lease Reliant Resources office space in its headquarters building in Houston, Texas for an interim period. Other Agreements. In connection with the separation of Reliant Resources' businesses from those of Reliant Energy, Reliant Resources will also enter into other agreements providing, among other things, for mutual indemnities and releases with respect to Reliant Resources' respective businesses and operations, matters relating to corporate governance, matters relating to responsibility for employee compensation and benefits, and allocation of tax liabilities. In addition, Reliant Resources and Reliant Energy will enter into various agreements relating to ongoing commercial arrangements, including among other things the leasing of optical fiber and related maintenance activities, rights to build fiber networks along existing rights of way, and the provision of local exchange telecommunications and data services in the greater Houston metropolitan area and long distance telecommunications services. Reliant Energy will agree that $1.9 billion of intercompany indebtedness owed by Reliant Resources and its subsidiaries prior to the closing of the Offering will be converted into equity as a capital contribution to Reliant Resources. (c) Transition Plan. In June 1998, the Texas Utility Commission issued an order in Docket No. 18465 approving the Company's Transition Plan filed by Reliant Energy HL&P in December 1997. The Transition Plan included base rate credits to residential customers of 4% in 1998 and an additional 2% in 1999. Commercial customers whose monthly billing is 1,000 kva or less were entitled to receive base rate credits of 2% in each of 1998 and 1999. The Company implemented the Transition Plan effective January 1, 1998. (d) Reliant Energy HL&P Filings. As of December 31, 2000, Reliant Energy HL&P had recorded as a regulatory asset under-recovered fuel cost of $558 million. In two separate filings in 2000, Reliant Energy HL&P filed and received approval to implement a fuel surcharge to collect the under recovery of fuel expenses, as well as to adjust the fuel factor to compensate for significant increases in the price of natural gas. On March 15, 2001, Reliant Energy HL&P filed to revise its fuel factor and address the Company's undercollected fuel costs of $389 million, which is the accumulated amount since September 2000 through February 2001 plus estimates for March and April, 2001. Reliant Energy HL&P is requesting to revise its fixed fuel factor to be implemented with the May 2001 billing cycle and has proposed to defer the collection of the $389 million until the 2004 stranded costs true-up proceeding, discussed in Note 4(a) above. o (5) DERIVATIVE FINANCIAL INSTRUMENTS (a) Price Risk Management and Trading Activities. The Company offers energy price risk management services primarily related to natural gas, electric power and other energy related commodities. The Company provides these services by utilizing a variety of derivative financial instruments, including (a) fixed and variable-priced physical forward contracts, (b) fixed and variable-priced swap agreements, (c) options traded in the over-the-counter financial markets and (d) exchange-traded energy futures and option contracts (Trading Derivatives). Fixed-price swap agreements require payments to, or receipts of payments from, counterparties based on the differential between a fixed and variable price for the commodity. Variable-price swap agreements require payments to, or receipts of payments from, counterparties based on the differential between industry pricing publications or exchange quotations. 24 The Company applies mark-to-market accounting for all of its energy trading, marketing and price risk management operations. Accordingly, these Trading Derivatives are recorded at fair value with realized and unrealized gains (losses) recorded as a component of revenues. The recognized, unrealized balances are included in price risk management assets/liabilities. The notional quantities, maximum terms and the estimated fair value of Trading Derivatives at December 31, 1999 and 2000 are presented below (volumes in billions of British thermal units equivalent (Bbtue) and dollars in millions):
VOLUME-FIXED VOLUME-FIXED MAXIMUM PRICE PAYOR PRICE RECEIVER TERM (YEARS) ------------ -------------- ------------ 1999 Natural gas.................................... 1,278,953 1,251,319 9 Electricity.................................... 242,868 239,452 10 Oil and other.................................. 285,251 286,521 3 2000 Natural gas.................................... 1,876,358 1,868,597 17 Electricity.................................... 526,556 523,942 6 Oil and other.................................. 52,820 42,380 2
FAIR VALUE AVERAGE FAIR VALUE(1) --------------------- --------------------- ASSETS LIABILITIES ASSETS LIABILITIES ------ ----------- ------ ----------- 1999 Natural gas.................................. $ 581 $ 564 $ 550 $ 534 Electricity.................................. 122 91 96 74 Oil and other................................ 193 206 183 187 ------ ------ ------ ------ $ 896 $ 861 $ 829 $ 795 ====== ====== ====== ====== 2000 Natural gas.................................. $4,059 $4,054 $2,058 $2,038 Electricity.................................. 1,115 1,087 601 561 Oil and other................................ 39 39 63 70 ------ ------ ------ ------ $5,213 $5,180 $2,722 $2,669 ====== ====== ====== ======
- --------------- (1) Computed using the ending balance of each quarter. In addition to the fixed-price notional volumes above, the Company also has variable-priced agreements, as discussed above, totaling 2,147,173 Bbtue and 3,004,336 Bbtue as of December 31, 1999 and 2000, respectively. Notional amounts reflect the commodity volumes underlying the transactions but do not represent the amounts exchanged by the parties to the financial instruments. Accordingly, notional amounts do not accurately measure the Company's exposure to market or credit risks. All of the fair values shown in the table above at December 31, 1999 and 2000, have been recognized in income. The Company estimated the fair value as of December 31, 1999 and 2000, using quoted prices where available and other valuation techniques when market data was not available, for example in illiquid markets. For financial instruments for which quoted prices are not available, the Company utilizes alternative pricing methodologies, including, but not limited to, extrapolation of forward pricing curves using historically reported data from illiquid pricing points. These same pricing techniques are used to evaluate a contract prior to taking the position. The prices and fair values are subject to significant changes based on changing market conditions. The weighted-average term of the trading portfolio, based on volumes, is less than one year. The maximum and average terms disclosed herein are not indicative of likely future cash flows, as these positions may be changed by new transactions in the trading portfolio at any time in response to changing market 25 conditions, market liquidity and the Company's risk management portfolio needs and strategies. Terms regarding cash settlements of these contracts vary with respect to the actual timing of cash receipts and payments. In addition to the risk associated with price movements, credit risk is also inherent in the Company's risk management activities. Credit risk relates to the risk of loss resulting from non-performance of contractual obligations by a counterparty. The following table shows the composition of the total price risk management assets of the Company as of December 31, 1999 and 2000.
DECEMBER 31, 1999 DECEMBER 31, 2000 ------------------ ------------------- INVESTMENT INVESTMENT GRADE(1) TOTAL GRADE(1) TOTAL ---------- ----- ---------- ------ (IN MILLIONS) Energy marketers................................ $202 $230 $2,507 $2,709 Financial institutions.......................... 90 159 1,159 1,296 Gas and electric utilities...................... 220 221 511 586 Oil and gas producers........................... 31 31 500 599 Industrials..................................... 3 4 78 89 Others.......................................... 174 263 -- -- ---- ---- ------ ------ Total................................. $720 908 $4,755 5,279 ==== ====== Credit and other reserves....................... (12) (66) ---- ------ Energy price risk management assets(2).......... $896 $5,213 ==== ======
- --------------- (1) "Investment Grade" is primarily determined using publicly available credit ratings along with the consideration of credit support (such as parent company guarantees) and collateral, which encompass cash and standby letters of credit. (2) As of December 31, 2000, the Company had credit risk exposure to three investment-grade counterparties that each represented greater than 5% of price risk management assets. This information excludes some offsetting contracts that either require or permit net settlement with non-trading transactions not included in price risk management assets. The Company's resulting net credit risk exposure to these three counterparties is below 5% of price risk management assets. (b) Non-Trading Activities. To reduce the risk from market fluctuations in the revenues derived from the sale of electric power and natural gas and related transportation, the Company enters into futures transactions, forward contracts, swaps and options (Energy Derivatives) in order to hedge some expected purchases of electric power and natural gas and sales of electric power and natural gas (a portion of which are firm commitments at the inception of the hedge). Energy Derivatives are also utilized to fix the price of compressor fuel or other future operational gas requirements and to protect natural gas distribution earnings against unseasonably warm weather during peak gas heating months, although usage to date for this purpose has not been material. The Company applies hedge accounting for its derivative financial instruments utilized in non-trading activities. Unrealized changes in the market value of Energy Derivatives utilized as hedges are not generally recognized in the Company's Statements of Consolidated Operations until the underlying hedged transaction occurs. Once it becomes probable that an anticipated transaction will not occur, the Company recognizes deferred gains and losses. In general, the financial impact of transactions involving these Energy Derivatives is included in the Company's Statements of Consolidated Operations under the captions (a) fuel expenses, in the case of natural gas transactions, (b) purchased power, in the case of electric power purchase transactions, and (c) revenues, in the case of electric power sales transactions. Cash flows resulting from these transactions in Energy Derivatives are included in the Company's Statements of Consolidated Cash Flows in the same category as the item being hedged. 26 In connection with the Company's acquisition of UNA in 1999, the Company entered into call option agreements with several banks to hedge the impact of foreign exchange movements on the Dutch guilder. These call options provided the right, but not the obligation, to purchase NLG 695 million from specific banks at specific strike prices. The total premium paid, classified as other expense on the Company's Statement of Consolidated Operations, for all of the options that were to expire on October 26, 1999, was $8 million. On October 12, 1999, the Company sold the remaining value in the call options for $0.6 million. The proceeds were reflected in the Company's results of operations as a reduction of other expense. As of December 31, 1999 and 2000, the Company had outstanding foreign currency swaps for 258 million and Euros 671 million, respectively (approximately $228 million and $632 million), terminating in September 2000 and January 2001, respectively. The Company also issued Euro-denominated debt, maturing in March and June 2001. The foreign currency swaps and Euro-denominated debt hedge the Company's net investment in UNA. In January 2001, the Company entered into foreign currency swaps for Euros 671 million (approximately $633 million) to replace the foreign currency swaps that expired in January 2001. These foreign currency swaps terminate in January 2002. In January and March 2001, the Company entered into foreign currency forward contracts for Euros 159 million (approximately $150 million) to adjust the hedge of its net investment in UNA. These forward contracts expire in January 2002. The Company records changes in the value of the hedging instruments and debt as foreign currency translation adjustments as a component of stockholders' equity and accumulated other comprehensive loss. The effectiveness of the hedging instruments can be measured by the net change in foreign currency translation adjustments attributed to the net investment in UNA. These amounts generally offset amounts recorded in stockholders' equity as adjustments resulting from translation of the hedged investment into U.S. dollars. As of December 31, 1999 and 2000, the net carrying value of the currency swaps was a $6 million receivable and $62 million obligation, respectively, and was recorded in other current assets and other current liabilities in the Company's Consolidated Balance Sheets. During 2000, European Energy entered into financial instruments to purchase approximately $120 million to hedge future fuel purchases payable in U.S. dollars. As of December 31, 2000, the fair value of these financial instruments was a $6 million liability. Unrealized changes in the market value of these financial instruments are not recognized in the Company's Statements of Consolidated Operations until the underlying hedged transaction occurs. For transactions involving either Energy Derivatives or foreign currency derivatives, hedge accounting is applied only if the derivative reduces the risk of the underlying hedged item and is designated as a hedge at its inception. Additionally, the derivatives must be expected to result in financial impacts that are inversely correlated to those of the item(s) to be hedged. This correlation, a measure of hedge effectiveness, is measured both at the inception of the hedge and on an ongoing basis, with an acceptable level of correlation of at least 80% for hedge designation. If and when correlation ceases to exist at an acceptable level, hedge accounting ceases and mark-to-market accounting is applied. At December 31, 1999, the Company was a fixed-price payor and a fixed-price receiver in Energy Derivatives covering 33,108 Bbtu and 5,481 Bbtu of natural gas, respectively. At December 31, 2000, the Company was a fixed-price payor and a fixed-price receiver in Energy Derivatives covering 198,001 Bbtu and 22,874 Bbtu of natural gas, respectively, and 486 Bbtu and zero Bbtu of oil, respectively. In addition to the fixed-price notional volumes above, the Company also has variable-priced agreements totaling 44,958 Bbtu and 174,900 Bbtu of natural gas at December 31, 1999 and 2000, respectively. The weighted average maturity of these instruments is less than two years. The notional amount is intended to be indicative of the Company's level of activity in these derivatives. However, the amounts at risk are significantly smaller because, in view of the price movement correlation required for hedge accounting, changes in the market value of these derivatives generally are offset by changes in the value associated with the underlying physical transactions or in other derivatives. When Energy Derivatives are closed out in advance of the underlying commitment or anticipated transaction, however, the market value changes may not offset due to the fact that price movement correlation ceases to exist when the 27 positions are closed, as further discussed above. Under these circumstances, gains (losses) are deferred and recognized as a component of income when the underlying hedged item is recognized in income. The average maturity discussed above and the fair value discussed in Note 15 are not necessarily indicative of likely future cash flows as these positions may be changed by new transactions in the trading portfolio at any time in response to changing market conditions, market liquidity and the Company's risk management portfolio needs and strategies. Terms regarding cash settlements of these contracts vary with respect to the actual timing of cash receipts and payments. (c) Trading and Non-trading -- General Policy. In addition to the risk associated with price movements, credit risk is also inherent in the Company's risk management activities. Credit risk relates to the risk of loss resulting from non-performance of contractual obligations by a counterparty. The Company has off-balance sheet risk to the extent that the counterparties to these transactions may fail to perform as required by the terms of each contract. In order to minimize this risk, the Company enters into these contracts primarily with counterparties having a minimum investment grade index rating, i.e. a Standard & Poor's or Moody's rating of BBB- or Baa3, respectively. For long-term arrangements, the Company periodically reviews the financial condition of these firms in addition to monitoring the effectiveness of these financial contracts in achieving the Company's objectives. If the counterparties to these arrangements fail to perform, the Company would seek to compel performance at law or otherwise obtain compensatory damages. The Company might be forced to acquire alternative hedging arrangements or be required to replace the underlying commitment at then-current market prices. In this event, the Company might incur additional losses to the extent of amounts, if any, already paid to the counterparties. For information regarding credit risk related to the California wholesale electricity market, see Note 14(h). The Company's policies prohibit the use of leveraged financial instruments. A leveraged financial instrument, for this purpose, is a transaction involving a derivative whose financial impact will be based on an amount other than the notional amount or volume of the instrument. The Company has established a Risk Oversight Committee, comprised of corporate and business segment officers that oversees all commodity price and credit risk activities, including the Company's trading, marketing, power origination and risk management activities. The committee's duties are to establish the Company's commodity risk policies, allocate risk capital within limits established by the Company's Board of Directors, approve trading of new products and commodities, monitor risk positions and ensure compliance with the Company's risk management policies and procedures and trading limits established by the Company's Board of Directors. o (8) INDEXED DEBT SECURITIES (ACES AND ZENS) AND AOL TIME WARNER SECURITIES (a) Original Investment in Time Warner Securities. On July 6, 1999, the Company converted its 11 million shares of Time Warner Inc. (TW) convertible preferred stock (TW Preferred) into 45.8 million shares of Time Warner common stock (TW Common). Prior to the conversion, the Company's investment in the TW Preferred was accounted for under the cost method at a value of $990 million in the Company's Consolidated Balance Sheets. The TW Preferred was redeemable after July 6, 2000, had an aggregate liquidation preference of $100 per share (plus accrued and unpaid dividends), was entitled to annual dividends of $3.75 per share until July 6, 1999 and was convertible by the Company. The Company recorded pre-tax dividend income with respect to the TW Preferred of $21 million in 1999 prior to the conversion and $41 million in 1998. Effective on the conversion date, the shares of TW Common were classified as trading securities under SFAS No. 115 and an unrealized gain was recorded in the amount of $2.4 billion ($1.5 billion after-tax) to reflect the cumulative appreciation in the fair value of the Company's investment in Time Warner securities. 28 (b) ACES. In July 1997, in order to monetize a portion of the cash value of its investment in TW Preferred, the Company issued 22.9 million of its unsecured 7% Automatic Common Exchange Securities (ACES) having an original principal amount of $1.052 billion and maturing July 1, 2000. The market value of ACES was indexed to the market value of TW Common. On the July 1, 2000 maturity date, the Company tendered 37.9 million shares of TW Common to fully settle its obligations in connection with its unsecured 7% ACES having a value of $2.9 billion. (c) ZENS. On September 21, 1999, the Company issued approximately 17.2 million of its 2.0% Zero-Premium Exchangeable Subordinated Notes due 2029 (ZENS) having an original principal amount of $1.0 billion. The original principal amount per ZENS will increase each quarter to the extent that the sum of the quarterly cash dividends and the interest paid during a quarter on the reference shares attributable to one ZENS is less than $.045, so that the annual yield to investors from the date the Company issued the ZENS to the date of computation of the contingent principal amount is not less than 2.309%. At maturity the holders of the ZENS will receive in cash the higher of the original principal amount of the ZENS (subject to adjustment as discussed above) or an amount based on the then-current market value of TW Common, or other securities distributed with respect to TW Common (one share of TW Common and such other securities, if any, are referred to as reference shares). Each ZENS has an original principal amount of $58.25 (the closing market price of the TW Common on September 15, 1999) and is exchangeable at any time at the option of the holder for cash equal to 95% (100% in some cases) of the market value of the reference shares attributable to one ZENS. The Company pays interest on each ZENS at an annual rate of 2% plus the amount of any quarterly cash dividends paid in respect of the quarterly interest period on the reference shares attributable to each ZENS. Subject to some conditions, the Company has the right to defer interest payments from time to time on the ZENS for up to 20 consecutive quarterly periods. As of December 31, 2000, no interest payments on the ZENS had been deferred. On January 11, 2001, TW and America Online, Inc. combined to form AOL Time Warner Inc. (AOL TW). As a result of the combination each share of TW Common was converted into 1.5 shares of AOL TW Common Stock (AOL TW Common) and the Company now holds 25.8 million shares of AOL TW Common. As a result of the combination, the reference shares attributable to one ZENS is 1.5 shares of AOL TW Common. The Company used $537 million of the net proceeds from the offering of the ZENS to purchase 9.2 million shares of TW Common, which are classified as trading securities under SFAS No. 115. Unrealized gains and losses resulting from changes in the market value of the TW Common are recorded in the Company's Statements of Consolidated Operations. Prior to January 1, 2001, an increase above $58.25 (subject to some adjustments) in the market value per share of TW Common resulted in an increase in the Company's liability for the ZENS. However, as the market value per share of TW Common declined below $58.25 (subject to some adjustments), the liability for the ZENS did not decline below the original principal amount. As of December 31, 1999 and 2000, the market value of TW Common was $72.31 and $52.24, respectively. Therefore, during 2000, the Company recorded a pre-tax net unrealized loss on its investment in TW Common and its obligation on its indexed debt securities of $103 million. Prior to the purchase of additional shares of TW Common on September 21, 1999, the Company owned approximately 8 million shares of TW Common that were in excess of the 38 million shares needed to economically hedge its ACES obligation. For the period from July 6, 1999 to the ZENS issuance date, losses (due to the decline in the market value of the TW Common during such period) on these 8 million shares were $122 million ($79 million after-tax). The 8 million shares of TW Common combined with the additional 9.2 million shares purchased are expected to be held to facilitate the Company's ability to meet its obligation under the ZENS. 29 The following table sets forth summarized financial information regarding the Company's investment in TW securities and the Company's ACES and ZENS obligations.
TW INVESTMENT ACES ZENS ------------- ------- ------ (IN MILLIONS) Balance at December 31, 1997......................... $ 990 $ 1,174 Loss on indexed debt securities...................... -- 1,176 ------- ------- Balance at December 31, 1998......................... 990 2,350 Issuance of indexed debt securities.................. -- -- $1,000 Purchase of TW Common................................ 537 -- -- Loss on indexed debt securities...................... -- 388 241 Gain on TW Common.................................... 2,452 -- -- ------- ------- ------ Balance at December 31, 1999......................... 3,979 2,738 1,241 ------- ------- ------ Loss (Gain) on indexed debt securities............... -- 139 (241) Loss on TW Common.................................... (205) -- -- Settlement of ACES................................... (2,877) (2,877) -- ------- ------- ------ Balance at December 31, 2000......................... $ 897 $ -- $1,000 ======= ======= ======
Upon adoption of SFAS No. 133 effective January 1, 2001, the ZENS obligation is bifurcated into a debt component and a derivative component (the holder's option to receive the appreciated value of AOL TW Common at maturity). The derivative component is valued at fair value and determines the initial carrying value assigned to the debt component ($121 million) as the difference between the original principal amount of the ZENS ($1.0 billion) and the fair value of the derivative component at issuance ($879 million). Effective January 1, 2001 the debt component is recorded at its accreted amount of $122 million and the derivative component is recorded at its current fair value of $788 million, as a current liability, resulting in a transition adjustment pre-tax gain of $90 million. The transition adjustment gain will be reported in the first quarter of 2001 as the effect of a change in accounting principle. Subsequently, the debt component will accrete through interest charges at 17.5% up to the minimum amount payable upon maturity of the ZENS in 2029, approximately $1.1 billion, and changes in the fair value of the derivative component will be recorded in the Company's Statements of Consolidated Operations. Changes in the fair value of the AOL TW Common held by the Company should substantially offset changes in the fair values of the derivative component of the ZENS. o (14) COMMITMENTS AND CONTINGENCIES (a) Capital and Environmental Commitments. The Company has various commitments for capital and environmental expenditures. The Wholesale Energy segment has entered into commitments associated with various non-rate regulated electric generating projects, including commitments for the purchase of combustion turbines aggregating $436 million. In addition, the Wholesale Energy segment has options to purchase additional generating equipment for a total estimated cost of $544 million for future generating projects. The Company anticipates investing up to $711 million in capital and other special project expenditures between 2001 and 2005 for environmental compliance. The Company anticipates expenditures to be as follows (in millions): 2001........................................................ $217 2002........................................................ 259 2003........................................................ 80 2004........................................................ 76 2005........................................................ 79 ---- Total............................................. $711 ====
30 (b) Fuel and Purchased Power. Reliant Energy HL&P is a party to several long-term coal, lignite and natural gas contracts, which have various quantity requirements and durations. Minimum payment obligations for coal and transportation agreements that extend through 2011 are approximately $280 million in 2001, $281 million in 2002 and $274 million in 2003. Purchase commitments related to lignite mining and lease agreements, natural gas purchases and storage contracts, and purchased power are not material to the operations of the Company. Currently, Reliant Energy HL&P is allowed recovery of these costs through base rates for electric service. As of December 31, 2000, some of these contracts are above market. The Company anticipates that stranded costs associated with these obligations will be recoverable through the stranded costs recovery mechanisms contained in the Legislation. For information regarding the Legislation, see Note 4(a). REMA is a party to several long-term fuel supply contracts which have various quantity requirements and durations. Minimum payment obligations under these agreements that extend through 2004 are as follows as of December 31, 2000 (in millions): 2001........................................................ $ 85 2002........................................................ 66 2003........................................................ 29 2004........................................................ 14 ---- Total............................................. $194 ====
The Company's other long-term fuel supply commitments which have various quantity requirements and durations are not considered material either individually or in the aggregate to the Company's results of operations or cash flows. (c) Lease Commitments. In August 2000, the Company entered into separate sale/leaseback transactions with each of 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. As lessee, the Company leases an interest in each facility from each owner-lessor under a facility lease agreement. The equity interests in all the subsidiaries of REMA are pledged as collateral for REMA's lease obligations. In addition, the subsidiaries have guaranteed the lease obligations. The lease documents contain some restrictive covenants that restrict REMA's ability to, among other things, make dividend distributions unless REMA satisfies various conditions. The covenant restricting dividends would be suspended if the direct or indirect parent of REMA, meeting specified criteria, guarantees the lease obligations. The Company will make lease payments through 2029. The lease terms expire in 2034. The following table sets forth information concerning the Company's obligations under non-cancelable long-term operating leases at December 31, 2000, which primarily relate to the REMA leases mentioned above. Other non-cancelable long-term operating leases principally consist of rental agreements for building space, data processing equipment and vehicles, including major work equipment.
REMA SALE-LEASE OBLIGATION OTHER TOTAL ---------- ----- ------ (IN MILLIONS) 2001....................................................... $ 259 $ 16 $ 275 2002....................................................... 137 10 147 2003....................................................... 77 8 85 2004....................................................... 84 6 90 2005....................................................... 75 6 81 2006 and beyond............................................ 1,188 36 1,224 ------ ---- ------ Total............................................ $1,820 $ 82 $1,902 ====== ==== ======
31 Total lease expense for all operating leases was $10 million, $13 million and $46 million during 1998, 1999 and 2000, respectively. (d) Cross Border Leases. During the period from 1994 through 1997, under cross border lease transactions, UNA leased several of its power plants and related equipment and turbines to non-Netherlands based investors (the head leases) and concurrently leased the facilities back under sublease arrangements with remaining terms as of December 31, 2000, of 1 to 24 years. UNA utilized proceeds from the head lease transactions to prepay its sublease obligations and to provide a source for payment of end of term purchase options and other financial undertakings. The initial sublease obligations totaled $2.4 billion of which $1.7 billion remained outstanding as of December 31, 2000. These transactions involve UNA providing to a foreign investor an ownership right in (but not necessarily title to) an asset, with a leaseback of that asset. The net proceeds to UNA of the transactions were recorded as a deferred gain and are currently being amortized to income over the lease terms. At December 31, 1999 and 2000, the unamortized deferred gain on these transactions totaled $87 million and $77 million, respectively. The power plants, related equipment and turbines remain on the financial statements of UNA and continue to be depreciated. UNA is required to maintain minimum insurance coverages, perform minimum annual maintenance and, in specified situations, post letters of credit. UNA's shareholder is subject to some restrictions with respect to the liquidation of UNA's shares. In the case of early termination of these contracts, UNA would be contingently liable for some payments to the sublessors, which at December 31, 2000, are estimated to be $274 million. Starting in March 2000, UNA was required by some of the lease agreements to obtain standby letters of credit in favor of the sublessors in the event of early termination. The amount of the required letters of credit was $274 million as of December 31, 2000. Commitments for these letters of credit have been obtained as of December 31, 2000. (e) Naming Rights to Houston Sports Complex. In October 2000, the Company acquired the naming rights for the new football stadium for the Houston Texans, the National Football League's newest franchise. In addition, the naming rights cover the entertainment and convention facilities included in the stadium complex. The agreement extends for 32 years. In addition to naming rights, the agreement provides the Company with significant sponsorship rights. The aggregate cost of the naming rights will be approximately $300 million. During the fourth quarter of 2000, the Company incurred an obligation to pay $12 million in order to secure the long-term commitment and for the initial advertising of which $10 million was expensed in the Company's Statement of Consolidated Operations in 2000. Starting in 2002, when the new stadium is operational, the Company will pay $10 million each year through 2032 for annual advertising under this agreement. (f) Transportation Agreement. A subsidiary of RERC Corp. had an agreement (ANR Agreement) with ANR Pipeline Company (ANR) that contemplated that this subsidiary would transfer to ANR an interest in some of RERC Corp.'s pipeline and related assets. As of December 31, 1999 and 2000, the Company had recorded $41 million in other long-term liabilities in the Company's Consolidated Balance Sheets to reflect the Company's obligation to ANR for the use of 130 Mmcf/day of capacity in some of the Company's transportation facilities. The level of transportation will decline to 100 Mmcf/day in the year 2003 with a refund of $5 million to ANR. The ANR Agreement will terminate in 2005 with a refund of $36 million. (g) Legal, Environmental and Other Regulatory Matters. LEGAL MATTERS. Reliant Energy HL&P Municipal Franchise Fee Lawsuits. In February 1996, the cities of Wharton, Galveston and Pasadena filed suit, for themselves and a proposed class of all similarly situated cities in Reliant Energy HL&P's service area, against Reliant Energy and Houston Industries Finance, Inc. (formerly a wholly 32 owned subsidiary of Reliant Energy) alleging underpayment of municipal franchise fees. Plaintiffs claim that they are entitled to 4% of all receipts of any kind for business conducted within these cities over the previous four decades. Because the franchise ordinances at issue affecting Reliant Energy HL&P expressly impose fees only on its own receipts and only from sales of electricity for consumption within a city, the Company regards all of plaintiffs' allegations as spurious and is vigorously contesting the case. The plaintiffs' pleadings asserted that their damages exceeded $250 million. The 269th Judicial District Court for Harris County granted partial summary judgment in favor of Reliant Energy dismissing all claims for franchise fees based on sales tax collections. Other motions for partial summary judgment were denied. A six-week jury trial of the original claimant cities (but not the class of cities) ended on April 4, 2000 (three cities case). Although the jury found for Reliant Energy on many issues, they found in favor of the original claimant cities on three issues, and assessed a total of $4 million in actual and $30 million in punitive damages. However, the jury also found in favor of Reliant Energy on the affirmative defense of laches, a defense similar to a statute of limitations defense, due to the original claimant cities having unreasonably delayed bringing their claims during the 43 years since the alleged wrongs began. The trial court in the three cities case granted most of Reliant Energy's motions to disregard the jury's findings. The trial court's rulings reduced the judgment to $1.7 million, including interest, plus an award of $13.7 million in legal fees. In addition, the trial court granted Reliant Energy's motion to decertify the class and vacated its prior orders certifying a class. Following this ruling, 45 cities filed individual suits against Reliant Energy in the District Court of Harris County. The extent to which issues in the three cities case may affect the claims of the other cities served by Reliant Energy HL&P cannot be assessed until judgments are final and no longer subject to appeal. However, the trial court's rulings disregarding most of the jury's findings are consistent with Texas Supreme Court opinions over the past decade. The Company estimates the range of possible outcomes for the plaintiffs to be between zero and $17 million inclusive of interest and attorneys' fees. The three cities case has been appealed. The Company believes that the $1.7 million damage award resulted from serious errors of law and that it will be set aside by the Texas appellate courts. In addition, the Company believes that because of an agreement between the parties limiting fees to a percentage of the damages, reversal of the award of $13.7 million in attorneys' fees in the three cities case is probable. California Wholesale Market. Reliant Energy and Reliant Energy Services, Inc. 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. RERC Corp. has also been named as a defendant on one of the lawsuits. Pursuant to the terms of the master separation agreement between Reliant Energy and Reliant Resources (see Note 4(b)), Reliant Resources will agree to indemnify RERC Corp. for any damages arising under this lawsuit, and will agree to indemnify Reliant Energy for damages arising under any of these lawsuits, and may elect to defend these lawsuits at Reliant Resources' own expense. 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. 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 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 during all or portions of 2000, costs of suit and attorneys' fees. In one of the cases the plaintiffs allege aggregate damages of over $4 billion. Defendants have filed petitions to remove the cases to federal court. Furthermore, defendants have filed a motion with the Panel on Multidistrict Litigation seeking transfer and consolidation of all the cases. These lawsuits have only recently been filed. Therefore, the ultimate outcome of the lawsuits cannot be predicted with any degree of certainty at this time. However, the Company does not believe, based on its analysis to date of the claims asserted in these lawsuits and the underlying facts, that resolution of these lawsuits will have a material adverse effect on the Company's financial condition, results of operations or cash flows. 33 ENVIRONMENTAL MATTERS. Manufactured Gas Plant Sites. RERC Corp. and its subsidiaries (RERC) and its predecessors operated a manufactured gas plant (MGP) adjacent to the Mississippi River in Minnesota, formerly known as Minneapolis Gas Works (MGW) until 1960. RERC has substantially completed remediation of the main site other than ongoing water monitoring and treatment. The manufactured gas was stored in separate holders. RERC is negotiating clean-up of one such holder. There are six other former MGP sites in the Minnesota service territory. Remediation has been completed on one site. Of the remaining five sites, RERC believes that two were neither owned nor operated by RERC. RERC believes it has no liability with respect to the sites it neither owned nor operated. At December 31, 1999 and 2000, RERC had accrued $19 million and $17 million, respectively, for remediation of the Minnesota sites. At December 31, 2000, the estimated range of possible remediation costs was $8 million to $36 million. The cost estimates of the MGW site are based on studies of that site. The remediation costs for the other sites are based on industry average costs for remediation of sites of similar size. The actual remediation costs will be dependent upon the number of sites remediated, the participation of other potentially responsible parties, if any, and the remediation methods used. Other Minnesota Matters. At December 31, 1999 and 2000, RERC had recorded accruals of $1 million and $2 million, respectively (with a maximum estimated exposure of approximately $13 million and $17 million at December 31, 1999 and 2000, respectively), for other environmental matters in Minnesota for which remediation may be required. Issues relating to the identification and remediation of MGPs are common in the natural gas distribution industry. The Company has received notices from the United States Environmental Protection Agency and others regarding its status as a potentially responsible party (PRP) for other sites. Based on current information, the Company has not been able to quantify a range of environmental expenditures for potential remediation expenditures with respect to other MGP sites. Mercury Contamination. The Company's pipeline and distribution operations have in the past employed elemental mercury in measuring and regulating equipment. It is possible that small amounts of mercury may have been spilled in the course of normal maintenance and replacement operations and that these spills may have contaminated the immediate area with elemental mercury. This type of contamination has been found by the Company at some sites in the past, and the Company has conducted remediation at sites found to be contaminated. Although the Company is not aware of additional specific sites, it is possible that other contaminated sites may exist and that remediation costs may be incurred for these sites. Although the total amount of these costs cannot be known at this time, based on experience by the Company and that of others in the natural gas industry to date and on the current regulations regarding remediation of these sites, the Company believes that the costs of any remediation of these sites will not be material to the Company's financial position, results of operations or cash flows. REMA Ash Disposal Site Closures and Site Contaminations. Under the agreement to acquire REMA (see Note 3(a)), 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 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 December 31, 2000, REMA has liabilities associated with six ash disposal site closures and six site investigations and environmental remediations. The Company has recorded its estimate of these environmental liabilities in the amount of $36 million as of December 31, 2000. The Company expects approximately $13 million will be paid over the next five years. UNA Asbestos Abatement and Soil Remediation. Prior to the Company's acquisition of UNA (see Note 3(b)), UNA had a $25 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 UNA's properties. UNA 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 34 agreements with municipalities in which the contaminated properties are located. All remediation efforts are to be fully completed by 2005. As of December 31, 2000, the estimated undiscounted liability for this asbestos abatement and soil remediation was $24 million. Other. From time to time the Company has received notices from regulatory authorities or others regarding its status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. In addition, the Company has been named as a defendant in litigation related to such sites and in recent years has been named, along with numerous others, as a defendant in several lawsuits filed by a large number of individuals who claim injury due to exposure to asbestos while working at sites along the Texas Gulf Coast. Most of these claimants have been workers who participated in construction of various industrial facilities, including power plants, and some of the claimants have worked at locations owned by the Company. The Company anticipates that additional claims like those received may be asserted in the future and intends to continue vigorously contesting claims which it does not consider to have merit. Although their ultimate outcome cannot be predicted at this time, the Company does not believe, based on its experience to date, that these matters, either individually or in the aggregate, will have a material adverse effect on the Company's financial position, results of operations or cash flows. OTHER MATTERS. The Company is involved in other legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. Some of these proceedings 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. The Company's management believes that the disposition of these matters will not have a material adverse effect on the Company's financial condition, results of operations or cash flows. (h) California Wholesale Market Uncertainty. During the summer and fall of 2000, 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, decreases in net electric imports, structural market flaws including over-reliance on the electric spot market, and limitations on supply as a result of maintenance and other outages. Although wholesale prices increased, California's deregulation legislation kept retail rates frozen below 1996 levels. This caused two of California's public utilities, which are the Company's customers based on its deliveries to the Cal PX and the Cal ISO, to amass billions of dollars of uncollected wholesale power costs and to ultimately default in January and February 2001 on payments owed for wholesale power purchased through the Cal PX and from the Cal ISO. As of December 31, 2000, the Company was owed $101 million by the Cal PX and $181 million by the Cal ISO. In the fourth quarter of 2000, the Company recorded a pre-tax provision of $39 million against receivable balances related to energy sales in the California market. From January 1, 2001 through February 28, 2001, the Company has collected $105 million of these receivable balances. As of March 1, 2001, the Company was owed a total of $358 million by the Cal ISO, the Cal PX, the California Department of Water Resources (CDWR) and California Energy Resource Scheduling, for energy sales in the California wholesale market from the fourth quarter of 2000 through February 28, 2001. Management will continue to assess the collectibility of these receivables based on further developments affecting the California electricity market and the market participants described herein. Additional provisions to the allowance may be warranted in the future. In response to the filing of a number of complaints challenging the level of wholesale prices, the FERC initiated a staff investigation and issued an order on December 15, 2000 implementing a series of wholesale market reforms, including an interim price review procedure for prices above a $150/MWh "breakpoint" on sales to the Cal ISO and through the Cal PX. The order does not prohibit sales above the "breakpoint," but the seller is subject to weekly reporting and monitoring requirements. For each reported transaction, potential refund liability extends for a period of 60 days following the date any such transaction is reported to the FERC. On March 9, 2001, the FERC issued a further order establishing a proxy market 35 clearing price of $273/MWh for January 2001, and on March 16, 2001 the FERC issued a further order adjusting the proxy market clearing price to $430/MWh for February 2001. New market monitoring and mitigation measures to replace the $150/MWh breakpoint and reporting obligation are being developed by the FERC to take effect on May 1, 2001. In the FERC's March 9 and March 16 orders, the FERC outlined criteria for determining amounts subject to possible refund based on the proxy market clearing price for January and February 2001 and indicated that approximately $12 million of the $125 million charged by the Company in January 2001 in California to the Cal ISO and the Cal PX and approximately $7 million of the $47 million charged by the Company in February 2001 in California to the Cal ISO and the Cal PX were subject to possible refunds. In the March 9 and March 16 orders, the FERC set forth procedures for challenging possible refund obligations. Because the Company believes that there is cost or other justification for prices charged above the proxy market clearing prices established in the March 9 and March 16 orders, the Company intends to pursue such a challenge with respect to the Company's potential refund amounts identified in such orders. Any refunds the Company may ultimately be obligated to pay are to be credited against unpaid amounts owed to the Company for its sales in the Cal PX or to the Cal ISO. The December 15 order established that a refund condition would be in place for the period beginning October 2, 2000 through December 31, 2002. The December 15 order also eliminated the requirement that California's public utilities sell all of their generation into and purchase all of their power from the Cal PX and directed that the Cal PX wholesale tariffs be terminated effective April 2001. The Cal PX has since suspended its day-ahead and day-of markets and filed for bankruptcy protection on March 9, 2001. Motions for rehearing have been filed on a number of issues related to the December 15 order and such motions are still pending before the FERC. 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 Public Utilities Commission, the California Electricity Oversight Board, the California Bureau of State Audits and the California Office of the Attorney General all have separate ongoing investigations into the high prices and their causes. None of these investigations have been completed and no findings have been made in connection with any of them. Despite the market restructuring ordered under the December 15 order, the California public utilities have continued to accrue unrecovered wholesale costs. As a result, the credit ratings of two of these public utilities were severely downgraded to below investment grade in January 2001. As their credit lines became unavailable, the two utilities defaulted on payments due to the Cal PX and the Cal ISO, which operate financially as pass-through entities, coordinating payments from buyers and sellers of electricity. As a result, the Cal PX and Cal ISO were not able to pay final invoices to market participants totaling over $1 billion. The default of two of California's public utilities on amounts owed the Cal PX and the Cal ISO for purchased power has further exacerbated the current crisis in the California wholesale markets and resulted in substantial uncollected receivables owed to the Company by the Cal ISO and the Cal PX. The Cal PX's efforts to recover the available collateral of the utilities, in the form of block forward contracts, have been frustrated by the emergency acts of California's Governor, who seized control of the contracts upon the expiration of temporary restraining orders prohibiting such action. Although obligated to pay reasonable value for the contracts, the state of California has not yet made any payment for the contracts. Various actions have been filed challenging the Governor's ability to seize these contracts. Upon the default of the two utilities of amounts due to the Cal PX, the Cal PX issued "charge-backs" allocating the utilities' defaults to the other market participants. Proceedings were brought both in federal court and at the FERC seeking a suspension of the charge-backs and challenging the reasonableness of the Cal PX's actions. The Cal PX has since agreed to a preliminary injunction suspending any of its charge-back activities in order to allow the FERC to address the charge-back issues. Amounts owed to the Company were debited in invoices by the Cal PX for charge-backs in the amount of $29 million and, on February 14, 2001, the Company filed its own lawsuit against the Cal PX in the United States District Court for the Central District of California, seeking a recovery of those amounts and a stay of any further charge-backs by the Cal 36 PX. The filing of bankruptcy by the Cal PX will automatically stay for some period the various court and administrative cases against the Cal PX. The two defaulting utilities have both filed lawsuits challenging the refusal of state regulators to allow wholesale power costs to be passed through to retail customers under the "filed rate doctrine". The filed rate doctrine provides that wholesale power costs approved by the FERC are entitled to be recovered through rates. Additionally, to address the failing financial condition of the two defaulting utilities and the utilities' potential bankruptcy, the California Legislature passed emergency legislation, effective January 18, 2001 and February 2, 2001, appropriating funds to be used by the CDWR for the purchase of wholesale electricity on behalf of the utilities and authorizing the sale of bonds to fund future purchases under long-term power contracts with wholesale generators. The CDWR began the process of soliciting bids from generators for long-term contracts and continued the purchasing of short-term power contracts. No bonds have yet been issued by the CDWR to support long-term power purchases or to provide credit support for short-term purchases. As noted above two of California's public utilities have defaulted in their payment obligations to the Cal PX and the Cal ISO as a result of the refusal of state regulators to allow them to recover their wholesale power costs. This refusal by state regulators has also caused the utilities to default on numerous other financial obligations, which could result in either the voluntary or involuntary bankruptcy of the utilities. While a bankruptcy filing would result in further post-petition purchases of wholesale electricity being considered administrative expenses of the debtor, a substantial delay could be experienced in the payment of pre-petition receivables pending the confirmation of a reorganization plan. The California Legislature is currently considering legislation under which a state entity would be formed to purchase and operate a substantial share of the transmission lines in California in an effort to provide cash to the utilities and thereby avoid potential bankruptcy filings by the utilities. A number of the creditors for the two California public utilities have indicated, however, that unless California moves quickly with such a plan, an involuntary bankruptcy filing may be made by one or more of such creditors. Because California's power reserves remain at low levels, in part as a result of the lack of creditworthy buyers of power given the defaults of the California utilities, the Cal ISO has relied on emergency dispatch orders requiring generators to provide at the Cal ISO's direction all power not already under contract. The power supplied to the Cal ISO has been used to meet the needs of the customers of the utilities, even though two of those utilities do not have the credit required to receive such power and may be unable to pay for it. The Company has contested the obligation to provide power under these circumstances. The Cal ISO sought a temporary restraining order compelling the Company to continue to comply with the emergency dispatch orders despite the utilities' defaults. Although the payment issue is still disputed, on February 21, 2001, the Company and the CDWR entered into a contract expiring March 23, 2001 for the purchase of all of the Company's available capacity not already under contract and the litigation has been temporarily stayed. The CDWR is current in its payments under this contract, but the Company is still owed $108 million for power provided in compliance with the emergency dispatch orders for the six weeks prior to the agreement. Depending on the outcome of the court proceedings initiated by the Cal ISO seeking to enjoin us from ceasing power deliveries to the Cal ISO, the Company may be forced to continue selling power without the guarantee of payment. Additionally, the Company is seeking a prompt FERC determination that the Cal ISO is not complying with the credit provisions of its tariff and a related order of the FERC issued on February 14, 2001, requiring the Cal ISO not to make purchases in the real time market unless a creditworthy purchaser is responsible for such purchases. (i) Indemnification of Stranded Costs. The stranded costs in the Dutch electricity market are considered to be the liabilities, uneconomical contractual commitments, and other costs associated with obligations entered into by the coordinating body for the Dutch electricity generating sector, N.V. Samenwerkende elecktriciteits-produktiebedrijven (SEP), plus some district heating contracts with some municipalities in Holland. As of December 29, 2000, SEP changed its name to BV Nederlands Elektriciteit Administratiekantoor. 37 SEP was incorporated as the coordinating body for four of the large-scale Dutch electricity generation companies, including UNA, which currently has an equity interest in SEP of 25%. Among other things, SEP prior to 2001 owned and managed the dispatch for the national transmission grid, coordinated the fuel supply, managed the import and the export of electricity, and settled production costs for the electricity generation companies. Under the Cooperation Agreement (OvS Agreement), UNA and the other Dutch generators agreed to sell their generating output through SEP. Over the years, SEP incurred stranded costs as a result of a perceived need to cover anticipated shortages in energy production supply. SEP stranded costs consist primarily of investments in alternative energy sources and fuel and power purchase contracts currently estimated to be uneconomical. In December 2000, the Dutch parliament adopted legislation, The Electricity Production Sector Transitional Arrangements Act (Transition Act), allocating to the Dutch generation sector, including UNA, financial responsibility for various stranded costs contracts and other liabilities of SEP. The Transition Act also authorizes the government to purchase from SEP at least a majority of the shares in the Dutch national transmission grid company. The legislation became effective in all material respects on January 1, 2001. The Transition Act allocates financial responsibility to the individual Dutch generators based on their average share in the costs and revenues under the OvS Agreement during the past ten years. UNA's allocated share of these costs has been set at 22.5%. In particular, the Transition Act allocates to the four Dutch generation companies, including UNA, financial responsibility for SEP's obligations to purchase electricity and gas under an import gas supply contract and three electricity import contracts. The gas import contract expires in 2015 and provides for gas imports aggregating 2.283 billion cubic meters per year. The three electricity contracts have the following capacities and terms: (a) 300 MW through 2005, (b) 600 MW through 2005 and (c) 600 MW through 2002 and 750 MW through 2009. The generators have the option of assuming their pro rata interests in the contracts or, subject to the assignment terms of the contracts, selling their interests to third parties. The Transition Act provides that, subject to the approval of the European Commission, the Dutch government will make financial compensations to the Dutch generation sector for the out of market costs associated with two stranded cost items: an experimental coal facility and district heating contracts. The four Dutch generation companies and SEP are in discussions with the Dutch Ministry of Economic Affairs regarding the implementation of the Transition Act. The parties have reached an agreement in principle with the Dutch Ministry of Economic Affairs regarding the compensation to be paid to SEP for the national transmission grid company. The proposed compensation amount is NLG 2.55 billion (approximately $1.1 billion based on an exchange rate of 2.34 NLG per U.S. dollar as of December 31, 2000). Although the Transition Act clarifies many issues regarding the anticipated resolution of the stranded costs debate in the Netherlands, there remain considerable uncertainties regarding the exact manner in which the Transition Act will be implemented and the potential for third parties to challenge the Transition Act on legal and constitutional grounds. In connection with the acquisition of UNA, the selling shareholders of UNA agreed to indemnify UNA for some stranded costs in an amount not to exceed NLG 1.4 billion (approximately $599 million based on an exchange rate of 2.34 NLG per U.S. dollar as of December 31, 2000), which may be increased in some circumstances at the option of the Company up to NLG 1.9 billion (approximately $812 million). Of the total consideration paid by the Company for the shares of UNA, NLG 900 million (approximately $385 million) has been placed by the selling shareholders in an escrow account under the direction of the Dutch Ministry of Economic Affairs to secure the indemnity obligations. Although the Company's management believes that the indemnity provision will be sufficient to fully satisfy UNA's ultimate share of any stranded costs obligation, this judgment is based on numerous assumptions regarding the ultimate outcome and timing of the resolution of the stranded cost issue, the former shareholders' timely performance of their obligations under the indemnity arrangement, and the amount of stranded costs which at present is not determinable. 38 (j) Operations Agreement with City of San Antonio. As part of the 1996 settlement of certain litigation claims asserted by the City of San Antonio with respect to the South Texas Project, the Company entered into a 10-year joint operations agreement under which the Company and the City of San Antonio, acting through the City Public Service Board of San Antonio (CPS), share savings resulting from the joint dispatching of their respective generating assets in order to take advantage of each system's lower cost resources. In January 2000, the contract term was extended for three years and is expected to terminate in 2009. Under the terms of the joint operations agreement entered into between CPS and Electric Operations, the Company has guaranteed CPS minimum annual savings of $10 million up to a total cumulative savings of $150 million over the term of the agreement. It is anticipated that the cumulative obligation will be met in the first quarter of 2001. In 1998, 1999 and 2000, savings generated for CPS' account were $14 million, $14 million and $60 million, respectively. Through December 31, 2000, cumulative savings generated for CPS' account were $124 million. (k) Nuclear Insurance. The Company and the other owners of the South Texas Project maintain nuclear property and nuclear liability insurance coverage as required by law and periodically review available limits and coverage for additional protection. The owners of the South Texas Project currently maintain $2.75 billion in property damage insurance coverage, which is above the legally required minimum, but is less than the total amount of insurance currently available for such losses. Pursuant to the Price Anderson Act, the maximum liability to the public of owners of nuclear power plants was $9.3 billion as of December 31, 2000. Owners are required under the Price Anderson Act to insure their liability for nuclear incidents and protective evacuations. The Company and the other owners of the South Texas Project currently maintain the required nuclear liability insurance and participate in the industry retrospective rating plan. There can be no assurance that all potential losses or liabilities will be insurable, or that the amount of insurance will be sufficient to cover them. Any substantial losses not covered by insurance would have a material effect on the Company's financial condition, results of operations and cash flows. (l) Nuclear Decommissioning. The Company contributes $14.8 million per year to a trust established to fund its share of the decommissioning costs for the South Texas Project. For a discussion of the accounting treatment for the securities held in the Company's nuclear decommissioning trust, see Note 2(l). In July 1999, an outside consultant estimated the Company's portion of decommissioning costs to be approximately $363 million. While the current and projected funding levels currently exceed minimum NRC requirements, no assurance can be given that the amounts held in trust will be adequate to cover the actual decommissioning costs of the South Texas Project. Such costs may vary because of changes in the assumed date of decommissioning and changes in regulatory requirements, technology and costs of labor, materials and equipment. Pursuant to the Legislation, costs associated with nuclear decommissioning that have not been recovered as of January 1, 2002, will continue to be subject to cost-of-service rate regulation and will be included in a non-bypassable charge to transmission and distribution customers. For information regarding the effect of the Business Separation Plan on funding of the nuclear decommissioning trust fund, see Note 4(b). o (20) SUBSEQUENT EVENTS (a) Credit Facilities. Between December 2000 and March 2001, Reliant Resources entered into eleven bilateral credit facilities with financial institutions, which provide for an aggregate of $1.6 billion in committed credit. The facilities became effective subsequent to December 31, 2000 and expire on October 2, 2001. Concurrent with the effectiveness of these facilities, $500 million of the facilities of a financing subsidiary were canceled. Interest rates on the borrowings are based on LIBOR plus a margin, a base rate or a rate determined through a bidding 39 process. These facilities contain various business and financial covenants requiring Reliant Resources to, among other things, maintain a ratio of net debt to the sum of net debt, subordinated affiliate debt and shareholders' equity not to exceed 0.60 to 1.00. These covenants are not anticipated to materially restrict Reliant Resources from borrowing funds or obtaining letters of credit under these facilities. The credit facilities are subject to commitment and usage fees that are calculated based on the amount of the facility and/or the amounts outstanding under the facilities, respectively. (b) RERC Corp. Debt Issuance. In February 2001, RERC Corp. issued $550 million of unsecured notes that bear interest at 7.75% per year and mature in February 2011. Net proceeds to RERC Corp. were $545 million. RERC Corp. used the net proceeds from the sale of the notes to pay a $400 million dividend to Reliant Energy, and for general corporate purposes. Reliant Energy used the $400 million proceeds from the dividend for general corporate purposes, including the repayment of short-term borrowings. (c) Florida Tolling Arrangement. In the first quarter 2001, the Company entered into tolling arrangements with a third party to purchase the right to utilize and dispatch electric generating capacity of approximately 1,100 MW. This electricity is expected to be generated by two gas-fired, simple-cycle peaking plants, with fuel oil backup, to be constructed by the tolling partner in Florida, which are anticipated to be completed by the summer of 2002, at which time the Company will commence tolling payments. 40 EX-99.B 4 h92033ex99-b.txt ITEMS FROM RELIANT ENERGY MARCH 31, 2001 10-Q EXHIBIT 99(b).REI ITEMS INCORPORATED BY REFERENCE FROM RELIANT ENERGY MARCH 31, 2001 FORM 10-Q (2) DERIVATIVE FINANCIAL INSTRUMENTS Effective January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended (SFAS No. 133), which establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. This statement requires that derivatives be recognized at fair value in the balance sheet and that changes in fair value be recognized either currently in earnings or deferred as a component of other comprehensive income, depending on the intended use of the derivative, its resulting designation and its effectiveness. If certain conditions are met, an entity may designate a derivative instrument as hedging (a) the exposure to changes in the fair value of an asset or liability (Fair Value Hedge), (b) the exposure to variability in expected future cash flows (Cash Flow Hedge) or (c) the foreign currency exposure of a net investment in a foreign operation. For a derivative not designated as a hedging instrument, the gain or loss is recognized in earnings in the period it occurs. Adoption of SFAS No. 133 on January 1, 2001 resulted in an after-tax increase in net income of $61 million and a cumulative after-tax increase in accumulated other comprehensive loss of $252 million. The adoption also increased current assets, long-term assets, current liabilities and long-term liabilities by $703 million, $252 million, $805 million and $340 million, respectively, in the Company's Consolidated Balance Sheet. The Company also 41 reclassified $788 million related to the Company's Zero-Premium Exchangeable Subordinated Notes (ZENS) due to the adoption from the current portion of long-term debt to indexed debt securities derivative. During the three months ended March 31, 2001, less than $1 million of the initial transition adjustment recognized in other comprehensive income was realized in net income. The application of SFAS No. 133 is still evolving and further guidance from the Financial Accounting Standards Board (FASB) is expected. The FASB released tentative guidance in April 2001 on three issues that impact our industry. The FASB concluded in its tentative guidance that contracts subject to "bookouts," a scheduling convenience used when two utilities have offsetting transactions, cannot qualify for the normal purchases and sales exception. The FASB also released tentative guidance that will prohibit option contracts on electricity to qualify for the normal purchases and normal sales exception. Lastly, the FASB issued tentative guidance that forward contracts containing optionality features which modify the quantity delivered cannot qualify for the normal purchases and sales exception. The tentative guidance issued by the FASB is subject to a comment period which ends on June 1, 2001. If the tentative guidance is unchanged, the Company is required to adopt this guidance as of July 1, 2001. The Company is in the process of determining the effect of adoption. The Company is exposed to various market risks. These risks are inherent in the Company's financial statements and arise from transactions entered into in the normal course of business. The Company utilizes derivative financial instruments to mitigate the impact of changes in electricity, natural gas and fuel prices on its operating results and cash flows. The Company utilizes cross-currency swaps and options to hedge its net investments in foreign subsidiaries, interest rate swaps to mitigate the impact of changes in interest rates and other financial instruments to manage various other market risks. Trading and marketing operations often involve market risks associated with managing energy commodities and establishing open positions in the energy markets, primarily on a short-term basis. These risks fall into three different categories: price and volume volatility, credit risk of trading counterparties and adequacy of the control environment for trading. The Company routinely enters into futures, forward contracts, swaps and options to hedge purchase and sale commitments, fuel requirements and inventories of natural gas, coal, electricity, oil, emission allowances, weather derivatives and other commodities and to minimize the risk of market fluctuations in its trading, marketing, power origination and risk management operations. (a) Energy Trading, Marketing and Price Risk Management Activities. The Company offers energy price risk management services primarily related to natural gas, electric power and other energy related commodities. The Company provides these services by utilizing a variety of derivative financial instruments, including (a) fixed and variable-priced physical forward contracts, (b) fixed and variable-priced swap agreements, (c) options traded in the over-the-counter financial markets and (d) exchange-traded energy futures and option contracts (Trading Derivatives). Fixed-price swap agreements require payments to, or receipts of payments from, counterparties based on the differential between a fixed and variable price for the commodity. Variable-price swap agreements require payments to, or receipts of payments from, counterparties based on the differential between industry pricing publications or exchange quotations. The Company applies mark-to-market accounting for all of its energy trading, marketing and price risk management operations. Accordingly, these Trading Derivatives are recorded at fair value with net realized and unrealized gains (losses) recorded as a component of revenues. The recognized, unrealized balances are included in price risk management assets/liabilities. (b) Non-Trading Activities. Cash Flow Hedges. To reduce the risk from market fluctuations in revenues and the resulting cash flows derived from the sale of electric power and natural gas and related transportation, the Company enters into futures transactions, forward contracts, swaps and options (Energy Derivatives) in order to hedge some expected purchases of electric power, natural gas and other commodities and sales of electric power and natural gas (a portion of which are firm commitments at the inception of the hedge). Energy Derivatives are also utilized to fix the price of compressor fuel or other future operational gas requirements and to protect natural gas distribution earnings and cash flows against unseasonably warm weather during peak gas heating months, although usage to date for this purpose 42 has not been material. The Energy Derivative portfolios are managed to complement the physical transaction portfolio, reducing overall risks within management-prescribed limits. During the three months ended March 31, 2001, the Company entered into interest-rate swaps in order to adjust the interest rate on $375 million of its floating rate debt. In addition, as of March 31, 2001, the Company's European Energy segment has entered into financial instruments to purchase approximately $120 million to hedge future fuel purchases payable in U.S. dollars. The Company applies hedge accounting for its derivative financial instruments utilized in non-trading activities only if there is a high correlation between price movements in the derivative and the item designated as being hedged. This correlation, a measure of hedge effectiveness, is measured both at the inception of the hedge and on an ongoing basis, with an acceptable level of correlation of at least 80% for hedge designation. If and when correlation ceases to exist at an acceptable level, hedge accounting ceases and mark-to-market accounting is applied. During the three months ended March 31, 2001, the amount of hedge ineffectiveness recognized in earnings from derivatives that are designated and qualify as cash flow hedges was immaterial. No component of the derivative instruments' gain or loss was excluded from the assessment of effectiveness. If it becomes probable that an anticipated transaction will not occur, the Company realizes in net income the deferred gains and losses recognized in accumulated other comprehensive loss. During the three months ended March 31, 2001, there were no deferred gains or losses 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. Once the anticipated transaction occurs, the accumulated deferred gain or loss recognized in accumulated other comprehensive loss is reclassified to net income and included in the Company's Statements of Consolidated Income under the captions (a) fuel expenses, in the case of natural gas transactions, (b) purchased power, in the case of electric power purchase transactions, (c) revenues, in the case of electric power sales transactions and (d) interest expense, in the case of interest rate swap transactions. Cash flows resulting from these transactions in Energy Derivatives are included in the Company's Statements of Consolidated Cash Flows in the same category as the item being hedged. As of March 31, 2001, current non-trading derivative assets and liabilities and corresponding amounts in accumulated other comprehensive loss are expected to be reclassified to net income during the next twelve months. The maximum length of time the Company is hedging its exposure to the variability in future cash flows for forecasted transactions excluding the payment of variable interest on existing financial instruments is five years. The maximum length of time the Company is hedging its exposure to the payment of variable interest rates is approximately five years. Hedge of Net Investment in Foreign Subsidiaries. The Company has substantially hedged its net investment in its European subsidiaries through a combination of Euro-denominated borrowings, foreign currency swaps and foreign currency forward contracts to reduce the Company's exposure to changes in foreign currency rates. During the normal course of business, the Company reviews its currency hedging strategies and determines the hedging approach deemed appropriate based upon the circumstances of each situation. The Company records the changes in the value of the foreign currency hedging instruments and Euro-denominated borrowings as foreign currency translation adjustments as a component of stockholders' equity and accumulated other comprehensive loss. The effectiveness of the hedging instruments can be measured by the net change in foreign currency translation adjustments attributed to the Company's net investment in its European subsidiaries. These amounts generally offset amounts recorded in stockholders' equity as adjustments resulting from translation of the hedged investment into U.S. dollars. During the three months ended March 31, 2001, the derivative and nonderivative instruments designated as hedging the net investment in its European subsidiaries resulted in a gain of $155 million which is included in the balance of the cumulative translation adjustment. Other Derivatives. Upon adoption of SFAS No. 133 effective January 1, 2001, the Company's indexed debt securities obligations related to its ZENS obligation was bifurcated into a debt component valued at $122 million and an embedded derivative component valued at $788 million. Changes in the fair value of the derivative component are recorded in the Company's Statements of Consolidated Income. Changes in the fair value of the Company's Investment in AOL Time Warner Inc. common stock should substantially offset changes in the fair value of the derivative component of the ZENS. 43 In December 2000, the Dutch parliament adopted legislation allocating to the Dutch generation sector, including a subsidiary of the Company, N.V. UNA (UNA), financial responsibility for various stranded costs contracts and other liabilities. The legislation became effective in all material respects on January 1, 2001. In particular, the legislation allocated to the four Dutch generation companies, including UNA, financial responsibility to purchase electricity and gas under an import gas supply contract and three electricity import contracts. The gas import contract expires in 2015 and provides for gas imports aggregating 2.283 billion cubic meters per year. These contracts are derivatives pursuant to SFAS No. 133 due to the pricing indices. As of March 31, 2001, the Company has recognized $326 million in long-term non-trading derivative liabilities for UNA's portion of these stranded costs contracts. For additional information regarding UNA's stranded costs and the related indemnification by former shareholders of these stranded costs, see Note 11(e). Subsequent to March 31, 2001, the Company has entered into interest rate swaps to fix the rate on $1.3 billion of the Company's floating rate debt, which expire in 2002. The Company has not designated these derivative instruments as hedges. Changes in the fair value of the swaps will be recorded in the Company's Statements of Consolidated Income. 44 EX-99 5 h92033ex99.txt MANAGEMENT'S DISCUSSION & ANALYSIS OF FINANCIALS EXHIBIT 99.RERC RELIANT ENERGY RESOURCES CORP. ITEMS INCORPORATED BY REFERENCE ITEMS INCORPORATED BY REFERENCE FROM THE RELIANT ENERGY FORM 10-K o ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- CERTAIN FACTORS AFFECTING OUR FUTURE EARNINGS Our earnings for the past three years are not necessarily indicative of our future earnings and results. The level of our future earnings depends on numerous factors including: - state and federal legislative, as well as international 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, - the timing of the implementation of our Business Separation Plan, - industrial, commercial and residential growth in our service territories, - our pursuit of potential business strategies, including acquisitions or dispositions of assets or the development of additional power generation facilities, - state, federal and other rate regulations in the United States and in foreign countries in which we operate or into which we might expand our operations, - the timing and extent of changes in commodity prices and interest rates, - weather variations and other natural phenomena, - our ability to cost-effectively finance and refinance, - the determination of the amount of our Texas generating assets' stranded costs and the recovery of these costs, - the ability to consummate and the timing of the consummation of acquisitions and dispositions, - the performance of our generation projects undertaken, - the successful operation of deregulating power markets, including the resolution of the crisis in the California market, and - risks incidental to our overseas operations, including the effects of fluctuations in foreign currency exchange rates. In order to adapt to the increasingly competitive environment, we continue to evaluate a wide array of potential business strategies, including business combinations or acquisitions involving other utility or non-utility businesses or properties, dispositions of currently owned businesses, as well as developing new generation projects, products, services and customer strategies. BUSINESS SEPARATION AND RESTRUCTURING In anticipation of electric deregulation in Texas, and pursuant to the Legislation, we submitted a business separation plan in January 2000 to the Texas Utility Commission. Pursuant to the Business Separation Plan, we will restructure our businesses into two separate publicly traded companies in order to separate our unregulated businesses from our rate-regulated businesses. Reliant Resources holds substantially all of our unregulated businesses. We expect Reliant Resources will conduct the Offering in 2001. Also, we anticipate that the Regulated Holding Company will conduct the Distribution within 12 months of the completion of the 1 Offering, subject to receipt of a favorable tax ruling and other regulatory approvals. For additional information regarding the Business Separation Plan and the Restructuring, please read "Business -- Our Business -- Restructuring" in Item 1 of this Form 10-K and Note 4(b) to our consolidated financial statements. We have sought a ruling from the Internal Revenue Service that the Distribution will be tax-free to the Regulated Holding Company and its shareholders. At this time, we do not have a ruling from the Internal Revenue Service regarding the tax treatment of the Distribution. If we do not obtain a favorable tax ruling, the Distribution is not likely to be made in the expected time frame or, perhaps, at all. In order for the Distribution to be tax-free, various requirements must be met, including ownership by its parent of at least 80% of all classes of Reliant Resources' outstanding capital stock at the time of the Distribution. Additionally, in connection with the Distribution, Reliant Energy plans to restructure its remaining businesses to achieve a public utility holding company structure and to register the Regulated Holding Company as a public utility holding company under the 1935 Act. Creation of the Regulated Holding Company will require the approval of Reliant Energy's shareholders. For additional information regarding the Regulated Holding Company, please read "Business -- Our Business -- Restructuring" in Item 1 of this Form 10-K and Note 4(b) to our consolidated financial statements. The Restructuring will also require the approval of the Louisiana Public Service Commission and the Nuclear Regulatory Commission. We cannot assure you that those approvals will be obtained. After the Restructuring, the Regulated Holding Company will become a registered public utility holding company under the 1935 Act. COMPETITIVE, REGULATORY AND OTHER FACTORS AFFECTING OUR ELECTRIC OPERATIONS Competition and Deregulation. In June 1999, the Texas legislature adopted the Legislation, which substantially amended the regulatory structure governing electric utilities in Texas in order to allow retail competition. Retail pilot projects for up to 5% of each utility's load in all customer classes will begin in June 2001 and retail electric competition for all other customers will begin on January 1, 2002. Our retail operations will be conducted by indirect wholly owned subsidiaries of Reliant Resources. Under the market framework established by the Legislation, we will initially be required to sell electricity to Houston area residential and small commercial customers at a specified price, which is referred to in the Legislation as the "price to beat," whereas other retail electric providers will be allowed to sell electricity to these same customers at any price. We will not be permitted to offer electricity to these customers at a price other than the price to beat until January 1, 2005, unless before that date the Texas Utility Commission determines that 40% or more of the amount of electric power that was consumed in 2000 by residential or small commercial customers, as applicable, within the affiliated transmission and distribution utility's certificated service territory, as of January 1, 2002, is committed to be served by other retail electric providers. In addition, as long as we continue to provide retail service, the Legislation requires us to make the price to beat available to residential and small commercial customers in Reliant Energy HL&P's service territory through January 1, 2007. Because we will not be able to compete for residential and small commercial customers on the basis of price in Reliant Energy HL&P's service area, and because we expect that the retail market framework established by the Legislation will encourage competition from new retail electric providers, we could lose a significant number of these customers to other providers. When the pilot projects begin in June 2001, and until full retail electric competition begins, the Legislation provides that 5% of our customers may elect to purchase electricity from other retail electric providers. Our affiliated retail electric providers cannot participate in the pilot projects in Reliant Energy HL&P's service area. Reliant Energy HL&P will collect from retail electric providers the rates approved from its Wires Case to cover the cost of providing transmission and distribution service and any other non-bypassable charges. Generally, retail electric providers will procure or buy electricity from the wholesale generators at unregulated rates, sell electricity at retail to their customers and pay the transmission and distribution utility a regulated tariffed rate for delivering the electricity to their customers. The results of our retail electric operations will be largely dependent upon the amount of gross margin, or "headroom," available in the "price to beat." The available headroom will equal the difference between the price to beat and the sum of the charges, fees and transmission and distribution utility rate approved by the Texas Utility Commission and the price we pay for power to meet our price to beat load. The larger the amount of headroom, the more incentive 2 new market entrants should have to provide retail electric services in Reliant Energy HL&P's service territory. The Texas Utility Commission's regulations allow us to adjust our price to beat fuel factor based on the percentage change in the price of natural gas. In addition, we may also request an adjustment as a result of changes in our price of purchased energy. In such a request, we may adjust the fuel factor to the extent necessary to restore the amount of headroom that existed at the time our initial price to beat fuel factor was set by the Texas Utility Commission. We may not request that our price to beat be adjusted more than twice a year. Currently, we do not know nor can we estimate the amount of headroom in our initial price to beat or in the initial price to beat for the affiliated retail electric provider in each other Texas retail electric market. Similarly, we cannot estimate with any certainty the magnitude and frequency of the adjustments required, if any, and the eventual impact of such adjustments on the amount of headroom. In preparation for this competition, we expect to make significant changes in the electric utility operations currently conducted through Reliant Energy HL&P. For additional information regarding these changes, the Legislation, retail competition, its application to our Electric Operations segment and the "price to beat," please read "Business -- Our Business -- Deregulation and Competition," "-- Restructuring," "-- Electric Operations" and "Business -- Regulation -- State and Local Regulations -- Texas -- Electric Operations -- The Legislation" in Item 1 of this Form 10-K and Note 4 to our consolidated financial statements. Also, market volatility in the price of fuel for our generation operations, as well as in the price of purchased power, could have an effect on our cost to generate or acquire power. For additional information regarding commodity prices and supplies, please read "-- Competitive, Regulatory and Other Factors Affecting Our Wholesale Energy Operations -- Price Volatility." Other Regulatory Factors. Pursuant to the Legislation, Reliant Energy HL&P will be entitled to recover its stranded costs (i.e., the excess of net book value of generation assets, as defined by the Legislation, over the market value of those assets) and its regulatory assets related to generation. The Legislation prescribes specific methods for determining the amount of stranded costs and the details for their recovery. However, during the base rate freeze period from 1999 through 2001, earnings above the utility's authorized rate of return formula may be applied in a manner to accelerate depreciation of generation related plant assets for regulatory purposes. In addition, depreciation expense for transmission and distribution related assets may be redirected to generation assets for regulatory purposes during that period. The Legislation also provides for Reliant Energy HL&P, or a special purpose entity, to issue securitization bonds for the recovery of generation related regulatory assets and a portion of stranded costs. Any stranded costs not recovered through the sale of securitization bonds may be recovered through a non-bypassable charge to transmission and distribution customers. For additional information regarding these securitization bonds, please read "-- Liquidity and Capital Resources -- Future Sources and Uses of Cash -- Securitization." The Texas Utility Commission recently stated on record that it would consider requiring electric utilities to reverse the amount of redirected depreciation and accelerated depreciation previously taken if in its estimation the utility has overmitigated its stranded costs. The reversal could occur through a lower rate for the transmission and distribution utility and/or through credits contained in the transmission and distribution utility's rate. Any order requiring the reversal of these amounts would likely be included in the Texas Utility Commission proceeding establishing the initial rate of the transmission and distribution utility or in the case of our Electric Operations segment, the Wires Case. We do not expect the final transmission and distribution rate in the Wires Case to be established until August 2001. For more information regarding the Wires Case, see "Business -- Regulation -- State and Local Regulations -- Texas -- Electric Operations -- Rate Case." At June 30, 1999, we performed an impairment test of Reliant Energy HL&P's previously regulated electric generation assets pursuant to SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" (SFAS No. 121), on a plant specific basis. Under SFAS No. 121, an asset is considered impaired, and should be written down to fair value, if the future undiscounted net cash flows expected to be generated by the use of the asset are insufficient to recover the carrying amount of the asset. For assets that are impaired pursuant to SFAS No. 121, we determined the fair value for each generating plant by estimating the net present value of future cash inflows and outflows over the estimated life of each plant. The difference between fair value and net book value was recorded as a reduction in the current 3 book value. We determined that $797 million of electric generation assets were impaired as of June 30, 1999. Of these amounts, $745 million related to the South Texas Project and $52 million related to two gas-fired generation plants. The Legislation provides for recovery of this impairment through regulated cash flows during the transition period and through non-bypassable charges to transmission and distribution customers. As such, a regulatory asset has been recorded for an amount equal to the impairment loss. We recorded amortization expense related to the recoverable impaired plant costs and other assets created from discontinuing regulatory accounting of $221 million in the third and fourth quarters of 1999 and $329 million in 2000. We expect to fully amortize this regulatory asset as it is recovered from regulated cash flows in 2001. The impairment analysis requires estimates of possible future market prices, load growth, competition and many other factors over the lives of the plants. The resulting impairment loss is highly dependent on these underlying assumptions. In addition, after January 10, 2004, Reliant Energy HL&P must finalize and reconcile stranded costs (as defined by the Legislation) in a filing with the Texas Utility Commission. Any positive difference between the regulatory net book value and the fair market value of the generation assets (as defined by the Legislation) will be collected through future non-bypassable charges. Any over-mitigation of stranded costs may be refunded through future non-bypassable charges. This final reconciliation allows alternative methods of third party valuation of the fair market value of these assets, including outright sale, stock valuations and asset exchanges. Because generally accepted accounting principles require us to estimate fair market values on a plant-by-plant basis in advance of the final reconciliation, the financial impacts of the Legislation with respect to the final determination of stranded costs in 2004 are subject to material changes. Factors affecting such change may include estimation risk, uncertainty of future energy and commodity prices and the economic lives of the plants. If events occur that make the recovery of all or a portion of the regulatory assets associated with the generation plant impairment loss and other assets created from discontinuance of regulatory accounting pursuant to the Legislation no longer probable, we will write off the corresponding balance of these assets as a non-cash charge against earnings. One of the results of discontinuing the application of regulatory accounting for the generation operations is the elimination of the regulatory accounting effects of excess deferred income taxes and investment tax credits related to these operations. We believe it is probable that some parties will seek to return these amounts to ratepayers and, accordingly, we have recorded an offsetting liability. In accordance with the Legislation, beginning on January 1, 2002, and ending at December 31, 2003, any difference between market power prices received in the generation capacity auction and the Texas Utility Commission's earlier estimates of those market prices will be included in the 2004 stranded costs true-up. The Texas Utility Commission's estimate serves as a preliminary identification of stranded costs for recovery through securitization. This component of the true-up is intended to ensure that neither the customers nor we are disadvantaged economically as a result of the two-year transition period by providing this pricing structure. Since the time of our original impairment calculation in June 1999 when we discontinued application of SFAS No. 71 for our generation operations, natural gas prices have risen 295% from June 1999 to December 31, 2000 resulting in increases in estimated market prices for power during 2002 and 2003. Generally, for Reliant Energy HL&P's generation portfolio, sustained increases in natural gas prices result in an increase in the fair value of Reliant Energy HL&P's generation portfolio, due to our mix of lower variable cost of electric generation. Therefore, as electric power prices increase, the amount of our estimated stranded costs decline and the estimate of our 2002 and 2003 capacity true-up amounts which may be owed to customers increases. For additional information regarding the impairment of regulatory assets and electric generating plant and equipment as well as the recovery of stranded costs, please read Note 4(a) to our consolidated financial statements. For additional information regarding our filings to recover under-recovered fuel costs, please read Note 4(d) to our consolidated financial statements. Other. For additional information regarding litigation over franchise fees, please read Note 14(g) to our consolidated financial statements. 4 COMPETITIVE, REGULATORY AND OTHER FACTORS AFFECTING OUR WHOLESALE ENERGY OPERATIONS Competition. As of December 31, 2000, our Wholesale Energy business segment owned and operated 9,231 MW of electric generation assets that serve wholesale energy markets located in the Mid-Atlantic, Southwest and Midcontinent regions of the United States and the states of Florida and Texas. Competitive factors affecting the results of operations of these generation assets include new market entrants and construction by others of more efficient generation assets. The wholesale power industry has numerous competitors, some of which may have more operating experience, more acquisition and development experience, larger staffs and/or greater financial resources than we do. Like us, many of our competitors are seeking attractive opportunities to acquire or develop power generation facilities, both in the United States and abroad. This competition may adversely affect our ability to make investments or acquisitions. Also, industry restructuring requires or encourages the disaggregation of many vertically-integrated utilities into separate generation, transmission and distribution, and retail businesses. As a result, a significant number of additional competitors could become active in the wholesale power generation segment of our industry. Furthermore, other competitors operate power generation projects in the regions where we have invested in electric generation assets. While demand for electric energy services is generally increasing throughout the United States, the rate of construction and development of new, more efficient electric generation facilities may exceed increases in demand in some regional electric markets. Although local permitting and siting issues often reduce the risk of a rapid growth in supply of generation capacity in any particular region, projects are likely to be built over time. The commencement of commercial operation of these new facilities in the regional markets where we have facilities will likely increase the competitiveness of the wholesale power market in those regions, which could have a material effect on our business and lower the value of some of our electric generation assets. Finally, our trading, marketing, power origination and risk management operations compete with other energy merchants based on the ability to aggregate supplies at competitive prices from different sources and locations and to efficiently utilize transportation from third-party pipelines and transmission from electric utilities. These operations also compete against other energy marketers on the basis of their relative skills, financial position and access to credit sources. This competitive factor reflects the tendency of energy customers, wholesale energy suppliers and transporters to seek financial guarantees and other assurances that their energy contracts will be satisfied. As pricing information becomes increasingly available in the energy trading and marketing business and as deregulation in the electricity markets continues to accelerate, we anticipate that our trading, marketing, power origination and risk management operations will experience greater competition and downward pressure on per-unit profit margins. Regulation. The regulatory environment applicable to the electric power industry has recently undergone substantial changes as a result of restructuring initiatives at both the state and federal levels. These initiatives have had a significant impact on the nature of the industry and the manner in which its participants conduct their business. Our Wholesale Energy segment has targeted the deregulating wholesale and retail segments of the electric power industry created by these initiatives. These changes are ongoing and we cannot predict the future development of deregulation in these markets or the ultimate effect that this changing regulatory environment will have on our business. Moreover, existing regulations may be revised or reinterpreted, new laws and regulations may be adopted or become applicable to us or our facilities, and future changes in laws and regulations may have a detrimental effect on our business. Certain restructured markets, particularly California, have recently experienced supply problems and price volatility. These supply problems and volatility have been the subject of a significant amount of press coverage, much of which has been critical of the restructuring initiatives. In some markets, including California (please read "-- California" below), proposals have been made by governmental agencies and/or other interested parties to slow the pace of deregulation or to re-regulate areas of these markets that have previously been deregulated. If the current trend towards competitive restructuring of the wholesale and 5 retail power markets is reversed, discontinued or delayed, the business growth prospects of our Wholesale Energy segment would be slowed and the financial outlook for our existing positions could be impacted. If RTOs are established as envisioned by FERC Order 2000, "rate pancaking," or multiple transmission charges that apply to a single point-to-point delivery of energy, will be eliminated within a region, and wholesale transactions within the region, and between regions will be facilitated. The end result could be a more competitive, transparent market for the sale of energy and a more economic and efficient use and allocation of resources. For additional information regarding FERC Order 2000 affecting these RTOs, please read "Business -- Regulation -- Federal Energy Regulatory Commission" in Item 1 of this Form 10-K. Price Volatility. Our Wholesale Energy business segment sells electricity from our non-Texas power generation facilities into the spot market or other competitive power markets or on a contractual basis. Our Wholesale Energy business segment is not guaranteed any rate of return on our capital investments through mandated rates, and our revenues and results of operations are likely to depend, in large part, upon prevailing market prices for electricity and fuel in our regional markets and other competitive markets. These market prices may fluctuate substantially over relatively short periods of time. In addition, the FERC, which has jurisdiction over wholesale power rates, as well as independent system operators that oversee some of these markets, may impose price limitations, bidding rules and other mechanisms to address some of the volatility in these markets. Most of our Wholesale Energy business segment's domestic power generation facilities purchase fuel under short-term contracts or on the spot market. Fuel prices may also be volatile, and the price we can obtain for power sales may not change at the same rate as changes in fuel costs. These factors could have an adverse impact on our revenues and results of operations. Volatility in market prices for fuel and electricity may result from: - weather conditions, - seasonality, - electricity usage, - illiquid markets, - transmission or transportation constraints or inefficiencies, - availability of competitively priced alternative energy sources, - demand for energy commodities, - natural gas, crude oil and refined products, and coal production levels, - natural disasters, wars, embargoes and other catastrophic events, and - federal, state and foreign energy and environmental regulation and legislation. Trading, Marketing, Power Origination and Risk Management Operations. To lower our Wholesale Energy business segment's financial exposure related to commodity price fluctuations, its trading, marketing, power origination and risk management operations routinely enter into contracts to hedge a portion of its purchase and sale commitments, weather positions, fuel requirements and inventories of natural gas, coal, crude oil and refined products, and other commodities. As part of this strategy, our Wholesale Energy business segment routinely utilizes fixed-price forward physical purchase and sales contracts, futures, financial swaps and option contracts traded in the over-the-counter markets or on exchanges. However, our Wholesale Energy business segment does not expect to cover the entire exposure of its assets or its positions to market price volatility and the coverage will vary over time. To the extent our Wholesale Energy business segment has unhedged positions, fluctuating commodity prices can impact our financial results and financial position, either favorably or unfavorably. At times, our Wholesale Energy business segment has open trading positions in the market, within established guidelines, resulting from the management of its trading portfolio. To the extent open trading 6 positions exist, fluctuating commodity prices can impact our financial results and financial position, either favorably or unfavorably. The risk management procedures our Wholesale Energy business segment has in place may not always be followed or may not always work as planned. As a result of these and other factors, we cannot predict with precision the impact that our risk management decisions may have on our businesses, operating results or financial position. Although our Wholesale Energy business segment devotes a considerable amount of management effort to these issues, their outcome is uncertain. Our trading, marketing, power origination and risk management operations are also exposed to the risk that counterparties who owe it money or physical commodities, such as energy or gas, as a result of market transactions will not perform their obligations. Should the counterparties to these arrangements fail to perform, our trading, marketing, power origination and risk management operations might be forced to acquire alternative hedging arrangements or replace the underlying commitment at then-current market prices. In this event, our trading, marketing, power origination and risk management operations might incur additional losses to the extent of amounts, if any, already paid to the counterparties. California. During the summer and fall of 2000, 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, decreases in net electric imports, structural market flaws including over-reliance on the electric spot market, and limitations on supply as a result of maintenance and other outages. Although wholesale prices increased, California's deregulation legislation kept retail rates frozen below 1996 levels. This caused two of California's public utilities, which are our customers based on our deliveries to the Cal PX and the Cal ISO, to amass billions of dollars of uncollected wholesale power costs and to ultimately default in January and February 2001 on payments owed for wholesale power purchased through the Cal PX and from the Cal ISO. As of December 31, 2000, we were owed $101 million by the Cal PX and $181 million by the Cal ISO. In the fourth quarter of 2000, we recorded a pre-tax provision of $39 million against receivable balances related to energy sales in the California market. From January 1, 2001 through February 28, 2001, we have collected $105 million of these receivable balances. As of March 1, 2001, we were owed a total of $358 million by the Cal ISO, the Cal PX, the CDWR and California Energy Resources Scheduling for energy sales in the California wholesale market from the fourth quarter of 2000 through February 28, 2001. Management will continue to assess the collectibility of these receivables based on further developments affecting the California electricity market and the market participants described herein. Additional provisions to the allowance may be warranted in the future. In response to the filing of a number of complaints challenging the level of wholesale prices, the FERC initiated a staff investigation and issued an order on December 15, 2000 implementing a series of wholesale market reforms, including an interim price review procedure for prices above a $150/MWh "breakpoint" on sales to the Cal ISO and through the Cal PX. The order does not prohibit sales above the "breakpoint," but the seller is subject to weekly reporting and monitoring requirements. For each reported transaction, potential refund liability extends for a period of 60 days following the date any such transaction is reported to the FERC. On March 9, 2001, the FERC issued a further order establishing a proxy market clearing price of $273/MWh for January 2001, and on March 16, 2001 the FERC issued a further order adjusting the proxy market clearing price to $430/MWh for February 2001. New market monitoring and mitigation measures to replace the $150/MWh breakpoint and reporting obligation are being developed by the FERC to take effect on May 1, 2001. In the FERC's March 9 and March 16 orders, the FERC outlined criteria for determining amounts subject to possible refund based on the proxy market clearing price for January and February 2001 and indicated that approximately $12 million of the $125 million charged by us in January 2001 in California to the Cal ISO and the Cal PX and approximately $7 million of the $47 million charged by us in February 2001 in California to the Cal ISO and the Cal PX were subject to possible refunds. In the March 9 and March 16 orders, the FERC set forth procedures for challenging possible refund obligations. Because we believe that there is cost or other justification for prices charged above the proxy market clearing prices established in the 7 March 9 and March 16 orders, we intend to pursue such a challenge with respect to our potential refund amounts identified in such orders. Any refunds we may ultimately be obligated to pay are to be credited against unpaid amounts owed to us for our sales in the Cal PX or to the Cal ISO. The December 15 order established that a refund condition would be in place for the period beginning October 2, 2000 through December 31, 2002. The December 15 order also eliminated the requirement that California's public utilities sell all of their generation into and purchase all of their power from the Cal PX and directed that the Cal PX wholesale tariffs be terminated effective April 2001. The Cal PX has since suspended its day-ahead and day-of markets and filed for bankruptcy protection on March 9, 2001. Motions for rehearing have been filed on a number of issues related to the December 15 order and such motions are still pending before the FERC. 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 Public Utilities Commission, the California Electricity Oversight Board, the California Bureau of State Audits and the California Office of the Attorney General all have separate ongoing investigations into the high prices and their causes. None of these investigations have been completed and no findings have been made in connection with any of them. Despite the market restructuring ordered under the December 15 order, the California public utilities have continued to accrue unrecovered wholesale costs. As a result, the credit ratings of two of these public utilities were severely downgraded to below investment grade in January 2001. As their credit lines became unavailable, the two utilities defaulted on payments due to the Cal PX and the Cal ISO, which operate financially as pass-through entities, coordinating payments from buyers and sellers of electricity. As a result, the Cal PX and Cal ISO were not able to pay final invoices to market participants totaling over $1 billion. The default of two of California's public utilities on amounts owed the Cal PX and the Cal ISO for purchased power has further exacerbated the current crisis in the California wholesale markets and resulted in substantial uncollected receivables owed to us by the Cal ISO and the Cal PX. The Cal PX's efforts to recover the available collateral of the utilities, in the form of block forward contracts, have been frustrated by the emergency acts of California's Governor, who seized control of the contracts upon the expiration of temporary restraining orders prohibiting such action. Although obligated to pay reasonable value for the contracts, the state of California has not yet made any payment for the contracts. Various actions have been filed challenging the Governor's ability to seize these contracts. Upon the default of the two utilities of amounts due to the Cal PX, the Cal PX issued "charge-backs" allocating the utilities' defaults to the other market participants. Proceedings were brought both in federal court and at the FERC seeking a suspension of the charge-backs and challenging the reasonableness of the Cal PX's actions. The Cal PX has since agreed to a preliminary injunction suspending any of its charge-back activities in order to allow the FERC to address the charge-back issues. Amounts owed to us were debited in invoices by the Cal PX for charge-backs in the amount of $29 million and, on February 14, 2001, we filed our own lawsuit against the Cal PX in the United States District Court for the Central District of California, seeking a recovery of those amounts and a stay of any further charge-backs by the Cal PX. The filing of bankruptcy by the Cal PX will automatically stay for some period the various court and administrative cases against the Cal PX. The two defaulting utilities have both filed lawsuits challenging the refusal of state regulators to allow wholesale power costs to be passed through to retail customers under the "filed rate doctrine." The filed rate doctrine provides that wholesale power costs approved by the FERC are entitled to be recovered through rates. Additionally, to address the failing financial condition of the two defaulting utilities and the utilities' potential bankruptcy, the California Legislature passed emergency legislation, effective January 18, 2001 and February 2, 2001, appropriating funds to be used by the CDWR for the purchase of wholesale electricity on behalf of the utilities and authorizing the sale of bonds to fund future purchases under long-term power contracts with wholesale generators. The CDWR began the process of soliciting bids from generators for long-term contracts and continued the purchasing of short-term power contracts. No bonds have yet been issued by the CDWR to support long-term power purchases or to provide credit support for short-term purchases. 8 As noted above, two of California's public utilities have defaulted in their payment obligations to the Cal PX and the Cal ISO as a result of the refusal of state regulators to allow them to recover their wholesale power costs. This refusal by state regulators has also caused the utilities to default on numerous other financial obligations, which could result in either the voluntary or involuntary bankruptcy of the utilities. While a bankruptcy filing would result in further post-petition purchases of wholesale electricity being considered administrative expenses of the debtor, a substantial delay could be experienced in the payment of pre-petition receivables pending the confirmation of a reorganization plan. The California Legislature is currently considering legislation under which a state entity would be formed to purchase and operate a substantial share of the transmission lines in California in an effort to provide cash to the utilities and thereby avoid potential bankruptcy filings by the utilities. A number of the creditors for the two California public utilities have indicated, however, that unless California moves quickly with such a plan, an involuntary bankruptcy filing may be made by one or more of such creditors. Because California's power reserves remain at low levels, in part as a result of the lack of creditworthy buyers of power given the defaults of the California utilities, the Cal ISO has relied on emergency dispatch orders requiring generators to provide at the Cal ISO's direction all power not already under contract. The power supplied to the Cal ISO has been used to meet the needs of the customers of the utilities, even though two of those utilities do not have the credit required to receive such power and may be unable to pay for it. We have contested the obligation to provide power under these circumstances. The Cal ISO sought a temporary restraining order compelling us to continue to comply with the emergency dispatch orders despite the utilities' defaults. Although the payment issue is still disputed, on February 21, 2001, we and the CDWR entered into a contract expiring March 23, 2001 for the purchase of all of our available capacity not already under contract and the litigation has been temporarily stayed. The CDWR is current in its payments under this contract, but we are still owed $108 million for power provided in compliance with the emergency dispatch orders for the six weeks prior to the agreement. Depending on the outcome of the court proceedings initiated by the Cal ISO seeking to enjoin us from ceasing power deliveries to the Cal ISO, we may be forced to continue selling power without the guarantee of payment. Additionally, we are seeking a prompt FERC determination that the Cal ISO is not complying with the credit provisions of its tariff and a related order of the FERC issued on February 14, 2001, requiring the Cal ISO not to make purchases in the real time market unless a creditworthy purchaser is responsible for such purchases. For additional information regarding the situation in California, please read "Business -- Wholesale Energy -- Power Generation Operations -- Southwest Region" and "Business -- Regulation -- State and Local Regulations -- California" in Item 1 of this Form 10-K, "-- Results of Operations by Business Segment -- Wholesale Energy -- 2000 Compared to 1999," as well as Notes 14(g) and 14(h) to our consolidated financial statements. COMPETITIVE, REGULATORY AND OTHER FACTORS AFFECTING OUR EUROPEAN ENERGY OPERATIONS Competition. The European energy market is highly competitive. In addition, over the next several years, we expect an increasing consolidation of the participants in the European generating market. Our European wholesale operations compete in the Netherlands, primarily against the three other largest Dutch generating companies, various cogenerators of electric power, various alternate sources of power and non-Dutch generators of electric power, primarily from France and Germany. In 2000, UNA and the three other largest Dutch generating companies supplied approximately 50% of the electricity consumed in the Netherlands. Smaller Dutch producers supplied about 25% of the consumed electricity, and the remainder was imported. At present, the Dutch electricity system has three operational interconnection points with Germany and two interconnection points with Belgium. There are also a number of projects that are at various stages of development and that may increase the number of interconnections in the future (post 2005) including interconnections with Norway and the United Kingdom. The Belgian interconnections are used to import electricity from France, but a larger portion of Dutch electricity imports comes from Germany. 9 Our European trading and marketing operations will also be subject to increasing levels of competition. As of December 31, 2000, there were 32 trading and marketing companies registered with the Amsterdam Power Exchange. Competition among power generators for customers is intense, and we expect competition to increase with the deregulation of the market. Please read "-- Regulation." The primary elements of competition affecting both the generation and trading and marketing operations of our European Energy business segment are price, credit support, and supply and delivery reliability. Deregulation. The Dutch electricity market was opened to limited wholesale and retail competition on January 1, 1999 as retail competition for large industrial customers began. The Dutch wholesale electric market was completely opened to competition on January 1, 2001. Consistent with our expectations at the time we made the acquisition, we anticipate that our European Energy business segment may experience a significant decline in gross margin in 2001 attributable to the deregulation of the market and termination of an agreement with the other Dutch generators and the Dutch distributors. The next customer segment, composed primarily of commercial customers, will be liberalized by 2002. The remainder of the market, mainly residential, will be open to competition by 2003. The timing of these market openings is subject to change, however, at the discretion of the Dutch Minister of Economic Affairs. In addition, the results of our European Energy segment will be negatively impacted beginning in 2002 due to the imposition of a standard Dutch corporate income tax rate, which is currently 35%, on the income of UNA. In 2000 and prior years, UNA's Dutch corporate income tax rate was zero percent. Other. Another factor that could have a significant impact on the Dutch energy industry, including the operations of our European Energy business segment, is the ultimate resolution of stranded costs issues in the Netherlands. Prior to 2001, UNA and the other Dutch generators sold their generating output through the coordinating body for the Dutch electricity generating sector, B.V. Nederlands Elektriciteit Administratiekantor (NEA). Over the years, NEA has incurred "stranded" costs as a result of, among other things, a perceived need to cover anticipated shortages in energy production supply. NEA stranded costs consist primarily of investments in alternative energy sources and fuel and power purchase contracts currently estimated to be uneconomical. Legislation has been approved by the Dutch parliament which would transfer the liability for the stranded costs from NEA to its four shareholders, one of which is UNA. For information regarding this legislation, please read Note 14(i) to our consolidated financial statements. In connection with our acquisition of UNA, the selling shareholders of UNA agreed to indemnify UNA for some stranded costs in an amount not to exceed NLG 1.4 billion ($599 million based on an exchange rate of 2.34 NLG per U.S. dollar as of December 31, 2000), which may be increased in some circumstances at our option up to NLG 1.9 billion ($812 million). Of the total consideration we paid for the shares of UNA, NLG 900 million ($385 million) has been placed by the selling shareholders under the direction of the Dutch Minister of Economic Affairs in an escrow account to secure the indemnity obligations by the former shareholders of UNA. Although our management believes that the indemnity provision will be sufficient to fully satisfy UNA's ultimate share of any stranded costs obligation, this judgment is based on numerous assumptions regarding the ultimate outcome and timing of the resolution of the stranded cost issue, the former shareholders' timely performance of their obligations under the indemnity arrangement, and the amount of stranded costs, which at present is not determinable. Any shortfall in the indemnity provision could have a material adverse effect on our results of operations. Our European operations are subject to various risks incidental to investing or operating in foreign countries. These risks include economic risks, such as fluctuations in currency exchange rates, restrictions on the repatriation of foreign earnings and/or restrictions on the conversion of local currency earnings into U.S. dollars. For example, we estimate that the impact of the devaluation of the Euro relative to the U.S. dollar during 2000 negatively impacted U.S. dollar net income in the amount of approximately $8 million. Impact of Currency Fluctuations on Company Earnings. For information about our exposure through our investment in Europe to losses resulting from fluctuations in currency rates, please read "Quantitative and Qualitative Disclosures About Market Risk" in Item 7A of this Form 10-K. 10 COMPETITIVE AND OTHER FACTORS AFFECTING RERC OPERATIONS Natural Gas Distribution. Our Natural Gas Distribution business segment competes primarily with alternate energy sources such as electricity and other fuel sources. In some areas, intrastate pipelines, other gas distributors and marketers also compete directly with our Natural Gas Distribution business segment for gas sales to end-users. In addition, as a result of federal regulatory changes affecting interstate pipelines, natural gas marketers operating on these pipelines may be able to bypass our Natural Gas Distribution business segment's facilities and market, sell and/or transport natural gas directly to commercial and industrial customers. Generally, the regulations of the states in which our Natural Gas Distribution business segment operates allow us to pass through changes in the costs of natural gas to our customers through purchased gas adjustment provisions in rates. There is, however, an inherent timing difference between our purchases of natural gas and the ultimate recovery of these costs. Consequently, we may incur additional "carrying" costs as a result of this timing difference and the resulting, temporary under-recovery of our purchased gas costs. To a large extent, these additional carrying costs are not recovered from our customers. Pipelines and Gathering. Our Pipelines and Gathering segment competes with other interstate and intrastate pipelines in the transportation and storage of natural gas. The principal elements of competition among pipelines are rates, terms of service, and flexibility and reliability of service. Our Pipelines and Gathering segment competes indirectly with other forms of energy available to its customers, including electricity, coal and fuel oils. The primary competitive factor is price. Changes in the availability of energy and pipeline capacity, the level of business activity, conservation and governmental regulations, the capability to convert to alternative fuels, and other factors, including weather, affect the demand for natural gas in areas we serve and the level of competition for transportation and storage services. Since FERC Order No. 636, REGT's and MRT's commodity sales activity has been minimal. Commodity transactions are usually related to system management activity which we have been able to manage with little exposure. We have not been nor do we anticipate to be, negatively impacted from the recent price levels and the tightening of supply. In addition, competition for our gathering operations is impacted by commodity pricing levels in its markets because these prices influence the level of drilling activity in those markets. Natural Gas Pipeline Company of America has proposed, and is soliciting customers for a 30" pipeline paralleling MRT's East Line in Illinois to a point 17 miles East of St. Louis Metro, with a proposed in-service date of June 2002. MRT has renewed or is engaged in negotiations to renew service agreements under multi-year terms, including service and potential expansion needs along MRT's existing East Line in Illinois. Our Pipelines and Gathering business segment derives approximately 14% of its revenues from its contract with Laclede, which has been under an annual evergreen term provision since 1999. In the event we are not able to renegotiate a long-term extension to the contract with Laclede, and Laclede engages another pipeline for the transportation services it currently obtains from us, the operating and financial results of our Pipelines and Gathering business segment would be materially adversely affected. FLUCTUATIONS IN COMMODITY PRICES AND DERIVATIVE INSTRUMENTS For information regarding our exposure to risk as a result of fluctuations in commodity prices and derivative instruments, please read "Quantitative and Qualitative Disclosures About Market Risk" in Item 7A of this Form 10-K. INDEXED DEBT SECURITIES (ZENS) AND OUR AOL TIME WARNER INVESTMENT For information on our indexed debt securities and our investment in AOL Time Warner common stock, please read "Quantitative and Qualitative Disclosures About Market Risk" in Item 7A of this Form 10-K and Note 8 to our consolidated financial statements. 11 ENVIRONMENTAL EXPENDITURES We are subject to numerous environmental laws and regulations, which require us to incur substantial costs to operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past operations on the environment. For additional information regarding environmental contingencies, please read Note 14(g) to our consolidated financial statements. Clean Air Act Expenditures. We expect the majority of capital expenditures associated with environmental matters to be incurred by our Electric Operations and Wholesale Energy business segments in connection with emission limitations for NOx under the Clean Air Act, or to enhance operational flexibility under Clean Air Act requirements. In 2000, emission reduction requirements for NOx were finalized for our electric generating facilities in Texas and the Mid-Atlantic region. We currently estimate that up to $534 million will be required to comply with the requirements through the end of 2003, with an estimated $215 million to be incurred in 2001. The Texas regulations require additional reductions that must be completed by March 2007. Estimates for the Texas units for the period 2004 through 2007 have not been defined, but could be up to $230 million. We are currently litigating the economic and technical viability of the Texas post-2004 reduction requirements, but cannot predict the outcome of this litigation. In addition, the Legislation created a program mandating air emissions reductions for some generating facilities of our Electric Operations segment. The Legislation provides for stranded costs recovery for costs associated with this obligation incurred before May 1, 2003. For additional information regarding the Legislation, please read Note 4(a) to our consolidated financial statements. Additional NOx emission controls for our generating units located in California may result in expenditures of up to $30 million through 2002. For additional information regarding environmental regulation of air emissions, please read "Business -- Environmental Matters -- Air Emissions" in Item 1 of this Form 10-K. Site Remediation Expenditures. From time to time we have received notices from regulatory authorities or others regarding our status as a potentially responsible party in connection with sites found to require remediation due to the presence of environmental contaminants. Based on currently available information, we believe that remediation costs will not materially affect our financial position, results of operations or cash flows. There can be no assurance, however, that future developments, including additional information about existing sites or the identification of new sites, will not require material revisions to our estimates. For information about specific sites that are the subject of remediation claims, please read Note 14(g) to our consolidated financial statements and Note 9(c) to RERC's consolidated financial statements. Water, Mercury and Other Expenditures. As discussed under "Business -- Environmental Matters -- Water Issues" in Item 1 of this Form 10-K, regulatory authorities are in the process of implementing regulations and quality standards in connection with the discharge of pollutants into waterways. Once these regulations and quality standards are enacted, we will be able to determine if our operations are in compliance, or if we will have to incur costs in order to comply with the quality standards and regulations. Until that time, however, we are not able to predict the amount of these expenditures, if any. To date, however, our expenditures associated with respect to permits, registrations and authorizations for operation of facilities under the statutes regulating the discharge of pollutants into surface water have not been material. With regard to mercury remediation and other environmental matters, such as the disposal of solid wastes, our expenditures have not been, and are not expected to be material, based on our experiences and that of others in our industries. Please read "Business -- Environmental Matters -- Mercury Contamination" and "-- Other" in Item 1 of this Form 10-K. OTHER CONTINGENCIES For a description of other legal and regulatory proceedings affecting us, please read Notes 4 and 14 to our consolidated financial statements and Note 9 to RERC's consolidated financial statements. 12 ITEMS INCORPORATED BY REFERENCE FROM THE RELIANT ENERGY RESOURCE CORP. FORM 10-K o ITEM 3. LEGAL PROCEEDINGS (b) RERC CORP. For a description of certain legal and regulatory proceedings affecting RERC, see Notes 9(c) and 9(d) to RERC's consolidated financial statements, which notes are incorporated herein by reference. o ITEM 7. MANAGEMENT'S NARRATIVE ANALYSIS OF THE RESULTS OF OPERATIONS OF RERC AND ITS CONSOLIDATED SUBSIDIARIES The following narrative and analysis should be read in combination with the consolidated financial statements and notes of Reliant Energy Resources Corp. (RERC Corp.) and its subsidiaries (collectively, RERC) contained in Item 8 of the Form 10-K of RERC Corp. RELIANT ENERGY RESOURCES CORP. Because RERC Corp. is a wholly owned subsidiary of Reliant Energy, Incorporated (Reliant Energy), RERC's determination of reportable segments considers the strategic operating units under which Reliant Energy manages sales, allocates resources and assesses performance of various products and services to wholesale or retail customers in differing regulatory environments. Reliant Energy has identified the following reportable segments: Electric Operations, Natural Gas Distribution, Pipelines and Gathering, Wholesale Energy, European Energy, and Other Operations. Of these segments, the following operations have historically been conducted by RERC: - Natural Gas Distribution, - Pipelines and Gathering, - Wholesale Energy (which includes wholesale energy trading, marketing, power origination and risk management services in North America but excludes the operations of Reliant Energy Power Generation, Inc., an indirect wholly owned subsidiary of Reliant Energy), - European Energy (which includes the energy trading and marketing operations initiated in the fourth quarter of 1999 in the Netherlands and other countries in Europe but excludes N.V. UNA, a Dutch power company), and - Certain Other Operations. On July 27, 2000, Reliant Energy announced its intention to divide into two publicly traded companies in order to separate its unregulated businesses from its regulated businesses. In August 2000, Reliant Energy formed Reliant Resources, Inc. (Reliant Resources) to own and operate a substantial portion of Reliant Energy's unregulated operations and to offer no more than 20% of Reliant Resources' common stock in an initial public offering (Offering). Reliant Energy expects the Offering to be followed by a distribution to Reliant Energy's or its successor's shareholders of the remaining common stock of Reliant Resources within twelve months after the Offering. On December 31, 2000, RERC Corp. transferred all of the outstanding capital stock of Reliant Energy Services International, Inc. (RESI), Arkla Finance Corporation (Arkla Finance) and Reliant Energy Europe Trading & Marketing, Inc. (RE Europe Trading), all of which were wholly owned subsidiaries of RERC Corp., to Reliant Resources (collectively, Stock Transfer). Both RERC Corp. and Reliant Resources are wholly owned subsidiaries of Reliant Energy. As a result of the Stock Transfer, RESI, Arkla Finance and RE Europe Trading each became a wholly owned subsidiary of Reliant Resources. Also, on December 31, 2000, a wholly owned subsidiary of Reliant Resources merged with and into Reliant Energy Services, Inc. (Reliant Energy Services), a wholly owned subsidiary of RERC Corp., with 13 Reliant Energy Services as the surviving corporation (Merger). As a result of the Merger, Reliant Energy Services became a wholly owned subsidiary of Reliant Resources. As consideration for the Stock Transfer and the Merger, Reliant Resources paid $94 million to RERC Corp. Reliant Energy Services, together with RESI and RE Europe Trading, conduct the Wholesale Energy segment's trading, marketing, power origination and risk management business and operations of Reliant Energy. Arkla Finance is a company that holds an investment in marketable equity securities. RERC Corp. has guaranteed or indemnified the performance of a portion of the obligations of Reliant Energy's trading, marketing, power origination and risk management businesses. Some of these guarantees and indemnities are for fixed amounts, others have a fixed maximum amount and others do not specify a maximum amount. Pursuant to the master separation agreement, Reliant Resources will agree to indemnify RERC Corp. for any amounts RERC Corp. pays under these guarantees and indemnities. The Stock Transfer and the Merger are part of Reliant Energy's previously announced restructuring. RERC is reporting the results of RE Europe Trading as discontinued operations for all periods presented in the consolidated financial statements in accordance with Accounting Principles Board Opinion No. 30. For additional information regarding the operating results of the entities transferred to Reliant Resources, please read Note 13 to RERC's consolidated financial statements. RERC Corp. meets the conditions specified in General Instruction I (1)(a) and (b) to Form 10-K and is thereby permitted to use the reduced disclosure format for wholly owned subsidiaries of reporting companies specified therein. Accordingly, RERC Corp. has omitted from this Combined Form 10-K the information called for by Item 4 (submission of matters to a vote of security holders), Item 10 (directors and executive officers), Item 11 (executive compensation), Item 12 (security ownership of certain beneficial owners and management) and Item 13 (certain relationships and related party transactions) of Form 10-K. In lieu of the information called for by Item 6 (selected financial data) and Item 7 (management's discussion and analysis of financial condition and results of operations) of Form 10-K, RERC Corp. has included the following Management's Narrative Analysis of the Results of Operations to explain material changes in the amount of revenue and expense items of RERC between 1998, 1999 and 2000. Reference is hereby made to Item 1 (Business), Item 2 (Properties), Item 3 (Legal Proceedings), Item 5 (Market for Reliant Energy's and RERC Corp's Common Equity and Related Stockholder Matters), Item 7A (Quantitative and Qualitative Disclosures about Market Risk) and Item 9 (Changes in and Disagreements with Accountants on Accounting and Financial Disclosure) of this Combined Form 10-K for additional information regarding RERC required by the reduced disclosure format of General Instruction I to Form 10-K. CONSOLIDATED RESULTS OF OPERATIONS RERC's results of operations are affected by seasonal fluctuations in the demand for natural gas and price movements of energy commodities. RERC's results of operations are also affected by, among other things, the actions of various federal and state governmental authorities having jurisdiction over rates charged by RERC, competition in RERC's various business operations, debt service costs and income tax expense. For a discussion of some other factors that may affect RERC's future earnings please read "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Certain Factors Affecting Our Future Earnings -- Business Separation and Restructuring," "-- Competitive and Other Factors Affecting RERC Operations" and "-- Environmental Expenditures" in Item 7 of Reliant Energy's 2000 Form 10-K. 14 The following table sets forth selected financial and operating data for the years ended December 31, 1998, 1999 and 2000, followed by a discussion of significant variances in period-to-period results: SELECTED FINANCIAL RESULTS
YEAR ENDED DECEMBER 31, ----------------------------- 1998 1999 2000 ------- -------- -------- (IN MILLIONS) Operating Revenues.................................... $ 6,758 $ 10,543 $ 22,659 Operating Expenses.................................... (6,448) (10,242) (22,327) ------- -------- -------- Operating Income...................................... 310 301 332 Interest Expense, net................................. (111) (119) (143) Distribution on Trust Preferred Securities............ (1) -- -- Other Income, net..................................... 8 11 2 Income Tax Expense.................................... (112) (89) (93) ------- -------- -------- Income from Continuing Operations..................... 94 104 98 Loss from Discontinued Operations..................... -- (4) (24) ------- -------- -------- Net Income.................................. $ 94 $ 100 $ 74 ======= ======== ========
2000 Compared to 1999. RERC's net income for 2000 was $74 million compared to net income of $100 million in 1999. The $26 million decrease in net income was primarily due to: - a decline in operating income of the Natural Gas Distribution segment, - an after-tax impairment loss of $17 million on marketable equity securities classified as "available-for-sale" incurred in 2000 by the Other Operations segment, - increased third-party interest expense primarily resulting from higher levels of short-term borrowings and long-term debt during 2000 compared to 1999, and - increased start-up costs of the European trading and marketing operations in 2000 included in loss from discontinued operations. The above items were partially offset by improved operating results from the Wholesale Energy segment's trading and marketing operations in North America, increased operating income from the Pipelines and Gathering segment, increased interest income earned on margin deposits on energy trading activities and income resulting from a tax refund in 2000. During 2000, RERC incurred a pre-tax impairment loss of $27 million on marketable equity securities classified as "available-for-sale" by the Other Operations segment. Management's determination to recognize this impairment resulted from a combination of events occurring in 2000 related to this investment. These events affecting the investment included changes occurring in the investment's senior management, announcement of significant restructuring charges and related downsizing for the entity, reduced earnings estimates for this entity by brokerage analysts and the bankruptcy of a competitor of the investment in the first quarter of 2000. These events, coupled with the stock market value of RERC's investment in these securities continuing to be below RERC's cost basis, caused management to believe the decline in fair value to be other than temporary. This investment is held by Arkla Finance which was transferred to Reliant Resources effective December 31, 2000. Operating income increased in 2000 by $31 million, or 10%, from 1999. The increase was primarily due to significantly improved operating margins (revenues less natural gas and purchased power expenses) from the Wholesale Energy segment's trading and marketing activity in the western U.S. market (primarily California and Nevada), increased operating margins (revenues less natural gas expenses) from the Natural Gas 15 Distribution segment and increased gathering and processing revenues from the Pipelines and Gathering segment. These items were partially offset by increased operating expenses, including: - costs incurred in connection with non-rate regulated retail natural gas business activities outside RERC's established market areas, which have been discontinued, - additional provisions against receivable balances resulting from the implementation of a new billing system for Reliant Energy Arkla, - increased costs associated with higher staffing levels to support increased sales and expanded trading and marketing efforts, - increased depreciation expenses of the Natural Gas Distribution segment, and - increased benefit expense related to an updated actuarial valuation of employee benefit plans. RERC's operating revenues for 2000 were $22.7 billion compared to $10.5 billion for 1999. The $12.2 billion, or 115%, increase was primarily due to the increase in the Wholesale Energy segment's trading and marketing revenues from increased trading volumes for power and natural gas, as well as higher sale prices for these commodities. RERC's operating expenses for 2000 were $22.3 billion compared to $10.2 billion in 1999. The $12.1 billion, or 118%, increase was primarily due to an increase in volumes and cost of purchased power and natural gas, as discussed above. Other operating expenses also increased due to the increase in expenses discussed above. RERC's effective tax rate in 2000 was 49% compared to 46% in 1999. This increase was primarily due to an increase in state income taxes in 2000 as compared to 1999. RERC is reporting the results of RE Europe Trading as discontinued operations for all periods presented in RERC's consolidated financial statements in accordance with Accounting Principles Board Opinion No. 30. For additional information, please read Note 13 to RERC's consolidated financial statements. The European Energy segment was created in the fourth quarter of 1999 with the acquisition of N.V. UNA by a subsidiary of Reliant Energy. Beginning in the second half of 2000, the European Energy segment's trading and marketing operations began participating in the emerging wholesale energy trading and marketing industry in Northwest Europe. Losses from discontinued operations in 1999 and 2000 are primarily related to start-up costs for the European trading and marketing operations. For additional information regarding the operating results of the other entities transferred to Reliant Resources, please read Note 13 to RERC's consolidated financial statements. 1999 Compared to 1998. RERC's net income for 1999 was $100 million compared to net income of $94 million in 1998. The $6 million increase was primarily due to: - a significant increase in operating margins of the Wholesale Energy segment's trading and marketing operations, and - a decrease in RERC's effective tax rate. The above items were partially offset by decreased earnings in the Natural Gas Distribution and Pipelines and Gathering segments and increased general insurance liability expense. Although results of the Wholesale Energy segment's trading and marketing operations significantly improved, it continues to incur higher operating expenses relating to staffing and personnel to support its increased sales and marketing efforts. Operating income decreased in 1999 by $9 million, or 3%, from 1998. The decline was primarily due to increased operating expenses, in particular employee benefit expenses at the Natural Gas Distribution and Pipelines and Gathering segments and increased general liability insurance expense. The decline was partially offset by increased operating income of the Wholesale Energy segment's trading and marketing operations. 16 RERC's operating revenues for 1999 were $10.5 billion compared to $6.8 billion for 1998. The $3.7 billion, or 56%, increase was primarily due to increased wholesale trading and marketing revenues from increased trading volumes for power, natural gas and oil, as well as higher sale prices for these commodities. RERC's operating expenses for 1999 were $10.2 billion compared to $6.4 billion in 1998. The $3.8 billion, or 59%, increase was primarily attributable to an increase in volumes and cost of purchased power, natural gas and oil, as discussed above. In addition, operating expenses also increased due to: - increased employee benefit expenses for the Natural Gas Distribution and Pipelines and Gathering segments, - increased operating expenses to support increased sales and marketing of the Wholesale Energy segment's trading and marketing operations (as discussed above), and - increased general insurance liability expense. RERC's effective tax rate in 1999 was 46% compared to 54% in 1998. This decrease was primarily due to a decrease in state income taxes in 1999 as compared to 1998. NEW ACCOUNTING PRONOUNCEMENTS Reference is made to "Management's Discussion and Analysis of Financial Condition and Results of Operations -- New Accounting Pronouncements" in Item 7 of Reliant Energy's 2000 Form 10-K, which section is incorporated by reference herein, and Note 2(q) to RERC's consolidated financial statements, for discussion of new accounting issues that affect RERC. ITEMS INCORPORATED BY REFERENCE FROM THE RELIANT ENERGY 10-K NOTES o (2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (f) Regulatory Assets. RERC applies the accounting policies established in Statement of Financial Accounting Standards (SFAS) No. 71 "Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71) to the accounts of the utility operations of Natural Gas Distribution and MRT. As of December 31, 1999 and 2000, RERC had recorded $4 million and $5 million, respectively, of net regulatory assets. If, as a result of changes in regulation or competition, RERC's ability to recover these assets and liabilities would not be assured, then pursuant to SFAS No. 101, "Regulated Enterprises Accounting for the Discontinuation of Application of SFAS No. 71" (SFAS No. 101) and SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" (SFAS No. 121), RERC would be required to write off or write down these regulatory assets and liabilities. In addition, RERC would be required to determine any impairment to the carrying costs of plant and inventory assets. o (4) DERIVATIVE FINANCIAL INSTRUMENTS (a) Price Risk Management and Trading Activities. Historically, RERC offered energy price risk management services primarily related to natural gas, electric power and other energy related commodities, through Reliant Energy Services. As discussed in Note 1, effective December 31, 2000, Reliant Energy Services is no longer a part of RERC. RERC provided these services by utilizing a variety of derivative financial instruments, including (a) fixed and variable-priced physical forward contracts, (b) fixed and variable-priced swap agreements, (c) options traded in the over-the-counter financial markets and (d) exchange-traded energy futures and option contracts (Trading Derivatives). Fixed-price swap agreements require payments to, or receipts of payments from, counterparties based on the differential between a fixed and variable price for the commodity. Variable-price swap agreements require 17 payments to, or receipts of payments from, counterparties based on the differential between industry pricing publications or exchange quotations. RERC applied mark-to-market accounting for all of its energy trading, marketing and price risk management operations. Accordingly, these Trading Derivatives are recorded at fair value with realized and unrealized gains (losses) recorded as a component of revenues. The recognized, unrealized balances are included in price risk management assets/liabilities. The notional quantities, maximum terms and estimated fair value of Trading Derivatives at December 31, 1999 are presented below (volumes in billions of British thermal units equivalent (Bbtue) and dollars in millions):
VOLUME-FIXED VOLUME-FIXED PRICE MAXIMUM PRICE PAYOR RECEIVER TERM (YEARS) ------------ ------------ ------------ 1999 Natural gas.................................... 1,278,953 1,251,319 9 Electricity.................................... 242,868 239,452 10 Oil and other.................................. 285,251 286,521 3
FAIR VALUE AVERAGE FAIR VALUE(1) ---------------------- ---------------------- ASSETS LIABILITIES ASSETS LIABILITIES ------ ----------- ------ ----------- 1999 Natural gas................................. $581 $564 $550 $534 Electricity................................. 122 91 96 74 Oil and other............................... 193 206 183 187 ---- ---- ---- ---- $896 $861 $829 $795 ==== ==== ==== ====
- --------------- (1) Computed using the ending balance of each quarter. In addition to the fixed-price notional volumes above, RERC also had variable-priced agreements, as discussed above, totaling 2,147,173 Bbtue as of December 31, 1999. Notional amounts reflect the commodity volumes underlying the transactions but do not represent the amounts exchanged by the parties to the financial instruments. Accordingly, notional amounts do not accurately measure RERC's exposure to market or credit risks. All of the fair values shown in the table above at December 31, 1999, have been recognized in income. RERC estimated the fair value as of December 31, 1999, using quoted prices where available and other valuation techniques when market data was not available, for example in illiquid markets. For financial instruments for which quoted prices are not available, RERC utilized alternative pricing methodologies, including, but not limited to, extrapolation of forward pricing curves using historically reported data from illiquid pricing points. These same pricing techniques were used to evaluate a contract prior to taking the position. The weighted-average term of the trading portfolio, based on volumes, is less than one year. The maximum and average terms disclosed herein are not indicative of likely future cash flows, as these positions may be changed by new transactions in the trading portfolio at any time in response to changing market conditions, market liquidity and RERC's risk management portfolio needs and strategies. Terms regarding cash settlements of these contracts vary with respect to the actual timing of cash receipts and payments. In addition to the risk associated with price movements, credit risk was also inherent in RERC's risk management activities. Credit risk relates to the risk of loss resulting from non-performance of contractual 18 obligations by a counterparty. The following table shows the composition of the total price risk management assets of RERC as of December 31, 1999.
DECEMBER 31, 1999 ------------------ INVESTMENT GRADE(1) TOTAL ---------- ----- (IN MILLIONS) Energy marketers............................................ $202 $230 Financial institutions...................................... 90 159 Gas and electric utilities.................................. 220 221 Oil and gas producers....................................... 31 31 Industrials................................................. 3 4 Others...................................................... 174 263 ---- ---- Total............................................. $720 908 ==== Credit and other reserves................................... (12) ---- Energy price risk management assets......................... $896 ====
- --------------- (1) "Investment Grade" is primarily determined using publicly available credit ratings along with the consideration of credit support (such as parent company guarantees) and collateral, which encompass cash and standby letters of credit. (b) Non-trading Activities. To reduce the risk from market fluctuations in the revenues derived from the sale of natural gas and related transportation, RERC enters into futures transactions, forward contracts, swaps and options (Energy Derivatives) in order to hedge some expected purchases of natural gas and sales of natural gas (a portion of which are firm commitments at the inception of the hedge). Energy Derivatives are also utilized to fix the price of compressor fuel or other future operational gas requirements and to protect natural gas distribution earnings against unseasonably warm weather during peak gas heating months, although usage to date for this purpose has not been material. RERC applies hedge accounting for its derivative financial instruments utilized in non-trading activities. Unrealized changes in the market value of Energy Derivatives utilized as hedges are not generally recognized in RERC's Statements of Consolidated Income until the underlying hedged transaction occurs. Once it becomes probable that an anticipated transaction will not occur, RERC recognizes deferred gains and losses. In general, the financial impact of transactions involving these Energy Derivatives is included in RERC's Statements of Consolidated Income under the captions fuel expenses, in the case of natural gas transactions and revenues, in the case of natural gas sales transactions. Cash flows resulting from these transactions in Energy Derivatives are included in RERC's Statements of Consolidated Cash Flows in the same category as the item being hedged. For transactions involving Energy Derivatives, hedge accounting is applied only if the derivative reduces the risk of the underlying hedged item and is designated as a hedge at its inception. Additionally, the derivatives must be expected to result in financial impacts that are inversely correlated to those of the item(s) to be hedged. This correlation, a measure of hedge effectiveness, is measured both at the inception of the hedge and on an ongoing basis, with an acceptable level of correlation of at least 80% for hedge designation. If and when correlation ceases to exist at an acceptable level, hedge accounting ceases and mark-to-market accounting is applied. At December 31, 1999, RERC was a fixed-price payor and a fixed-price receiver in Energy Derivatives covering 29,596 billion British thermal units (Bbtu) and 5,481 Bbtu of natural gas, respectively. At December 31, 2000, RERC was a fixed-price payor and a fixed-price receiver in Energy Derivatives covering 40,991 Bbtu and 14,949 Bbtu of natural gas, respectively. In addition to the fixed-price notional volumes, RERC also has variable-priced agreements totaling 41,341 Bbtu and 12,630 Bbtu at December 31, 1999 and 2000, respectively. The weighted average maturity of these instruments is less than one year. 19 The notional amount is intended to be indicative of RERC's level of activity in these derivatives. However, the amounts at risk are significantly smaller because, in view of the price movement correlation required for hedge accounting, changes in the market value of these derivatives generally are offset by changes in the value associated with the underlying physical transactions or in other derivatives. When Energy Derivatives are closed out in advance of the underlying commitment or anticipated transaction, however, the market value changes may not offset due to the fact that price movement correlation ceases to exist when the positions are closed, as further discussed above. Under these circumstances, gains (losses) are deferred and recognized as a component of income when the underlying hedged item is recognized in income. The average maturity discussed above and the fair value discussed in Note 10 are not necessarily indicative of likely future cash flows as these positions may be changed by new transactions at any time in response to changing market conditions, market liquidity and RERC's risk management portfolio needs and strategies. Terms regarding cash settlements of these contracts vary with respect to the actual timing of cash receipts and payments. (c) Trading and Non-trading -- General Policy. In addition to the risk associated with price movements, credit risk is also inherent in RERC's risk management activities. Credit risk relates to the risk of loss resulting from non-performance of contractual obligations by a counterparty. RERC has off-balance sheet risk to the extent that the counterparties to these transactions may fail to perform as required by the terms of each contract. In order to minimize this risk, RERC enters into these contracts primarily with counterparties having a minimum investment grade index rating, i.e. a Standard & Poor's or Moody's rating of BBB- or Baa3, respectively. For long-term arrangements, RERC periodically reviews the financial condition of these firms in addition to monitoring the effectiveness of these financial contracts in achieving RERC's objectives. If the counterparties to these arrangements fail to perform, RERC would seek to compel performance at law or otherwise obtain compensatory damages. RERC might be forced to acquire alternative hedging arrangements or be required to replace the underlying commitment at then-current market prices. In this event, RERC might incur additional losses to the extent of amounts, if any, already paid to the counterparties. RERC's policies prohibit the use of leveraged financial instruments. A leveraged instrument, for this purpose, is a transaction involving a derivative whose financial impact will be based on an amount other than the notional amount or volume of the instrument. Reliant Energy has established a Risk Oversight Committee, comprised of corporate and business segment officers that oversees all commodity price and credit risk activities, including RERC's trading, marketing, power origination and risk management activities. The committee's duties are to establish RERC's commodity risk policies, allocate risk capital within limits established by Reliant Energy's Board of Directors, approve trading of new products and commodities, monitor risk positions and ensure compliance with Reliant Energy's risk management policies and procedures and trading limits established by Reliant Energy's Board of Directors. 20 o (9) COMMITMENTS AND CONTINGENCIES (a) Lease Commitments. The following table sets forth information concerning RERC's obligations under non-cancelable long-term operating leases principally consisting of rental agreements for building space, data processing equipment and vehicles, including major work equipment (in millions): 2001........................................................ $13 2002........................................................ 8 2003........................................................ 7 2004........................................................ 5 2005........................................................ 4 2006 and beyond............................................. 18 --- Total............................................. $55 ===
RERC has a master leasing agreement which provides for the lease of vehicles, construction equipment, office furniture, data processing equipment and other property. For accounting purposes, the lease is treated as an operating lease. At December 31, 2000, the unamortized value of equipment covered by the master leasing agreement was $10 million. RERC does not expect to lease additional property under this lease agreement. Total rental expense for all leases was $25 million, $33 million and $19 million in 1998, 1999 and 2000, respectively. (b) Transportation Agreement. A predecessor of Reliant Energy Services had an agreement (ANR Agreement) with ANR Pipeline Company (ANR) which contemplated that RERC would transfer to ANR an interest in some of RERC's pipeline and related assets. The interest represented capacity of 250 Mmcf/day. Under the ANR Agreement, an ANR affiliate advanced $125 million to RERC. Subsequently, the parties restructured the ANR Agreement and RERC refunded in 1995 and 1993, respectively, $50 million and $34 million to ANR or an affiliate. Reliant Energy Services recorded a liability reflecting ANR's or its affiliates' use of 130 Mmcf/day of capacity in some of RERC's transportation facilities. The level of transportation will decline to 100 Mmcf/day in the year 2003 with a refund of $5 million to an ANR affiliate. The ANR Agreement will terminate in 2005 with a refund of the $36 million. RERC has agreed to reimburse Reliant Energy Services for any transportation payments made under the ANR agreement and for the refund of the $41 million. In RERC's Consolidated Balance Sheets, RERC has recorded a long-term notes payable to Reliant Energy Services of $28 million and a deferred obligation to ANR of $13 million as of December 31, 2000. (c) Environmental Matters. Manufactured Gas Plant Sites. RERC and its predecessors operated a manufactured gas plant (MGP) adjacent to the Mississippi River in Minnesota formerly known as Minneapolis Gas Works (MGW) until 1960. RERC has substantially completed remediation of the main site other than ongoing water monitoring and treatment. The manufactured gas was stored in separate holders. RERC is negotiating cleanup of one such holder. There are six other former MGP sites in the Minnesota service territory. Remediation has been completed on one site. Of the remaining five sites, RERC believes that two were neither owned nor operated by RERC. RERC believes it has no liability with respect to the sites it neither owned nor operated. At December 31, 1999 and 2000, RERC had accrued $19 million and $17 million, respectively, for remediation of the Minnesota sites. At December 31, 2000, the estimated range of possible remediation costs was $8 million to $36 million. The cost estimates of the MGW site are based on studies of that site. The remediation costs for the other sites are based on industry average costs for remediation of sites of similar size. The actual remediation costs will be dependent upon the number of sites remediated, the participation of other potentially responsible parties, if any, and the remediation methods used. 21 Other Minnesota Matters. At December 31, 1999 and 2000, RERC had recorded accruals of $1 million and $2 million, respectively (with a maximum estimated exposure for these accruals of approximately $13 million and $17 million at December 31, 1999 and 2000, respectively), for other environmental matters in Minnesota for which remediation may be required. Issues relating to the identification and remediation of MGPs are common in the natural gas distribution industry. RERC has received notices from the United States Environmental Protection Agency and others regarding its status as a potentially responsible party (PRP) for other sites. Based on current information, RERC has not been able to quantify a range of environmental expenditures for potential remediation expenditures with respect to other MGP sites. Mercury Contamination. RERC's pipeline and distribution operations have in the past employed elemental mercury in measuring and regulating equipment. It is possible that small amounts of mercury may have been spilled in the course of normal maintenance and replacement operations and that these spills may have contaminated the immediate area with elemental mercury. This type of contamination has been found by RERC at some sites in the past, and RERC has conducted remediation at sites found to be contaminated. Although RERC is not aware of additional specific sites, it is possible that other contaminated sites may exist and that remediation costs may be incurred for these sites. Although the total amount of these costs cannot be known at this time, based on experience by RERC and that of others in the natural gas industry to date and on the current regulations regarding remediation of these sites, RERC believes that the costs of any remediation of these sites will not be material to RERC's financial position, results of operations or cash flows. Potentially Responsible Party Notifications. From time to time RERC has received notices from regulatory authorities or others regarding its status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. Considering the information currently known about such sites and the involvement of RERC in activities at these sites, RERC does not believe that these matters will have a material adverse effect on RERC's financial position, results of operations or cash flows. (d) Other Legal Matters. California Wholesale Market. Reliant Energy and Reliant Energy Services 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. RERC Corp. has also been named as a defendant in one of the lawsuits. Pursuant to the terms of the master separation agreement between Reliant Energy and Reliant Resources (see Note 1), Reliant Resources will agree to indemnify Reliant Energy and RERC Corp. for any damages arising under this lawsuit and may elect to defend this lawsuit at Reliant Resources' own expense. This lawsuit was filed in Superior Court in San Francisco County in January 2001. While plaintiffs alleged various violations by the defendants of the state antitrust laws and state laws against unfair and unlawful business practices, this lawsuit is grounded on the central allegation that defendants conspired to drive up the wholesale price of electricity. In addition to injunctive relief, the plaintiffs in this lawsuit seek restitution of alleged overpayments, disgorgement of alleged unlawful profits for sales of electricity during all or portions of 2000, costs of suit and attorneys' fees. Defendants have filed petitions to remove this case to federal court. Furthermore, defendants have filed a motion with the Panel on Multidistrict Litigation seeking transfer and consolidation of all the cases. This lawsuit has only recently been filed. Therefore, the ultimate outcome of this lawsuit cannot be predicted with any degree of certainty at this time. However, RERC Corp. does not believe, based on its analysis to date of the claims asserted in this lawsuit, the indemnification agreement with Reliant Resources and the underlying facts, that resolution of this lawsuit will have a material adverse effect on RERC's financial condition, results of operations or cash flows. RERC is a party to litigation (other than that specifically noted) which arises in the normal course of business. Management regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. Management believes that the effects, if any, from the disposition of these matters will not have a material adverse effect on RERC's financial position, results of operations or cash flows. 22 -----END PRIVACY-ENHANCED MESSAGE-----