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1 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, 1999 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 12 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 5, 1999, Reliant Energy, Incorporated had 295,671,579 shares of common stock outstanding, including 10,719,489 ESOP shares not deemed outstanding for financial statement purposes and excluding 1,610,918 shares held as treasury stock. As of November 5, 1999, all 1,000 shares of Reliant Energy Resources Corp. common stock were held by Reliant Energy, Incorporated.
2 THIS COMBINED QUARTERLY REPORT ON FORM 10-Q IS SEPARATELY FILED BY RELIANT ENERGY, INCORPORATED (COMPANY) AND RELIANT ENERGY RESOURCES CORP. (RESOURCES). INFORMATION CONTAINED HEREIN RELATING TO RESOURCES IS FILED BY THE COMPANY AND SEPARATELY BY RESOURCES ON ITS OWN BEHALF. RESOURCES MAKES NO REPRESENTATION AS TO INFORMATION RELATING TO THE COMPANY (EXCEPT AS IT MAY RELATE TO RESOURCES AND ITS SUBSIDIARIES) OR TO ANY OTHER AFFILIATE OR SUBSIDIARY OF THE COMPANY. RELIANT ENERGY, INCORPORATED AND RELIANT ENERGY RESOURCES CORP. QUARTERLY REPORT ON FORM 10-Q FOR THE QUARTER ENDED SEPTEMBER 30, 1999 TABLE OF CONTENTS PART I. FINANCIAL INFORMATION COMPANY: Financial Statements...............................................................................1 Statements of Consolidated Operations Three and Nine Months Ended September 30, 1999 and 1998 (Unaudited)............................1 Consolidated Balance Sheets September 30, 1999 (Unaudited) and December 31, 1998...........................................2 Statements of Consolidated Cash Flows Nine Months Ended September 30, 1999 and 1998 (Unaudited)......................................4 Statements of Consolidated Retained Earnings and Comprehensive Income (Loss) Three and Nine Months Ended September 30, 1999 and 1998 (Unaudited)............................6 Notes to Unaudited Consolidated Financial Statements...........................................7 Management's Discussion and Analysis of Financial Condition and Results of Operations of the Company.....................................................................19 Quantitative and Qualitative Disclosures About Market Risk of the Company.........................34 RESOURCES: Financial Statements..............................................................................36 Statements of Consolidated Operations Three and Nine Months Ended September 30, 1999 and 1998 (Unaudited)...........................36 Consolidated Balance Sheets September 30, 1999 (Unaudited) and December 31, 1998..........................................37 Statements of Consolidated Cash Flows Nine Months Ended September 30, 1999 and 1998 (Unaudited).....................................39 Consolidated Statements of Retained Earnings and Comprehensive Income (Loss) Three and Nine Months Ended September 30, 1999 and 1998 (Unaudited)...........................40 Notes to Unaudited Consolidated Financial Statements..........................................41 Management's Narrative Analysis of the Results of Operations of Resources.......................................................................43 PART II. OTHER INFORMATION Item 1. Legal Proceedings......................................................................45 Item 5. Other Information......................................................................45 Item 6. Exhibits and Reports on Form 8-K.......................................................46
3 PART I. FINANCIAL INFORMATION RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED OPERATIONS (THOUSANDS OF DOLLARS, EXCEPT PER SHARE AMOUNTS) (UNAUDITED) THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------------------ ------------------------------ 1999 1998 1999 1998 ------------ ------------ ------------ ------------ REVENUES: Electric Operations ...................................... $ 1,496,596 $ 1,415,832 $ 3,513,144 $ 3,443,694 Natural Gas Distribution ................................. 302,698 266,177 1,310,153 1,327,562 Interstate Pipelines ..................................... 70,024 70,394 202,246 217,891 Wholesale Energy ......................................... 2,908,119 1,610,653 5,854,052 3,416,048 International ............................................ 34,126 31,813 26,273 228,494 Corporate ................................................ 250,036 157,351 673,209 502,593 Eliminations ............................................. (114,407) (86,733) (331,153) (302,847) ------------ ------------ ------------ ------------ Total ................................................ 4,947,192 3,465,487 11,247,924 8,833,435 ------------ ------------ ------------ ------------ EXPENSES: Fuel and cost of gas sold ................................ 1,563,552 1,143,149 4,631,147 3,487,332 Purchased power .......................................... 2,062,679 970,041 3,315,667 1,872,557 Operation and maintenance ................................ 455,687 430,060 1,281,898 1,184,545 Taxes other than income taxes ............................ 113,643 148,039 340,800 368,226 Depreciation and amortization ............................ 288,833 267,204 705,337 677,838 ------------ ------------ ------------ ------------ Total ................................................ 4,484,394 2,958,493 10,274,849 7,590,498 ------------ ------------ ------------ ------------ OPERATING INCOME ........................................... 462,798 506,994 973,075 1,242,937 ------------ ------------ ------------ ------------ OTHER INCOME (EXPENSE): Unrealized gain on Time Warner investment ................ 1,816,105 1,816,105 Unrealized gain (loss) on indexed debt securities ........ 406,717 (40,231) 6,778 (484,009) Time Warner dividend income .............................. 2,622 10,313 23,247 30,938 Other - net .............................................. 10,045 8,652 15,448 24,919 ------------ ------------ ------------ ------------ Total ................................................ 2,235,489 (21,266) 1,861,578 (428,152) ------------ ------------ ------------ ------------ INTEREST AND OTHER CHARGES: Interest on long-term debt ............................... 98,245 101,229 307,965 310,584 Other interest ........................................... 17,931 18,829 60,794 64,653 Distributions on trust securities ........................ 14,652 7,248 38,433 21,960 ------------ ------------ ------------ ------------ Total ................................................ 130,828 127,306 407,192 397,197 ------------ ------------ ------------ ------------ INCOME BEFORE INCOME TAXES AND PREFERRED DIVIDENDS ................................................ 2,567,459 358,422 2,427,461 417,588 INCOME TAX EXPENSE ......................................... 877,372 106,616 872,304 154,218 ------------ ------------ ------------ ------------ NET INCOME ................................................. 1,690,087 251,806 1,555,157 263,370 PREFERRED DIVIDENDS ........................................ 97 97 292 292 ------------ ------------ ------------ ------------ NET INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS .............................................. $ 1,689,990 $ 251,709 $ 1,554,865 $ 263,078 ============ ============ ============ ============ BASIC INCOME PER COMMON SHARE .............................. $ 5.92 $ .89 $ 5.45 $ .93 DILUTED INCOME PER COMMON SHARE ............................ $ 5.90 $ .88 $ 5.43 $ .92 See Notes to the Company's Consolidated Financial Statements. 1
4 RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (THOUSANDS OF DOLLARS) (UNAUDITED) ASSETS SEPTEMBER 30, DECEMBER 31, 1999 1998 ------------- ------------ CURRENT ASSETS: Cash and cash equivalents .......................................... $ 489,878 $ 29,673 Investment in Time Warner securities ............................... 3,343,160 Accounts receivable - net .......................................... 880,236 726,377 Accrued unbilled revenues .......................................... 113,004 175,515 Fuel, gas and petroleum products ................................... 209,300 211,750 Materials and supplies, at average cost ............................ 186,474 171,998 Price risk management assets ....................................... 481,147 265,203 Restricted deposit for bond redemption ............................. 70,315 Prepayments and other current assets ............................... 89,244 88,655 ----------- ----------- Total current assets ............................................. 5,862,758 1,669,171 ----------- ----------- PROPERTY, PLANT AND EQUIPMENT -- AT COST: Electric ........................................................... 14,423,741 13,969,302 Natural gas distribution and gathering systems ..................... 1,870,869 1,686,159 Interstate pipelines ............................................... 1,316,329 1,302,829 Other property ..................................................... 119,878 72,299 ----------- ----------- Total ............................................................ 17,730,817 17,030,589 Less accumulated depreciation and amortization ..................... 6,772,020 5,499,448 ----------- ----------- Property, plant and equipment - net .............................. 10,958,797 11,531,141 ----------- ----------- OTHER ASSETS: Goodwill - net ..................................................... 2,061,682 2,098,890 Equity investments and advances to unconsolidated affiliates ....... 936,338 1,051,600 Investment in Time Warner securities ............................... 990,000 Recoverable impaired plant costs ................................... 664,106 Price risk management assets ....................................... 100,593 21,414 Other .............................................................. 2,019,843 1,800,681 ----------- ----------- Total other assets ............................................... 5,782,562 5,962,585 ----------- ----------- TOTAL ASSETS ................................................... $22,604,117 $19,162,897 =========== =========== See Notes to the Company's Consolidated Financial Statements. 2
5 RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS - (CONTINUED) (THOUSANDS OF DOLLARS) (UNAUDITED) LIABILITIES AND STOCKHOLDERS' EQUITY SEPTEMBER 30, DECEMBER 31, 1999 1998 -------------- ------------ CURRENT LIABILITIES: Notes payable ........................................................... $ 1,883,163 $ 1,812,739 Accounts payable ........................................................ 899,419 807,977 Price risk management liabilities ....................................... 457,420 227,652 Current portion of long-term debt ....................................... 3,791,562 397,454 Other ................................................................... 1,032,239 825,120 -------------- -------------- Total current liabilities ........................................... 8,063,803 4,070,942 -------------- -------------- DEFERRED CREDITS: Accumulated deferred income taxes ....................................... 2,868,652 2,364,036 Unamortized investment tax credit ....................................... 274,397 328,949 Price risk management liabilities ....................................... 95,494 29,108 Other ................................................................... 1,034,289 905,014 -------------- -------------- Total deferred credits .............................................. 4,272,832 3,627,107 -------------- -------------- LONG-TERM DEBT ............................................................ 4,063,041 6,800,748 -------------- -------------- COMMITMENTS AND CONTINGENCIES (NOTE 1) TOTAL LIABILITIES ................................................. 16,399,676 14,498,797 -------------- -------------- COMPANY/RESOURCES OBLIGATED MANDATORILY REDEEMABLE TRUST PREFERRED SECURITIES OF SUBSIDIARY TRUSTS HOLDING SOLELY JUNIOR SUBORDINATED DEBENTURES OF COMPANY/RESOURCES - NET .................... 705,261 342,232 -------------- -------------- PREFERENCE STOCK, NONE OUTSTANDING CUMULATIVE PREFERRED STOCK, NOT SUBJECT TO MANDATORY REDEMPTION ........... 9,740 9,740 -------------- -------------- STOCKHOLDERS' EQUITY: Common stock, no par value ............................................ 3,170,989 3,136,826 Treasury stock, at cost ............................................... (41,198) (2,384) Unearned ESOP shares .................................................. (203,053) (217,780) Retained earnings ..................................................... 2,679,024 1,445,081 Accumulated other comprehensive loss .................................. (116,322) (49,615) -------------- -------------- Total stockholders' equity .......................................... 5,489,440 4,312,128 -------------- -------------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY ........................ $ 22,604,117 $ 19,162,897 ============== ============== See Notes to the Company's Consolidated Financial Statements. 3
6 RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED CASH FLOWS (THOUSANDS OF DOLLARS) (UNAUDITED) NINE MONTHS ENDED SEPTEMBER 30, ---------------------------- 1999 1998 ----------- ----------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income attributable to common stockholders ............................... $ 1,554,865 $ 263,078 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization .............................................. 705,337 677,838 Deferred income taxes ...................................................... 606,786 (154,092) Investment tax credit ...................................................... (54,552) (15,092) Unrealized gain on investment in Time Warner securities .................... (1,816,105) Unrealized (gain) loss on indexed debt securities .......................... (6,778) 484,009 Undistributed loss (earnings) of equity investments in unconsolidated affiliates ............................................................... 65,401 (26,496) Changes in other assets and liabilities: Accounts receivable - net ................................................ (91,348) (591,241) Accounts receivable - IRS ................................................ 140,532 Inventory ................................................................ (12,026) (129,444) Other current assets ..................................................... (589) (37,801) Accounts payable ......................................................... 91,442 528,582 Interest and taxes accrued ............................................... (44,821) 58,810 Other current liabilities ................................................ 122,936 (17,200) Net price risk management assets ......................................... 1,031 (4,638) Other - net .............................................................. 4,810 (2,766) ----------- ----------- Net cash provided by operating activities .............................. 1,126,389 1,174,079 ----------- ----------- CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures ......................................................... (708,542) (447,152) Investment in Time Warner securities ......................................... (537,055) Acquisitions of non-rate regulated electric power plants ..................... (275,056) Sale of equity investments in foreign electric system projects ............... 242,744 Equity investment in foreign electric system projects ........................ (240,377) Equity investment and advances to unconsolidated affiliates .................. (97,080) (42,439) Other - net ................................................................. 35,422 (40,339) ----------- ----------- Net cash used in investing activities .................................. $(1,307,255) $ (802,619) ----------- ----------- (Continued on next page) 4
7 RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED CASH FLOWS - (CONTINUED) (THOUSANDS OF DOLLARS) (UNAUDITED) NINE MONTHS ENDED SEPTEMBER 30, ---------------------------- 1999 1998 ----------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES: Payment of matured bonds ...................................... $ (76,000) Proceeds from issuance of indexed debt securities ............. $ 980,000 Proceeds from issuance of trust preferred securities .......... 362,994 Proceeds from issuance of pollution control revenue bonds ..... 284,102 454,258 Restricted deposit for bond redemption ........................ (70,315) (68,700) Proceeds from issuance of debentures .......................... 298,514 Payment of debentures ......................................... (12,042) Payment of common stock dividends ............................. (320,461) (316,968) Repurchase of common stock .................................... (38,757) Decrease in notes payable - net ............................... (153,835) (226,836) Extinguishment of long-term debt .............................. (395,636) (402,587) Redemption of convertible securities .......................... (57) (10,399) Other - net ................................................... 5,078 (18,151) ----------- ----------- Net cash provided by (used in) financing activities ....... 641,071 (366,869) ----------- ----------- NET INCREASE IN CASH AND CASH EQUIVALENTS ....................... 460,205 4,591 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD ................ 29,673 51,712 ----------- ----------- CASH AND CASH EQUIVALENTS AT END OF PERIOD ...................... $ 489,878 $ 56,303 =========== =========== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash payments: Interest (net of amounts capitalized) ......................... $ 365,052 $ 376,194 Income taxes .................................................. 277,725 302,474 See Notes to the Company's Consolidated Financial Statements. 5
8 RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED RETAINED EARNINGS AND COMPREHENSIVE INCOME (LOSS) (THOUSANDS OF DOLLARS) (UNAUDITED) THREE MONTHS ENDED SEPTEMBER 30, --------------------------------------------------------------------- 1999 1998 -------------------------------- -------------------------------- RETAINED EARNINGS: Balance at beginning of period ...................... $ 1,096,058 $ 1,813,934 Net income .......................................... 1,689,990 $ 1,689,990 251,709 $ 251,709 ------------- ------------- Total ........................................... 2,786,048 2,065,643 Common stock dividends .............................. (107,024) (106,647) ------------- ------------- Balance at end of period ............................ $ 2,679,024 $ 1,958,996 ============= ============= ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX: Balance at beginning of period ...................... $ (91,225) $ (16,535) Foreign currency translation adjustments, net of tax of $12,127 and $84 ........................... (22,521) (22,521) (156) (156) Unrealized loss on available for sale securities, net of tax of $1,449 and $3,304 ....... (2,576) (2,576) (5,874) (5,874) ------------- ------------- Balance at end of period ............................ $ (116,322) $ (22,565) ============= ============= ------------- ------------- COMPREHENSIVE INCOME .................................. $ 1,664,893 $ 245,679 ============= ============= NINE MONTHS ENDED SEPTEMBER 30, ------------------------------------------------------------------------ 1999 1998 --------------------------------- --------------------------------- RETAINED EARNINGS: Balance at beginning of period ................. $ 1,445,081 $ 2,013,055 Net income ..................................... 1,554,865 $ 1,554,865 263,078 $ 263,078 -------------- -------------- Total ...................................... 2,999,946 2,276,133 Common stock dividends ......................... (320,922) (317,137) -------------- -------------- Balance at end of period ....................... $ 2,679,024 $ 1,958,996 ============== ============== ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX: Balance at beginning of period ................. $ (49,615) $ (6,455) Foreign currency translation adjustments, net of tax of $35,242 and $2,801 .................... (65,450) (65,450) (5,201) (5,201) Unrealized loss on available for sale securities, net of tax of $707 and $6,136 .... (1,257) (1,257) (10,909) (10,909) -------------- -------------- Balance at end of period ....................... $ (116,322) $ (22,565) ============== ============== -------------- -------------- COMPREHENSIVE INCOME ............................. $ 1,488,158 $ 246,968 ============== ============== See Notes to the Company's Consolidated Financial Statements. 6
9 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 (Company) and for Reliant Energy Resources Corp. (Resources) are the Company's and Resources' consolidated interim financial statements and notes (Interim Financial Statements) including such 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 the Company (Company Form 10-K) and Resources (Resources Form 10-K) for the year ended December 31, 1998 and the combined Quarterly Reports on Form 10-Q of the Company (Company First Quarter 10-Q and Second Quarter 10-Q) and Resources (Resources First Quarter 10-Q and Second Quarter 10-Q) for the quarters ended March 31, 1999 and June 30, 1999, respectively. For additional information regarding the presentation of interim period results, see Note 13. The financial statements for the three and nine months ended September 30, 1998 have been restated to reflect the Company's and Resources' adoption of mark-to-market accounting in the fourth quarter of 1998, retroactive to January 1, 1998. See Note 1(r) of the Company 10-K Notes (as defined below). The following notes to the financial statements in the Company Form 10-K and the Resources Form 10-K relate to material contingencies. These notes, as updated herein, are incorporated herein by reference: Notes to Consolidated Financial Statements of the Company (Company 10-K Notes): Note 1(c) (Regulatory Assets and Other Long-Lived Assets), Note 1(n) (Investments in Time Warner Securities), Note 1(p) (Foreign Currency Adjustments), Note 2 (Derivative Financial Instruments), Note 3 (Rate Matters), Note 4 (Jointly Owned Electric Utility Plant), Note 5 (Equity Investments and Advances to Unconsolidated Subsidiaries), Note 12 (Commitments and Contingencies) and Note 16(a) (Foreign Currency Devaluation). Notes to Consolidated Financial Statements of Resources (Resources 10-K Notes): Note 1(c) (Regulatory Assets and Regulation), Note 2 (Derivative Financial Instruments) and Note 8 (Commitments and Contingencies). Historically, the Company has applied 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). For a discussion of the Company's accounting policies under SFAS No. 71, see Note 1(c) of the Company 10-K Notes. The Texas Electric Choice Plan, enacted in June 1999, will ultimately deregulate the Company's electric generation operations. As a result, effective June 30, 1999, the Company was required to discontinue the use of SFAS No. 71 for such operations. For additional information on the discontinuation of SFAS No. 71, see Note 2 of the Company Second Quarter 10-Q and Note 2 below. 7
10 (2) TEXAS ELECTRIC CHOICE PLAN AND DISCONTINUANCE OF SFAS NO. 71 FOR ELECTRIC GENERATION OPERATIONS In June 1999, the State of Texas adopted the Texas Electric Choice Plan (Legislation) that substantially amends the regulatory structure governing electric utilities in order to allow retail competition beginning on January 1, 2002. In preparation for that competition, the Company will make significant changes in the electric utility operations it conducts through Reliant Energy HL&P. For additional information regarding the Legislation, see Note 2 of the Company Second Quarter 10-Q. At June 30, 1999, the Company performed an impairment test of its 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," on a plant specific basis. The Company determined that $797 million of its electric generation assets was impaired as of June 30, 1999. 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 a result, a regulatory asset was recorded for an amount equal to the impairment loss and is included on the Company's Consolidated Balance Sheets as recoverable impaired plant costs. In addition, the Company has recorded an additional $12 million of recoverable impaired plant costs in the third quarter of 1999 related to previously incurred costs that are now deemed to be recoverable pursuant to the Legislation. During the third quarter of 1999, the Company recorded amortization expense related to the recoverable impaired plant costs of $144 million in its Statements of Consolidated Operations. The Company will continue to amortize this regulatory asset as it is recovered. The impairment test required 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 the assumptions underlying these estimates. 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 Public Utility Commission of Texas (Texas PUC). Any difference between the fair market value and the regulatory net book value of the generation related assets (as defined by the Legislation) will either be refunded or collected through future transmission and distribution rates. 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 stranded costs are subject to material changes. Factors affecting such changes may include estimation risk, uncertainty of future energy prices and the economic lives of the plants. If events occur that make the recovery of all or a portion of the regulatory asset associated with the generation plant impairment loss and deferred debits created from discontinuance of SFAS No. 71 pursuant to the Legislation no longer probable, the Company will write off the corresponding balance of such assets as a non-cash charge against earnings. Following are the classes of electric property, plant and equipment at cost, with associated accumulated depreciation at September 30, 1999 (including the impairment loss discussed above) and December 31, 1998. TRANSMISSION CONSOLIDATED AND GENERAL ELECTRIC PLANT GENERATION DISTRIBUTION AND INTANGIBLE IN SERVICE ---------- -------------- -------------- ---------------- (IN MILLIONS) September 30, 1999: Original cost ............................. $ 9,002 $ 4,471 $ 951 $14,424 Accumulated depreciation .................. 4,878 1,265 251 6,394 Property, plant and equipment - net (1) ... 4,124 3,206 700 8,030 8
11 TRANSMISSION CONSOLIDATED AND GENERAL ELECTRIC PLANT GENERATION DISTRIBUTION AND INTANGIBLE IN SERVICE ---------- -------------- -------------- ---------------- (IN MILLIONS) December 31, 1998: Original cost ............................. $ 8,843 $ 4,196 $ 930 $13,969 Accumulated depreciation .................. 3,822 1,276 207 5,305 Property, plant and equipment - net (1) ... 5,021 2,920 723 8,664 - --------------------- (1) Includes non-utility generation facilities of $387 million at September 30, 1999 and $338 million at December 31, 1998 and international distribution facilities of $28 million at September 30, 1999 and $19 million at December 31, 1998. In order to reduce potential exposure to stranded costs related to generation assets, Reliant Energy HL&P redirected $102 million and $195 million of depreciation in the six months ended June 30, 1999, and the year ended December 31, 1998, respectively, from transmission and distribution related plant assets to generation assets for regulatory and financial reporting purposes. Such redirection was in accordance with the Company's transition to competition plan, approved by the Texas PUC (Transition Plan). See Note 3(b) of the Company 10-K Notes. 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. For the third quarter of 1999, $51 million in depreciation expense has been redirected from transmission and distribution for regulatory purposes and established as an embedded asset included in transmission and distribution related plant and equipment balances. As of September 30, 1999, the cumulative amount of redirected depreciation is $348 million. Reliant Energy HL&P plans to file an application with the Texas PUC requesting a financing order authorizing the issuance by a special purpose entity organized by the Company, pursuant to the Legislation, of approximately $1 billion of transition bonds related to Reliant Energy HL&P's generation-related regulatory assets. Payments on the transition bonds will be made from non-bypassable transition charges to Reliant Energy HL&P's transmission and distribution customers. The offering and sale of the transition bonds will be registered under the Securities Act of 1933 and is expected to be consummated in the first quarter of 2000. (3) FOREIGN CURRENCY ADJUSTMENTS For information about the Company's foreign currency adjustments, see Note 1(p) of the Company 10-K Notes. The Company has an indirect 11.8% common stock interest in Light Servicos de Eletricidade S.A. (Light) and, through its investment in Light, has a 9.2% common stock interest in Metropolitana Eletricidade de Sao Paulo S.A. (Metropolitana), both Brazilian operating companies. The Company accounts for its investment in Light under the equity method and records its proportionate share, based on stock ownership, in the net income of Light and its affiliates (including Metropolitana) as part of the Company's consolidated net income. As of September 30, 1999, Light and Metropolitana had total borrowings of $2.7 billion denominated in non-local currencies. During the first quarter of 1999, the Brazilian real was devalued and allowed to float against other major currencies. The effects of devaluation on the non-local currency denominated borrowings caused the Company to record an after-tax charge for the three months and nine months ended September 30, 1999 of $19 million and $114 million, respectively, as a result of foreign currency transaction losses recorded by both Light and Metropolitana in such periods. At September 30, 1999, one U.S. dollar could be exchanged for 1.9223 Brazilian reais. Because the Company uses the Brazilian real as the functional currency to report Light's equity earnings, any decrease 9
12 in the value of the Brazilian real below its September 30, 1999 level will increase Light's liability represented by the non-local currency denominated borrowings. This amount will also be reflected in the Company's consolidated earnings, to the extent of the Company's ownership interest in Light. Similarly, any increase in the value of the Brazilian real above its September 30, 1999 level will decrease Light's liability represented by such borrowings. In November 1999, Light issued 650 million Brazilian reais of subordinated debentures. The proceeds of the debentures will be used to retire approximately $325 million of non-local currency denominated borrowings. At September 30, 1999, one U.S. dollar could be exchanged for 1.9223 Brazilian reais. (4) DEPRECIATION (a) Company. The Company calculates depreciation using the straight-line method. The Company's depreciation expense for the third quarter and first nine months of 1999 was $123 million and $458 million, respectively, compared to $227 million and $559 million for the corresponding 1998 periods. Pursuant to the Transition Plan, the Company recorded $58 million of additional depreciation for the six months ended June 30, 1999. 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 depreciation for financial reporting purposes. The Company recorded $91 million and $171 million of additional depreciation pursuant to the Transition Plan for the third quarter and the first nine months of 1998, respectively. For information regarding the additional depreciation of electric utility generating assets under the Transition Plan, see Note 3(b) of the Company 10-K Notes. Pursuant to the Legislation, the Company is allowed to recover generation related regulatory assets and liabilities reported in the Company 10-K as of December 31, 1998. Therefore, the Company discontinued amortizing certain generation related regulatory assets effective as of January 1, 1999, reversed the related amortization expense of $46 million incurred prior to June 30, 1999 and recorded additional depreciation expense of a like amount. (b) Resources. Resources calculates depreciation using the straight-line method. Resources' depreciation expense was $35 million and $106 million for the third quarter and first nine months of 1999, respectively, compared to $40 million and $103 million for the corresponding 1998 periods. (5) COMBINED FINANCIAL STATEMENT DATA OF EQUITY INVESTMENTS AND ADVANCES TO UNCONSOLIDATED AFFILIATES The following table shows certain summary financial information for the Company's unconsolidated affiliates: THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, -------------------- ----------------------- 1999 1998 1999 1998 ------- -------- -------- --------- (IN MILLIONS) Revenues ................ $ 986 $ 606 $ 3,369 $ 3,286 Operating expenses ...... 808 382 2,552 2,368 Net income (loss) ....... 47 81 (519) 357 Dividends received from these affiliates were $11 million and $6 million for the three months ended September 30, 1999 and 1998, respectively. For the nine months ended September 30, 1999 and 1998, dividends received from these affiliates were $22 million and $33 million, respectively. 10
13 (6) CHANGE IN ACCOUNTING PRINCIPLE The Company and Resources adopted Emerging Issues Task Force 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (EITF 98-10) on January 1, 1999 for the energy trading activities of Reliant Energy Services, Inc. The adoption of EITF 98-10 had no material impact on the Company's or Resources' consolidated financial statements. (7) ZENS AND TIME WARNER SECURITIES INVESTMENT On September 21, 1999, the Company issued 17.2 million of its 2.0% Zero-Premium Exchangeable Subordinated Notes due 2029 (ZENS) having an original principal amount of $1.0 billion. At maturity the holders of the ZENS will receive in cash the higher of the principal amount of the ZENS or an amount based on the then-current market value of Time Warner Inc. (TW) common stock (TW Common), or other securities distributed in connection with such stock (one share of TW Common and such other securities are referred to as reference shares). Each ZENS having a principal amount of $58.25 (the closing market price of the TW Common on September 15, 1999) is exchangeable at any time at the option of the holder for cash equal to 95% (and in certain cases 100%) of the market value of a reference share. In addition to paying interest at an accrued rate of 2.0%, the amount of any cash dividend on the reference shares will be paid to the ZENS holders. Of the $980 million net proceeds from the offering, the Company used $443 million for general corporate purposes, including repayment of Company indebtedness. The Company used $537 million of the net proceeds to purchase 9.2 million shares of TW Common, which are classified as trading securities under SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities." Therefore, unrealized gains and losses resulting from changes in the market value of the TW Common are recorded in the Statements of Consolidated Operations. An increase above $58.25 (subject to certain adjustments) in the market value per share of TW Common results in an increase in the liability for the ZENS and is recorded by the Company as a non-cash expense. If the market value per share of TW Common declines below $58.25(subject to certain adjustments), the liability for the ZENS would not decline below the original principal amount. However, the decline in market value of the Company's investment in the TW Common would be recorded as an unrealized loss as discussed above. On July 6, 1999, the Company converted its 11 million shares of Time Warner convertible preferred stock into 45.8 million shares of TW Common. Prior to the conversion, the Company's investment in the Time Warner preferred stock was accounted for under the cost method. 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 $2.38 billion ($1.53 billion after tax) to reflect the cumulative appreciation in the fair value of the Company's investment in Time Warner securities. In the future, changes in the market value of the Company's TW Common investment and the related offsetting changes in the liability related to the Company's unsecured 7% Automatic Common Exchange Securities (ACES) will be recorded in the Company's Statement of Consolidated Operations. For the period from July 1, 1999 to the conversion date of July 6, 1999, non-cash, unrealized accounting losses on the ACES were $35 million ($23 million after tax). Prior to the purchase of additional shares of TW Common on September 21, 1999, the Company owned 8.0 million shares of TW Common that were in excess of the 38 million shares needed to economically hedge its ACES obligation. For more information about the ACES obligations, see Note 7 to the Company Second Quarter 10-Q. 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 8.0 million shares were $122 million ($79 million after tax). The 8.0 million shares of TW Common combined with the additional 9.2 11
14 million shares purchased are expected to be held to provide an economic hedge against increases in the ZENS obligation. (8) CAPITAL STOCK (a) Common Stock. The Company has 700,000,000 authorized shares of common stock. At September 30, 1999, the Company had 297,224,668 shares of common stock issued (284,994,244 outstanding). At December 31, 1998, the Company had 296,271,063 shares of common stock issued (284,494,195 outstanding). Outstanding common shares exclude (i) shares pledged to secure a loan to the Company's Employee Stock Ownership Plan (10,719,489 and 11,674,063 at September 30, 1999 and December 31, 1998, respectively) and (ii) treasury shares (1,510,935 and 102,805 at September 30, 1999 and December 31, 1998, respectively). The Company has a registration statement under which 15,000,000 shares of its common stock are available for issuance. The issuance of all securities registered by the Company is subject to market and other conditions. During the third quarter of 1999, the Company purchased 1,419,200 shares of its common stock for $38.8 million at an average price of $27.34 per share. As of September 30, 1999, the Company was authorized to purchase an additional $49.9 million of its common stock. Purchases depend on market conditions, might not be announced in advance and may be made in open market or privately negotiated transactions. For information on the Company's purchases since September 30, 1999, see Note 12. (b) Earnings Per Share. The following table presents the Company's basic and diluted earnings per share (EPS) calculation: THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------------- ------------------------- 1999(1) 1998 1999(2) 1998 ---------- ---------- ---------- ---------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Basic EPS Calculation: Income before preferred dividends ......... $1,690,087 $ 251,806 $1,555,157 $ 263,370 Preferred dividends ....................... 97 97 292 292 ---------- ---------- ---------- ---------- Net income attributable to common stock ... $1,689,990 $ 251,709 $1,554,865 $ 263,078 ========== ========== ========== ========== Weighted average shares outstanding ....... 285,287 284,344 285,247 283,965 Basic EPS ................................. $ 5.92 $ 0.89 $ 5.45 $ 0.93 ========== ========== ========== ========== 12
15 THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------------- ------------------------- 1999(1) 1998 1999(2) 1998 ---------- ---------- ---------- ---------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Diluted EPS Calculation: Income before preferred dividends ........... $1,690,087 $ 251,806 $1,555,157 $ 263,370 Interest on 6 1/4% convertible debentures ... 8 14 25 43 ---------- ---------- ---------- ---------- Income before preferred dividends assuming dilution .................................. 1,690,095 251,820 1,555,182 263,413 Preferred dividends ......................... 97 97 292 292 ---------- ---------- ---------- ---------- Net income attributable to common stock ..... $1,689,998 $ 251,723 $1,554,890 $ 263,121 ========== ========== ========== ========== Weighted average shares outstanding ......... 285,287 284,344 285,247 283,965 Stock options ........................... 362 432 525 368 Restricted stock ........................ 740 492 740 492 6 1/4% convertible debentures ........... 25 44 25 44 ---------- ---------- ---------- ---------- Weighted average shares assuming dilution ... 286,414 285,312 286,537 284,869 Diluted EPS ................................. $ 5.90 $ 0.88 $ 5.43 $ 0.92 ========== ========== ========== ========== - ------------------ (1) For the three months ended September 30, 1999, the computation of diluted EPS excludes purchase options for 51,631 shares of common stock that have exercise prices (ranging from $28.71 to $35.18 per share) greater than the $27.41 per share average market price for the period and would thus be anti-dilutive if exercised. (2) For the nine months ended September 30, 1999, the computation of diluted EPS excludes purchase options for 29,316 shares of common stock that have exercise prices (ranging from $28.71 to $35.18 per share) greater than the $28.26 per share average market price for the period and would thus be anti-dilutive if exercised. (c) Preferred Stock. At September 30, 1999 and December 31, 1998, the Company had 10,000,000 authorized shares of preferred stock, of which 97,397 shares of $4.00 Preferred Stock were outstanding. The Preferred Stock pays an annual dividend of $4.00 per share, is redeemable at $105 per share and has a liquidation price of $100 per share. (d) Preference Stock. At September 30, 1999 and December 31, 1998, the Company had 10,000,000 authorized shares of preference stock, which were designated and outstanding, as shown below. ----------------------------- ------------------------------ SEPTEMBER 30, 1999 DECEMBER 31, 1998 ----------------------------- ------------------------------ LIQUIDATION SHARES SHARES SHARES SHARES VALUE PER SHARE DESIGNATED OUTSTANDING DESIGNATED OUTSTANDING --------------- ---------- ----------- ---------- ----------- Series A $ 1,000 700,000 -- 700,000 -- Series B $ 100,000 27,000 17,000 27,000 17,000 Series C $ 100,000 1,575 -- 1,575 1,575 Series D Euro 100,000(1) 5,880 3,660 -- -- - ---------- (1) As of September 30, 1999, one U.S. dollar could be exchanged for 1.0651 Euros. The Series A Preference Stock is issuable in accordance with the Company's Shareholder Rights Agreement upon the occurrence of certain events. The Series C Preference Stock was redeemed in March 1999. The Series B Preference Stock and the Series D Preference Stock are not deemed outstanding for financial reporting purposes because the sole holders of each series are separate wholly owned financing 13
16 subsidiaries of the Company. For information regarding the Company's Series E Preference Stock issued in the fourth quarter of 1999, see Note 12. (9) COMPANY/RESOURCES OBLIGATED MANDATORILY REDEEMABLE TRUST PREFERRED SECURITIES OF SUBSIDIARY TRUSTS HOLDING SOLELY JUNIOR SUBORDINATED DEBENTURES OF THE COMPANY/ RESOURCES (a) Company. For information regarding $375 million of preferred securities issued by a statutory business trust formed by the Company, see Note 8(a) of the Company First Quarter 10-Q. For information regarding $250 million of preferred securities and $100 million of capital securities previously issued by statutory business trusts formed by the Company, see Note 9(a) of the Company 10-K Notes. The sole asset of each trust consists of junior subordinated debentures of the Company 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 such trust. The Company has a registration statement under which $125 million of trust preferred securities and related junior subordinated debt securities is available for issuance. The issuance of all securities registered by the Company and its affiliates is subject to market and other conditions. (b) Resources. For information regarding $177.8 million of convertible preferred securities previously issued by a statutory business trust formed by Resources, of which approximately $1 million was outstanding at September 30, 1999, see Note 5 of Resources 10-K Notes. The sole asset of the trust consists of junior subordinated debentures of Resources having an interest rate and maturity date corresponding to the preferred securities, and a principal amount corresponding to the common and preferred securities issued by the trust. (10) LONG-TERM DEBT AND SHORT-TERM FINANCING (a) Company. (i) Consolidated Debt. The Company's consolidated long-term and short-term debt outstanding is summarized in the following table: SEPTEMBER 30, 1999 DECEMBER 31, 1998 -------------------------- -------------------------- LONG-TERM CURRENT LONG-TERM CURRENT --------- ---------- --------- ------- (IN MILLIONS) Short-Term Borrowings (1): Commercial Paper ...................... $ 1,170 $ 1,360 Lines of Credit ....................... 360 150 Resources Receivables Facility ........ 350 300 Notes Payable ......................... 3 3 --------- -------- --------- ------- Total Short-Term Borrowings ............. 1,883 1,813 --------- -------- --------- ------- 14
17 SEPTEMBER 30, 1999 DECEMBER 31, 1998 -------------------------- -------------------------- LONG-TERM CURRENT LONG-TERM CURRENT --------- ---------- --------- ------- (IN MILLIONS) Long-Term Debt - net: ACES ...................................... 2,300 $2,350 ZENS (4) .................................. 1,043 Debentures (2)(3) ......................... $1,468 1,482 First Mortgage Bonds (2) .................. 1,427 221 1,866 170 Pollution Control Bonds ................... 871 581 Resources Medium-Term Notes (3) ........... 174 178 Notes Payable (3) ......................... 110 227 330 226 Capital Leases ............................ 13 1 14 1 ------ ------ ------ ------ Total Long-Term Debt ........................ 4,063 3,792 6,801 397 ------ ------ ------ ------ Total Long-Term and Short-Term Debt ....... $4,063 $5,675 $6,801 $2,210 ====== ====== ====== ====== - --------------------- (1) Includes amounts due within one year of the date noted. (2) Includes unamortized discount related to debentures of approximately $0.4 million at September 30, 1999 and $1 million at December 31, 1998 and unamortized premium related to debentures of approximately $16 million at September 30, 1999 and $17 million at December 31, 1998. The unamortized discount related to first mortgage bonds was approximately $9 million at September 30, 1999 and $10 million at December 31, 1998. (3) Includes unamortized premium related to fair value adjustments of approximately $17 million and $18 million for debentures at September 30, 1999 and December 31, 1998, respectively. The unamortized premium for Resources long-term notes was approximately $8 million and $12 million at September 30, 1999 and December 31, 1998, respectively. The unamortized premium for notes payable was approximately $2 million and $6 million at September 30, 1999 and December 31, 1998, respectively. (4) As ZENS are exchangeable at any time at the option of the holder, these notes are classified as a current portion of long-term debt. Consolidated maturities of long-term debt and sinking fund requirements for the Company (including Resources) are approximately $11 million for the remainder of 1999. (ii) Financing Developments. At September 30, 1999, a financing subsidiary of the Company had $1.136 billion in commercial paper borrowings supported by a $1.644 billion revolving credit facility. At September 30, 1999, the weighted average interest rate of these commercial paper borrowings was 5.98%. On September 24, 1999, another financing subsidiary of the Company established a 364-day Euro 560 million (approximately $596 million) revolving credit facility (FinanceCo III Facility). At September 30, 1999, borrowings under the FinanceCo III Facility were Euro 338 million (approximately $360 million) at an interest rate of 3.127%. Borrowings under the facility are determined based on competitive bids or by adding a margin to the rate at which Euro deposits are offered in the interbank Euro market. For additional information regarding the Company's and its subsidiaries' bank facilities and commercial paper programs, see Note 8(c) and (d) of the Company 10-K Notes. For information regarding the redemption of $200 million revenue refunding bonds in July 1999, see Note 10(a) to the Company Second Quarter 10-Q. In July 1999, the Matagorda County Navigation District Number One (MCND) issued on behalf of the Company $70.315 million of revenue refunding bonds having an interest rate of 5.95%. The MCND bonds will mature in 2030, and proceeds from the issuance were used on October 1, 1999 to redeem all outstanding 7.60% MCND Series 1989D collateralized pollution control revenue bonds 15
18 ($70.315 million) at a redemption price of 102% of their aggregate principal amount. For financial reporting purposes, both the MCND bonds issued in July 1999 and the MCND bonds redeemed in October 1999 were deemed to be outstanding at September 30, 1999. On September 21, 1999, the Company issued 17.2 million of its ZENS having an original principal amount of $1.0 billion. For information on the ZENS, see Note 7. (b) Resources. As of September 30, 1999, Resources had outstanding $1.9 billion of long-term and short-term debt. For information regarding Resources' financing arrangements and lease commitments, see Notes 4 and 8(a) of the Resources 10-K Notes. In July 1999, Resources repaid at maturity $200 million of its 8.875% Notes. In August 1999, Resources increased its receivables facility by $50 million and received $50 million of additional proceeds from its sale of receivables. For information regarding Resources' $350 million receivables facility, see Note 4(a) of the Resources 10-K Notes. At September 30, 1999, Resources had sold $350 million of receivables under the facility at a weighted average interest rate of 5.53%. For information regarding Resources' $350 million revolving credit facility, see Note 4(a) of the Resources 10-K Notes. This facility includes a $65 million sub-facility under which letters of credit may be obtained. At September 30, 1999, commercial paper borrowings supported by the facility aggregated $34.2 million and had a weighted average interest rate of 6.05%. As of September 30, 1999, letters of credit issued under the facility aggregated $22.8 million. (11) REPORTABLE SEGMENTS In accordance with SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information," the Company has identified the following reportable segments: Electric Operations, Natural Gas Distribution, Interstate Pipelines, Wholesale Energy, International and Corporate. Electric Operations provides electric utility generation, transmission, distribution and sales to customers. Natural Gas Distribution operations consist of natural gas utility sales to, and natural gas utility transportation for, residential, commercial and industrial customers. Interstate Pipelines operates two interstate natural gas pipelines. Wholesale Energy is engaged in the acquisition, development and operation of, and sale of capacity, energy and ancilliary services from, domestic and certain international non-utility power generation facilities and in the wholesale energy trading and marketing and natural gas gathering businesses. International invests in foreign electric and gas utility retail operations, primarily in Latin America. Corporate includes a non-rate regulated retail service business, certain real estate holdings and corporate expenses. Financial data for the business segments are as follows (in thousands): 16
19 ELECTRIC NATURAL GAS INTERSTATE WHOLESALE INTER- OPERATIONS DISTRIBUTION PIPELINES ENERGY NATIONAL ----------- ------------ ---------- ---------- ---------- For the Three Months Ended September 30, 1999: Revenues ..................... $1,496,596 $ 302,387 $ 37,303 $2,847,388 $ 34,126 Intersegment revenues ........ 311 32,721 60,731 Operating income (loss) ...... 410,234 (12,349) 28,767 43,584 9,809 For the Three Months Ended September 30, 1998: Revenues ..................... 1,415,832 265,911 34,110 1,584,472 31,813 Intersegment revenues ........ 266 36,284 26,181 Operating income (loss) ...... 412,669 (17,212) 27,421 94,511 14,419 RECONCILING CORPORATE ELIMINATIONS CONSOLIDATED ---------- ------------ ------------ For the Three Months Ended September 30, 1999: Revenues ..................... $ 229,392 $4,947,192 Intersegment revenues ........ 20,644 $ (114,407) Operating income (loss) ...... (17,247) 462,798 For the Three Months Ended September 30, 1998: Revenues ..................... 133,349 3,465,487 Intersegment revenues ........ 24,002 (86,733) Operating income (loss) ...... (24,814) 506,994 ELECTRIC NATURAL GAS INTERSTATE WHOLESALE INTER- OPERATIONS DISTRIBUTION PIPELINES ENERGY NATIONAL ----------- ------------ ----------- ----------- ----------- As of and for the Nine Months Ended September 30, 1999: Revenues ..................... $ 3,513,144 $ 1,309,241 $ 90,608 $ 5,692,028 $ 26,273 Intersegment revenues ........ 912 111,638 162,024 Operating income (loss) ...... 836,413 80,141 83,866 53,378 (52,894) Total Assets ................. 10,427,643 2,960,971 2,025,244 2,725,752 1,100,138 As of and for the Nine Months Ended September 30, 1998: Revenues ..................... 3,443,694 1,326,672 103,919 3,298,008 228,494 Intersegment revenues ........ 890 113,972 118,040 Operating income (loss) ...... 846,275 80,403 92,343 68,551 176,430 Total Assets ................. 10,604,590 2,830,260 2,116,927 2,108,629 1,086,407 RECONCILING CORPORATE ELIMINATIONS CONSOLIDATED ----------- ------------ ------------ As of and for the Nine Months Ended September 30, 1999: Revenues ..................... $ 616,630 $11,247,924 Intersegment revenues ........ 56,579 $ (331,153) Operating income (loss) ...... (27,829) 973,075 Total Assets ................. 4,010,246 (645,877) 22,604,117 As of and for the Nine Months Ended September 30, 1998: Revenues ..................... 432,648 8,833,435 Intersegment revenues ........ 69,945 (302,847) Operating income (loss) ...... (21,065) 1,242,937 Total Assets ................. 1,762,848 (851,829) 19,657,832 Reconciliation of operating income to net income (in thousands) is as follows: THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, --------------------------- --------------------------- 1999 1998 1999 1998 ----------- ----------- ----------- ----------- Operating income ........................... $ 462,798 $ 506,994 $ 973,075 $ 1,242,937 Dividend income ............................ 2,622 10,313 23,247 30,938 Interest expense ........................... 116,176 120,058 368,759 375,237 Unrealized gain on Time Warner investment ............................. 1,816,105 1,816,105 Unrealized gain (loss) on indexed debt securities ............................. 406,717 (40,231) 6,778 (484,009) Distribution on trust securities ........... 14,652 7,248 38,433 21,960 Income tax expense ......................... 877,372 106,616 872,304 154,218 Other income - net ......................... 9,948 8,555 15,156 24,627 ----------- ----------- ----------- ----------- Net income attributable to common shareholders ........................... $ 1,689,990 $ 251,709 $ 1,554,865 $ 263,078 =========== =========== =========== =========== 17
20 (12) SUBSEQUENT EVENTS On October 7, 1999, the Company completed the first phase of its acquisition of the Dutch power generation company N.V. UNA (UNA). On that date, a subsidiary of the Company purchased 40 percent of the capital stock of UNA for $780 million, which included $354 million in cash and a $426 million five-year promissory note. The promissory note must be prepaid in certain circumstances. In accordance with the stock purchase agreement, the Company's subsidiary has irrevocable fixed commitments to increase its ownership interest in UNA to 52 percent by December 1, 1999 and purchase the remaining shares of UNA on March 1, 2000. The total purchase price of the acquisition is approximately $2.4 billion. All purchase price obligations are denominated in Dutch guilders (NLG). The amounts shown above assume an exchange rate of 2.0565 NLG per U.S. dollar (the exchange rate on October 7, 1999). In connection with obtaining the necessary Dutch regulatory approvals, the Company, UNA and the other shareholders of UNA agreed to revise the terms of their original agreement that provided that if UNA's stranded costs exceeded NLG 500 million, the purchase price would be reduced. Any downward adjustment would have been limited to approximately NLG 1.4 billion. Under the amended agreement, the other UNA shareholders are responsible for up to NLG 1.9 billion of UNA's stranded costs. Accordingly, the purchase price was increased by NLG 500 million. This payment will be made in December 1999. During the period from October 1, 1999 through November 12, 1999, the Company purchased 90,800 shares of its common stock for $2.4 million at an average price of $26.45 per share. See Note 8 for more information. In October 1999, Resources called for redemption the remaining $42.76 million principal amount of its 10% Debentures due 2019. The debentures will be redeemed on November 15, 1999 at 105% of their principal amount plus accrued interest. On November 10, 1999, the Brazos River Authority (BRA) issued on behalf of the Company $100 million of revenue refunding bonds having an annual interest rate of 5.20% and a maturity date of December 1, 2018. The BRA bonds will be subject to mandatory tender or optional redemption on December 1, 2002 at a price equal to 100% of the principal amount. The proceeds from the issuance will be used on December 13, 1999 to redeem all outstanding BRA Series 1989B collateralized revenue refunding bonds ($100 million) at a redemption price of 102% of the aggregate principal amount. On November 10, 1999, the MCND issued on behalf of the Company $75 million of revenue refunding bonds having an annual interest rate of 5.20% and a maturity date of May 1, 2029. The MCND bonds will be subject to mandatory tender or optional redemption on November 1, 2002 at a price equal to 100% of the principal amount. The proceeds from the issuance will be used on December 13, 1999 to redeem all outstanding MCND Series 1989E collateralized revenue refunding bonds ($75 million) at a redemption price of 102% of the aggregate principal amount. On November 12, 1999, a financing subsidiary issued $300 million of Senior Notes due 2002 having an annual interest rate of 7.4%. The proceeds from the issuance were used by the financing subsidiary to purchase Series E Preference Stock of the Company. As a result of the transaction, the financing subsidiary owns 3,160 shares of the Series E Preference Stock. These shares are not deemed outstanding for financial reporting purposes because they are held by a wholly owned financing subsidiary of the Company. The Company anticipates that the proceeds from the sale of such preference stock will be used for general corporate purposes, including the repayment of indebtedness. The devaluation of the Brazilian real has resulted in the inability of Light and Metropolitana to distribute adequate dividends to meet debt requirements of a subsidiary of the Company. In July 1999, the subsidiary executed a guarantee of up to $45 million. In November 1999, it is anticipated that the Company will make a capital contribution of approximately $20 million to fund a portion of this obligation. 18
21 (13) COMPANY/RESOURCES INTERIM PERIOD RESULTS; RECLASSIFICATIONS The Company's and Resources' 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 Operations and Resources' Statements of Consolidated Operations are not necessarily indicative of amounts expected for a full-year period due to the effects of, among other things, (i) seasonal variations in energy consumption, (ii) timing of maintenance and other expenditures and (iii) acquisitions and dispositions of assets and other interests. In addition, certain amounts from the prior year have been reclassified to conform to the Company's and Resources' presentation of financial statements in the current year. These reclassifications do not affect their respective earnings. 19
22 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF THE COMPANY The following should be read in combination with the unaudited consolidated financial statements and notes thereto. Reliant Energy, Incorporated (Company), together with various divisions and subsidiaries, including Reliant Energy Resources Corp. (Resources), is a diversified international energy services company. The Company reports its financial information in six segments. The Company's Electric Operations segment operates one of the nation's largest utility in terms of kilowatt-hour (KWH) sales. The Natural Gas Distribution segment includes the gas utility operations of Resources and is the third largest such operation in the U.S. in terms of number of customers served. The Interstate Pipelines segment operates two interstate natural gas pipelines. The Wholesale Energy segment is engaged in the acquisition, development and operation of, and sale of capacity, energy and ancillary services from, domestic and certain international non-utility power generation facilities, and in the wholesale energy trading and marketing and natural gas gathering businesses. The International segment invests in foreign electric and gas retail utility operations, primarily in Latin America. The Corporate segment includes a non-rate regulated retail service business, certain real estate holdings and corporate expenses. CONSOLIDATED RESULTS OF OPERATIONS THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------------ PERCENT ----------------------- PERCENT 1999 1998 CHANGE 1999 1998 CHANGE --------- ---------- ------- ---------- --------- ------- (IN MILLIONS, EXCEPT PER (IN MILLIONS, EXCEPT PER SHARE DATA) SHARE DATA) Revenues .......................... $ 4,947 $ 3,465 43% $ 11,248 $ 8,833 27% Operating Expenses ................ 4,484 2,958 52% 10,275 7,590 35% Operating Income .................. 463 507 (9%) 973 1,243 (22%) Other (Expenses) Income (1) ....... 2,235 (21) -- 1,861 (428) -- Interest and Other Charges ........ 131 127 3% 407 398 2% Income Tax Expense ................ 877 107 -- 872 154 -- --------- --------- --------- --------- Net Income (1) .................... $ 1,690 $ 252 -- $ 1,555 $ 263 -- ========= ========= ========= ========= Basic Income Per Share (1) ........ $ 5.92 $ 0.89 -- $ 5.45 $ 0.93 -- Diluted Income Per Share (1) ...... $ 5.90 $ 0.88 -- $ 5.43 $ 0.92 -- - -------------- (1) Other (Expenses) Income and Net Income reflect the effect of a $1.816 billion non-cash, unrealized pre-tax ($1.161 billion after-tax) accounting gain recorded in the three and nine months ended September 30, 1999 related to the unrealized gain on the Company's investment in Time Warner. No such gain was recorded in 1998. The line items also reflect unrealized gains and losses on the indexed debt securities (ACES and ZENS). Such amounts were a pre-tax gain of $407 million and $7 million for the three and nine month periods of 1999, respectively, compared to a pre-tax loss of $40 million and $484 million for the same periods in 1998, respectively. See Note 7 to the Company's Interim Financial Statements regarding both of these items. Third Quarter of 1999 Compared to Third Quarter of 1998. The Company reported consolidated net income of $1.690 billion ($5.92 per basic share) for the third quarter of 1999 compared to consolidated net income of $252 million ($0.89 per basic share) for the third quarter of 1998. The 1999 results reflect a $1.161 billion after-tax, non-cash unrealized accounting gain on the Company's investment in TW Common, a $264 million after-tax, non-cash unrealized gain on indexed debt securities 20
23 and an after-tax loss of $19 million due to the devaluation of the Brazilian real. The third quarter of 1998 results include a $26 million after-tax, non-cash unrealized accounting loss on indexed debt securities. After adjusting for the gains and losses described above, the Company would have had consolidated net income of $283 million ($0.99 per basic share) in the third quarter of 1999 compared to $278 million ($0.98 per basic share) in the third quarter of 1998. First Nine Months of 1999 Compared to First Nine Months of 1998. The Company reported consolidated net income of $1.555 billion ($5.45 per basic share) for the first nine months of 1999 compared to consolidated net income of $263 million ($0.93 per basic share) for the same period of 1998. The 1999 results reflect a $1.161 billion after-tax, non-cash unrealized accounting gain on the Company's investment in TW Common, a $4 million after-tax, non-cash unrealized accounting gain on indexed debt securities and a $114 million after-tax loss due to the devaluation of the Brazilian real. Net income for the 1998 period reflects a $315 million after-tax, non-cash unrealized accounting loss on indexed debt securities. After adjusting for the gains and losses described above, the Company would have had consolidated net income of $504 million ($1.77 per basic share) for the first nine months of 1999 and $577 million ($2.03 per basic share) for the first nine months of 1998. The $73 million decrease was primarily due to an $80 million after-tax gain on the sale of an Argentine electric distribution company in 1998 and lower earnings in 1999 from the Wholesale Energy, Electric Operations and Interstate Pipelines segments, partially offset by improved results from the International segment. The table below shows operating income (loss) by segment: THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, -------------------- -------------------- 1999 1998 1999 1998 ------- ------- ------- ------- (IN MILLIONS) Electric Operations .......... $ 410 $ 413 $ 837 $ 846 Natural Gas Distribution ..... (12) (17) 80 80 Interstate Pipelines ......... 29 27 84 92 Wholesale Energy ............. 44 95 53 69 International ................ 10 14 (53) 176 Corporate .................... (18) (25) (28) (20) ------- ------- ------- ------- Total Consolidated ..... $ 463 $ 507 $ 973 $ 1,243 ======= ======= ======= ======= ELECTRIC OPERATIONS Electric Operations are conducted under the name "Reliant Energy HL&P," an unincorporated division of the Company. Electric Operations provides electric generation, transmission, distribution and sales to approximately 1.7 million customers in a 5,000 square mile area on the Texas Gulf Coast, including Houston (the nation's fourth largest city). 21
24 THREE MONTHS ENDED SEPTEMBER 30, --------------------------- PERCENT 1999 1998 CHANGE ----------- ----------- ---------- (IN MILLIONS) Operating Revenues: Base Revenues (1) .................... $ 975 $ 986 (1%) Reconcilable Fuel Revenues (2) ....... 521 430 21% ----------- ----------- Total Operating Revenues ....... 1,496 1,416 6% ----------- ----------- Operating Expenses: Fuel and Purchased Power ............. 536 447 20% Operation and Maintenance ............ 214 242 (12%) Depreciation and Amortization ........ 233 209 11% Other Operating Expenses ............. 103 105 (2%) ----------- ----------- Total Operating Expenses ........ 1,086 1,003 8% ----------- ----------- Operating Income ....................... $ 410 $ 413 (1%) =========== =========== Electric Sales (MWH): Residential .......................... 7,732,696 7,971,198 (3%) Commercial ........................... 4,854,343 4,860,627 -- Industrial - Firm .................... 6,836,545 7,018,296 (3%) Municipal and Public Utilities ....... 101,231 95,204 6% ----------- ----------- Total Firm Billed Sales ............ 19,524,815 19,945,325 (2%) =========== =========== Average Cost of Fuel (Cents/MMBtu) ..... 198.8 173.4 15% NINE MONTHS ENDED SEPTEMBER 30, --------------------------- PERCENT 1999 1998 CHANGE ----------- ----------- ------- (IN MILLIONS) Operating Revenues: Base Revenues (1) .................... $ 2,330 $ 2,344 (1%) Reconcilable Fuel Revenues (2) ....... 1,183 1,100 8% ----------- ----------- Total Operating Revenues ......... 3,513 3,444 2% ----------- ----------- Operating Expenses: Fuel and Purchased Power ............. 1,224 1,147 7% Operation and Maintenance ............ 640 662 (3%) Depreciation and Amortization ........ 541 524 3% Other Operating Expenses ............. 271 265 2% ----------- ----------- Total Operating Expenses ......... 2,676 2,598 3% ----------- ----------- Operating Income ....................... $ 837 $ 846 (1%) =========== =========== Electric Sales (MWH): Residential .......................... 16,285,847 16,043,238 2% Commercial ........................... 12,507,322 12,182,317 3% Industrial - Firm .................... 19,683,042 20,160,044 (2%) Municipal and Public Utilities ....... 267,626 253,113 6% =========== =========== Total Firm Billed Sales .......... 48,743,837 48,638,712 -- =========== =========== Average Cost of Fuel (Cents/MMBtu) .... 188.0 176.7 6% - ---------------- (1) Includes miscellaneous revenues (including transmission revenues) and certain purchased power-related revenues. 22
25 (2) Includes revenues collected through a fixed fuel factor and surcharge, net of over/under recovery of fuel. Pursuant to the Legislation, Reliant Energy HL&P can recover fuel costs during the base rate freeze period from 1999 through 2001. Electric Operations' operating income for the third quarter and first nine months of 1999 decreased $3 million and $9 million, respectively, compared to the corresponding 1998 periods. For both periods, the decrease is primarily attributable to milder weather, additional base rate reductions and higher depreciation and amortization expenses, which were partially offset by strong customer growth and reduced operation and maintenance expenses. Fuel and purchased power expenses for the third quarter of 1999 increased by $89 million compared to the 1998 period as a result of higher cost per unit for purchased power ($0.0373 per KWH in the 1999 period compared to $0.0270 per KWH in the 1998 period) and higher reconcilable cost of natural gas ($2.65 per MMBtu in the 1999 period compared to $2.08 per MMBtu in the 1998 period). Fuel and purchased power expenses for the first nine months of 1999 increased by $77 million compared to the 1998 period as a result of higher reconcilable cost of natural gas ($2.41 per MMBtu for 1999 compared to $2.21 for 1998), lignite ($1.48 per MMBtu for 1999 compared to $1.24 for 1998) and purchased power ($0.0271 per KWH for 1999 compared to $0.0249 for 1998). Operations and maintenance expense for the third quarter of 1999 decreased $28 million compared to the same period in 1998, primarily due to lower insurance, advertising and nuclear operation and maintenance expenses. Operations and maintenance expense decreased $22 million for the first nine months of 1999 compared to the same period in 1998. This decrease is attributable to lower costs mentioned above partially offset by higher materials and supplies expense. Depreciation and amortization expense increased $24 million and $17 million for the third quarter and first nine months of 1999, respectively, compared to the same periods in 1998 due to the net increase in amortization pursuant to the Legislation. Other operating expenses increased for the first nine months of 1999 compared to 1998 largely due to higher state franchise and gross receipts taxes. NATURAL GAS DISTRIBUTION Natural Gas Distribution operations are conducted through three divisions of Resources: Reliant Energy Arkla, Reliant Energy Entex and Reliant Energy Minnegasco. These operations consist of intrastate natural gas sales to, and natural gas transportation for, residential, commercial and industrial customers in six states: Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas. THREE MONTHS ENDED SEPTEMBER 30, --------------------- PERCENT 1999 1998 CHANGE -------- -------- ------- (IN MILLIONS) Operating Revenues: Base Revenues ................... $ 156 $ 136 15% Recovered Gas Revenues .......... 146 130 12% -------- -------- Total Operating Revenues ...... 302 266 14% -------- -------- 23
26 THREE MONTHS ENDED SEPTEMBER 30, --------------------- PERCENT 1999 1998 CHANGE -------- -------- ------- (IN MILLIONS) Operating Expenses: Natural Gas .......................... 156 126 24% Operation and Maintenance ............ 108 105 3% Depreciation and Amortization ........ 33 33 -- Other Operating Expenses ............. 17 19 (11%) -------- -------- Total Operating Expenses ........... 314 283 11% -------- -------- Operating Loss ......................... $ (12) $ (17) 29% ======== ======== Throughput Data (in Bcf): Residential and Commercial Sales ..... 33 31 6% Industrial Sales ..................... 13 14 (7%) Transportation ....................... 11 9 22% -------- -------- Total Throughput ................... 57 54 6% ======== ======== NINE MONTHS ENDED SEPTEMBER 30, -------------------- PERCENT 1999 1998 CHANGE -------- -------- ---------- (IN MILLIONS) Operating Revenues: Base Revenues ........................ $ 578 $ 565 2% Recovered Gas Cost Revenues .......... 732 762 (4%) -------- -------- Total Operating Revenues ........... 1,310 1,327 (1%) -------- -------- Operating Expenses: Natural Gas .......................... 742 758 (2%) Operation and Maintenance ............ 326 322 1% Depreciation and Amortization ........ 98 97 1% Other Operating Expenses ............. 64 70 (9%) -------- -------- Total Operating Expenses ........... 1,230 1,247 (1%) -------- -------- Operating Income ....................... $ 80 $ 80 -- ======== ======== Throughput Data (in Bcf): Residential and Commercial Sales ..... 199 200 (1%) Industrial Sales ..................... 39 42 (7%) Transportation ....................... 34 32 6% -------- -------- Total Throughput ................... 272 274 (1%) ======== ======== Natural Gas Distribution operating loss for the third quarter of 1999 decreased $5 million compared to the 1998 period, primarily due to increased revenue from customer growth, weather related usage and increased appliance services and sales. Operating expenses, other than natural gas expense, were consistent between the two periods. INTERSTATE PIPELINES The Interstate Pipelines segment provides interstate gas transportation and related services to customers. These operations are conducted by Reliant Energy Gas Transmission Company and Mississippi River Transmission Corporation, two wholly owned subsidiaries of Resources. 24
27 THREE MONTHS ENDED SEPTEMBER 30, -------------------- PERCENT 1999 1998 CHANGE -------- -------- ------- (IN MILLIONS) Operating Revenues ..................... $ 70 $ 70 -- Operating Expenses: Natural Gas .......................... 10 6 67% Operation and Maintenance ............ 15 20 (25%) Depreciation and Amortization ........ 12 13 (8%) Other Operating Expenses ............. 4 4 -- -------- -------- Total Operating Expenses ........... 41 43 (5%) -------- -------- Operating Income ....................... $ 29 $ 27 7% ======== ======== Throughput Data (in MMBtu): Natural Gas Sales .................... 3 4 (25%) Transportation ....................... 202 186 9% Elimination (1) .................... (3) (4) 25% -------- -------- Total Throughput ....................... 202 186 9% ======== ======== NINE MONTHS ENDED SEPTEMBER 30, -------------------- PERCENT 1999 1998 CHANGE ------- ------- -------- (IN MILLIONS) Operating Revenues .................... $ 202 $ 218 (7%) Operating Expenses: Natural Gas ......................... 18 22 (18%) Operation and Maintenance ........... 51 60 (15%) Depreciation and Amortization ....... 37 32 16% Other Operating Expenses ............ 12 12 -- ------- ------- Total Operating Expenses .......... 118 126 (6%) ------- ------- Operating Income ...................... $ 84 $ 92 (9%) ======= ======= Throughput Data (in MMBtu): Natural Gas Sales ................... 11 12 (8%) Transportation ...................... 637 610 4% Elimination (1) ................... (11) (11) -- ------- ------- Total Throughput ...................... 637 611 4% ======= ======= - ------------------ (1) Elimination of volumes both transported and sold. Interstate Pipelines operating income increased by $2 million and decreased by $8 million in the third quarter and first nine months of 1999, respectively, compared to the same periods in 1998. The increase for the three-month period was primarily due to the reduction of operation and maintenance expenses related to continued cost control initiatives. The decrease for the nine-month period is primarily due to the settlement of a dispute related to certain gas purchase contracts that resulted in $6 million of revenues in the second quarter of 1998 and a rate settlement reflected in the first quarter of 1998 as a $5 million reduction of depreciation rates retroactive to July 1996. This decrease was partially offset by lower operation and maintenance expenses related to continued cost control initiatives. 25
28 WHOLESALE ENERGY Wholesale Energy includes the acquisition, development and operation of, and sales of capacity, energy and ancillary services from, domestic and certain international non-utility power generation facilities; wholesale energy trading and marketing; and natural gas gathering activities. This segment includes operations of subsidiaries owned by the Company and Resources. THREE MONTHS ENDED SEPTEMBER 30, ------------------------- PERCENT 1999 1998 CHANGE ---------- ---------- --------- (IN MILLIONS) Operating Revenues ..................... $ 2,908 $ 1,611 81% Operating Expenses: Natural Gas ......................... 945 566 67% Purchased Power ...................... 1,861 907 105% Operation and Maintenance ............ 51 35 (46%) Depreciation and Amortization ........ 6 6 -- Other Operating Expenses ............. 1 2 (50%) ---------- ---------- Total Operating Expenses ........... 2,864 1,516 89% ---------- ---------- Operating Income ....................... $ 44 $ 95 (54%) ========== ========== Operations Data: Natural Gas (in Bcf): Sales ................................ 432 294 47% Gathering ............................ 70 60 17% ---------- ---------- Total .............................. 502 354 42% ========== ========== Electricity (in thousand MWH): Wholesale Power Sales ................ 43,856 22,353 96% ========== ========== NINE MONTHS ENDED SEPTEMBER 30, ---------------------- PERCENT 1999 1998 CHANGE --------- --------- --------- (IN MILLIONS) Operating Revenues ..................... $ 5,854 $ 3,416 71% Operating Expenses: Natural Gas .......................... 2,703 1,647 64% Purchased Power ...................... 2,936 1,604 83% Operation and Maintenance ............ 139 80 74% Depreciation and Amortization ........ 18 12 50% Other Operating Expenses ............. 5 4 25% --------- --------- Total Operating Expenses ........... 5,801 3,347 73% --------- --------- Operating Income ....................... $ 53 $ 69 (23%) ========= ========= Operations Data: Natural Gas (in Bcf): Sales ................................ 1,317 800 65% Gathering ............................ 198 175 13% --------- --------- Total .............................. 1,515 975 55% ========= ========= Electricity (in thousand MWH): Wholesale Power Sales ................ 77,624 52,471 48% ========= ========= 26
29 Wholesale Energy operating income for the third quarter and first nine months of 1999 decreased by $51 million and $16 million, respectively, over the 1998 periods. The decreases are primarily due to milder weather, competition from higher levels of hydro-electric generation imports in the California market and higher operating expense due to staffing increases for trading and marketing activities. The decreases were partially offset by improved margins and volumes from the trading and marketing activities largely due to higher power marketing and petroleum margins offset by lower natural gas margins. Wholesale Energy operating revenues increased $1.3 billion and $2.4 billion in the third quarter and first nine months of 1999, respectively, primarily due to an increase in gas and power marketing sales volumes, partially offset by a decrease in the average sales price of gas. Wholesale Energy natural gas costs increased $379 million and $1.1 billion in the third quarter and first nine months of 1999, respectively, due to an increase in gas sales volume, partially offset by a decrease in the average price of gas. Wholesale Energy purchased power expense increased $954 million and $1.3 billion in the third quarter and first nine months of 1999, respectively, primarily due to increased power sales volume. Wholesale Energy operating and maintenance expense increased $16 million in the third quarter of 1999 compared to the same period of 1998 primarily due to staffing increases for trading and marketing activities. Operation and maintenance expense for Wholesale Energy increased $59 million in the first nine months of 1999 primarily due to operating expenses of the California plants for the full nine months and staffing increases. Depreciation and amortization expense for Wholesale Energy remained steady in the third quarter and increased $6 million in the first nine months of 1999 largely due to the depreciation of the California plants for the full period. To minimize the Company's risks associated with fluctuations in the price of natural gas and transportation, the Company, primarily through Reliant Energy Services, Inc. (a subsidiary of Resources), enters into futures transactions, swaps and options relating to (i) certain commitments to buy, sell and transport natural gas, (ii) existing natural gas and heating oil inventory, (iii) future power sales and natural gas purchases by generation facilities, (iv) crude oil and refined products and (v) certain anticipated transactions, some of which carry off-balance sheet risk. Reliant Energy Services also enters into commodity derivatives in its trading and price risk management activities. For a discussion of the Company's accounting treatment of derivative instruments, see Note 2 of the Company 10-K Notes and Item 7A (Quantitative and Qualitative Disclosure About Market Risk) in the Company Form 10-K. INTERNATIONAL The International segment includes Reliant Energy International, Inc. (a wholly owned subsidiary of the Company) and the international operations of Resources. Substantially all of International's operations are in Latin America. THREE MONTHS ENDED SEPTEMBER 30, ------------------- PERCENT 1999 1998 CHANGE ------- ------- --------- (IN MILLIONS) Operating Revenues ..................... $ 34 $ 32 6% Operating Expenses: Fuel ................................. 11 5 120% Operation and Maintenance ............ 12 12 -- Depreciation and Amortization ........ 1 1 -- ------- ------- Total Operating Expenses ........... 24 18 33% ------- ------- Operating Income ....................... $ 10 $ 14 (29%) ======= ======= 27
30 NINE MONTHS ENDED SEPTEMBER 30, --------------------- PERCENT 1999 1998 CHANGE -------- -------- ------- (IN MILLIONS) Operating Revenues ..................... $ 26 $ 228 (89%) Operating Expenses: Fuel ................................. 36 15 140% Operation and Maintenance ............ 40 34 18% Depreciation and Amortization ........ 3 3 -- -------- --------- Total Operating Expenses ........... 79 52 52% -------- --------- Operating Income (Loss) ................ $ (53) $ 176 -- ======== ========= International had operating income of $10 million in the third quarter of 1999 and operating loss of $53 million in the first nine months of 1999 compared to operating income of $14 and $176 million in the same periods of 1998, respectively. The third quarter of 1999 operating income includes a $19 million after tax loss resulting from the devaluation of the Brazilian real on Light and Metropolitana's non-local currency denominated debt. Such devaluation losses stem from the Brazilian government's January 1999 decision to allow the Brazilian real to float against other foreign currencies. Excluding the loss from the currency devaluation, operating income for the third quarter of 1999 was $29 million. The increase from the prior year, after consideration of the currency devaluation, is primarily attributed to increases in equity earnings. For more information regarding risks of the Company's international operations, see "Certain Factors Affecting Future Earnings - Risks of International Operations" below. The operating loss for the nine-month period of 1999 includes a $114 million after tax loss resulting from the devaluation of the Brazilian real as discussed above. Excluding the loss from the currency devaluation, operating income for the first nine months of 1999 was $61 million. The decrease from the prior year is primarily attributed to a $138 million pre-tax gain on the sale of International's 63% interest in an Argentine electric distribution company in 1998. This was partially offset by increased equity earnings and earnings from a cogeneration facility that became operational in November 1998. Fuel expenses increased in the third quarter and first nine months of 1999 compared to the same periods in 1998 primarily due to the cogeneration facility that became operational in November 1998. CORPORATE In the third quarter of 1999, Corporate had an operating loss of $18 million compared to an operating loss of $25 million in 1998. The operating loss for the first nine months of 1999 was $28 million compared to an operating loss of $20 million for the 1998 period. The improved results in the third quarter of 1999 compared to 1998 were due to reduced benefit liabilities. The increased operating loss in the nine month period compared to the 1998 period is due to increased information system, general insurance liability and business development expenses. 28
31 CERTAIN FACTORS AFFECTING FUTURE EARNINGS For information on developments, factors and trends that may have an impact on the Company's future earnings, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations of the Company - Certain Factors Affecting Future Earnings of the Company and its Subsidiaries" in the Company Form 10-K, which is incorporated herein by reference. Among the factors discussed are: "Competition and Restructuring of the Electric Utility Industry," "Competition - Other Operations," "Fluctuation In Commodity Prices and Derivative Instruments," "Accounting Treatment of ACES," "Impact of the Year 2000 Issue and Other System Implementation Issues," "Risks of International Operations," "Environmental Expenditures" and "Other Contingencies." Certain updated information contained in the Notes to the Company's Interim Financial Statements is referenced below. ACCOUNTING TREATMENT OF ACES AND ZENS For information on the accounting treatment of the ACES, the Company's investment in Time Warner common stock (TW Common) and the ZENS issued in September 1999, see Note 7 to the Company's Interim Financial Statements. TEXAS ELECTRIC CHOICE PLAN In June 1999, the State of Texas adopted legislation that substantially amends the regulatory structure governing electric utilities in order to allow retail competition beginning on January 1, 2002. In preparation for that competition, the Company will make significant changes in the electric utility operations it conducts through Reliant Energy HL&P. For additional information regarding the Legislation, see Note 2 to the Company's Interim Financial Statements. The Legislation is further described in Note 2 to the Company Second Quarter 10-Q, which description is incorporated herein by reference. IMPACT OF THE YEAR 2000 AND OTHER SYSTEM IMPLEMENTATION ISSUES For a description of the Company's Year 2000 and other system implementation issues, see "Management's Discussion and Analysis of Financial Condition and Results of Operations of the Company - Certain Factors Affecting Future Earnings of the Company and its Subsidiaries - Impact of the Year 2000 and Other System Implementation Issues" in the Company Form 10-K. All of the Company's and its subsidiaries' business units have completed a Year 2000 Project analysis of critical systems and equipment that control the production and delivery of energy, as well as corporate, departmental and personnel systems and equipment. Remediation and testing of all systems and equipment that could affect the production and delivery of energy (Priority 1 items) were completed during the second quarter of 1999. The Company also completed Year 2000 contingency planning during the second quarter of 1999. Remediation and testing of substantially all systems and equipment that impact financial operation processes such as billing, repairs and payroll (Priority 2 items) were completed during the third quarter of 1999. It is anticipated that work will be completed by December 31, 1999 with respect to Priority 3 items (activities that would cause inconvenience or productivity loss, such as air conditioning systems and elevators). The following table illustrates the Company's completion percentages for the Year 2000 activities as of October 31, 1999: PRIORITY 1 PRIORITY 2 PRIORITY 3 -------------- -------------- --------------- Assessment ......... 100% 100% 100% Conversion ......... 100% 100% 99% Testing ............ 100% 100% 98% Implementation ..... 100% 100% 96% 29
32 Total direct costs of resolving the Year 2000 issue with respect to the Company and its subsidiaries are expected to be between $30 and $35 million and include approximately $26.3 million spent through September 30, 1999. The Company is in the process of implementing SAP America, Inc.'s (SAP) proprietary R/3 enterprise software. Although it is anticipated that the implementation of the SAP system will have the incidental effect of negating the need to modify many of the Company's computer systems to accommodate the Year 2000 problem, the Company does not deem the costs of the SAP system as directly related to its Year 2000 compliance program. Portions of the SAP system were implemented in December 1998, March 1999 and September 1999, and it is expected that the final portion of the SAP system will be fully implemented by August 2000. The cost of implementing the SAP system is currently estimated to be approximately $226 million, inclusive of internal costs. As of September 30, 1999, $173 million has been spent on the implementation. RISKS OF INTERNATIONAL OPERATIONS The Company's international operations are subject to various risks incidental to investing or operating in emerging market countries. These risks include political risks, such as government instability, and 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. The Company's international operations are also highly capital intensive and significantly dependent on the availability of bank financing and other sources of capital on commercially acceptable terms. To offset the devaluation of the Brazilian real, and the resulting increased operating costs and inflation, Light and Metropolitana received tariff rate increases of 16% and 21%, respectively, which were phased in during June and July 1999. Light also received its annual rate adjustment in November 1999 resulting in a tariff rate increase of 11%. The Company is pursuing additional tariff increases to mitigate the impact of the devaluation; however, there can be no assurance that such adjustments will be timely or that they will permit substantial recovery of the impact of the devaluation. For more information on the risks of international operations, see "Qualitative and Quantitative Disclosures About Market Risk of the Company" herein, Note 3 to the Company's Interim Financial Statements and "Management's Discussion and Analysis of Financial Condition and Results of Operations of the Company - Certain Factors Affecting Future Earnings of the Company and its Subsidiaries - Risks of International Operations" in the Company Form 10-K. LIQUIDITY AND CAPITAL RESOURCES For the nine months ended September 30, 1999, the Company's net cash provided by operating activities decreased $48 million compared to the same period in 1998 due in part to a $141 million tax refund received in the 1998 period and changes in working capital. Net cash used in investing activities increased $505 million for the nine months ended September 30, 1999 compared to the 1998 period primarily due to the purchase of additional TW Common. Cash flows from financing activities for the nine months ended September 30, 1999 reflected a cash inflow of $641 million as compared to a cash outflow of $367 million for the same period in 1998. The funds in 1999 included proceeds from the issuance of indexed debt securities, trust preferred securities, commercial paper, pollution control revenue bonds and borrowings under a Euro revolving credit facility, partially offset by the extinguishment of long-term debt, the payment of common stock dividends and the payment of notes payable. 30
33 On October 7, 1999, a subsidiary of the Company purchased the 619-megawatt Indian River Steam Generation Plant in Florida for $205 million. External funding for the acquisition was obtained through the issuance of commercial paper at a financing subsidiary of the Company. On October 7, 1999, a subsidiary of the Company purchased 40% of the capital stock of UNA for $780 million, which included $354 million in cash and a $426 million five-year promissory note. The promissory note must be prepaid under certain circumstances. In accordance with the stock purchase agreement, the Company's subsidiary has irrevocable fixed commitments to increase its ownership interest of UNA to 52% by December 1, 1999 and will purchase the remaining shares of UNA on March 1, 2000. The total purchase price of the acquisition is approximately $2.4 billion. All purchase price obligations are denominated in NLG. The dollar amounts shown above assume an exchange rate of 2.0565 NLG per U.S. dollar (the exchange rate on October 7, 1999). The Company is evaluating financing alternatives in connection with the funding of increases in its UNA ownership interest and promissory note payments. During the three months ended September 30, 1999 and the period from October 1, 1999 through November 8, 1999, the Company purchased 1,419,200 and 90,800 shares, respectively, of its common stock for $38.8 million and $2.4 million. As of September 30, 1999, the Company was authorized to purchase an additional $47.5 million of its common stock. The following tables provide information about the Company's and Resources' unused sources of capital at September 30, 1999 and financing transactions that occurred in the third quarter of 1999. UNUSED SOURCES OF CAPITAL AT SEPTEMBER 30, 1999 SOURCE AVAILABILITY ------ ------------ (IN MILLIONS) COMPANY: $200 million revolving credit facility (1)......................... $ 200 Shelf registration statements (2).................................. $ 230 preferred stock 580 debt securities 125 trust preferred securities and related junior subordinated debt securities 406 common stock (3) RESOURCES:(4) $350 million revolving credit facility (5)......................... $ 293 FINANCING SUBSIDIARIES: $1.6 billion revolving credit facility (6)......................... $ 508 Euro 560 million revolving credit facility (7)..................... Euro 222 (approximately $236) - ---------------- (1) Supports up to $200 million of commercial paper borrowings. (2) Issuance of securities under the shelf registration statements is subject to market and other conditions. (3) Amount is based on the closing price of the common stock as of September 30, 1999. The registration statement covers the sale of 15 million shares. (4) Resources also has a $350 million receivables facility that was fully utilized at September 30, 1999. (5) Supports commercial paper borrowings and has a $65 million subfacility which may be used for letters of credit. At September 30, 1999, there were outstanding letters of credit totaling $22.8 million and outstanding commercial paper of $34.2 million. (6) Supports up to $1.6 billion of commercial paper borrowings. (7) Borrowings under this facility are denominated in Euros. 31
34 On September 30, 1999, Reliant Energy Power Generation, Inc. (REPG), a wholly owned subsidiary of the Company, had Euro 338 million (approximately $360 million) invested at an overnight rate of 2.25% in anticipation of funding the cash portion (approximately $354 million) of the acquisition of a 40% interest in UNA which occurred on October 7, 1999. Reliant Energy HL&P plans to file an application with the Public Utility Commission of Texas requesting a financing order authorizing the issuance by a special purpose entity organized by the Company, pursuant to the Legislation, of approximately $1 billion of transition bonds related to Reliant Energy HL&P's generation related regulatory assets. Payments on the transition bonds will be made from non-bypassable transition charges to Reliant Energy HL&P's transmission and distribution customers. The offering and sale of the transition bonds will be registered under the Securities Act of 1933 and is expected to be consummated in the first quarter of 2000. THIRD QUARTER 1999 REPAYMENTS AND REDEMPTIONS TYPE OF DEBT AMOUNT - ------------ ------------- (IN MILLIONS) COMPANY OR ON BEHALF OF COMPANY: Brazos River Authority (BRA) 7.625% Collateralized Revenue Refunding Bonds, Series 1989A ................................................................... $ 100 Matagorda County Navigation District Number One (MCND) 7.125% Collateralized Revenue Refunding Bonds, Series 1989C ....................................... 100 Reduction in outstanding commercial paper ...................................... 47 RESOURCES: 8.875% Notes due 1999 .......................................................... 200 FINANCING SUBSIDIARIES: Reduction in outstanding commercial paper ...................................... 328 On October 1, 1999, MCND Series 1989D 7.60% Collateralized Pollution Control Revenue Bonds aggregating $70.315 million were redeemed at 102% of their principal amount plus accrued interest. In October 1999, Resources called for redemption the remaining $42.76 million principal amount of its 10% Debentures due 2019. The debentures will be redeemed on November 15, 1999 at 105% of their principal amount plus accrued interest. 32
35 THIRD QUARTER 1999 FINANCINGS TYPE OF DEBT AMOUNT INTEREST RATE MATURITY DATE - ------------ ------------- ------------- -------------- (IN MILLIONS) COMPANY: MCND 5.95% Revenue Refunding Bonds (1) $ 70.315 5.95% 2030 ZENS (2) $ 1,000 2.0% 2029 RESOURCES: Receivables Facility (3) $ 50 5.53% 2000 FINANCING SUBSIDIARIES: Bank Borrowings (4) Euro 338 (approximately $360) 3.127% 2000 - ------------------ (1) On behalf of the Company. Proceeds from the sale were used October 1, 1999 to redeem $70.315 million 7.6% MCND Series 1989D collateralized revenue refunding bonds at a price of 102%. (2) See Notes 7 and 10(a) to the Interim Financial Statements for a description of the ZENS. (3) In August 1999, Resources increased the size of its receivables facility from $300 million to $350 million and received an additional $50 million from its sale of receivables. The receivables facility expires in August 2000. (4) In September 1999, a finance subsidiary of the Company established a Euro 560 million (approximately $596 million) revolving credit facility expiring in September 2000 and borrowed Euro 338 million under such facility. On April 8, 1999, in anticipation of the UNA transaction, REPG entered into call option agreements with several banks to hedge the impact of foreign exchange movements in NLG. These call options provided the right, but not the obligation, to purchase 695 million NLG at strike prices ranging from 1.99 to 2.01 NLG per US dollar. The total premium paid for the options, which expired on October 26, 1999, was $7.7 million. The premium was being amortized on a straight line basis. On October 12, 1999, REPG sold the remaining value in the call options for $0.6 million which will be reflected in the fourth quarter results of operations. Due to the worsening economic and political conditions in Colombia, S.A., the Company expects that 1999 operating cash flow for certain of its Colombian operations will not meet their working capital and capital expenditure needs. Consequently, a short-term loan was entered into by the Colombian operating companies. In September 1999, the Company made a contribution of approximately $33 million and expects to make an additional contribution of approximately $12 million during the fourth quarter of 1999. These funds will be used in large part to repay the short-term loan. In November 1999, Light issued 650 million Brazilian reais of subordinated debentures. The proceeds of the debentures will be used to retire approximately $325 million of non-local currency denominated borrowings. At September 30, 1999, one U.S. dollar could be exchanged for 1.9223 Brazilian reais. 33
36 On November 10, 1999, the BRA issued on behalf of the Company $100 million of revenue refunding bonds having an annual interest rate of 5.20% and a maturity date of December 1, 2018. The BRA bonds will be subject to mandatory tender or optional redemption on December 1, 2002 at a price equal to 100% of the principal amount. The proceeds from the issuance will be used on December 13, 1999 to redeem all outstanding BRA Series 1989B collateralized revenue refunding bonds ($100 million) at a redemption price of 102% of their aggregate principal amount. On November 10, 1999, the MCND issued on behalf of the Company $75 million of revenue refunding bonds having an annual interest rate of 5.20% and a maturity date of May 1, 2029. The MCND bonds will be subject to mandatory tender or optional redemption on November 1, 2002 at a price equal to 100% of the principal amount. The proceeds from the issuance will be used on December 13, 1999 to redeem all outstanding MCND Series 1989E collateralized revenue refunding bonds ($75 million) at a redemption price of 102% of their aggregate principal amount. On November 12, 1999, a financing subsidiary issued $300 million of Senior Notes due 2002 having an annual interest rate of 7.4%. The proceeds from the issuance were used by the financing subsidiary to purchase Series E Preference stock of the Company. As a result of the transaction, the financing subsidiary owns 3,160 shares of the Series E Preference Stock. The Company anticipates that the proceeds from the sale of such preference stock will be used for general corporate purposes, including the repayment of indebtedness. The devaluation of the Brazilian real has resulted in the inability of Light and Metropolitana to distribute adequate dividends to meet debt requirements of a subsidiary of the Company. In July 1999, the subsidiary executed a guarantee of up to $45 million. In November 1999, it is anticipated that the Company will make a capital contribution of approximately $20 million to fund a portion of this obligation. If Light and Metropolitana are not able to distribute adequate dividends to meet debt requirements of the subsidiary, it is anticipated that the Company will make a capital contribution in May 2000 to fund the remainder of this obligation. The Company believes that its current level of cash and borrowing capability along with future cash flows from operations is sufficient to meet the needs of its existing businesses. However, to achieve its objectives, the Company may, when necessary, supplement its available cash resources by seeking funds in the equity or debt markets. NEW ACCOUNTING ISSUES In 2001, the Company and Resources expect to adopt Statement of Financial Accounting Standards (SFAS) 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 hedging instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities. The Company and Resources are in the process of determining the effect of the adoption of SFAS No. 133 on their consolidated financial statements. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK OF THE COMPANY The Company and its subsidiaries have financial instruments that involve various market risks and uncertainties. For information regarding the Company's exposure to risks associated with interest rates, equity market prices, foreign currency exchange rate risk and energy commodity prices, see Item 7A of the Company Form 10-K. These risks have not materially changed from the market risks disclosed in the Company Form 10-K, except as discussed below. As described in "Management's Discussion and Analysis of Financial Conditions and Results of Operations of the Company," for the nine months period ended on September 30, 1999, the Company reported a $114 million charge to net income and a $65 million charge to other comprehensive income, due to the devaluation of the Brazilian real. The charge to net income reflects increases in the liabilities at Light and Metropolitana for their non-local currency denominated borrowings using the exchange rate in effect at September 30, 1999 and a monthly weighted average exchange rate for the nine-month period then ended. The charge to other comprehensive income 34
37 reflects the translation effect on the local currency denominated net assets underlying the Company's investment in Light. As of September 30, 1999, the Brazilian real exchange rate was 1.9223 per U.S. dollar. An increase of 10% from the September 30, 1999 exchange rate would result in the Company recording an additional charge of $18 million and $14 million to net income and other comprehensive income, respectively. As discussed in Notes 7 and 10 to the Company's Interim Financial Statements, the Company owns approximately 55 million shares of TW Common, of which approximately 38 million and 17 million shares are expected to economically hedge the ACES and ZENS, respectively. Unrealized gains and losses resulting from changes in the market value of the Company's TW Common are recorded in the Consolidated Statement of Operations. Increases in the market value of TW Common result in an increase in the liability for the ZENS and ACES and are recorded as a non-cash expense. Such non-cash expense will be offset by an unrealized gain on the Company's TW Common investment. However, if the market value of TW Common declines below $58.25, the ZENS payment obligation will not decline below its original principal amount. Therefore, a decrease of 10% from the September 30, 1999 market value of TW Common of $60.75 per share would result in a $40 million after-tax unrealized loss on the TW Common investment that would not be offset by the decrease in the liability for the ZENS. 35
38 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, ------------------------------- ------------------------------- 1999 1998 1999 1998 --------------- --------------- --------------- --------------- REVENUES............................................. $ 3,446,925 $ 1,927,156 $7,705,879 $ 5,062,167 --------------- --------------- --------------- --------------- EXPENSES: Natural gas and purchased power.................... 3,171,485 1,685,067 6,793,915 4,221,741 Operation and maintenance.......................... 176,522 140,331 461,897 426,506 Depreciation and amortization...................... 50,045 53,240 148,159 144,305 Taxes other than income taxes...................... 21,145 24,865 79,054 86,734 --------------- --------------- --------------- --------------- 3,419,197 1,903,503 7,483,025 4,879,286 --------------- --------------- --------------- --------------- OPERATING INCOME..................................... 27,728 23,653 222,854 182,881 --------------- --------------- --------------- --------------- OTHER INCOME (EXPENSE): Interest expense................................... (30,378) (25,736) (90,231) (78,115) Distributions on trust securities.................. (64) (106) (261) (533) Other - net........................................ 1,846 1,049 8,604 5,585 --------------- --------------- --------------- --------------- (28,596) (24,793) (81,888) (73,063) --------------- --------------- --------------- --------------- INCOME (LOSS) BEFORE INCOME TAXES.................... (868) (1,140) 140,966 109,818 INCOME TAX EXPENSE................................... 5,664 1,446 70,569 55,449 --------------- --------------- --------------- --------------- NET INCOME (LOSS).................................... $ (6,532) $ (2,586) $ 70,397 $ 54,369 =============== =============== =============== =============== See Notes to Resources' Consolidated Financial Statements. 36
39 RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES (A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED) CONSOLIDATED BALANCE SHEETS (THOUSANDS OF DOLLARS) (UNAUDITED) ASSETS SEPTEMBER 30, DECEMBER 31, 1999 1998 ------------------- ------------------- CURRENT ASSETS: Cash and cash equivalents............................................. $ 69,507 $ 26,576 Accounts and notes receivable, principally customer................... 874,324 682,552 Unbilled revenue...................................................... 44,851 145,131 Accounts and notes receivable - affiliated companies, net............. 193,177 Income tax receivable................................................. 44,270 Materials and supplies................................................ 35,100 33,947 Fuel, gas and petroleum products...................................... 148,015 161,085 Price risk management assets.......................................... 481,147 265,203 Other current assets.................................................. 49,611 39,234 ------------------- ------------------- Total current assets................................................ 1,746,825 1,546,905 ------------------- ------------------- PROPERTY, PLANT AND EQUIPMENT: Natural gas distribution and gathering systems........................ 1,870,869 1,686,159 Interstate pipelines.................................................. 1,316,329 1,302,829 Other................................................................. 20,870 13,976 ------------------- ------------------- Total............................................................... 3,208,068 3,002,964 Less accumulated depreciation and amortization........................ 290,317 187,936 ------------------- ------------------- Property, plant and equipment - net................................... 2,917,751 2,815,028 ------------------- ------------------- OTHER ASSETS: Goodwill - net........................................................ 1,994,608 2,050,386 Price risk management assets.......................................... 100,593 21,414 Deferred debits ...................................................... 259,522 221,788 ------------------- ------------------- Total other assets.................................................. 2,354,723 2,293,588 ------------------- ------------------- TOTAL ASSETS............................................................ $ 7,019,299 $ 6,655,521 =================== =================== See Notes to Resources' Consolidated Financial Statements. 37
40 RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES (A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED) CONSOLIDATED BALANCE SHEETS - (CONTINUED) (THOUSANDS OF DOLLARS) (UNAUDITED) LIABILITIES AND STOCKHOLDER'S EQUITY SEPTEMBER 30, DECEMBER 31, 1999 1998 ------------------- ------------------- CURRENT LIABILITIES: Current maturities of long-term debt.................................. $ 201,671 $ 203,438 Receivables facility.................................................. 350,000 300,000 Notes payable......................................................... 34,200 Accounts payable, principally trade................................... 694,467 622,262 Accounts and notes payable - affiliated companies, net................ 55,938 Interest payable...................................................... 29,030 36,197 Other taxes........................................................... 42,971 42,107 Customer deposits..................................................... 33,349 36,985 Price risk management liabilities..................................... 457,420 227,652 Other current liabilities............................................. 233,063 172,616 ------------------- ------------------- Total current liabilities....................................... 2,132,109 1,641,257 ------------------- ------------------- DEFERRED CREDITS AND OTHER LIABILITIES: Accumulated deferred income taxes..................................... 548,334 511,070 Price risk management liabilities..................................... 95,494 29,108 Other................................................................. 318,178 397,141 ------------------- ------------------- Total deferred credits and other liabilities...................... 962,006 937,319 ------------------- ------------------- LONG-TERM DEBT, LESS CURRENT MATURITIES................................. 1,292,479 1,513,289 ------------------- ------------------- Total Liabilities................................................ 4,386,594 4,091,865 ------------------- ------------------- COMMITMENTS AND CONTINGENCIES (NOTE 1) RESOURCES OBLIGATED MANDATORILY REDEEMABLE CONVERTIBLE PREFERRED SECURITIES OF SUBSIDIARY TRUST HOLDING SOLELY JUNIOR SUBORDINATED DEBENTURES OF RESOURCES - NET........................................ 1,066 1,157 ------------------- ------------------- STOCKHOLDER'S EQUITY: Common stock.......................................................... 1 1 Paid-in capital....................................................... 2,463,831 2,463,831 Retained earnings..................................................... 185,068 114,671 Accumulated other comprehensive income................................ (17,261) (16,004) ------------------- ------------------- Total stockholder's equity...................................... 2,631,639 2,562,499 ------------------- ------------------- TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY........................... $ 7,019,299 $ 6,655,521 =================== =================== See Notes to Resources' Consolidated Financial Statements. 38
41 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, ---------------------------------------- 1999 1998 ------------------- ------------------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income............................................................ $ 70,397 $ 54,369 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization....................................... 148,159 144,305 Deferred income taxes............................................... 46,356 21,029 Changes in other assets and liabilities: Accounts and notes receivable - net................................. (91,492) (473,373) Inventories......................................................... 11,917 (116,942) Other current assets................................................ (10,377) (18,056) Accounts payable.................................................... 86,240 511,261 Accounts and notes receivable/payable - affiliated companies........ 249,115 92,959 Interest and taxes accrued.......................................... (59,665) (55,780) Other current liabilities........................................... 56,811 (34,844) Net price risk management activities................................ 1,031 (20,974) Other - net......................................................... (118,286) 88,364 ------------------- ------------------- Net cash provided by operating activities....................... 390,206 192,318 ------------------- ------------------- CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures.................................................. (200,858) (184,301) Other - net.......................................................... (7,950) 4,032 ------------------- ------------------- Net cash used in investing activities........................... (208,808) (180,269) ------------------- ------------------- CASH FLOWS FROM FINANCING ACTIVITIES: Retirements and reacquisitions of long-term debt...................... (212,042) (76,000) Proceeds from receivables facility.................................... 50,000 Increase (decrease) in notes payable.................................. 34,200 (216,931) Proceeds from issuance of debentures.................................. 298,514 Redemption of convertible securities.................................. (57) (10,399) Other - net........................................................... (10,568) (20,504) ------------------- ------------------- Net cash used in financing activities............................. (138,467) (25,320) ------------------- ------------------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS.................... 42,931 (13,271) CASH AND CASH EQUIVALENTS AT BEGINNING OF THE PERIOD.................... 26,576 35,682 ------------------- ------------------- CASH AND CASH EQUIVALENTS AT END OF THE PERIOD.......................... $ 69,507 $ 22,411 =================== =================== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash payments: Interest (net of amounts capitalized)................................. $ 93,493 $ 97,822 Income taxes - net.................................................... 66,095 (57,863) See Notes to Resources' Consolidated Financial Statements. 39
42 RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES (A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED) CONSOLIDATED STATEMENTS OF RETAINED EARNINGS AND COMPREHENSIVE INCOME (LOSS) (THOUSANDS OF DOLLARS) (UNAUDITED) THREE MONTHS ENDED SEPTEMBER 30, -------------------------------------------------------------------- 1999 1998 --------------------------------- --------------------------------- RETAINED EARNINGS: Balance at beginning of period............. $ 191,600 $ 77,802 Net loss................................... (6,532) $ (6,532) (2,586) $ (2,586) ---------------- ---------------- Balance at end of period................... $ 185,068 $ 75,216 ================ ================ ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX: Balance at beginning of period............. $ (14,685) $ (10,669) Unrealized loss on available for sale securities, net of tax of $1,449 and $3,304 (2,576) (2,576) (5,874) (5,874) ---------------- ---------------- Balance at end of period................... $ (17,261) $ (16,543) ================ ================ ---------------- ---------------- COMPREHENSIVE LOSS........................... $ (9,108) $ (8,460) ================ ================ NINE MONTHS ENDED SEPTEMBER 30, -------------------------------------------------------------------- 1999 1998 --------------------------------- --------------------------------- RETAINED EARNINGS: Balance at beginning of period............. $ 114,671 $ 20,847 Net income................................. 70,397 $ 70,397 54,369 $ 54,369 ---------------- ---------------- Balance at end of period................... $ 185,068 $ 75,216 ================ ================ ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX: Balance at beginning of period............. $ (16,004) $ (5,634) Unrealized loss on available for sale securities, net of tax of $707 and $6,136 (1,257) (1,257) (10,909) (10,909) ---------------- ---------------- Balance at end of period................... $ (17,261) $ (16,543) ================ ================ ---------------- --------------- COMPREHENSIVE INCOME......................... $ 69,140 $ 43,460 ================ =============== See Notes to the Resources' Consolidated Financial Statements. 40
43 RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS The Notes to the unaudited consolidated financial statements of Reliant Energy Resources Corp. (Resources) are included in the Notes to the unaudited consolidated financial statements of Reliant Energy, Incorporated (Company) as follows and are incorporated herein by reference: (1) BASIS OF PRESENTATION -- see Note 1 to the Company's Interim Financial Statements. (2) DEPRECIATION -- see Note 4(b) to the Company's Interim Financial Statements. (3) CHANGE IN ACCOUNTING PRINCIPLE -- see Note 6 to the Company's Interim Financial Statements. (4) COMPANY/RESOURCES OBLIGATED MANDATORILY REDEEMABLE TRUST PREFERRED SECURITIES OF SUBSIDIARY TRUSTS HOLDING SOLELY JUNIOR SUBORDINATED DEBENTURES OF THE COMPANY/RESOURCES -- see Note 9(b) to the Company's Interim Financial Statements. (5) LONG-TERM DEBT AND SHORT-TERM FINANCING -- see Note 10(b) to the Company's Interim Financial Statements. (6) REPORTABLE SEGMENTS Effective January 1, 1998, Resources adopted SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information" (SFAS No. 131). Because Resources is a wholly owned subsidiary of the Company, Resources has determined its reportable segments based in part on the operating units under which its parent manages sales to wholesale or retail customers in differing regulatory environments. The segment financial data include information for the Company and Resources on a combined basis, except for Electric Operations, which has no Resources operations, and International, which has minimal Resources operations. Reconciling items included under the caption "Elimination of Non-Resources Operations" reduce the amounts by those operations not conducted within the Resources legal entity. Operations not owned or operated by Resources, but included in segment information before elimination, include primarily the operations of the Company's non-rate regulated power generation business, and non-Resources corporate expenses. In accordance with SFAS No. 131, the Company has identified the following reportable segments: Electric Operations, Natural Gas Distribution, Interstate Pipelines, Wholesale Energy, International and Corporate. See Note 11 to the Company's Interim Financial Statements for a description of these segments. 41
44 Financial data for business segments are as follows (in thousands): ELIMINATION OF NON- NATURAL GAS INTERSTATE WHOLESALE CORPORATE RECONCILING RESOURCE DISTRIBUTION PIPELINES ENERGY AND OTHER ELIMINATIONS(1) OPERATIONS CONSOLIDATED ------------ ----------- ----------- ----------- --------------- ----------- ------------ For the Three Months Ended September 30, 1999: Revenues .................... $ 302,387 $ 37,303 $ 2,847,388 $ 229,392 $ 30,455 $ 3,446,925 Intersegment revenues ....... 311 32,721 60,731 20,644 $ (114,407) Operating income (loss) ..... (12,349) 28,767 43,584 (17,247) (15,027) 27,728 For the Three Months Ended September 30, 1998: Revenues .................... 265,911 34,110 1,584,472 133,349 (90,686) 1,927,156 Intersegment revenues ....... 266 36,284 26,181 24,002 (86,733) Operating income (loss) ..... (17,212) 27,421 94,511 (24,814) (56,253) 23,653 As of and for the Nine Months Ended September 30, 1999: Revenues .................... $ 1,309,241 $ 90,608 $ 5,692,028 $ 616,630 $ (2,628) $ 7,705,879 Intersegment revenues ....... 912 111,638 162,024 56,579 $ (331,153) Operating income (loss) ..... 80,141 83,866 53,378 (27,829) 33,298 222,854 Total assets ................ 2,960,971 2,025,244 2,725,752 4,010,246 (645,877) (4,057,037) 7,019,299 As of and for the Nine Months Ended September 30, 1998: Revenues .................... 1,326,672 103,919 3,298,008 432,648 (99,080) 5,062,167 Intersegment revenues ....... 890 113,972 118,040 69,945 (302,847) Operating income (loss) ..... 80,403 92,343 68,551 (21,065) (37,351) 182,881 Total assets ................ 2,830,260 2,116,927 2,108,629 1,762,848 (851,829) (1,019,779) 6,947,056 - ---------- (1) Includes data for operations conducted at the parent level and for subsidiaries of the Company that are not Resources entities. This data is eliminated for purposes of the consolidated data at the Company level. Reconciliation of operating income to net income (loss) (in thousands) is as follows: THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, --------------------------------- --------------------------------- 1999 1998 1999 1998 ---------------- ---------------- ---------------- --------------- Operating income.............................. $ 27,728 $ 23,653 $ 222,854 $ 182,881 Interest expense.............................. 30,378 25,736 90,231 78,115 Distribution on trust securities.............. 64 106 261 533 Income tax expense............................ 5,664 1,446 70,569 55,449 Other income - net............................ 1,846 1,049 8,604 5,585 ---------------- ---------------- ---------------- --------------- Net income (loss)............................. $ (6,532) $ (2,586) $ 70,397 $ 54,369 ================ ================ ================ =============== (7) COMPANY/RESOURCES INTERIM PERIOD RESULTS; RECLASSIFICATIONS -- see Note 13 to the Company's Interim Financial Statements. 42
45 MANAGEMENT'S NARRATIVE ANALYSIS OF THE RESULTS OF OPERATIONS OF RESOURCES Resources reports its financial information in the following segments: Natural Gas Distribution, Interstate Pipelines, Wholesale Energy (through which Resources conducts energy trading and marketing operations and natural gas gathering operations, but does not conduct the operations of Reliant Energy Power Generation, Inc.) and Corporate. Although Resources has international operations, they are not significant. Resources meets the conditions specified in General Instruction H to Form 10-Q and is permitted to use the reduced disclosure format for wholly owned subsidiaries of reporting companies. Accordingly, Resources has omitted from this report the information called for by Item 3 (quantitative and qualitative disclosure 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 Resources between the three and nine month periods ended September 30, 1999 and 1998. Reference is made to Management's Narrative Analysis of the Results of Operations in Item 7 of Resources Form 10-K, the Resources 10-K Notes referred to herein and Resources' Interim Financial Statements contained in this Form 10-Q. CONSOLIDATED RESULTS OF OPERATIONS THREE MONTHS ENDED SEPTEMBER 30, ------------------------------------- PERCENT 1999 1998 CHANGE ----------------- ------------------ ------------------ (IN THOUSANDS) Operating Revenues................................... $ 3,446,925 $ 1,927,156 79% Operating Expenses................................... 3,419,197 1,903,503 80% Operating Income - Net............................... 27,728 23,653 17% Interest Expense .................................... 30,378 25,736 18% Distributions on Trust Securities.................... 64 106 (40%) Other Income - Net................................... 1,846 1,049 76% Income Tax Expense................................... 5,664 1,446 -- ----------------- ------------------ Net Income (Loss).................................. $ (6,532) $ (2,586) -- ================= ================== NINE MONTHS ENDED SEPTEMBER 30, ------------------------------------- PERCENT 1999 1998 CHANGE ----------------- ------------------ ------------------ (IN THOUSANDS) Operating Revenues................................... $ 7,705,879 $ 5,062,167 52% Operating Expenses................................... 7,483,025 4,879,286 53% Operating Income - Net............................... 222,854 182,881 22% Interest Expense..................................... 90,231 78,115 16% Distributions on Trust Securities.................... 261 533 (51%) Other Income - Net................................... 8,604 5,585 54% Income Tax Expense................................... 70,569 55,449 27% ----------------- ------------------ Net Income......................................... $ 70,397 $ 54,369 29% ================= ================== Resources' net loss increased $3.9 million in the third quarter of 1999 compared to the 1998 period, primarily due to an increase in the quarterly effective tax rate, interest expense and general insurance liability expense, partially offset by an increase in operating income from Wholesale Energy trading and marketing activities and a decrease in operating loss from the Natural Gas Distribution segment. Wholesale Energy trading and marketing activities increased due to improved margins and volumes partially offset by higher operating expenses due to staffing increases. Improved margins from 43
46 trading and marketing activities were largely due to higher power marketing and petroleum margins offset by lower natural gas margins. Natural Gas Distribution's operating loss for the third quarter of 1999 compared to the same period in 1998 decreased primarily due to increased revenue from customer growth, weather related usage and increased appliance services and sales. Resources' net income increased $16 million in the nine months of 1999 compared to the 1998 period primarily due to increased operating income related to improved trading and marketing results at Wholesale Energy, as discussed above. This increase was partially offset by lower operating income at Interstate Pipelines for the nine-month period and increased interest and general insurance liability expenses. Interstate Pipelines' operating income decreased primarily due to the settlement of a dispute related to certain gas purchase contracts that resulted in $6 million of revenues in the second quarter of 1998 and a rate settlement reflected in the first quarter of 1998 as a $5 million reduction of depreciation rates retroactive to July 1996. This decrease from Interstate Pipelines was partially offset by lower operation and maintenance expenses related to continued cost control initiatives in this segment. Resources' revenues increased $1.5 billion and $2.6 billion in the third quarter and first nine months of 1999, respectively, compared to the same periods of 1998. Resources' operating expenses increased $1.5 billion and $2.6 billion in the third quarter and first nine months of 1999, respectively, compared to the corresponding periods in 1998. The increases in revenues and expenses in both periods primarily resulted from an increase in gas and power marketing sales volumes, partially offset by a decrease in the average price of gas. To minimize risks associated with fluctuations in the price of natural gas and transportation, Resources, through its subsidiary, Reliant Energy Services, Inc., enters into futures transactions, swaps and options relating to (i) certain commitments to buy, sell and transport natural gas, (ii) existing natural gas and heating oil inventory, (iii) crude oil and refined products and (iv) certain anticipated transactions, some of which carry off-balance sheet risk. Reliant Energy Services also enters into commodity derivatives in its trading and price risk management activities. For a discussion of the accounting treatment of derivative instruments, see Note 2 of Resources 10-K Notes and Item 7A (Quantitative and Qualitative Disclosure About Market Risk) in the Company Form 10-K. Seasonality and Other Factors. Resources' results of operations are affected by seasonal fluctuations in the demand for and, to a lesser extent, the price of natural gas. Resources' 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 Resources and its subsidiaries, competition in Resources' various business operations, debt service costs and income tax expense. For a discussion of certain other factors that may affect Resources' future earnings see "Management's Discussion and Analysis of Financial Condition and Results of Operations of the Company - Certain Factors Affecting Future Earnings of the Company and its Subsidiaries Competition - Other Operations," "- Fluctuations in Commodity Prices and Derivative Instruments," "Environmental Expenditures" and "- Other Contingencies" in the Company Form 10-K. NEW ACCOUNTING ISSUES Reference is made to "Management's Discussion and Analysis of Financial Condition and Results of Operations of the Company -- New Accounting Issues" in the Company Form 10-Q for a discussion of certain new accounting issues affecting Resources. 44
47 PART II. OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS. Company: For a description of legal proceedings affecting the Company and its subsidiaries, please review Item 3 of the Company Form 10-K and Notes 3(b), 12(h) and 12(i) of the Company 10-K Notes, which are incorporated herein by reference. Resources: For a description of legal proceedings affecting Resources, please review Note 8(g) of the Resources 10-K Notes, which is incorporated herein by reference. ITEM 5. OTHER INFORMATION. Forward-Looking Statements. From time to time, the Company and Resources may make statements regarding their assumptions, projections, expectations, intentions or beliefs about future events. These statements and other statements that are not historical facts are intended as "forward-looking statements" under the Private Securities Litigation Reform Act of 1995. The Company and Resources caution that assumptions, projections, expectations, intentions or beliefs about future events may and often do vary materially from actual results, and the differences between assumptions, projections, expectations, intentions or beliefs and actual results can be material. Accordingly, there can be no assurance that actual results will reflect those expressed or implied by the forward-looking statements. The following are some of the factors that could cause actual results to differ from those expressed or implied in forward-looking statements: (i) state and federal legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures and affect the speed and degree to which competition enters the electric and natural gas industries; (ii) industrial, commercial and residential growth in service territories of the Company and Resources; (iii) the weather and other natural phenomena; (iv) the timing and extent of changes in commodity prices and interest rates; (v) changes in environmental and other laws and regulations to which the Company, Resources and their respective subsidiaries are subject or other external factors over which the Company and Resources have no control; (vi) the results of financing efforts; (vii) growth in opportunities for the Company's and Resources' subsidiaries and diversified operations; (viii) risks incidental to the Company's overseas operations (including the effects of fluctuations in foreign currency exchange rates); (ix) the effect of the Company's and Resources' accounting policies; (x) the timing of the closing of the Company's acquisition of an interest in UNA; (xi) the success of integrating acquired operations; and (xii) other factors discussed in this and other filings by the Company and Resources with the Securities and Exchange Commission. When used in the Company's or Resources' documents or oral presentations, the words "anticipate," "estimate," "expect," "objective," "projection," "forecast," "goal" and similar words are intended to identify forward-looking statements. 45
48 ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K. (a) Exhibits. Company: -------- Exhibit 12 Ratio of Earnings to Fixed Charges and Preferred Dividends. Exhibit 27 Financial Data Schedule. Exhibit 99 Items incorporated by reference from the Company Form 10-K: Item 3 "Legal Proceedings," Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations of the Company - Certain Factors Affecting Future Earnings of the Company and its Subsidiaries" and "- New Accounting Issues," and Item 7A "Quantitative and Qualitative Disclosures About Market Risk" and Note 1(c) (Regulatory Assets and Other Long-Lived Assets), Note 1(f) (Depreciation and Amortization Expense), Note 1(n) (Investments in Time Warner Securities), Note 1(p) (Foreign Currency Adjustments), Note 1(r) (Change in Accounting Principle), Note 2 (Derivative Financial Instruments), Note 3 (Rate Matters), Note 4 (Jointly Owned Electric Utility Plant), Note 5 (Equity Investments and Advances to Unconsolidated Subsidiaries), Note 8(c) (FinanceCo and FinanceCo II Credit Facilities), Note 8(d) (Company Credit Facility), Note 9(a) (Trust Securities - Company), Note 12 (Commitments and Contingencies) and Note 16(a) (Foreign Currency Devaluation) of the Company 10-K Notes. Items incorporated by reference from the Company First Quarter 10-Q: Note 8(a) (Company/Resources Obligated Mandatorily Redeemable Trust Preferred Securities of Subsidiary Trusts Holding Solely Junior Subordinated Debentures of the Company/Resources), Note 9(a) (Long-Term Debt and Short-Term Financing) and Note 11 (Acquisitions). Items incorporated by reference from the Company Second Quarter 10-Q: Note 2 (Texas Electric Choice Plan and Discontinuance of SFAS No. 71 for Electric Generation Operations) and Note 7 (Time Warner Securities Investment). Resources: ---------- Exhibit 12 Ratio of Earnings to Fixed Charges. Exhibit 27 Financial Data Schedule. Exhibit 99 Items incorporated by reference from Resources Form 10-K: Item 3 "Legal Proceedings," Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations of the Company - Certain Factors Affecting Future Earnings of the Company and its Subsidiaries" and "- New Accounting Issues," Item 7A "Quantitative and Qualitative Disclosures About Market Risk," Item 7 "Management's Narrative Analysis of the Results of Operations of Reliant Energy Resources Corp. and Consolidated Subsidiaries" and Note 1(c) (Regulatory Assets and Regulation), Note 2 (Derivative Financial Instruments), Note 4 (Long-Term and Short-Term Financing), Note 5 (Trust Securities), and Note 8 (Commitments and Contingencies) of Resources 10-K Notes. Item incorporated by reference from the Resources First Quarter 10-Q: Note 9(b) (Long-Term Debt and Short-Term Financing). 46
49 (b) Reports on Form 8-K. Company: -------- Form 8-K filed with the SEC on July 7, 1999 regarding the passage of Texas Electric Choice Plan. Form 8-K filed with the SEC on September 21, 1999 regarding the execution of an Underwriting Agreement relating to the issuance and sale of the ZENS. Form 8-K filed with the SEC on October 18, 1999 regarding (i) the closing of the first phase of the UNA acquisition, (ii) the closing of the ZENS offering, (iii) the conversion of the TW Preferred into TW Common and (iv) the filing of an application with the Texas PUC requesting a financing order authorizing the issuance of transition bonds. Resources: ---------- None. 47
50 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 Ricciardello Senior Vice President and Comptroller (Principal Accounting Officer) Date: November 12, 1999 48
51 EXHIBIT INDEX Exhibits. Description Company: -------- Exhibit 12.A Ratio of Earnings to Fixed Charges and Preferred Dividends. Exhibit 27.A Financial Data Schedule. Exhibit 99.A Items incorporated by reference from the Company Form 10-K: Item 3 "Legal Proceedings," Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations of the Company - Certain Factors Affecting Future Earnings of the Company and its Subsidiaries" and "- New Accounting Issues," and Item 7A "Quantitative and Qualitative Disclosures About Market Risk" and Note 1(c) (Regulatory Assets and Other Long-Lived Assets), Note 1(f) (Depreciation and Amortization Expense), Note 1(n) (Investments in Time Warner Securities), Note 1(p) (Foreign Currency Adjustments), Note 1(r) (Change in Accounting Principle), Note 2 (Derivative Financial Instruments), Note 3 (Rate Matters), Note 4 (Jointly Owned Electric Utility Plant), Note 5 (Equity Investments and Advances to Unconsolidated Subsidiaries), Note 8(c) (FinanceCo and FinanceCo II Credit Facilities), Note 8(d) (Company Credit Facility), Note 9(a) (Trust Securities - Company), Note 12 (Commitments and Contingencies) and Note 16(a) (Foreign Currency Devaluation) of the Company 10-K Notes. Items incorporated by reference from the Company First Quarter 10-Q: Note 8(a) (Company/Resources Obligated Mandatorily Redeemable Trust Preferred Securities of Subsidiary Trusts Holding Solely Junior Subordinated Debentures of the Company/Resources), Note 9(a) (Long-Term Debt and Short-Term Financing) and Note 11 (Acquisitions). Items incorporated by reference from the Company Second Quarter 10-Q: Note 2 (Texas Electric Choice Plan and Discontinuance of SFAS No. 71 for Electric Generation Operations) and Note 7 (Time Warner Securities Investment). Resources: ---------- Exhibit 12.B Ratio of Earnings to Fixed Charges. Exhibit 27.B Financial Data Schedule. Exhibit 99.B Items incorporated by reference from Resources Form 10-K: Item 3 "Legal Proceedings," Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations of the Company - Certain Factors Affecting Future Earnings of the Company and its Subsidiaries" and "- New Accounting Issues," Item 7A "Quantitative and Qualitative Disclosures About Market Risk," Item 7 "Management's Narrative Analysis of the Results of Operations of Reliant Energy Resources Corp. and Consolidated Subsidiaries" and Note 1(c) (Regulatory Assets and Regulation), Note 2 (Derivative Financial Instruments), Note 4 (Long-Term and Short-Term Financing), Note 5 (Trust Securities), and Note 8 (Commitments and Contingencies) of Resources 10-K Notes. Item incorporated by reference from the Resources First Quarter 10-Q: Note 9(b) (Long-Term Debt and Short-Term Financing).
1 EXHIBIT 12A RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES (THOUSANDS OF DOLLARS) NINE TWELVE MONTHS ENDED MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ----------------- ----------------- 1999 1999 ----------------- ----------------- Fixed Charges as Defined: (1) Interest on Long-Term Debt........................................ $ 307,965 $ 413,519 (2) Other Interest.................................................... 60,794 89,604 (3) Capitalized Interest.............................................. 12,227 14,943 (4) Distribution on Trust Securities.................................. 38,433 45,674 (5) Interest Component of Rentals Charged to Operating Expense........ 8,237 11,309 ----------------- ----------------- (6) Total Fixed Charges............................................... $ 427,656 $ 575,049 ================= ================= Earnings as Defined: (7) Income from Continuing Operations................................. $ 1,554,865 $ 1,150,305 (8) Income Taxes for Continuing Operations............................ 872,304 687,654 (9) Fixed Charges (line 6)............................................ 427,656 575,049 (10) Capitalized Interest.............................................. (12,227) (14,943) ----------------- ----------------- (11) Income from Continuing Operations Before Income Taxes and Fixed Charges........................................................... $ 2,842,598 $ 2,398,065 ================= ================= Ratio of Earnings to Fixed Charges (line 11 divided by line 6)............. 6.65 4.17 Preferred Dividends Requirements: (12) Preferred Stock Dividends......................................... $ 292 $ 390 (13) Less Tax Deduction for Preferred Dividends........................ 27 54 ----------------- ----------------- (14) Total............................................................. $ 265 $ 336 ================= ================= (15) Ratio of Pre-Tax Income from Continuing Operations to Net Income (line 7 plus line 8 divided by line 7)............................ 1.56 1.60 ----------------- ----------------- (16) Line 14 times line 15............................................. $ 413 $ 538 (17) Add Back Tax Deduction (line 13).................................. 27 54 ----------------- ----------------- (18) Preferred Dividends Factor........................................ $ 440 $ 592 ================= ================= (19) Total Fixed Charges (line 6)...................................... $ 427,656 $ 575,049 (20) Preferred Dividends Factor (line 18)............................. 440 592 ----------------- ----------------- (21) Total............................................................. $ 428,096 $ 575,641 ================= ================= Ratios of Earnings to Fixed Charges and Preferred Dividends (line 11 divided by line 21)....................................................... 6.64 4.17 ================= =================
OPUR1 0000048732 RELIANT ENERGY, INCORPORATED 1,000 9-MOS DEC-31-1999 SEP-30-1999 PER-BOOK 9,041,732 2,853,403 5,862,758 4,846,224 0 22,604,117 2,926,738 0 2,562,702 5,489,440 0 715,001 4,050,162 0 712,804 1,170,359 3,790,361 0 12,879 1,201 6,661,910 22,604,117 11,247,924 872,304 10,274,849 10,274,849 973,075 1,823,145 2,796,220 368,759 1,555,157 292 1,554,865 320,922 252,715 1,126,389 5.45 5.43 Total annual interest charges on all bonds is as of year-to-date 09/30/99.
1 EXHIBIT 99A [ITEMS INCORPORATED BY REFERENCE FROM THE COMPANY 10-K, THE COMPANY FIRST QUARTER 10-Q AND THE COMPANY SECOND QUARTER 10-Q.] ITEM 3. LEGAL PROCEEDINGS. (a) Company. For a description of certain legal and regulatory proceedings affecting the Company, see Notes 3(b), 12(h) and 12(i) to the Company's Consolidated Financial Statements, which notes are incorporated herein by reference. ITEM. 7 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF THE COMPANY CERTAIN FACTORS AFFECTING FUTURE EARNINGS OF THE COMPANY AND ITS SUBSIDIARIES Earnings for the past three years are not necessarily indicative of future earnings and results. The level of future earnings depends on numerous factors including (i) the future growth in the Company's and its subsidiaries' energy sales; (ii) weather; (iii) the success of the Company's and its subsidiaries' entry into non-rate regulated businesses such as energy marketing and international and domestic power projects; (iv) the Company's and its subsidiaries' ability to respond to rapid changes in a competitive environment and in the legislative and regulatory framework under which they have traditionally operated; (v) rates of economic growth in the Company's and its subsidiaries' service areas; (vi) the ability of the Company and its subsidiaries to control costs and to maintain pricing structures that are both attractive to customers and profitable; (vii) the outcome of future rate proceedings; (viii) the effect that foreign exchange rate changes may have on the Company's investments in international operations; and (ix) future legislative initiatives. In order to adapt to the increasingly competitive environment in which the Company operates, the Company continues to evaluate a wide array of potential business strategies, including business combinations or acquisitions involving other utility or non-utility businesses or properties, internal restructuring, reorganizations or dispositions of currently owned properties or currently operating business units and new products, services and customer strategies. In addition, the Company continues to engage in new business ventures, such as electric power trading and marketing, which arise from competitive and regulatory changes in the utility industry. COMPETITION AND RESTRUCTURING OF THE ELECTRIC UTILITY INDUSTRY The electric utility industry is becoming increasingly competitive due to changing government regulations, technological developments and the availability of alternative energy sources. Long-Term Trends in Electric Utility Industry. The electric utility industry historically has been composed of vertically integrated companies providing electric service on an exclusive basis within governmentally-defined geographic areas. Prices for electric service have typically been set by governmental authorities under principles designed to provide the utility with an opportunity to recover its cost of providing electric service plus a reasonable return on its invested capital. Federal legislation and regulation as well as legislative and regulatory initiatives in various states have encouraged competition among electric utility and non-utility owned power generators. These developments, combined with increased demand for lower-priced electricity and technological advances in electric generation, have continued to move the electric utility industry in the direction of more competition. Based on a strategic review of the Company's business and of ongoing developments in the electric utility and related industries regarding competition, regulation and consolidation, the Company's management believes that the electric utility industry will continue its path toward competition, albeit on a state-by-state basis. The Company's management also believes the business of electricity and natural gas are converging and consolidating and these trends will alter the structure and business practices of companies serving these markets in the future. Competition in Wholesale Market. The Federal Energy Policy Act of 1992, the Public Utility Regulatory Act of 1995 (now the Texas Utilities Code) and regulations promulgated by the Federal Energy Regulatory Commission (FERC) contain provisions intended to facilitate the development of a wholesale energy market. Although Reliant Energy HL&P's wholesale sales traditionally have accounted for less than 1% of its total revenues, the expansion of competition in the wholesale electric market is significant in that it has increased the range of non-utility competitors, such as exempt wholesale generators (EWGs) and power marketers, in the Texas electric market as well as resulted in fundamental changes in the operation of the state transmission grid. In February 1996, the Texas Utility Commission adopted rules granting third-party users of transmission systems open access to such systems at rates, terms and conditions comparable to those available to utilities owning such transmission assets. Under the Texas Utility Commission order implementing the rule, Reliant Energy HL&P was required to separate, on an operational basis, its wholesale power marketing operations from the operations of the transmission grid and, for purposes of transmission pricing, to disclose each of its separate costs of generation, transmission and distribution. Within ERCOT, an independent system operator (ISO) manages the state's electric grid, ensuring system reliability and providing non-discriminatory transmission access to all power producers and traders. The ERCOT ISO, the first in the nation, is a key component for implementing the Texas Utility Commission's overall strategy to create a
2 competitive wholesale market. ERCOT formed an ad hoc committee in early 1998 to investigate the potential impacts of a competitive retail market on the ISO. The ERCOT committee report was released in December 1998 and concluded that the ISO's role and function would necessarily expand in a competitive retail environment, but the changes required of the ISO to support retail choice should not impede introduction of retail choice. Competition in Retail Market. The Company estimates that, since 1978, cogeneration projects representing approximately one-third of current total peak generating capability have been built in the Houston area and that, as a result, Reliant Energy HL&P has seen a reduction of approximately 2,500 MW in customer load to self-generation. Reliant Energy HL&P has utilized flexible pricing to respond to situations where large industrial customers have an alternative to buying power from it, primarily by constructing their own generating facilities. Under a tariff option approved by the Texas Utility Commission in 1995, Reliant Energy HL&P was permitted to implement contracts based upon flexible pricing for up to 700 MW. Currently, this rate is fully subscribed. Texas law currently does not permit retail sales by unregulated entities such as cogenerators. The Company anticipates that cogenerators and other interests will continue to exert pressure to obtain access to the electric transmission and distribution systems of regulated utilities for the purpose of making retail sales to customers of regulated utilities. Legislative Proposals. A number of proposals to restructure the electric utility industry have been introduced in the 1999 session of the Texas legislature. If adopted, legislation may permit and encourage alternative suppliers to compete to serve Reliant Energy HL&P's current rate-regulated retail customers. The various legislative proposals include provisions governing recovery of stranded costs and permitting securitization of those costs; freezing rates until 2002; requiring firm sales of energy to competing retail electric providers; requiring disaggregation of generation, transmission and distribution, and retail sales into separate companies and limiting the ability of existing utilities' affiliates competing for retail electric customers on the basis of price until they have lost a substantial percentage of their residential and small commercial load to alternative retail providers. In addition to the Texas legislative proposals, a number of federal legislative proposals to promote retail electric competition or restructure the U.S. electric utility industry have been introduced during the current congressional session. At this time, the Company is unable to make any prediction as to whether any legislation to restructure electric operations or provide retail competition will be enacted or as to the content or impact on the Company of any legislation which may be enacted. However, because the proposed legislation is intended to fundamentally restructure electric utility operations, it is likely that enacted legislation would have a material impact on the Company. Stranded Costs. As the U.S. electric utility industry continues its transition to a more competitive environment, a substantial amount of fixed costs previously approved for recovery under traditional utility regulatory practices (including regulatory assets and liabilities) may become "stranded," i.e., unrecoverable at competitive market prices. The issue of stranded costs could be particularly significant with respect to fixed costs incurred in connection with the past construction of generation plants, such as nuclear power plants, which, because of their high fixed costs, would not command the same price for their output as they have in a regulated environment. In January 1997, the Texas Utility Commission delivered a report to the Texas legislature on stranded investments in the electric utility industry in Texas (referred to by the Texas Utility Commission as "Excess Cost Over Market") (ECOM). In April 1998, the Texas Utility Commission submitted to the Texas Senate Interim Committee on Electric Utility Restructuring an updated study of ECOM estimates. Assuming that retail competition is adopted at the beginning of 2002, the updated study estimated that the total amount of stranded costs for all Texas electric utilities could be $4.5 billion. If instead, retail competition is adopted one year later, the study estimates statewide ECOM to be $3.3 billion. Estimates of ECOM vary widely and there is inherent uncertainty in calculating these costs. Transition Plan. In June 1998, the Texas Utility Commission approved the Transition Plan filed by Reliant Energy HL&P in December 1997. The Transition Plan included base rate credits to residential and certain commercial 2
3 customers in 1998 and 1999, an overall rate of return cap formula for 1998 and 1999 and approval of accounting procedures designed to accelerate recovery of stranded costs which may arise under restructuring legislation. The Transition Plan permits the redirection of depreciation expense to generation assets that Electric Operations otherwise would apply to transmission, distribution and general plant assets. In addition, the Transition Plan provides that all earnings above a 9.844% overall annual rate of return on invested capital be used to recover Electric Operations' investment in generation assets. In 1998, Reliant Energy HL&P recorded an additional $194 million in depreciation under the Transition Plan. Certain parties have appealed the order approving the Transition Plan. For additional information, see Notes 1(f) and 3(b) to the Company's Consolidated Financial Statements. COMPETITION -- OTHER OPERATIONs Natural Gas Distribution competes primarily with alternate energy sources such as electricity and other fuel sources as well as with providers of energy conservation products. In addition, as a result of federal regulatory changes affecting interstate pipelines, it has become possible for other natural gas suppliers and distributors to bypass Natural Gas Distribution's facilities and market, sell and/or transport natural gas directly to small commercial and/or large volume customers. The Interstate Pipeline 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. Interstate Pipeline 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 served by Interstate Pipeline and the level of competition for transport and storage services. Reliant Energy Services competes for sales in its gas and power trading and marketing business with other natural gas and power merchants, producers and pipelines based on its 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. Reliant Energy Services also competes against other energy marketers on the basis of its relative financial position and access to credit sources. This competitive factor reflects the tendency of energy customers, natural gas suppliers and natural gas 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, the Company anticipates that Reliant Energy Services will experience greater competition and downward pressure on per-unit profit margins in the energy marketing industry. Competition for acquisition of international and domestic non-rate regulated power projects is intense. International and Power Generation compete against a number of other participants in the non-utility power generation industry, some of which have greater financial resources and have been engaged in non-utility power projects for periods longer than the Company and have accumulated greater portfolios of projects. Competitive factors relevant to the non-utility power industry include financial resources, access to non-recourse funding and regulatory factors. FLUCTUATIONS IN COMMODITY PRICES AND DERIVATIVE INSTRUMENTS For information regarding the Company's exposure to risk as a result of fluctuations in commodity prices and derivative instruments, see "Quantitative and Qualitative Disclosures About Market Risk" in Item 7A of this Report. ACCOUNTING TREATMENT OF ACES The Company accounts for its investment in Time Warner Convertible Preferred Stock (TW Preferred) under the cost method. As a result of the Company's issuance of the ACES, a portion of the increase in the market value above $27.7922 per share of Time Warner common stock (the security into which the TW Preferred is convertible) (TW 3
4 Common) results in unrealized accounting losses to the Company, pending the conversion of the Company's TW Preferred into TW Common. For consistency purposes, the TW Common and related per share prices retroactively reflect a 2 for 1 stock split effective December 15, 1998. Prior to the conversion of the TW Preferred into TW Common, when the market price of TW Common increases above $27.7922, the Company records in Other Income (Expense) an unrealized, non-cash accounting loss for the ACES equal to the aggregate amount of such increase as applicable to all ACES multiplied by 0.8264. In accordance with generally accepted accounting principles, this accounting loss (which reflects the unrealized increase in the Company's indebtedness with respect to the ACES) may not be offset by accounting recognition of the increase in the market value of the TW Common that underlies the TW Preferred. Upon conversion of the TW Preferred (which is anticipated to occur in June 1999 when the preferential dividend on the TW Preferred expires), the Company will begin recording future unrealized net changes in the market prices of the TW Common and the ACES as a component of common stock equity and other comprehensive income. As of December 31, 1998, the market price of TW Common was $62.062 per share. Accordingly, the Company recognized an increase of $1.2 billion in 1998 in the unrealized liability relating to its ACES indebtedness (which resulted in an after-tax earnings reduction of $764 million or $2.69 basic earnings per share in 1998). The Company believes that the cumulative unrealized loss for the ACES of approximately $1.3 billion is more than economically offset by the approximately $1.8 billion unrecorded unrealized gain at December 31, 1998 relating to the increase in the fair value of the TW Common underlying the investment in TW Preferred since the date of its acquisition. Any gain related to the increase in fair value of TW Common would be recognized as a component of net income upon the sale of the TW Preferred or the shares of TW Common into which such TW Preferred is converted. As of March 11, 1999, the price of TW Common was $70.75 per share, which would have resulted in the Company recognizing an additional increase of $329 million in the unrealized liability represented by its indebtedness under the ACES. The related unrecorded unrealized gain as of March 11, 1999 would have been computed as an additional $398 million. Excluding the unrealized, non-cash accounting loss for ACES, the Company's retained earnings and total common stock equity would have been $2.3 billion and $5.2 billion, respectively. IMPACT OF THE YEAR 2000 ISSUE AND OTHER SYSTEM IMPLEMENTATION ISSUES Year 2000 Problem. At midnight on December 31, 1999, unless the proper modifications have been made, the program logic in many of the world's computer systems will start to produce erroneous results because, among other things, the systems will incorrectly read the date "01/01/00" as being January 1 of the year 1900 or another incorrect date. In addition, certain systems may fail to detect that the year 2000 is a leap year. Problems can also arise earlier than January 1, 2000, as dates in the next millennium are entered into non-Year 2000 compliant programs. Compliance Program. In 1997, the Company initiated a corporate-wide Year 2000 project to address mainframe application systems, information technology (IT) related equipment, system software, client-developed applications, building controls and non-IT embedded systems such as process controls for energy production and delivery. Incorporated into this project were Resources' and other Company subsidiaries' mainframe applications, infrastructures, embedded systems and client-developed applications that will not be migrated into existing or planned Company or Resources systems prior to the year 2000. The evaluation of Year 2000 issues included those related to significant customers, key vendors, service suppliers and other parties material to the Company's and its subsidiaries' operations. In the course of this evaluation, the Company has sought written assurances from such third parties as to their state of Year 2000 readiness. State of Readiness. Work has been prioritized in accordance with business risk. The highest priority has been assigned to activities that would disrupt the physical delivery of energy (Priority 1); activities that would impact back office activities such as billing (Priority 2); activities that would cause inconvenience or productivity loss in normal business operations (e.g. air conditioning systems and elevators) (Priority 3). All business units have completed an analysis of critical systems and equipment that control the production and delivery of energy, as well as corporate, departmental and personnel systems and equipment. The remediation and replacement work on the majority of IT 4
5 systems, non-IT systems and infrastructure began in the first quarter of 1998 and is expected to be completed by the second quarter of 1999. Testing of these systems began in the second quarter of 1998 and is scheduled to be completed in third quarter of 1999. The following table illustrates the Company's completion percentages for the Year 2000 activities as of February 28, 1999: PRIORITY 1 PRIORITY 2 PRIORITY 3 -------------- -------------- --------------- Assessment.............................................. 95% 86% 96% Conversion.............................................. 86% 70% 91% Testing................................................. 80% 61% 87% Implementation.......................................... 76% 54% 75% Costs to Address Year 2000 Compliance Issues. Based on current internal studies, as well as recently solicited bids from various computer software vendors, the Company estimates that the total direct cost of resolving the Year 2000 issue with respect to the Company and its subsidiaries will be between $35 and $40 million. This estimate includes approximately $7 million related to salaries and expenses of existing employees and approximately $3 million in hardware purchases that the Company expects to capitalize. In addition, the $35 to $40 million estimate includes approximately $2 million spent prior to 1998 and approximately $12 million during 1998. The remaining costs related to resolving the Year 2000 issue are expected to be expended in 1999. The Company expects to fund these expenditures through internal sources. In September 1997, the Company entered into an agreement with SAP America, Inc. (SAP) to license SAP proprietary R/3 enterprise software. The licensed software includes customer care, finance and accounting, human resources, materials management and service delivery components. The Company's purchase of this software license and related computer hardware is part of its response to changes in the electric utility and energy services industries, as well as changes in the Company's businesses and operations resulting from the acquisition of Resources and the Company's expansion into the energy trading and marketing business. Although it is anticipated that the implementation of the SAP system will have the incidental effect of negating the need to modify many of the Company's computer systems to accommodate the Year 2000 problem, the Company does not deem the costs of the SAP system as directly related to its Year 2000 compliance program. Portions of the SAP system were implemented in December 1998 and March 1999, and it is expected that the final portion of the SAP system will be fully implemented by July 2000. The estimated costs of implementing the SAP system is approximately $182 million, inclusive of internal costs. In 1998, the Company and its subsidiaries spent $108 million of such costs. In 1999, the Company and its subsidiaries expect to spend $59 million with the remaining amounts to be spent in 2000. The estimated Year 2000 project costs do not give effect to any future corporate acquisitions or divestitures made by the Company or its subsidiaries. Risks and Contingency Plans. The major systems which pose the greatest Year 2000 risks for the Company and its subsidiaries if implementation of the Year 2000 compliance program is not successful are the process control systems for energy delivery systems; the time in use, demand and recorder metering system for commercial and industrial customers; the outage analysis system; and the power billing systems. The potential problems related to these systems are temporary electric service interruptions to customers, temporary interruptions in revenue data gathering and temporary poor customer relations resulting from delayed billing. Although the Company does not believe that this scenario will occur, the Company has considerable experience responding to emergency situations, including computer failure. Existing emergency operations, disaster recovery and business continuation plans are being enhanced to ensure preparedness and to mitigate the long-term effect of such a scenario. The North American Electric Reliability Council (NERC) is coordinating electric utility industry contingency planning on a national level. Additional contingency planning is being done at the regional electric reliability council level. Reliant Energy HL&P filed a draft Year 2000 Contingency Plan with NERC and with the Texas Utility Commission in December 1998. The draft plan addresses restoration of electric service and related business processes, and is designed to work in conjunction with the Emergency Operating Plan and with the plans of NERC and ERCOT. 5
6 A final contingency plan is scheduled to be complete by June 30, 1999. In addition, Reliant Energy HL&P will participate in industry preparedness drills, such as the two NERC drills scheduled to be held on April 9, 1999 and September 9, 1999. The existing business continuity disaster recovery and emergency operations plans are being reviewed and enhanced, and where necessary, additional plans will be developed to include mitigation strategies and action plans specifically addressing potential Year 2000 scenarios. The expected completion date for these plans is June 30, 1999. In order to assist in preparing for and mitigating the foregoing scenarios, the Company intends to complete all mission critical Year 2000 remediation and testing activity by the end of the second quarter of 1999. In addition, the Company has initiated Year 2000 communications with significant customers, key vendors, service suppliers and other parties material to the Company's operations and is diligently monitoring the progress of such third parties' Year 2000 projects. The Company expects to meet with mission-critical third parties, including suppliers, in order to ascertain and assess the relative risks of Year-2000-related issues, and to mitigate such risks. Notwithstanding the foregoing, the Company cautions that (i) the nature of testing is such that it cannot comprehensively address all future combinations of dates and events and (ii) it is impossible for the Company to assess with precision or certainty the compliance of third parties with Year 2000 remediation efforts. Due to the speculative and uncertain nature of contingency planning, there can be no assurance that such plans actually will be sufficient to reduce the risk of material impacts on the Company's and its subsidiaries' operations. RISKS OF INTERNATIONAL OPERATIONS The Company's international operations are subject to various risks incidental to investing or operating in emerging market countries. These risks include political risks, such as governmental instability, and 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. The Company's international operations are also highly capital intensive and, thus, dependent to a significant extent on the continued availability of bank financing and other sources of capital on commercially acceptable terms. Impact of Currency Fluctuations on Company Earnings. The Company, through Reliant Energy International's subsidiaries, owns 11.69% of the stock of Light and, through its investment in Light, an 8.753% interest in the stock of Metropolitana Electricidade de Sao Paulo S.A. (Metropolitana). The Company accounts for its investment in Light under the equity method of accounting and records its proportionate share, based on stock ownership, in the net income of Light and its affiliates (including Metropolitana) as part of the Company's consolidated net income. At December 31, 1998, Light and Metropolitana had total borrowings of approximately $3.2 billion denominated in non-local currencies. Because of the devaluation of the Brazilian real subsequent to December 31, 1998, Light and Metropolitana are expected to record a charge to March 31, 1999 earnings that reflects the increase in the liability represented by their non-local currency denominated bank borrowings relative to the Brazilian real. Because the Company uses the Brazilian real as the functional currency in which it reports Light's equity earnings, the resulting decrease in Light's earnings will also be reflected in the Company's consolidated earnings to the extent of the Company's 11.69% ownership interest in Light. At December 31, 1998, one U. S. dollar could be exchanged for 1.21 Brazilian reais. Using the exchange rate of 2.06 Brazilian reais in effect at the end of February, and the average exchange rate in effect since the end of the year, the Company estimates that its share of the after-tax charge to be recorded by Light would be approximately $125 million. This estimate does not reflect the possibility of additional fluctuations in the exchange rate and does not include other non-debt-related impacts of Brazil's currency devaluation on Light's and Metropolitana's future earnings. 6
7 None of Light's or Metropolitana's tariff adjustment mechanisms are directly indexed to the U.S. dollar or other non-local currencies. Each company currently is evaluating various options including regulatory rate relief to mitigate the impact of the devaluation of the Brazilian real. For example, the long-term concession contracts under which Light and Metropolitana operate contain mechanisms for adjusting electricity tariffs to reflect changes in operating costs resulting from inflation. If the devaluation of the Brazilian real results in an increase in the local rate of inflation and if an adjustment to tariff rates is made promptly to reflect such increase, the Company believes that the financial results of Light and Metropolitana should be protected, at least in part, from the effects of devaluation. However, there can be no assurance the implementation of such tariff adjustments will be timely or that the economic impact of the devaluation will be completely reflected in increased inflation rates. Certain of Reliant Energy International's other foreign electric distribution companies have incurred U.S. dollar and other non-local currency indebtedness (approximately $71 million at December 31, 1998). For further analysis of foreign currency fluctuations in the Company's earnings and cash flows, see "Quantitative and Qualitative Disclosures About Market Risk -- Foreign Currency Exchange Rate Risk" in Item 7A of this Form 10-K. Impact of Foreign Currency Devaluation on Project Capital Resources. In the first quarter of 1999, approximately $117 million of Metropolitana's U.S. dollar denominated debt will mature. In the second quarter of 1999, approximately $980 million of Light's and approximately $696 million of Metropolitana's U.S. and non-local currency denominated bank debt will mature. In March 1999, Light refinanced approximately $130 million of its U.S. dollar denominated debt through a local - currency denominated loan. The ability of Light and Metropolitana to repay or refinance their debt obligations at maturity is dependent on many factors, including local and international economic conditions prevailing at the time such debt matures. If economic conditions in the international markets continue to be unsettled or deteriorate, it is possible that Light, Metropolitana and the other foreign electric distribution companies in which the Company holds investments might encounter difficulties in refinancing their debt (both local currency and non-local currency borrowings) on terms and conditions that are commercially acceptable to them and their shareholders. In such circumstances, in lieu of declaring a default or extending the maturity, it is possible that lenders might seek to require, among other things, higher borrowing rates, and additional equity contributions and/or increased levels of credit support from the shareholders of such entities. The availability or terms of refinancing such debt cannot be assured. Currency fluctuation and instability affecting Latin America may also adversely affect Reliant Energy International's ability to refinance its equity investments with debt. In 1998, Reliant Energy International invested $411 million in Colombia and El Salvador. As of January 1999, $100 million of these investments were refinanced with debt. Reliant Energy International intends to refinance approximately $75 million more of such initial investments with debt. ENVIRONMENTAL EXPENDITURES The Company and its subsidiaries, including Resources, are subject to numerous environmental laws and regulations, which require them 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. Clean Air Act Expenditures. The Company expects the majority of capital expenditures associated with environmental matters to be incurred by Electric Operations in connection with new emission limitations under the Federal Clean Air Act (Clean Air Act) for oxides of nitrogen (NOx). The standards applicable to Electric Operations' generating units in the Houston, Texas area will become effective in November 1999. NOx reduction costs incurred by Electric Operations totaled approximately $7 million in 1998. The Company estimates that Electric Operations will incur approximately $8 million in 1999 and $10 million in 2000 for such expenditures. The Texas Natural Resources Conservation Commission (TNRCC) has indicated that additional NOx reduction will be required after 2000; however, since the magnitude and timing of these reductions have not yet been established, it is impossible for the Company to estimate a reasonable range of such expenditures at this time. 7
8 In 1998, the Wholesale Energy spent approximately $100,000 in order to comply with NOx reduction with respect to Southern California generating facilities acquired by Power Generation from Southern California Edison (SCE) in 1998. In 1999, based on existing requirements, the Company projects that it will spend an additional $100,000 on NOx reduction standards with respect to such plants and approximately $1 million on continuous emission monitoring system upgrades for such plants. Site Remediation Expenditures. From time to time the Company and its subsidiaries have received notices from regulatory authorities or others regarding their status as potentially responsible parties in connection with sites found to require remediation due to the presence of environmental contaminants. The Company's identified sites with respect to which it may be claimed to have a remediation liability include several sites for which there is a lack of current available information, including the nature and magnitude of contamination, and the extent, if any, to which the Company may be held responsible for contributing to any costs incurred for remediating these sites. Thus, no reasonable estimate of cleanup costs can now be made for these sites. Based on currently available information, the Company believes that such costs ultimately will not materially affect its 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 such estimates. For information about specific sites that are the subject of remediation claims, see Note 12(h) to the Company's Consolidated Financial Statements and Note 8(g) to Resources' Consolidated Financial Statements, each of which is incorporated herein by reference. Mercury Contamination. Like other natural gas pipelines, Resources' pipeline operations have in the past employed elemental mercury in meters used on its pipelines. Although the mercury has now been removed from the meters, it is possible that small amounts of mercury have been spilled at some of those sites in the course of normal maintenance and replacement operations and that such spills have contaminated the immediate area around the meters with elemental mercury. Such contamination has been found by Resources at some sites in the past, and Resources has conducted remediation at sites found to be contaminated. Although Resources is not aware of additional specific sites, it is possible that other contaminated sites exist and that remediation costs will be incurred for such sites. Although the total amount of such costs cannot be known at this time, based on experience of Resources and others in the natural gas industry to date and on the current regulations regarding remediation of such sites, the Company and Resources believe that the cost of any remediation of such sites will not be material to the Company's or Resources' financial position, results of operations or cash flows. Other. 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 its practice of 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 CONTINGENCIES For a description of certain other legal and regulatory proceedings affecting the Company and its subsidiaries, see Notes 3, 4, 5 and 12 to the Company's Consolidated Financial Statements and Note 8 to Resources' Consolidated Financial Statements, which notes are incorporated herein by reference. 8
9 NEW ACCOUNTING ISSUES In 1998, the Company and Resources adopted SFAS No. 130, "Reporting Comprehensive Income" (SFAS No. 130), SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information" (SFAS No. 131) and SFAS No. 132, "Employers Disclosures about Pensions and Other Postretirement Benefits" (SFAS No. 132). For further discussion of these accounting statements, see Note 15 to the Company's Consolidated Financial Statements and Note 9 to Resources' Consolidated Financial Statements. In 2000, the Company and Resources expect to adopt SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133), which establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities. The Company is in the process of determining the effect of adoption of SFAS No. 133 on its consolidated financial statements. In December 1998, The Emerging Issues Task Force of the Financial Accounting Standards Board reached consensus on Issue 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (EITF Issue 98-10). EITF Issue 98-10 requires energy trading contracts to be recorded at fair value on the balance sheet, with the changes in fair value included in earnings. EITF Issue 98-10 is effective for fiscal years beginning after December 15, 1998. The Company expects to adopt EITF Issue 98-10 in the first quarter of 1999. The Company does not expect the implementation of EITF Issue 98-10 to be material to its consolidated financial statements. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK INTEREST RATE RISK The Company and its subsidiaries have long-term debt, Company/ Resources obligated mandatorily redeemable preferred securities of subsidiary trusts holding solely junior subordinated debentures of the Company/Resources (Trust Securities), securities held in the Company's nuclear decommissioning trust, bank facilities, certain lease obligations and interest rate swaps which subject the Company, Resources and certain of their subsidiaries to the risk of loss associated with movements in market interest rates. At December 31, 1998, the Company and certain of its subsidiaries had issued fixed-rate long-term debt (excluding ACES) and Trust Securities aggregating $5.0 billion in principal amount and having a fair value of $5.2 billion. These instruments are fixed-rate and, therefore, do not expose the Company and its subsidiaries to the risk of earnings loss due to changes in market interest rates (see Notes 8 and 9 to the Company's Consolidated Financial Statements). However, the fair value of these instruments would increase by approximately $260.6 million if interest rates were to decline by 10% from their levels at December 31, 1998. In general, such an increase in fair value would impact earnings and cash flows only if the Company and its subsidiaries were to reacquire all or a portion of these instruments in the open market prior to their maturity. The Company and certain of its subsidiaries' floating-rate obligations aggregated $1.8 billion at December 31, 1998 (see Note 8 to the Company's Consolidated Financial Statements), inclusive of (i) amounts borrowed under short-term and long-term credit facilities of the Company and its subsidiaries (including the issuance of commercial paper supported by such facilities), (ii) borrowings underlying Resources' receivables facility and (iii) amounts subject to a master leasing agreement of Resources under which lease payments vary depending on short-term interest rates. These floating-rate obligations expose the Company, Resources and their subsidiaries to the risk of increased interest and lease expense in the event of increases in short-term interest rates. If the floating rates were to increase by 10% from December 31, 1998 levels, the Company's consolidated interest expense and expense under operating leases would increase by a total of approximately $0.9 million each month in which such increase continued. As discussed in Notes 1(o), 4(c) and 13 to the Company's Consolidated Financial Statements, the Company contributes $14.8 million per year to a trust established to fund the Company's share of the decommissioning costs for the South Texas Project. The securities held by the trust for decommissioning costs had an estimated fair value of $119.1 million as of December 31, 1998, of which approximately 44% were fixed-rate debt securities that subject the Company to risk of loss of fair value with movements in market interest rates. If interest rates were to increase by 10% from their levels at December 31, 1998, the decrease in fair value of the fixed-rate debt securities would not be material to the Company. In addition, the risk of an economic loss is mitigated at this time as a result of the Company's regulated status. Any unrealized gains or losses are accounted for in accordance with SFAS No. 71 as a regulatory asset/liability because the Company believes that its future contributions which are currently recovered through the rate-making process will be adjusted for these gains and losses. Certain subsidiaries of the Company have entered into interest rate swaps for the purpose of decreasing the amount of debt subject to interest rate fluctuations. At December 31, 1998, these interest rate swaps had an aggregate notional amount of $75.4 million, which the Company could terminate at a cost of $3.2 million (see Notes 2 and 13 to the Company's Consolidated Financial Statements). An increase of 10% in the December 31, 1998 level of interest rates would not increase the cost of termination of the swaps by a material amount to the Company. Swap termination costs would impact the Company's and its subsidiaries' earnings and cash flows only if all or a portion of the swap instruments were terminated prior to their expiration. 12
10 As discussed in Note 8(h) to the Company's Consolidated Financial Statements, Resources sold $500 million aggregate principal amount of its 6 3/8% 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 December 31, 1998, the Company could terminate the option at a cost of $30.7 million. A decrease of 10% in the December 31, 1998 level of interest rates would not increase the cost of termination of the option by a material amount to the Company. The change in exposure to loss in earnings and cash flows related to interest rate risk from December 31, 1997 to December 31, 1998 is not material to the Company. EQUITY MARKET RISK The Company holds an investment in TW Preferred which is convertible into Time Warner common stock (TW Common) as described in "Management's Discussion and Analysis of Financial Condition and Results of Operations of the Company -- Certain Factors Affecting Future Earnings of the Company and its Subsidiaries -- Accounting Treatment of ACES" in Item 7 of this Form 10-K. As a result, the Company is exposed to losses in the fair value of this security. For purposes of analyzing market risk in this Item 7A, the Company assumed that the TW Preferred was converted into TW Common. In addition, Resources' investment in the common stock of Itron, Inc. (Itron) exposes the Company and Resources to losses in the fair value of Itron common stock. A 10% decline in the market value per share of TW Common and Itron common stock from the December 31, 1998 levels would result in a loss in fair value of approximately $284.4 million and $1.1 million, respectively. The Company's and its subsidiaries' ability to realize gains and losses related to the TW Preferred and the Itron common stock is limited by the following: (i) the TW Preferred is not publicly traded and its sale is subject to certain limitations and (ii) the market for the common stock of Itron is fairly illiquid. The ACES expose the Company to accounting losses as the Company is required to record in Other Income (Expense) an unrealized accounting loss equal to (i) the aggregate amount of the increase in the market price of TW Common above $27.7922 as applicable to all ACES multiplied by (ii) 0.8264. Prior to the conversion of the TW Preferred into TW Common, such loss would affect earnings. After conversion, such loss would be recognized as an adjustment to common stock equity through a reduction of other comprehensive income. However, there would be an offsetting increase in common stock equity through an increase in accumulated other comprehensive income on the Company's Statements of Consolidated Retained Earnings and Comprehensive Income for the fair value increase in the investment in TW Common. For additional information on the accounting treatment of the ACES and related accounting losses recorded in 1998, see Note 1(n) to the Company's Consolidated Financial Statements. An increase of 15% in the price of the TW Common above its December 31, 1998 market value of $62.062 per share would result in the recognition of an additional unrealized accounting loss (net of tax) of approximately $229.1 million. The Company believes that this additional unrealized loss for the ACES would be more than economically hedged by the unrecorded unrealized gain relating to the increase in the fair value of the TW Common underlying the investment in TW Preferred since the date of its acquisition. For a discussion of the non-cash, unrealized accounting loss recorded in 1998 and 1997 related to the ACES, see "-- Certain Factors Affecting Future Earnings of the Company and its Subsidiaries -- Accounting Treatment of ACES" in Item 7 of this Form 10-K. As discussed above under "-- Interest Rate Risk," the Company contributes to a trust established to fund the Company's share of the decommissioning costs for the South Texas Project which held debt and equity securities as of December 31, 1998. The equity securities expose the Company to losses in fair value. If the market prices of the individual equity securities were to decrease by 10% from their levels at December 31, 1998, the resulting loss in fair value of these securities would not be material to the Company. Currently, the risk of an economic loss is mitigated as a result of the Company's regulated status as discussed above under "--Interest Rate Risk." FOREIGN CURRENCY EXCHANGE RATE RISK As further described in "Certain Factors Affecting Future Earnings of the Company and Its Subsidiaries -- Risks of International Operations" in Item 7 of this Form 10-K, the Company, through Reliant Energy International invests in certain foreign operations which to date have been primarily in South America. As of December 31, 1998, the Company's Consolidated Balance Sheets reflected $1.1 billion of foreign investments, a substantial portion of which represent investments accounted for under the equity method. These foreign investments expose the Company to risk of loss in earnings and cash flows due to the fluctuation in foreign currencies relative to the Company's consolidated reporting currency, the U.S. dollar. The Company accounts for adjustments resulting from translation of its investments with functional currencies other than the U.S. dollar as a charge or credit directly to a separate component of stockholders' equity. For further discussion of the accounting for foreign currency adjustments, see Note 1(p) in the Notes to the Company's Consolidated Financial Statements. The cumulative translation loss of $34 million, recorded as of December 31, 1998, will be realized as a loss in earnings and cash flows only upon the disposition of the related investment. The foreign currency loss in earnings and cash flows related to debt obligations held by foreign operations in currencies other than their own functional currencies was not material to the Company as of December 31, 1997. 13
11 In addition, certain of Reliant Energy International's foreign operations have entered into obligations in currencies other than their own functional currencies which expose the Company to a loss in earnings. In such cases, as the respective investment's functional currency devalues relative to the non-local currencies, the Company will record its proportionate share of its investments' foreign currency transaction losses related to the non-local currency denominated debt. At December 31, 1998, Light and Metropolitana had borrowings of approximately $3.2 billion denominated in non-local currencies. Because of the devaluation of the Brazilian real subsequent to December 31, 1998, Light and Metropolitana are expected to record a charge to earnings for the quarter ended March 31, 1999, primarily related to foreign currency transaction losses on their non-local currency denominated debt. For further discussion and analysis of the possible effect on the Company's Consolidated Financial Statements, see "Certain Factors Affecting Future Earnings of the Company and Its Subsidiaries - -- Risks of International Operations" in Item 7 of this Form 10-K. The company attempts to manage and mitigate this foreign risk by properly balancing the higher cost of financing with local denominated debt against the risk of devaluation of that local currency and including a measure of the risk of devaluation in all its financial plans. In addition, where possible, Reliant Energy International attempts to structure its tariffs and revenue contracts to ensure some measure of adjustment due to changes in inflation and currency exchange rates; however, there can be no assurance that such efforts will compensate for the full effect of currency devaluation, if any. ENERGY COMMODITY PRICE RISK As further described in Note 2 to the Company's Consolidated Financial Statements, certain of the Company's subsidiaries utilize a variety of derivative financial instruments (Derivatives), including swaps and exchange-traded futures and options, as part of the Company's overall hedging strategies and for trading purposes. To reduce the risk from the adverse effect of market fluctuations in the price of electric power, natural gas, crude oil and refined products and related transportation, Resources and certain subsidiaries of the Company and Resources enter into futures transactions, forward contracts, swaps and options (Energy Derivatives) in order to hedge certain commodities in storage, as well as certain expected purchases, sales and transportation of energy commodities (a portion of which are firm commitments at the inception of the hedge). The Company's policies prohibit the use of leveraged financial instruments. In addition, Reliant Energy Services, a subsidiary of Resources, maintains a portfolio of Energy Derivatives to provide price risk management services and for trading purposes (Trading Derivatives). The Company uses value-at-risk and a sensitivity analysis method for assessing the market risk of its derivatives. With respect to the Energy Derivatives (other than Trading Derivatives) held by subsidiaries of the Company and Resources as of December 31, 1998, a decrease of 10% in the market prices of natural gas and electric power from year-end levels would decrease the fair value of these instruments by approximately $3 million. As of December 31, 1997, a decrease of 10% in the prices of natural gas would have resulted in a loss of $7 million in fair values of the Energy Derivatives (other than for trading purposes). The above analysis of the Energy Derivatives utilized for hedging purposes does not include the favorable impact that the same hypothetical price movement would have on the Company's and its subsidiaries' physical purchases and sales of natural gas and electric power to which the hedges relate. The portfolio of Energy Derivatives held for hedging purposes is no greater than the notional quantity of the expected or committed transaction volume of physical commodities with equal and opposite commodity price risk for the same time periods. Furthermore, the Energy Derivative portfolio is managed to complement the physical transaction portfolio, reducing overall risks within limits. Therefore, the adverse impact to the fair value of the portfolio of Energy Derivatives held for hedging purposes associated with the hypothetical changes in commodity prices referenced above would be offset by a favorable impact on the underlying hedged physical transactions, assuming (i) the Energy Derivatives are not closed out in advance of their expected term, (ii) the Energy Derivatives continue to function effectively as hedges of the underlying risk and (iii) as applicable, anticipated transactions occur as expected. The disclosure with respect to the Energy Derivatives relies on the assumption that the contracts will exist parallel to the underlying physical transactions. If the underlying transactions or positions are liquidated prior to the maturity of the Energy Derivatives, a loss on the financial instruments may occur, or the options might be worthless as determined by the prevailing market value on their termination or maturity date, whichever comes first. With respect to the Trading Derivatives held by Reliant Energy Services, consisting of natural gas, electric power, crude oil and refined products, physical forwards, swaps, options and exchange-traded futures, this subsidiary is exposed to losses in fair value due to changes in the price and volatility of the underlying derivatives. During the year ended December 31, 1998 and 1997, the highest, lowest and average monthly value-at-risk in the Trading Derivative portfolio was less than $5 million at a 95% confidence level and for a holding period of one business day. The Company uses the variance/covariance method for calculating the value-at-risk and includes the delta approximation for options positions. The Company has established a Corporate Risk Oversight Committee comprised of corporate and business segment officers that oversees all corporate price and credit risk activities, including derivative trading activities discussed above. The committee's duties are to establish the Company's policies and to monitor and ensure compliance with risk management policies and procedures and the trading limits established by the Company's board of directors. 14
12 COMPANY 10-K NOTES (1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (c) Regulatory Assets and Other Long-Lived Assets. The Company and certain subsidiaries of Resources apply the accounting policies established in SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71), to the accounts of Electric Operations, Natural Gas Distribution and the Interstate Pipeline operations of a subsidiary of Resources. In general, SFAS No. 71 permits a company with cost-based rates to defer certain costs that would otherwise be expensed to the extent that the rate regulated company is recovering or expects to recover such costs in rates charged to its customers. The following is a list of regulatory assets/liabilities reflected on the Company's Consolidated Balance Sheet as of December 31, 1998, detailed by Electric Operations and other segments. ELECTRIC TOTAL OPERATIONS OTHER COMPANY ---------- ----- ------- (MILLIONS OF DOLLARS) Deferred plant costs-- net............................................ $ 536 $ $ 536 Recoverable project costs-- net....................................... 55 55 Regulatory tax asset-- net............................................ 418 418 Unamortized loss on reacquired debt................................... 140 140 Fuel-related debits/credits-- net..................................... (15) (15) Other deferred debits................................................. 54 12 66 --------- -------- -------- Total....................................................... $ 1,188 $ 12 $ 1,200 --------- -------- -------- If, as a result of changes in regulation or competition, the Company's and Resources' ability to recover these assets and liabilities would not be assured, then pursuant to SFAS No. 101, "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 and Resources would be required to write off or write down such regulatory assets and liabilities, unless some form of transition cost recovery continues through rates established and collected for their remaining regulated operations. In addition, the Company and Resources would be required to determine any impairment to the carrying costs of deregulated plant and inventory assets. In order to reduce exposure to potentially stranded costs related to generation assets, Electric Operations redirected $195 million of depreciation in 1998 from transmission, distribution and general plant assets to generation assets. Such redirection is in accordance with the Company's transition to competition plan (Transition Plan) described in Note 1(f). If Electric Operations was required to apply SFAS No. 101 to the generation portion of its business only, the cumulative amount of redirected depreciation of $195 million would become a regulatory asset of the transmission and distribution portion of its business. Effective January 1, 1996, the Company and Resources adopted SFAS No. 121. SFAS No. 121 requires that long-lived assets and certain identifiable intangibles to be held and used or disposed of by an entity be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Adoption of the standard did not result in a write-down of the carrying amount of any asset on the books of the Company or Resources. In July 1997, the Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board 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 97-4). EITF 97-4 concluded that the application of SFAS No. 71 to a segment which is subject to a deregulation plan should cease when the legislation and enabling rate order contain sufficient detail for the utility to reasonably determine how the plan will affect the segment to be deregulated. In addition, EITF 97-4 requires the regulatory assets and liabilities to be allocated to the applicable portion of the electric utility from which the source of the regulated cash flows will be derived. As a part of the Transition Plan, the Company has agreed to support future legislation providing for retail customer choice and other provisions consistent with those in the 1997 proposed Texas legislation. At this time, the Company is unable to make any predictions as to the details of legislation being considered by the Texas legislature or the likelihood that such legislation will ultimately be enacted. Although the Company has determined that no impairment loss or write-offs of regulatory assets or carrying costs of plant and inventory assets need to be recognized for applicable assets of Electric Operations as of December 31, 1998, this conclusion may change in the future (i) as competition influences wholesale and retail pricing in the electric utility industry, (ii) depending on regulatory action, if any and (iii) depending on legislation, if any, that is passed.
13 (f) Depreciation and Amortization Expense. The Company's consolidated depreciation expense for 1998 was $548 million compared to $475 million for 1997 and $410 million for 1996. In June 1998, the Public Utility Commission of Texas (Texas Utility Commission) issued an order approving the Transition Plan filed by Electric Operations in December 1997. In order to reduce Electric Operations' exposure to potentially stranded costs related to generation assets, the Transition Plan permits the redirection to generation assets of depreciation expense that Electric Operations otherwise would apply to transmission, distribution and general plant assets. In addition, the Transition Plan provides that all earnings above a 9.844% overall annual rate of return on invested capital be used to recover Electric Operations' investment in generation assets. Electric Operations implemented the Transition Plan effective January 1, 1998 and pursuant to its terms, recorded an aggregate of $194 million in additional depreciation and $195 million in redirected depreciation in 1998. The Company's depreciation and amortization expenses included $50 million of additional depreciation relating to the South Texas Project Electric Generating Station (South Texas Project) in both 1997 and 1996 and goodwill amortization relating to the acquisition of Resources of $55 million in 1998 and $22 million in 1997. For additional information regarding the operation of goodwill in connection with the Merger, see Note 1(b) above. The depreciation expense recorded for the South Texas Project was made pursuant to the terms of the Company's 1995 rate case settlement (1995 Rate Case Settlement), which permitted the Company to write down as much as $50 million per year of its investment in the South Texas Project through December 31, 1999. These write-downs are treated under the 1995 Rate Case Settlement as reasonable and necessary expenses for purposes of any future earnings reviews or other proceedings. In 1998, 1997 and 1996, the Company, as permitted by the 1995 Rate Case Settlement, also amortized $4 million, $66 million and $50 million (pre-tax), respectively, of its $153 million investment in certain lignite reserves associated with a canceled generating station. The Company's remaining investment in the canceled generating station and certain lignite reserves will be amortized fully no later than December 31, 2002. (n) Investments in Time Warner Securities. The Company owns 11 million shares of non-publicly traded Time Warner convertible preferred stock (TW Preferred). The TW Preferred is redeemable after July 6, 2000, has an aggregate liquidation preference of $100 per share (plus accrued and unpaid dividends), is entitled to annual dividends of $3.75 per share until July 6, 1999, is currently convertible by the Company and after July 6, 1999 is exchangeable by Time Warner into approximately 45.8 million shares of Time Warner common stock (TW Common). Each share of TW Preferred is entitled to two votes (voting together with the holders of the TW Common as a single class). The Company has accounted for its investment in TW Preferred under the cost method at a value of $990 million on the Company's Consolidated Balance Sheets. Dividends on these securities are recognized as income at the time they are earned. The Company recorded pre-tax dividend income with respect to the Time Warner securities of $41.3 million in 1998 and 1997 and $41.6 million in 1996. To monetize its investment in the TW Preferred, the Company sold in July 1997, 22.9 million of ACES. At maturity in July 2000, the principal amount of the ACES will be mandatorily exchangeable by the Company into either (i) a number of shares of TW Common based on an exchange rate or (ii) cash having an equal value. Subject to adjustments that may result from certain dilution events, the exchange rate for each ACES is determined as follows: (i) 1.6528 shares of TW Common if the price of TW Common at maturity (Maturity Price) is at least $27.7922 per share, (ii) a fractional share of TW Common such that the fractional share will have a value equal to $22.96875 if the Maturity Price is less than $27.7922 but greater than $22.96875 and (iii) one share of TW Common if the Maturity Price is not more than $22.96875. The closing price of TW Common was $62.062 per share on December 31, 1998. Prior to maturity, the Company has the option of redeeming the ACES if (i) changes in federal tax regulations require recognition of a taxable gain on the Company's TW Preferred and (ii) the Company could defer such gain by redeeming the ACES. The redemption price is 105% of the closing sales price of the ACES as determined over a period prior to the redemption notice. The redemption price may be paid in cash or in shares of TW Common or a combination of the two. As a result of the issuance of the ACES, a portion of the increase in the market value above $27.7922 per share of TW Common results in non-cash, unrealized accounting losses to the Company for the ACES, pending the conversion of the Company's TW Preferred into TW Common. For example, prior to the conversion, when the market price of TW Common increases above $27.7922, the Company records in Other Income (Expense) an unrealized, non-cash accounting loss for the ACES equal to (i) the aggregate amount of such increase as applicable to all ACES multiplied by (ii) 0.8264. In accordance with generally accepted accounting principles, this accounting loss (which reflects the unrealized increase in the Company's indebtedness with respect to the ACES) may not be offset by accounting recognition of the increase in the market value of the TW Common that underlies the TW Preferred. Upon conversion of the TW Preferred (anticipated to occur in July 1999), the Company will begin recording future unrealized net changes in the market prices of the TW Common and the ACES as a component of common stock equity and other comprehensive income. As of December 31, 1998 and 1997, the market price of TW Common was $62.062 and $31.00 per share, respectively. Accordingly, the Company recognized an increase of $1.2 billion in 1998 and $121 million in 1997 in the unrealized liability relating to its ACES indebtedness (which resulted in an after-tax earnings reduction of $764 million or $2.69 basic earnings per share and $79 million or $.31 basic earnings per share, respectively). The Company believes that the cumulative unrealized loss for the ACES of approximately $1.3 billion is more than economically hedged by the approximately $1.8 billion unrecorded unrealized gain at December 31, 1998 relating to the increase in the fair value of the TW Common underlying the investment in TW Preferred since the date of its acquisition. Any gain related to the increase in fair value of TW Common would be recognized as a component of net income upon the sale of the TW Preferred or the shares of TW Common into which such TW Preferred is converted. As of March 11, 1999, the price of TW Common was $70.75 per share which would have resulted in the Company recognizing an additional increase of $329 million in the unrealized liability relating to its ACES indebtedness. The related unrecorded unrealized gain as of March 11, 1999 would have been computed as an additional $398 million. (p) Foreign Currency Adjustments International assets and liabilities where the local currency is the functional currency, have been translated into U.S. dollars using the exchange rate at the balance sheet date. Revenues, expenses, gains, and losses have been translated using the weighted average exchange rate for each month prevailing during the periods reported. Cumulative adjustments resulting from translation have been recorded in stockholders' equity and other comprehensive income. When the U.S. dollar is the functional currency, the financial statements of International are remeasured in U.S. dollars using historical exchange rates for non-monetary accounts and the current rate at the respective balance sheet date and the weighted average exchange rate for all other balance sheet and income statement accounts, respectively. All exchange gains and losses from remeasurement and foreign currency transactions are included in consolidated net income. However, fluctuations in foreign currency exchange rates relative to the U.S. dollar can have an impact on the reported equity earnings of the Company's foreign investments. For additional information about the Company's investments in unconsolidated affiliates, see Note 5. For additional information about the Company's investments in Brazil and the devaluation of the Brazilian real in January 1999, see Note 16(a). 2
14 (r) Change in Accounting Principle. In the fourth quarter of 1998, the Company adopted mark-to-market accounting for all of the energy price risk management and trading activities of Reliant Energy Services. Under mark-to-market accounting, the Company records the fair value of energy-related derivative financial instruments, including physical forward contracts, swaps, options and exchange-traded futures contracts at each balance sheet date. Such amounts are recorded in the Company's Consolidated Balance Sheet as price risk management assets, price risk management liabilities, deferred debits and deferred liabilities. The realized and unrealized gains (losses) are recorded as a component of operating revenues in the Company's Consolidated Statements of Income. The Company has applied mark-to-market accounting retroactively to January 1, 1998. This change was made in order to adopt a generally accepted accounting methodology that provided consistency between financial reporting and the methodology used in all reported periods by the Company in managing its trading activities. There was no material cumulative effect resulting from the accounting change. The Company will adopt Emerging Issues Task Force Issue 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" in the first quarter of 1999 for Reliant Energy Services' trading activities. The Company does not expect the implementation of EITF Issue 98-10 to be material to its consolidated financial statements. (2) DERIVATIVE FINANCIAL INSTRUMENTS (a) Price Risk Management and Trading Activities. The Company, through Reliant Energy Services, offers energy price risk management services primarily in the natural gas, electric and crude oil and refined product industries. Reliant Energy Services provides these services by utilizing, a variety of derivative financial instruments, including fixed and variable-priced physical forward contracts, fixed-price swap agreements, variable-price swap agreements, exchange-traded energy futures and option contracts, and swaps and options traded in the over-the-counter financial markets (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. Prior to 1998, Reliant Energy Services applied hedge accounting to certain physical commodity activities that qualified for hedge accounting. In 1998, Reliant Energy Services adopted mark-to-market accounting for all of its price risk management and trading activities. Accordingly, as of such date such Trading Derivatives are recorded at fair value with realized and unrealized gains (losses) recorded as a component of operating revenues in the Company's Consolidated Statements of Income. The recognized, unrealized balance is recorded as price risk management assets/liabilities and deferred debits/credits on the Company's Consolidated Balance Sheets (See Note 1(r)). The notional quantities, maximum terms and the estimated fair value of Trading Derivatives at December 31, 1998 are presented below (volumes in billions of British thermal units equivalent (BBtue) and dollars in millions): VOLUME-FIXED VOLUME-FIXED PRICE MAXIMUM 1998 PRICE PAYOR RECEIVER TERM (YEARS) ---- ----------- -------- ------------ Natural gas.................................................. 937,264 977,293 9 Electricity.................................................. 122,950 124,878 3 Crude oil and products....................................... 205,499 204,223 3 AVERAGE FAIR FAIR VALUE VALUE (a) ---------------------- ---------------------- 1998 ASSETS LIABILITIES ASSETS LIABILITIES ---- ------ ----------- ------ ----------- Natural gas.............................................. $ 224 $ 213 $ 124 $ 108 Electricity.............................................. 34 33 186 186 Crude oil and products................................... 29 23 21 17 ------ ----------- ------ ----------- $ 287 $ 269 $ 331 $ 311 ====== =========== ====== =========== 3
15 The notional quantities, maximum terms and the estimated fair value of derivative financial instruments at December 31, 1997 are presented below (volumes in BBtue and dollars in millions): VOLUME-FIXED VOLUME-FIXED PRICE MAXIMUM 1997 PRICE PAYOR RECEIVER TERM (YEARS) ---- ----------- -------- ------------ Natural gas.................................................. 85,701 64,890 4 Electricity.................................................. 40,511 42,976 1 AVERAGE FAIR FAIR VALUE VALUE (a) ---------------------- ---------------------- 1997 ASSETS LIABILITIES ASSETS LIABILITIES ---- ------ ----------- ------ ----------- Natural gas.............................................. $ 46 $ 39 $ 56 $ 48 Electricity.............................................. 6 6 3 2 ------ ----------- ------ ----------- $ 52 $ 45 $ 59 $ 50 ====== =========== ====== =========== - --------- (a) Computed using the ending balance of each month. In addition to the fixed-price notional volumes above, Reliant Energy Services also has variable-priced agreements, as discussed above, totaling 1,702,977 and 101,465 BBtue as of December 31, 1998 and 1997, respectively. Notional amounts reflect the volume of 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 value shown in the table above at December 31, 1998 and substantially all of the fair value at December 31, 1997 have been recognized in income. The fair value as of December 31, 1998 and 1997 was estimated using quoted prices where available and considering the liquidity of the market for the Trading Derivatives. The prices are subject to significant changes based on changing market conditions. At December 31, 1998, $22 million of the fair value of the assets and $41 million of the fair value of the liabilities are recorded as long-term on deferred debits and deferred credits, respectively on the Company's Consolidated Balance Sheets. 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 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 and its subsidiaries' 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 Reliant Energy Services as of December 31, 1998. INVESTMENT GRADE (1) TOTAL --------------------------------- (Thousands of Dollars) ------------ ------------ Energy marketers....................................... $ 102,458 $ 123,779 Financial institutions................................. 61,572 61,572 Gas and electric utilities............................. 46,880 48,015 Oil and gas producers.................................. 7,197 8,323 Industrials............................................ 1,807 3,233 Independent power producers............................ 1,452 1,463 Others................................................. 45,421 46,696 ------------ ------------ Total............................................. $ 266,787 $ 293,081 ============ Credit and other reserves.............................. (6,464) ------------ Energy price risk management assets (2)................ $ 286,617 ============ - --------- (1) "Investment Grade" is primarily determined using publicly available credit ratings along with the consideration of credit support (e.g., parent company guarantees) and collateral, which encompass cash and standby letters of credit. (2) The Company has credit risk exposure with respect to two investment grade customers, each of which represents an amount greater than 5% but less than 10% of Price Risk Management Assets. 4
16 (b) Non-Trading Activities. To reduce the risk from market fluctuations in the price of electric power, natural gas and related transportation, the Company, Resources and certain of its subsidiaries enter into futures transactions, swaps and options (Energy Derivatives) in order to hedge certain natural gas in storage, as well as certain expected purchases, sales and transportation of natural gas and electric power (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, although usage to date for this purpose has not been material. The Company applies hedge accounting with respect to its derivative financial instruments. Certain subsidiaries of the Company also utilize interest-rate derivatives (principally interest-rate swaps) in order to adjust the portion of its overall borrowings which are subject to interest rate risk and also utilize such derivatives to effectively fix the interest rate on debt expected to be issued for refunding purposes. For transactions involving either Energy Derivatives or interest-rate derivatives, hedge accounting is applied only if the derivative (i) reduces the price risk of the underlying hedged item and (ii) is designated as a hedge at its inception. Additionally, the derivatives must be expected to result in financial impacts which 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. In the case of interest-rate swaps associated with existing obligations, cash flows and expenses associated with the interest-rate derivative transactions are matched with the cash flows and interest expense of the obligation being hedged, resulting in an adjustment to the effective interest rate. When interest rate swaps are utilized to effectively fix the interest rate for an anticipated debt issuance, changes in the market value of the interest-rate derivatives are deferred and recognized as an adjustment to the effective interest rate on the newly issued debt. Unrealized changes in the market value of Energy Derivatives utilized as hedges are not generally recognized in the Company's Consolidated Statements of Income until the underlying hedged transaction occurs. Once it becomes probable that an anticipated transaction will not occur, deferred gains and losses are recognized. In general, the financial impact of transactions involving these Energy Derivatives is included in the Company's Statements of Consolidated Income under the captions (i) fuel expenses, in the case of natural gas transactions and (ii) purchased power, in the case of electric power 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. At December 31, 1998, subsidiaries of Resources were fixed-price payors and fixed-price receivers in Energy Derivatives covering 42,498 billion British thermal units (Bbtu) and 3,930 BBtu of natural gas, respectively. At December 31, 1997, subsidiaries of Resources were fixed-price payors and fixed-price receivers in Energy Derivatives covering 38,754 BBtu and 7,647 BBtu of natural gas, respectively. Also, at December 31, 1998 and 1997, subsidiaries of Resources were parties to variable-priced Energy Derivatives totaling 21,437 Bbtu and 3,630 BBtu of natural gas, respectively. The weighted average maturity of these instruments is less than one year. The notional amount is intended to be indicative of the Company's and its subsidiaries' level of activity in such derivatives, although 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 below. Under such 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 13 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. 5
17 (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 and its subsidiaries' risk management activities. Credit risk relates to the risk of loss resulting from non-performance of contractual obligations by a counterparty. While as yet the Company and its subsidiaries have experienced only minor losses due to the credit risk associated with these arrangements, 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 such contract. In order to minimize this risk, the Company and/or its subsidiaries, as the case may be, enter into such contracts primarily with those counterparties with a minimum Standard & Poor's or Moody's rating of BBB- or Baa3, respectively. For long-term arrangements, the Company and its subsidiaries periodically review the financial condition of such firms in addition to monitoring the effectiveness of these financial contracts in achieving the Company's objectives. Should the counterparties to these arrangements fail to perform, the Company would seek to compel performance at law or otherwise or obtain compensatory damages in lieu thereof. The Company might be forced to acquire alternative hedging arrangements or be required to honor the underlying commitment at then- current market prices. In such event, the Company might incur additional loss to the extent of amounts, if any, already paid to the counterparties. In view of its criteria for selecting counterparties, its process for monitoring the financial strength of these counterparties and its experience to date in successfully completing these transactions, the Company believes that the risk of incurring a significant financial statement loss due to the non-performance of counterparties to these transactions is minimal. The Company's policies prohibit the use of leveraged financial instruments. The Company has established a Corporate Risk Oversight Committee, comprised of corporate and business segment officers, to oversee all corporate price and credit risks, including Reliant Energy Services' trading, marketing and risk management activities. The Corporate Risk Oversight Committee's responsibilities include reviewing the Company's and its subsidiaries' hedging, trading and price risk management strategies, activities and limits and monitoring to ensure compliance with the Company's risk management policies and procedures and trading limits established by the Company's board of directors. (3) RATE MATTERS (a) Electric Proceedings. The Texas Utility Commission has original (or in some cases appellate) jurisdiction over Electric Operations' electric rates and services. Texas Utility Commission orders may be appealed to a District Court in Travis County, and from that court's decision an appeal may be taken to the Court of Appeals for the 3rd District at Austin (Austin Court of Appeals). Discretionary review by the Supreme Court of Texas may be sought from decisions of the Austin Court of Appeals. In the event that the courts ultimately reverse actions of the Texas Utility Commission, such matters are remanded to the Texas Utility Commission for action in light of the courts' orders. (b) Transition Plan. In June 1998, the Texas Utility Commission issued an order in Docket No. 18465 approving the Company's Transition Plan filed by Electric Operations 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 are entitled to receive base rate credits of 2% in each of 1998 and 1999. The Company implemented the Transition Plan effective January 1, 1998. For information about additional depreciation of generation assets and redirecting depreciation pursuant to the Transition Plan, see Note 1(f). Review of the Texas Utility Commission's order in Docket No. 18465 is currently pending before the Travis County District Court. In August 1998, the Office of the Attorney General for the State of Texas and a Texas municipality filed an appeal seeking, among other things, to reverse the portion of the Texas Utility Commission's order relating to the redirection of depreciation expenses under the Transition Plan. Because of the number of variables that can affect the ultimate resolution of an appeal of Commission orders, the Company is not in a position at this time to predict the outcome of this matter or the ultimate effect that adverse action by the courts could have on the Company. (4) JOINTLY OWNED ELECTRIC UTILITY PLANT (a) Investment in South Texas Project. The Company has a 30.8% interest in the South Texas Project, which consists of two 1,250 megawatt (MW) nuclear generating units and bears a corresponding 30.8% share of capital and operating costs associated with the project. As of December 31, 1998, the Company's investment in the South Texas Project (including AFUDC) was $1.4 billion (net of $1.1 billion accumulated depreciation). The Company's investment in nuclear fuel (including AFUDC) was $41 million (net of $230 million amortization) as of such date. 6
18 The South Texas Project is owned as a tenancy in common among its four co-owners, with each owner retaining its undivided ownership interest in the two nuclear-fueled generating units and the electrical output from those units. The four co-owners have delegated management and operation responsibility for the South Texas Project to the South Texas Nuclear Operating Company (STPNOC). STPNOC is managed by a board of directors comprised of one director from each of the four owners, along with the chief executive officer of STPNOC. The four owners provide oversight through an owners' committee comprised of representatives of each of the owners and through the board of directors of STPNOC. Prior to November 1997, the Company was the operator of the South Texas Project. (b) 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. This coverage consists of $500 million in primary property damage insurance and excess property insurance in the amount of $2.25 billion. With respect to excess property insurance, the Company and the other owners of the South Texas Project are subject to assessments, the maximum aggregate assessment under current policies being $16.5 million during any one policy year. The application of the proceeds of such property insurance is subject to the priorities established by the Nuclear Regulatory Commission (NRC) regulations relating to the safety of licensed reactors and decontamination operations. Pursuant to the Price Anderson Act, the maximum liability to the public of owners of nuclear power plants, such as the South Texas Project, was $9.145 billion as of December 31, 1998. Owners are required under the Price Anderson Act to insure their liability for nuclear incidents and protective evacuations by maintaining the maximum amount of financial protection available from private sources and by maintaining secondary financial protection through an industry retrospective rating plan. The assessment of deferred premiums provided by the plan for each nuclear incident is up to $83.9 million per reactor, subject to indexing for inflation, a possible 5% surcharge (but no more than $10 million per reactor per incident in any one year) and a 3% state premium tax. 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. (c) 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 1(o). In May 1994, an outside consultant estimated the Company's portion of decommissioning costs to be approximately $318 million (1994 dollars). The consultant's calculation of decommissioning costs for financial planning purposes used the DECON methodology (prompt removal/dismantling), one of the three alternatives acceptable to the NRC and assumed deactivation of Units Nos. 1 and 2 upon the expiration of their 40-year operating licenses. 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, changes in regulatory and accounting requirements, changes in technology and changes in costs of labor, materials and equipment. An update of the 1994 study is in the process of being completed. (d) Assessment Fees for Spent Fuel Disposal and Enrichment and Decommissioning. By contract, the United States Department of Energy (DOE) has committed itself ultimately to take possession of all spent fuel generated by the South Texas Project. The DOE contract currently requires payment of a spent fuel disposal fee on nuclear plant-generated electricity of one mill (one-tenth of a cent) per net KWH sold. This fee is subject to adjustment to ensure full cost recovery by the DOE. The Energy Policy Act also includes a provision that assesses a fee upon domestic utilities that purchased nuclear fuel enrichment services from the DOE before October 24, 1992. The South Texas Project's assessment is approximately $2 million per year (subject to escalation for inflation). The Company has a remaining estimated liability of $5 million for such assessments. 7
19 (e) 1996 Settlement of South Texas Project Litigation. In 1996, the Company recorded an aggregate $95 million ($62 million net of tax) charge in connection with various settlements of lawsuits filed by co-owners of the South Texas Project. For information about the execution of an operations agreement with the City of San Antonio in connection with one of these settlements, see Note 12(c). (5) EQUITY INVESTMENTS AND ADVANCES TO UNCONSOLIDATED SUBSIDIARIES The Company accounts for affiliate investments of its subsidiaries under the equity method of accounting where (i) the subsidiary's ownership interest in the affiliate ranges from 20% to 50%, (ii) the ownership interest is less than 20% but the subsidiary exercises significant influence over operating and financial policies of such affiliate or (iii) the subsidiary's ownership interest in the affiliate exceeds 50% but the subsidiary does not exercise control over the affiliate. The Company's and its subsidiaries' equity investments and advances in unconsolidated subsidiaries at December 31, 1998 and 1997 were $1 billion and $704 million, respectively. The Company's and its subsidiaries' equity income from these investments, included in International revenues and other net income, was $71 million, $49 million and $17 million in 1998, 1997 and 1996, respectively. Dividends received from the investments amounted to $44 million and $46 million in 1998 and 1997, respectively. No dividends were received from these investments in 1996. (a) International. In April 1998, Light ServiHos de Eletricidade S.A. (Light), a Brazilian corporation in which Reliant Energy International, Inc. (Reliant Energy International) indirectly owns an 11.69% common stock interest, purchased 74.88% of the common stock of Metropolitana Eletricidade de Sao Paulo S.A. (Metropolitana), an electric distribution company that serves the metropolitan area of Sao Paulo, Brazil. The purchase price for the shares was approximately $1.8 billion and was financed with proceeds from bank borrowings. As of December 31, 1998, Light and Metropolitana had approximately $3.2 billion in non-local currency denominated borrowings. For information regarding foreign currency adjustments, see Note 1(p). For information about the devaluation of the Brazilian real in January 1999, see Note 16(a). In May 1997, Reliant Energy International increased its indirect ownership interest in an Argentine electric utility from 48% to 63%. The purchase price of the additional interest was $28 million. On June 30, 1998, Reliant Energy International sold its 63% ownership interest in an Argentine affiliate and certain related assets for approximately $243 million. Reliant Energy International acquired its initial ownership interests in the electric utility in 1992. The Company recorded an $80 million after-tax gain from this sale in the second quarter of 1998. In 1998, a subsidiary of Reliant Energy International acquired for approximately $150 million, equity interests (currently ranging from approximately 36% to 45%) in three electric distribution systems located in El Salvador. Corporacion EDC S.A.C.A. (CEDC), Reliant Energy International's partner in this venture, acquired majority interests in the systems when they were privatized in early 1998. On June 30, 1998, CEDC closed on the sale of approximately half of its interests in the systems to a subsidiary of Reliant Energy International. In August 1998, Reliant Energy International and CEDC jointly acquired, through subsidiaries, 65% of the stock of two Colombian electric distribution companies, Electricaribe and Electrocosta. The shares of these companies are indirectly held by an offshore holding company jointly owned by special purpose subsidiaries of CEDC and Reliant Energy International. The purchase price for the joint investment in Electricaribe and Electrocosta was approximately $522 million, excluding transaction costs. The purchase price was funded with capital contributions from Reliant Energy International and CEDC and a U.S. $200 million loan obtained by the holding company from a United States bank. A $100 million advance on the loan was obtained in October 1998 with subsequent advances of $25 million and $75 million obtained in December 1998 and January 1999, respectively. The loan will mature on October 31, 2003. Reliant Energy International funded its capital contributions with a portion of the proceeds from the sale of the Argentine affiliate discussed above and capital contributions from the Company. Under the terms of a support agreement, Reliant Energy International and CEDC have agreed, among other things, to repurchase up to U.S. $50 million of the loan from the bank to the extent that the bank is unable to syndicate that portion of the loan to other banks on or prior to June 15, 1999. In June 1997, a consortium of investors which included a subsidiary of Reliant Energy International, acquired for $496 million a 56.7% controlling ownership interest in Empresa de Energia del Pacifico S.A.E.S.P. (EPSA), an electric utility system serving the Valle de Cauca province of Colombia, including the area surrounding the city of Cali. Reliant Energy International contributed $152 million of the purchase price for a 28.35% ownership interest in EPSA. In addition to its distribution facilities, EPSA owns 850 MW of electric generation capacity. 8
20 Reliant Energy International has accounted for these transactions under purchase accounting and has recorded its investments and its interest in the affiliates' earnings after the acquisition dates using the equity method. The purchase prices were allocated, on a preliminary basis, using the estimated fair market values of the assets acquired and the liabilities assumed as of the dates of acquisition. The differences between the amounts paid and the underlying fair values of the net assets acquired are being amortized as a component of earnings attributable to unconsolidated affiliates over the estimated lives of the projects ranging from 30 to 40 years. Purchase price adjustments to fixed assets are being amortized over the underlying assets' estimated useful lives. (b) Combined Financial Statement Data of Equity Investments and Advances to Unconsolidated Subsidiaries. The following table sets forth certain summarized financial information of the Company's unconsolidated affiliates as of December 31, 1998 and 1997 and for the years then ended or periods from the respective affiliates' acquisition date through December 31, 1998, 1997 and 1996, if shorter: YEAR ENDED DECEMBER 31, ---------------------------------------------------------- 1998 1997 1996 ---------------- ---------------- ---------------- ($ IN THOUSANDS) Income Statement: Revenues....................... $ 2,449,335 $ 2,011,927 $ 994,743 Operating Expenses............. 1,762,166 1,460,248 768,993 Net Income..................... 514,005 403,323 149,038 YEAR ENDED DECEMBER 31, ------------------------------------- 1998 1997 ---------------- ---------------- ($ IN THOUSANDS) Balance Sheet: Current Assets................... $ 1,841,857 $ 726,997 Noncurrent Assets................ 13,643,747 5,791,858 Current Liabilities.............. 4,074,603 566,596 Noncurrent Liabilities........... 6,284,821 1,398,385 Owner's Equity................... 5,126,180 4,553,874 (8) LONG-TERM DEBT AND SHORT-TERM BORROWINGS (c) FinanceCo and FinanceCo II Credit Facilities. In August 1997, a limited partnership special purpose subsidiary of the Company (FinanceCo) established a five-year, $1.644 billion revolving credit facility (FinanceCo Facility). The FinanceCo Facility supported $1.360 billion in commercial paper borrowings by FinanceCo at December 31, 1998 recorded as notes payable on the Company's Consolidated Balance Sheet. The weighted average interest rate of these borrowings was 5.88% at December 31, 1998, and 6.15% at December 31, 1997. Borrowings under the FinanceCo Facility bear interest at a rate based upon the London interbank offered rate (LIBOR) plus a margin, a base rate or at a rate determined through a bidding process. The FinanceCo Facility may be used (i) to support the issuance of commercial paper or other short-term indebtedness of FinanceCo, (ii) subject to certain limitations, to finance purchases of Company common stock and (iii) subject to certain limitations, to provide funds for general purposes of FinanceCo, including the making of intercompany loans to, or securing letters of credit for the benefit of, FinanceCo's affiliates. The FinanceCo Facility requires the Company to maintain a ratio of consolidated indebtedness for borrowed money to consolidated capitalization (as defined) that does not exceed 0.65:1.00. The FinanceCo Facility also contains restrictions applicable to the Company and certain of its subsidiaries with respect to, among other things, (i) liens, (ii) consolidations, mergers and dispositions of assets, (iii) dividends and purchases of common stock, (iv) certain types of investments and (v) certain changes in its business. The FinanceCo Facility contains customary covenants and default provisions applicable to FinanceCo and its subsidiaries, including limitations on, among other things, additional indebtedness (other than certain permitted indebtedness), liens and certain investments or loans. Subject to certain conditions and limitations, the Company is required to make cash payments from time to time to FinanceCo from excess cash flow (as defined in the FinanceCo Facility) to the extent necessary to enable FinanceCo to meet its financial obligations. At December 31, 1998, commercial paper supported by the FinanceCo Facility was secured by pledges of (i) all of the limited and general partner interests of FinanceCo, (ii) the Series B Preference Stock and (iii) certain intercompany notes held by FinanceCo. The obligations under the FinanceCo Facility are not secured by the utility assets of the Company or Resources or by the Company's investment in Time Warner securities. In March 1998, a limited partnership special purpose subsidiary of the Company (FinanceCo II) executed a $150 million credit agreement (FinanceCo II Facility) which terminated March 2, 1999. Proceeds from $150 million of borrowings under the FinanceCo II Facility were used to fund a portion of the April 1998 purchase by Reliant Energy Power Generation, Inc. (Power Generation) of four electric generation plants. Borrowings under the FinanceCo II Facility bore interest at LIBOR-based and negotiated rates. At December 31, 1998, FinanceCo II had $150 million of borrowings under this facility at an interest rate of 5.75%. In March 1999, the $150 million of borrowings under the FinanceCo II facility were paid at maturity with borrowings under the FinanceCo facility. 9
21 (d) Company Credit Facility. The Company meets its short-term financing needs primarily through sales of commercial paper supported by a $200 million revolving credit facility. Borrowings under the facility are unsecured and a facility fee is paid. At December 31, 1998, there was no outstanding commercial paper and there were no outstanding borrowings under the bank facility. (9) TRUST SECURITIES (a) Company. In February 1997, two Delaware statutory business trusts (Reliant Trusts) established by the Company issued (i) $250 million of preferred securities and (ii) $100 million of capital securities, respectively. The preferred securities have a distribution rate of 8.125% payable quarterly in arrears, a stated liquidation amount of $25 per preferred security and must be redeemed by March 2046. The capital securities have a distribution rate of 8.257% payable quarterly in arrears, a stated liquidation amount of $1,000 per capital security and must be redeemed by February 2037. The Reliant Trusts sold the preferred and capital securities to the public and used the proceeds to purchase $350 million aggregate principal amount of subordinated debentures (Debentures) from the Company having interest rates corresponding to the distribution rates of the securities and maturity dates corresponding to the mandatory redemption dates of the securities. The Reliant Trusts are accounted for as wholly owned consolidated subsidiaries of the Company. The Debentures represent the Reliant Trusts' sole assets and its entire operations. The Company has fully and unconditionally guaranteed, on a subordinated basis, each Trust's obligations, including the payment of distributions and all other payments due with respect to the respective preferred and capital securities. The preferred and capital securities are mandatorily redeemable upon the repayment of the related Debentures at their stated maturity or earlier redemption. Subject to certain limitations, the Company has the option of deferring payments of interest on the Debentures held by the Reliant Trusts. If and for as long as interest payments on the Debentures have been deferred, or an event of default under the indenture relating thereto has occurred and is continuing, the Company may not pay dividends on its capital stock. As of December 31, 1998, no interest payments on the Debentures had been deferred. (12) COMMITMENTS AND CONTINGENCIES (a) Commitments. The Company has various commitments for capital expenditures, fuel, purchased power, cooling water and operating leases. Commitments in connection with Electric Operations' capital program are generally revocable by the Company, subject to reimbursement to manufacturers for expenditures incurred or other cancellation penalties. The Company's and its subsidiaries' other commitments have various quantity requirements and durations. However, if these requirements could not be met, various alternatives are available to mitigate the cost associated with the contracts' commitments. (b) Fuel and Purchased Power. The Company 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 are approximately $210 million in 1999, $187 million in 2000 and $188 million in 2001. Additionally, minimum payment obligations for lignite mining and lease agreements are approximately $9 million for 1999, $10 million for 2000 and $10 million for 2001. Minimum payment obligations for both natural gas purchase and storage contracts associated with Electric Operations are approximately $10 million in 1999, $9 million in 2000 and $9 million in 2001. The Company also has commitments to purchase firm capacity from two cogenerators totaling approximately $22 million in both 1999 and 2000. Texas Utility Commission rules currently allow recovery of these costs through Electric Operations' base rates for electric service and additionally authorize the Company to charge or credit customers through a purchased power cost recovery factor for any variation in actual purchased power costs from the cost utilized to determine its base rates. In the event that the Texas Utility Commission, at some future date, does not allow recovery through rates of any amount of purchased power payments, these two firm capacity contracts contain provisions allowing the Company to suspend or reduce payments and seek repayment for amounts disallowed. Both of these firm capacity contracts have initial terms ending March 31, 2005. 10
22 (c) 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. 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 and a minimum cumulative savings of $150 million over the 10-year term of the agreement. Based on current forecasts and other assumptions regarding the combined operation of the two generating systems, the Company anticipates that the savings resulting from joint operations will equal or exceed the minimum savings guaranteed under the joint operating agreement. In 1996, savings generated for CPS' account for a partial year of joint operations were approximately $14 million. In 1997 and 1998, savings generated for CPS' account for a full year of operation were approximately $22 million and $14 million, respectively. (d) Transportation Agreement. Resources had an agreement (ANR Agreement) with ANR Pipeline Company (ANR) which contemplated that Resources would transfer to ANR an interest in certain of Resources' pipeline and related assets. The interest represented capacity of 250 Mmcf/day. Under the ANR Agreement, an ANR affiliate advanced $125 million to Resources. Subsequently, the parties restructured the ANR Agreement and Resources refunded in 1995 and 1993, respectively, $50 million and $34 million to ANR or an affiliate. Resources recorded $41 million as a liability reflecting ANR's or its affiliates' use of 130 Mmcf/day of capacity in certain of Resources' 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 remaining balance. (e) Lease Commitments. The following table sets forth certain information concerning the Company's obligations under non-cancelable long-term operating leases: Minimum Lease Commitments at December 31, 1998 (1) (Millions of Dollars) 1999.................................................... $ 20 2000.................................................... 16 2001.................................................... 15 2002.................................................... 11 2003.................................................... 10 2004 and beyond......................................... 66 --------- Total......................................... $ 138 --------- - ---------- (1) Principally consisting of rental agreements for building space and data processing equipment and vehicles (including major work equipment). Resources 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. Resources does not expect to lease additional property under this lease agreement. Total rental expense for all Resources' leases was approximately $25 million in 1998. Total rental expense for all leases in 1997 since the Acquisition Date was approximately $15 million. (f) Letters of Credit. At December 31, 1998, the Company and Resources had letters of credit incidental with their ordinary business operations totaling approximately $34 million under which they are obligated to reimburse drawings, if any. (g) Indemnity Provisions. At December 31, 1998, Resources had a $5.8 million accounting reserve on the Company's Consolidated Balance Sheet in Other Deferred Credits for possible indemnity claims asserted in connection with its disposition of Resources' former subsidiaries or divisions, including the sale of (i) Louisiana Intrastate Gas Corporation, a former Resources subsidiary engaged in the intrastate pipeline and liquids extraction business; (ii) Arkla Exploration Company, a former Resources subsidiary engaged in oil and gas exploration and production activities; and (iii) Dyco Petroleum Company, a former Resources subsidiary engaged in oil and gas exploration and production. (h) Environmental Matters. The Company is a defendant in litigation arising out of the environmental remediation of a site in Corpus Christi, Texas. The litigation was instituted in 1985 by adjacent landowners. The litigation is pending before the United States District Court for the Southern District of Texas, Corpus Christi Division. The site was operated by third parties as a metals reclaiming operation. Although the Company neither operated nor owned the site, certain transformers and other equipment originally sold by the Company may have been delivered to the site by third parties. The Company and others have remediated the site pursuant to a plan approved by appropriate state agencies and a federal court. To date, the Company has recovered or has commitments to recover from other responsible parties $2.2 million of the more than $3 million it has spent on remediation. 11
23 In 1992, the United States Environmental Protection Agency (EPA) (i) identified the Company, along with several other parties, as "potentially responsible parties" (PRP) under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) for the costs of cleaning up a site located adjacent to one of the Company's transmission lines in La Marque, Texas and (ii) issued an administrative order for the remediation of the site. The Company believes that the EPA took this action solely on the basis of information indicating that the Company in the 1950s acquired record title to a portion of the land on which the site is located. The Company does not believe that it now or previously has held any ownership interest in the property covered by the order and has obtained a judgement to that effect from a court in Galveston County, Texas. Based on this judgement and other defenses that the Company believes to be meritorious, the Company has elected not to adhere to the EPA's administrative order, even though the Company understands that other PRPs are proceeding with site remediation. To date, neither the EPA nor any other PRP has instituted an action against the Company for any share of the remediation costs for the site. However, if the Company was determined to be a responsible party, the Company could be jointly and severally liable along with the other PRPs for the aggregate remediation costs of the site (which the Company currently estimates to be approximately $80 million in the aggregate) and could be assessed substantial fines and damage claims. Although the ultimate outcome of this matter cannot currently be predicted at this time, the Company does not believe that this case will have a material adverse effect on the Company's financial condition, liquidity or results of operations. From time to time the Company and its subsidiaries have received notices from regulatory authorities or others regarding their status as potential PRPs in connection with sites found to require remediation due to the presence of environmental contaminants. In addition, the Company has been named as 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 its practice of 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 operation or cash flows. (i) Other. Electric Operations' service area is heavily dependent on oil, gas, refined products, petrochemicals and related businesses. Significant adverse events affecting these industries would negatively affect the revenues of the Company. The Company and Resources are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business, some of which involve substantial amounts. The Company's management regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. The Company's management believes that the effect on the Company's and Resources' respective financial statements, if any, from the disposition of these matters will not be material. In February 1996, the cities of Wharton, Galveston and Pasadena filed suit, for themselves and a proposed class, against the Company and Houston Industries Finance Inc. (formerly a wholly owned subsidiary of the Company) citing underpayment of municipal franchise fees. The plaintiffs claim, among other things, that from 1957 to the present, franchise fees should have been paid on sales taxes collected by Electric Operations on receipts from sales to other utilities and on receipts from services as well as sales of electricity. Plaintiffs advance their claims notwithstanding their failure to notice such claims over the previous four decades. Because all of the franchise ordinances affecting Electric Operations expressly impose fees only on receipts from sales of electricity for consumption within a city, the Company regards plaintiffs' allegations as spurious and is vigorously contesting the matter. The plaintiffs' pleadings assert that their damages exceed $250 million. The District Court for Harris County has granted a partial summary judgment in favor of the Company dismissing all claims for franchise fees based on sales tax collections. Other motions for partial summary judgment remain pending. Although the Company believes the claims to be without merit, the Company cannot at this time estimate a range of possible loss, if any, from the lawsuit, nor can any assurance be given as to its ultimate outcome. (16) SUBSEQUENT EVENTS (a) Foreign Currency Devaluation. In January 1999, the Brazilian real was devalued and allowed to float against other major currencies. The Company expects to take a charge against first quarter earnings as a result of the Brazilian devaluation. The charge will reflect the Company's proportionate share of the impact of the devaluation on foreign denominated debt of Brazilian corporations in which the Company holds an equity interest. The amount of the charge will not be known until the end of the first quarter. At December 31, 1998, one U.S. dollar could be exchanged for 1.21 Brazilian reais. Using the exchange rate of 2.06 reais/dollar in effect at the end of February, and the average exchange rate in effect since the end of the year, the Company estimates that its share of the after-tax charge that would be recorded by the Brazilian companies in which it owns an interest would be approximately $125 million. 12
24 COMPANY FIRST QUARTER 10-Q NOTES (8) COMPANY/RESOURCES OBLIGATED MANDATORILY REDEEMABLE TRUST PREFERRED SECURITIES OF SUBSIDIARY TRUSTS HOLDING SOLELY JUNIOR SUBORDINATED DEBENTURES OF THE COMPANY/RESOURCES (a) Company. In the first quarter of 1999, the Company, through the use of a Delaware statutory business trust (REI Trust I), registered $500 million of trust preferred securities and related junior subordinated debt securities. In February 1999, REI Trust I issued $375 million of preferred securities to the public and $11.6 million of common securities to the Company. The preferred securities have a distribution rate of 7.20% payable quarterly in arrears, a stated liquidation amount of $25 per preferred security and must be redeemed by March 2048. REI Trust I used the proceeds to purchase $386.6 million aggregate principal amount of subordinated debentures (REI Debentures) from the Company having an interest rate and maturity date that correspond to the distribution rate and mandatory redemption date of the preferred securities. The Company used the proceeds from the sale of the REI Debentures for general corporate purposes, including the repayment of short-term debt. The Company accounts for REI Trust I as a wholly owned consolidated subsidiary. The REI Debentures are the trust's sole asset and its entire operations. The Company has fully and unconditionally guaranteed, on a subordinated basis, all of REI Trust I's obligations with respect to the preferred securities. The preferred securities are mandatorily redeemable upon the repayment of the REI Debentures at their stated maturity or earlier redemption. Subject to certain limitations, the Company has the option of deferring payments of interest on the REI Debentures. During any period of deferral or event of default, the Company may not pay dividends on its capital stock. Under the registration statement, $125 million of these securities remain available for issuance. The issuance of all securities registered by the Company and its affiliates is subject to market and other conditions. For information regarding $250 million of preferred securities and $100 million of capital securities previously issued by statutory business trusts formed by the Company, see Note 9(a) of the Company 10-K Notes. The sole asset of each trust consists of junior subordinated debentures of the Company 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 such trust. 13
25 (9) LONG-TERM DEBT AND SHORT-TERM FINANCING (a) Company. (i) Consolidated Debt. The Company's consolidated long-term and short-term debt outstanding is summarized in the following table. MARCH 31, 1999 DECEMBER 31, 1998 ------------------------------- ------------------------------- LONG-TERM CURRENT LONG-TERM CURRENT ------------- ------------- ------------- ------------- (IN MILLIONS) Short-Term Borrowings (1): Commercial Paper............................ $ 1,436 $ 1,360 Lines of Credit............................. 150 Resources Receivables Facility.............. 300 300 Notes Payable............................... 2 3 ------------- ------------- ------------- ------------- Total Short-Term Borrowings................... 1,738 1,813 ------------- ------------- ------------- ------------- Long-Term Debt - net: ACES $ 2,681 $ 2,350 Debentures (2)(3)........................... 1,476 1,482 First Mortgage Bonds (2).................... 1,716 150 1,866 170 Pollution Control Bonds..................... 581 581 Resources Medium-Term Notes (3)............. 176 178 Notes Payable (3)........................... 330 224 330 226 Capital Leases.............................. 14 1 14 1 ------------- ------------- ------------- ------------- Total Long-Term Debt.......................... 6,974 375 6,801 397 ------------- ------------- ------------- ------------- Total Long-Term and Short-Term Debt......... $ 6,974 $ 2,113 $ 6,801 $ 2,210 ============= ============= ============= ============= - ---------- (1) Includes amounts due within one year of the date noted. (2) Includes unamortized discount related to debentures of approximately $0.5 million at March 31, 1999 and $1 million at December 31, 1998 and unamortized premium related to debentures of approximately $17 million at March 31, 1999 and December 31, 1998, respectively. The unamortized discount related to first mortgage bonds was approximately $10 million at March 31, 1999 and $10 million at December 31, 1998. (3) Includes unamortized premium related to fair value adjustments of approximately $17.6 million and $18.1 million for debentures at March 31, 1999 and December 31, 1998, respectively. The unamortized premium for Resources long-term notes was approximately $11 million and $12 million at March 31, 1999 and December 31, 1998, respectively. The unamortized premium for long-term and current notes payable was approximately $3 million and $2 million at March 31, 1999 and $3 million each at December 31, 1998, respectively. Consolidated maturities of long-term debt and sinking fund requirements for the Company (including Resources) are approximately $222 million for the remainder of 1999. (ii) Financing Developments. At March 31, 1999, a financing subsidiary of the Company had $1.293 billion in commercial paper borrowings supported by a $1.644 billion revolving credit facility. At March 31, 1999, the weighted average interest rate of these commercial paper borrowings was 5.12%. 14
26 On March 2, 1999, another financing subsidiary of the Company terminated a credit agreement under which it had borrowed $150 million. Funds for the repayment of the loan were indirectly obtained from the issuance of commercial paper by a separate financing subsidiary. For additional information regarding the Company's and its subsidiaries' financings, see Note 8(c) and (d) of the Company 10-K Notes. In February 1999, the Company repaid at maturity $25.4 million and $145.1 million of its Series A medium-term notes with interest rates of 9.85% and 9.80%, respectively. (11) ACQUISITIONS On March 29, 1999, the Company and one of its subsidiaries, N.V. Energieproduktiebedrijf UNA, a Dutch electric generating company (UNA), and the shareholders of UNA entered into an agreement providing for the initial acquisition of 40% of the capital stock of UNA by a subsidiary of the Company. The purchase price for the initial 40% interest is Dutch guilders (NLG) 1.6 billion (U.S. $840 million). The purchase price for the remaining 60% of UNA is approximately NLG 2.7 billion (U.S. $1.4 billion) and is expected to be paid no later than December 31, 2006. Depending on the timing of regulatory approvals and other conditions, the acquisition of the remaining interest could occur significantly earlier than 2006. All purchase price obligations are denominated in Dutch guilders. The amounts shown above are subject to adjustment and assume a conversion rate of NLG 1.88 per U.S. Dollar. It is anticipated that the closing of the initial 40% interest will occur in June 1999, subject to receipt of various Dutch regulatory approvals and the satisfaction of other closing conditions. UNA is one of four large Dutch generators with approximately 3,400 megawatts of generating capacity, representing nearly 20% of the Dutch market. It operates a mix of gas, coal and cogeneration plants in the Amsterdam and Utrecht areas. 15
27 COMPANY SECOND QUARTER 10-Q (2) TEXAS ELECTRIC CHOICE PLAN AND DISCONTINUANCE OF SFAS NO. 71 FOR ELECTRIC GENERATION OPERATIONS In June 1999, Texas adopted the Texas Electric Choice Plan (Legislation) that substantially amends the regulatory structure governing electric utilities in order to allow retail competition beginning on January 1, 2002. In preparation for that competition, the Company will make significant changes in the electric utility operations it conducts through Reliant Energy HL&P. In addition, the Legislation requires the Public Utility Commission of Texas (Texas PUC) 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 their present levels. The Legislation provides for utilities to recover 100 percent of their generation related stranded costs and regulatory assets (as defined in the Legislation). Retail Choice. Under the Legislation, on January 1, 2002, most retail customers of 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 PUC. Retail electric providers will not own or operate generation assets and their sales rates will not be subject to traditional cost-of-service regulation. Retail electric providers affiliated with the Company may compete statewide for these sales, but rates they charge within the electric utility's traditional service territory are subject to certain limitations at the outset of retail choice, as described below. The Texas PUC will prescribe regulations governing quality, reliability and other aspects of service from 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. Under the Legislation, Reliant Energy HL&P is required to submit a plan to accomplish that separation to the Texas PUC by January 10, 2000. The transmission and distribution business will continue to be subject to cost-of-service rate regulation and will be responsible for the delivery of electricity to retail consumers. 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, Reliant Energy HL&P and most other electric utilities will be required to sell at auction entitlements to 15 percent of their installed generating capacity no later than 60 days before January 1, 2002. That obligation to auction entitlements continues until the earlier of January 1, 2007 or the date the Texas PUC determines that at least 40 percent of the residential and small commercial load served in the electric utility's service area is being served by non-affiliated retail electric providers. In addition, a power generator that owns and controls more than 20 percent of the power generation in, or capable of delivering power to, a power region after the reductions from the capacity auction (calculated as prescribed in the Legislation) must submit a mitigation plan to reduce generation that it owns and controls to no more than 20 percent in the power region. The Legislation also creates a program mandating air emissions reductions for non-permitted generating facilities. The Company anticipates that costs associated with this obligation will be recoverable through the stranded cost recovery mechanisms contained in the Legislation. 16
28 Rates. Base rates charged by Reliant Energy HL&P on September 1, 1999 will be frozen until January 1, 2002. 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 percent from the average rates (on a bundled basis) in effect on January 1, 1999. 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 Reliant Energy HL&P'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 PUC determines that 40 percent of power consumed by that class 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 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 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 from 1999 until January 2002, 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 Legislation provides for Reliant Energy HL&P, or a special purpose entity, to issue securitization bonds for regulatory assets and for 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. Accounting. Historically, the Company has applied the accounting policies established in SFAS No. 71. For a discussion of the Company's accounting policies under SFAS No. 71, see Note 1(c) of the Company 10-K Notes. In general, SFAS No. 71 permits a company with cost-based rates to defer certain costs that would otherwise be expensed to the extent that it meets the following requirements: (1) its rates are regulated by a third party; (2) its rates are cost-based; and (3) 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, "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), 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 Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board 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 17
29 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 stop applying 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 its electric generation operations. Reliant Energy HL&P's transmission and distribution operations continue to meet the criteria of SFAS No. 71. The Company has evaluated the recovery of its generation related regulatory assets and liabilities. Because the Legislation provides for the issuance of securitization bonds up to the amount of generation related regulatory assets at December 31, 1998 and because these bonds will be amortized through non-bypassable charges to transmission and distribution customers, the Company believes these amounts are probable of full recovery. If events were to occur that made the recovery of certain of these 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 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. 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 considered impaired, and should be written down to fair value, if the future undiscounted cash flows 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 its $4.5 billion electric generation assets (prior to the impairment loss) was impaired as of June 30, 1999. Of such amounts, $745 million relate to the South Texas Project Electric Generating Station and $52 million relate to two gas-fired generation plants. The Legislation provides 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 recoverable impaired plant costs. This new regulatory asset will be amortized as it is recovered. 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 $797 million pre-tax 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 PUC. Any difference between the fair market value and the regulatory net book value of the generation assets (as defined by the Legislation) will either be refunded or collected through future transmission and distribution rates. 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 18
30 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 stranded costs are subject to material changes. Factors affecting such change may include estimation risk, uncertainty of future energy prices, the passage of time during the transition period and the economic lives of the plants. If events occur that make the recovery of the regulatory asset associated with the generation plant impairment loss and deferred debits created from discontinuance of SFAS No. 71 pursuant to the Legislation no longer probable, the Company will write off the remaining balance of such 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 such operations. The Company believes it is probable that some parties will seek to return such amounts to ratepayers and accordingly, the Company has recorded an offsetting liability. Following are the classes of electric property, plant and equipment at cost, with associated accumulated depreciation at June 30, 1999 (including the impairment loss discussed above) and December 31, 1998. TRANSMISSION CONSOLIDATED AND GENERAL ELECTRIC PLANT IN GENERATION DISTRIBUTION AND INTANGIBLE SERVICE ---------- ------------ -------------- ------------------ (IN MILLIONS) June 30, 1999: Original cost ............................ $ 8,920 $ 4,349 $ 970 $ 14,239 Accumulated depreciation .................. 4,904 1,270 210 6,384 Property, plant and equipment - net(1) .... 4,016 3,079 760 7,855 December 31, 1998: Original cost ............................. $ 8,843 $ 4,196 $ 930 $ 13,969 Accumulated depreciation .................. 3,822 1,276 207 5,305 Property, plant and equipment - net(1) .... 5,021 2,920 723 8,664 - --------------------- (1) Includes non-utility generation facilities of $354 million at June 30, 1999 and $338 million at December 31, 1998 and international distribution facilities of $25 million at June 30, 1999 and $19 million at December 31, 1998. In order to reduce potential exposure to stranded costs related to generation assets, Reliant Energy HL&P redirected $102 million and $195 million of depreciation in the six months ended June 30, 1999 and year ended December 31, 1998, respectively, from transmission, distribution and general plant assets to generation assets. Such redirection is in accordance with the Company's transition to competition plan, approved by the Texas PUC (Transition Plan). See Note 3(b) of the Company 10-K Notes. The cumulative amount of redirected depreciation of $297 million is an embedded regulatory asset included in transmission and distribution and general plant and equipment balances. The Company 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. 19
31 Other Accounting Policy Changes. As a result of discontinuing SFAS No. 71, other accounting policies related to the Company's electric generation plant 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." 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. When no new debt was issued to refinance the retired debt, these costs were amortized over the remaining 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." The economic lives of Reliant Energy HL&P's generation plant and equipment will be reassessed and prospective depreciation rates may be revised due to changing economic circumstances as a result of the Legislation. (7) TIME WARNER SECURITIES INVESTMENT As of June 30, 1999, the Company owned 11 million shares of Time Warner Inc. (Time Warner) convertible preferred stock (TW Preferred). On July 6, 1999, the Company converted its TW Preferred into 45.8 million shares of Time Warner common stock (TW Common). Accordingly, the Company will no longer receive the quarterly pre-tax dividend of $10.3 million that was paid on the TW Preferred, but is expected to receive a quarterly pre-tax dividend on the TW Common of approximately $2.1 million (based on current dividend levels). In 1997, in order to monetize a portion of the cash value of its investment in Time Warner, the Company sold 22.9 million of its unsecured 7% Automatic Common Exchange Securities (ACES). The market value of ACES is indexed to the market value of TW Common. In July 2000, the ACES will be mandatorily exchangeable for, at the Company's option, either shares of TW Common at the exchange rate set forth below or cash with an equal value. The current exchange rate is as follows: MARKET PRICE OF TW COMMON EXCHANGE RATE -------------------------- ------------- Below $22.96875 2.0 shares of TW Common $22.96875 - $27.7922 Share equivalent of $45.9375 Above $27.7922 1.6528 shares of TW Common By issuing the ACES, the Company effectively eliminated the economic exposure of its investment in Time Warner to decreases in the price of TW Common below $22.96875. In addition, the Company retained 100% of any increase in TW Common price up to $27.7922 per share and 17% of any increase in market price above $27.7922. The closing price per share of TW Common on June 30, 1999 was $72.625. Prior to the July 1999 conversion of the TW Preferred, any increase in the market value of TW Common above $27.7922 was treated for accounting purposes as an increase in the payment amount of the ACES equal to 83% of the increase in the market price per share and was recorded by the Company as a non-cash expense. As a result, the Company recorded in the second quarter and first half of 1999 a non-cash, unrealized accounting loss of $69 million and 20
32 $400 million, respectively (which resulted in an after-tax earnings reduction of $44 million, or $0.16 per share, and $260 million, or $0.91 per share, respectively); this correlates to the $83 million and $484 million unrecorded unrealized gain related to the increase in the market value of TW Common during the second quarter and first half of 1999. The Company believes the cumulative unrealized loss for the ACES of $1.7 billion is more than economically hedged by the approximately $2.3 billion unrecorded unrealized gain at June 30, 1999, relating to the increase in market value of the TW Common from the Company's cost. Upon conversion, the Company recorded an increase in its investment in TW Common of $2.3 billion, which represents the increase in market value of TW Common over the Company's cost for the TW Preferred. In addition, the Company recognized an increase of $1.5 billion in other comprehensive income, which represents the change in market price of TW Common, net of related deferred taxes. Upon the sale or other disposition of the TW Common, the Company is expected to record a gain equal to the amount realized on the sale or disposition less the original cost of the TW Preferred. As a result of the conversion, the Company will now record changes in the market price of the TW Common and the related changes in the market value of the ACES as a component of stockholders' equity and other comprehensive income. 21
1 EXHIBIT 12B RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES (THOUSANDS OF DOLLARS) NINE MONTHS TWELVE MONTHS ENDED ENDED SEPTEMBER 30, SEPTEMBER 30, -------------- ------------- 1999 1999 ------------- ------------- Income from Continuing Operations .............................................. $ 70,397 $ 109,852 Income Taxes from Continuing Operations ........................................ 70,569 126,950 ---------- ---------- Income from Continuing Operations Before Income Taxes .......................... $ 140,966 $ 236,802 ========== ========== Fixed Charges Interest ......................................................... $ 89,407 $ 122,506 Amortization of Debt Discount and Expense ...................................... 1,085 1,307 Portion of Rents Considered to Represent an Interest Factor .................... 9,388 6,786 ---------- ---------- Total Fixed Charges ............................................................ $ 99,880 $ 130,599 ========== ========== Income from Continuing Operations Before Income Taxes and Fixed Charges ........ $ 240,846 $ 367,401 Ratio of Earnings to Fixed Charges ............................................. 2.41 2.81 ========== ==========
OPUR1 0001042773 RELIANT ENERGY RESOURCES CORP. 1,000 9-MOS DEC-31-1999 SEP-30-1999 PER-BOOK 1,432,619 1,493,959 1,746,825 2,345,896 0 7,019,299 1 2,463,831 167,807 2,631,639 0 1,066 1,292,479 350,000 0 34,200 201,671 0 0 0 2,508,244 7,019,299 7,705,879 70,569 7,483,025 7,483,025 222,854 8,604 231,458 90,492 70,397 0 70,397 0 90,231 390,206 0.00 0.00
1 EXHIBIT 99B [ITEMS INCORPORATED FROM THE RESOURCES 10-K AND THE RESOURCES FIRST QUARTER 10-Q] ITEM 3. LEGAL PROCEEDINGS. (b) Resources. For a description of certain legal and regulatory proceedings affecting Resources, see Note 8(g) to Resources' Consolidated Financial Statements, which note is incorporated herein by reference. ITEM. 7 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF THE COMPANY CERTAIN FACTORS AFFECTING FUTURE EARNINGS OF THE COMPANY AND ITS SUBSIDIARIES Earnings for the past three years are not necessarily indicative of future earnings and results. The level of future earnings depends on numerous factors including (i) the future growth in the Company's and its subsidiaries' energy sales; (ii) weather; (iii) the success of the Company's and its subsidiaries' entry into non-rate regulated businesses such as energy marketing and international and domestic power projects; (iv) the Company's and its subsidiaries' ability to respond to rapid changes in a competitive environment and in the legislative and regulatory framework under which they have traditionally operated; (v) rates of economic growth in the Company's and its subsidiaries' service areas; (vi) the ability of the Company and its subsidiaries to control costs and to maintain pricing structures that are both attractive to customers and profitable; (vii) the outcome of future rate proceedings; (viii) the effect that foreign exchange rate changes may have on the Company's investments in international operations; and (ix) future legislative initiatives. In order to adapt to the increasingly competitive environment in which the Company operates, the Company continues to evaluate a wide array of potential business strategies, including business combinations or acquisitions involving other utility or non-utility businesses or properties, internal restructuring, reorganizations or dispositions of currently owned properties or currently operating business units and new products, services and customer strategies. In addition, the Company continues to engage in new business ventures, such as electric power trading and marketing, which arise from competitive and regulatory changes in the utility industry. COMPETITION AND RESTRUCTURING OF THE ELECTRIC UTILITY INDUSTRY The electric utility industry is becoming increasingly competitive due to changing government regulations, technological developments and the availability of alternative energy sources. Long-Term Trends in Electric Utility Industry. The electric utility industry historically has been composed of vertically integrated companies providing electric service on an exclusive basis within governmentally-defined geographic areas. Prices for electric service have typically been set by governmental authorities under principles designed to provide the utility with an opportunity to recover its cost of providing electric service plus a reasonable return on its invested capital. Federal legislation and regulation as well as legislative and regulatory initiatives in various states have encouraged competition among electric utility and non-utility owned power generators. These developments, combined with increased demand for lower-priced electricity and technological advances in electric generation, have continued to move the electric utility industry in the direction of more competition. Based on a strategic review of the Company's business and of ongoing developments in the electric utility and related industries regarding competition, regulation and consolidation, the Company's management believes that the electric utility industry will continue its path toward competition, albeit on a state-by-state basis. The Company's management also believes the business of electricity and natural gas are converging and consolidating and these trends will alter the structure and business practices of companies serving these markets in the future. Competition in Wholesale Market. The Federal Energy Policy Act of 1992, the Public Utility Regulatory Act of 1995 (now the Texas Utilities Code) and regulations promulgated by the Federal Energy Regulatory Commission (FERC) contain provisions intended to facilitate the development of a wholesale energy market. Although Reliant Energy HL&P's wholesale sales traditionally have accounted for less than 1% of its total revenues, the expansion of competition in the wholesale electric market is significant in that it has increased the range of non-utility competitors, such as exempt wholesale generators (EWGs) and power marketers, in the Texas electric market as well as resulted in fundamental changes in the operation of the state transmission grid. In February 1996, the Texas Utility Commission adopted rules granting third-party users of transmission systems open access to such systems at rates, terms and conditions comparable to those available to utilities owning such transmission assets. Under the Texas Utility Commission order implementing the rule, Reliant Energy HL&P was required to separate, on an operational basis, its wholesale power marketing operations from the operations of the transmission grid and, for purposes of transmission pricing, to disclose each of its separate costs of generation, transmission and distribution. Within ERCOT, an independent system operator (ISO) manages the state's electric grid, ensuring system reliability and providing non-discriminatory transmission access to all power producers and traders. The ERCOT ISO, the first in the nation, is a key component for implementing the Texas Utility Commission's overall strategy to create a
2 competitive wholesale market. ERCOT formed an ad hoc committee in early 1998 to investigate the potential impacts of a competitive retail market on the ISO. The ERCOT committee report was released in December 1998 and concluded that the ISO's role and function would necessarily expand in a competitive retail environment, but the changes required of the ISO to support retail choice should not impede introduction of retail choice. Competition in Retail Market. The Company estimates that, since 1978, cogeneration projects representing approximately one-third of current total peak generating capability have been built in the Houston area and that, as a result, Reliant Energy HL&P has seen a reduction of approximately 2,500 MW in customer load to self-generation. Reliant Energy HL&P has utilized flexible pricing to respond to situations where large industrial customers have an alternative to buying power from it, primarily by constructing their own generating facilities. Under a tariff option approved by the Texas Utility Commission in 1995, Reliant Energy HL&P was permitted to implement contracts based upon flexible pricing for up to 700 MW. Currently, this rate is fully subscribed. Texas law currently does not permit retail sales by unregulated entities such as cogenerators. The Company anticipates that cogenerators and other interests will continue to exert pressure to obtain access to the electric transmission and distribution systems of regulated utilities for the purpose of making retail sales to customers of regulated utilities. Legislative Proposals. A number of proposals to restructure the electric utility industry have been introduced in the 1999 session of the Texas legislature. If adopted, legislation may permit and encourage alternative suppliers to compete to serve Reliant Energy HL&P's current rate-regulated retail customers. The various legislative proposals include provisions governing recovery of stranded costs and permitting securitization of those costs; freezing rates until 2002; requiring firm sales of energy to competing retail electric providers; requiring disaggregation of generation, transmission and distribution, and retail sales into separate companies and limiting the ability of existing utilities' affiliates competing for retail electric customers on the basis of price until they have lost a substantial percentage of their residential and small commercial load to alternative retail providers. In addition to the Texas legislative proposals, a number of federal legislative proposals to promote retail electric competition or restructure the U.S. electric utility industry have been introduced during the current congressional session. At this time, the Company is unable to make any prediction as to whether any legislation to restructure electric operations or provide retail competition will be enacted or as to the content or impact on the Company of any legislation which may be enacted. However, because the proposed legislation is intended to fundamentally restructure electric utility operations, it is likely that enacted legislation would have a material impact on the Company. Stranded Costs. As the U.S. electric utility industry continues its transition to a more competitive environment, a substantial amount of fixed costs previously approved for recovery under traditional utility regulatory practices (including regulatory assets and liabilities) may become "stranded," i.e., unrecoverable at competitive market prices. The issue of stranded costs could be particularly significant with respect to fixed costs incurred in connection with the past construction of generation plants, such as nuclear power plants, which, because of their high fixed costs, would not command the same price for their output as they have in a regulated environment. In January 1997, the Texas Utility Commission delivered a report to the Texas legislature on stranded investments in the electric utility industry in Texas (referred to by the Texas Utility Commission as "Excess Cost Over Market") (ECOM). In April 1998, the Texas Utility Commission submitted to the Texas Senate Interim Committee on Electric Utility Restructuring an updated study of ECOM estimates. Assuming that retail competition is adopted at the beginning of 2002, the updated study estimated that the total amount of stranded costs for all Texas electric utilities could be $4.5 billion. If instead, retail competition is adopted one year later, the study estimates statewide ECOM to be $3.3 billion. Estimates of ECOM vary widely and there is inherent uncertainty in calculating these costs. Transition Plan. In June 1998, the Texas Utility Commission approved the Transition Plan filed by Reliant Energy HL&P in December 1997. The Transition Plan included base rate credits to residential and certain commercial 2
3 customers in 1998 and 1999, an overall rate of return cap formula for 1998 and 1999 and approval of accounting procedures designed to accelerate recovery of stranded costs which may arise under restructuring legislation. The Transition Plan permits the redirection of depreciation expense to generation assets that Electric Operations otherwise would apply to transmission, distribution and general plant assets. In addition, the Transition Plan provides that all earnings above a 9.844% overall annual rate of return on invested capital be used to recover Electric Operations' investment in generation assets. In 1998, Reliant Energy HL&P recorded an additional $194 million in depreciation under the Transition Plan. Certain parties have appealed the order approving the Transition Plan. For additional information, see Notes 1(f) and 3(b) to the Company's Consolidated Financial Statements. COMPETITION -- OTHER OPERATIONs Natural Gas Distribution competes primarily with alternate energy sources such as electricity and other fuel sources as well as with providers of energy conservation products. In addition, as a result of federal regulatory changes affecting interstate pipelines, it has become possible for other natural gas suppliers and distributors to bypass Natural Gas Distribution's facilities and market, sell and/or transport natural gas directly to small commercial and/or large volume customers. The Interstate Pipeline 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. Interstate Pipeline 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 served by Interstate Pipeline and the level of competition for transport and storage services. Reliant Energy Services competes for sales in its gas and power trading and marketing business with other natural gas and power merchants, producers and pipelines based on its 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. Reliant Energy Services also competes against other energy marketers on the basis of its relative financial position and access to credit sources. This competitive factor reflects the tendency of energy customers, natural gas suppliers and natural gas 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, the Company anticipates that Reliant Energy Services will experience greater competition and downward pressure on per-unit profit margins in the energy marketing industry. Competition for acquisition of international and domestic non-rate regulated power projects is intense. International and Power Generation compete against a number of other participants in the non-utility power generation industry, some of which have greater financial resources and have been engaged in non-utility power projects for periods longer than the Company and have accumulated greater portfolios of projects. Competitive factors relevant to the non-utility power industry include financial resources, access to non-recourse funding and regulatory factors. FLUCTUATIONS IN COMMODITY PRICES AND DERIVATIVE INSTRUMENTS For information regarding the Company's exposure to risk as a result of fluctuations in commodity prices and derivative instruments, see "Quantitative and Qualitative Disclosures About Market Risk" in Item 7A of this Report. ACCOUNTING TREATMENT OF ACES The Company accounts for its investment in Time Warner Convertible Preferred Stock (TW Preferred) under the cost method. As a result of the Company's issuance of the ACES, a portion of the increase in the market value above $27.7922 per share of Time Warner common stock (the security into which the TW Preferred is convertible) (TW 3
4 Common) results in unrealized accounting losses to the Company, pending the conversion of the Company's TW Preferred into TW Common. For consistency purposes, the TW Common and related per share prices retroactively reflect a 2 for 1 stock split effective December 15, 1998. Prior to the conversion of the TW Preferred into TW Common, when the market price of TW Common increases above $27.7922, the Company records in Other Income (Expense) an unrealized, non-cash accounting loss for the ACES equal to the aggregate amount of such increase as applicable to all ACES multiplied by 0.8264. In accordance with generally accepted accounting principles, this accounting loss (which reflects the unrealized increase in the Company's indebtedness with respect to the ACES) may not be offset by accounting recognition of the increase in the market value of the TW Common that underlies the TW Preferred. Upon conversion of the TW Preferred (which is anticipated to occur in June 1999 when the preferential dividend on the TW Preferred expires), the Company will begin recording future unrealized net changes in the market prices of the TW Common and the ACES as a component of common stock equity and other comprehensive income. As of December 31, 1998, the market price of TW Common was $62.062 per share. Accordingly, the Company recognized an increase of $1.2 billion in 1998 in the unrealized liability relating to its ACES indebtedness (which resulted in an after-tax earnings reduction of $764 million or $2.69 basic earnings per share in 1998). The Company believes that the cumulative unrealized loss for the ACES of approximately $1.3 billion is more than economically offset by the approximately $1.8 billion unrecorded unrealized gain at December 31, 1998 relating to the increase in the fair value of the TW Common underlying the investment in TW Preferred since the date of its acquisition. Any gain related to the increase in fair value of TW Common would be recognized as a component of net income upon the sale of the TW Preferred or the shares of TW Common into which such TW Preferred is converted. As of March 11, 1999, the price of TW Common was $70.75 per share, which would have resulted in the Company recognizing an additional increase of $329 million in the unrealized liability represented by its indebtedness under the ACES. The related unrecorded unrealized gain as of March 11, 1999 would have been computed as an additional $398 million. Excluding the unrealized, non-cash accounting loss for ACES, the Company's retained earnings and total common stock equity would have been $2.3 billion and $5.2 billion, respectively. IMPACT OF THE YEAR 2000 ISSUE AND OTHER SYSTEM IMPLEMENTATION ISSUES Year 2000 Problem. At midnight on December 31, 1999, unless the proper modifications have been made, the program logic in many of the world's computer systems will start to produce erroneous results because, among other things, the systems will incorrectly read the date "01/01/00" as being January 1 of the year 1900 or another incorrect date. In addition, certain systems may fail to detect that the year 2000 is a leap year. Problems can also arise earlier than January 1, 2000, as dates in the next millennium are entered into non-Year 2000 compliant programs. Compliance Program. In 1997, the Company initiated a corporate-wide Year 2000 project to address mainframe application systems, information technology (IT) related equipment, system software, client-developed applications, building controls and non-IT embedded systems such as process controls for energy production and delivery. Incorporated into this project were Resources' and other Company subsidiaries' mainframe applications, infrastructures, embedded systems and client-developed applications that will not be migrated into existing or planned Company or Resources systems prior to the year 2000. The evaluation of Year 2000 issues included those related to significant customers, key vendors, service suppliers and other parties material to the Company's and its subsidiaries' operations. In the course of this evaluation, the Company has sought written assurances from such third parties as to their state of Year 2000 readiness. State of Readiness. Work has been prioritized in accordance with business risk. The highest priority has been assigned to activities that would disrupt the physical delivery of energy (Priority 1); activities that would impact back office activities such as billing (Priority 2); activities that would cause inconvenience or productivity loss in normal business operations (e.g. air conditioning systems and elevators) (Priority 3). All business units have completed an analysis of critical systems and equipment that control the production and delivery of energy, as well as corporate, departmental and personnel systems and equipment. The remediation and replacement work on the majority of IT 4
5 systems, non-IT systems and infrastructure began in the first quarter of 1998 and is expected to be completed by the second quarter of 1999. Testing of these systems began in the second quarter of 1998 and is scheduled to be completed in third quarter of 1999. The following table illustrates the Company's completion percentages for the Year 2000 activities as of February 28, 1999: PRIORITY 1 PRIORITY 2 PRIORITY 3 -------------- -------------- --------------- Assessment.............................................. 95% 86% 96% Conversion.............................................. 86% 70% 91% Testing................................................. 80% 61% 87% Implementation.......................................... 76% 54% 75% Costs to Address Year 2000 Compliance Issues. Based on current internal studies, as well as recently solicited bids from various computer software vendors, the Company estimates that the total direct cost of resolving the Year 2000 issue with respect to the Company and its subsidiaries will be between $35 and $40 million. This estimate includes approximately $7 million related to salaries and expenses of existing employees and approximately $3 million in hardware purchases that the Company expects to capitalize. In addition, the $35 to $40 million estimate includes approximately $2 million spent prior to 1998 and approximately $12 million during 1998. The remaining costs related to resolving the Year 2000 issue are expected to be expended in 1999. The Company expects to fund these expenditures through internal sources. In September 1997, the Company entered into an agreement with SAP America, Inc. (SAP) to license SAP proprietary R/3 enterprise software. The licensed software includes customer care, finance and accounting, human resources, materials management and service delivery components. The Company's purchase of this software license and related computer hardware is part of its response to changes in the electric utility and energy services industries, as well as changes in the Company's businesses and operations resulting from the acquisition of Resources and the Company's expansion into the energy trading and marketing business. Although it is anticipated that the implementation of the SAP system will have the incidental effect of negating the need to modify many of the Company's computer systems to accommodate the Year 2000 problem, the Company does not deem the costs of the SAP system as directly related to its Year 2000 compliance program. Portions of the SAP system were implemented in December 1998 and March 1999, and it is expected that the final portion of the SAP system will be fully implemented by July 2000. The estimated costs of implementing the SAP system is approximately $182 million, inclusive of internal costs. In 1998, the Company and its subsidiaries spent $108 million of such costs. In 1999, the Company and its subsidiaries expect to spend $59 million with the remaining amounts to be spent in 2000. The estimated Year 2000 project costs do not give effect to any future corporate acquisitions or divestitures made by the Company or its subsidiaries. Risks and Contingency Plans. The major systems which pose the greatest Year 2000 risks for the Company and its subsidiaries if implementation of the Year 2000 compliance program is not successful are the process control systems for energy delivery systems; the time in use, demand and recorder metering system for commercial and industrial customers; the outage analysis system; and the power billing systems. The potential problems related to these systems are temporary electric service interruptions to customers, temporary interruptions in revenue data gathering and temporary poor customer relations resulting from delayed billing. Although the Company does not believe that this scenario will occur, the Company has considerable experience responding to emergency situations, including computer failure. Existing emergency operations, disaster recovery and business continuation plans are being enhanced to ensure preparedness and to mitigate the long-term effect of such a scenario. The North American Electric Reliability Council (NERC) is coordinating electric utility industry contingency planning on a national level. Additional contingency planning is being done at the regional electric reliability council level. Reliant Energy HL&P filed a draft Year 2000 Contingency Plan with NERC and with the Texas Utility Commission in December 1998. The draft plan addresses restoration of electric service and related business processes, and is designed to work in conjunction with the Emergency Operating Plan and with the plans of NERC and ERCOT. 5
6 A final contingency plan is scheduled to be complete by June 30, 1999. In addition, Reliant Energy HL&P will participate in industry preparedness drills, such as the two NERC drills scheduled to be held on April 9, 1999 and September 9, 1999. The existing business continuity disaster recovery and emergency operations plans are being reviewed and enhanced, and where necessary, additional plans will be developed to include mitigation strategies and action plans specifically addressing potential Year 2000 scenarios. The expected completion date for these plans is June 30, 1999. In order to assist in preparing for and mitigating the foregoing scenarios, the Company intends to complete all mission critical Year 2000 remediation and testing activity by the end of the second quarter of 1999. In addition, the Company has initiated Year 2000 communications with significant customers, key vendors, service suppliers and other parties material to the Company's operations and is diligently monitoring the progress of such third parties' Year 2000 projects. The Company expects to meet with mission-critical third parties, including suppliers, in order to ascertain and assess the relative risks of Year-2000-related issues, and to mitigate such risks. Notwithstanding the foregoing, the Company cautions that (i) the nature of testing is such that it cannot comprehensively address all future combinations of dates and events and (ii) it is impossible for the Company to assess with precision or certainty the compliance of third parties with Year 2000 remediation efforts. Due to the speculative and uncertain nature of contingency planning, there can be no assurance that such plans actually will be sufficient to reduce the risk of material impacts on the Company's and its subsidiaries' operations. RISKS OF INTERNATIONAL OPERATIONS The Company's international operations are subject to various risks incidental to investing or operating in emerging market countries. These risks include political risks, such as governmental instability, and 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. The Company's international operations are also highly capital intensive and, thus, dependent to a significant extent on the continued availability of bank financing and other sources of capital on commercially acceptable terms. Impact of Currency Fluctuations on Company Earnings. The Company, through Reliant Energy International's subsidiaries, owns 11.69% of the stock of Light and, through its investment in Light, an 8.753% interest in the stock of Metropolitana Electricidade de Sao Paulo S.A. (Metropolitana). The Company accounts for its investment in Light under the equity method of accounting and records its proportionate share, based on stock ownership, in the net income of Light and its affiliates (including Metropolitana) as part of the Company's consolidated net income. At December 31, 1998, Light and Metropolitana had total borrowings of approximately $3.2 billion denominated in non-local currencies. Because of the devaluation of the Brazilian real subsequent to December 31, 1998, Light and Metropolitana are expected to record a charge to March 31, 1999 earnings that reflects the increase in the liability represented by their non-local currency denominated bank borrowings relative to the Brazilian real. Because the Company uses the Brazilian real as the functional currency in which it reports Light's equity earnings, the resulting decrease in Light's earnings will also be reflected in the Company's consolidated earnings to the extent of the Company's 11.69% ownership interest in Light. At December 31, 1998, one U. S. dollar could be exchanged for 1.21 Brazilian reais. Using the exchange rate of 2.06 Brazilian reais in effect at the end of February, and the average exchange rate in effect since the end of the year, the Company estimates that its share of the after-tax charge to be recorded by Light would be approximately $125 million. This estimate does not reflect the possibility of additional fluctuations in the exchange rate and does not include other non-debt-related impacts of Brazil's currency devaluation on Light's and Metropolitana's future earnings. 6
7 None of Light's or Metropolitana's tariff adjustment mechanisms are directly indexed to the U.S. dollar or other non-local currencies. Each company currently is evaluating various options including regulatory rate relief to mitigate the impact of the devaluation of the Brazilian real. For example, the long-term concession contracts under which Light and Metropolitana operate contain mechanisms for adjusting electricity tariffs to reflect changes in operating costs resulting from inflation. If the devaluation of the Brazilian real results in an increase in the local rate of inflation and if an adjustment to tariff rates is made promptly to reflect such increase, the Company believes that the financial results of Light and Metropolitana should be protected, at least in part, from the effects of devaluation. However, there can be no assurance the implementation of such tariff adjustments will be timely or that the economic impact of the devaluation will be completely reflected in increased inflation rates. Certain of Reliant Energy International's other foreign electric distribution companies have incurred U.S. dollar and other non-local currency indebtedness (approximately $71 million at December 31, 1998). For further analysis of foreign currency fluctuations in the Company's earnings and cash flows, see "Quantitative and Qualitative Disclosures About Market Risk -- Foreign Currency Exchange Rate Risk" in Item 7A of this Form 10-K. Impact of Foreign Currency Devaluation on Project Capital Resources. In the first quarter of 1999, approximately $117 million of Metropolitana's U.S. dollar denominated debt will mature. In the second quarter of 1999, approximately $980 million of Light's and approximately $696 million of Metropolitana's U.S. and non-local currency denominated bank debt will mature. In March 1999, Light refinanced approximately $130 million of its U.S. dollar denominated debt through a local - currency denominated loan. The ability of Light and Metropolitana to repay or refinance their debt obligations at maturity is dependent on many factors, including local and international economic conditions prevailing at the time such debt matures. If economic conditions in the international markets continue to be unsettled or deteriorate, it is possible that Light, Metropolitana and the other foreign electric distribution companies in which the Company holds investments might encounter difficulties in refinancing their debt (both local currency and non-local currency borrowings) on terms and conditions that are commercially acceptable to them and their shareholders. In such circumstances, in lieu of declaring a default or extending the maturity, it is possible that lenders might seek to require, among other things, higher borrowing rates, and additional equity contributions and/or increased levels of credit support from the shareholders of such entities. The availability or terms of refinancing such debt cannot be assured. Currency fluctuation and instability affecting Latin America may also adversely affect Reliant Energy International's ability to refinance its equity investments with debt. In 1998, Reliant Energy International invested $411 million in Colombia and El Salvador. As of January 1999, $100 million of these investments were refinanced with debt. Reliant Energy International intends to refinance approximately $75 million more of such initial investments with debt. ENVIRONMENTAL EXPENDITURES The Company and its subsidiaries, including Resources, are subject to numerous environmental laws and regulations, which require them 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. Clean Air Act Expenditures. The Company expects the majority of capital expenditures associated with environmental matters to be incurred by Electric Operations in connection with new emission limitations under the Federal Clean Air Act (Clean Air Act) for oxides of nitrogen (NOx). The standards applicable to Electric Operations' generating units in the Houston, Texas area will become effective in November 1999. NOx reduction costs incurred by Electric Operations totaled approximately $7 million in 1998. The Company estimates that Electric Operations will incur approximately $8 million in 1999 and $10 million in 2000 for such expenditures. The Texas Natural Resources Conservation Commission (TNRCC) has indicated that additional NOx reduction will be required after 2000; however, since the magnitude and timing of these reductions have not yet been established, it is impossible for the Company to estimate a reasonable range of such expenditures at this time. 7
8 In 1998, the Wholesale Energy spent approximately $100,000 in order to comply with NOx reduction with respect to Southern California generating facilities acquired by Power Generation from Southern California Edison (SCE) in 1998. In 1999, based on existing requirements, the Company projects that it will spend an additional $100,000 on NOx reduction standards with respect to such plants and approximately $1 million on continuous emission monitoring system upgrades for such plants. Site Remediation Expenditures. From time to time the Company and its subsidiaries have received notices from regulatory authorities or others regarding their status as potentially responsible parties in connection with sites found to require remediation due to the presence of environmental contaminants. The Company's identified sites with respect to which it may be claimed to have a remediation liability include several sites for which there is a lack of current available information, including the nature and magnitude of contamination, and the extent, if any, to which the Company may be held responsible for contributing to any costs incurred for remediating these sites. Thus, no reasonable estimate of cleanup costs can now be made for these sites. Based on currently available information, the Company believes that such costs ultimately will not materially affect its 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 such estimates. For information about specific sites that are the subject of remediation claims, see Note 12(h) to the Company's Consolidated Financial Statements and Note 8(g) to Resources' Consolidated Financial Statements, each of which is incorporated herein by reference. Mercury Contamination. Like other natural gas pipelines, Resources' pipeline operations have in the past employed elemental mercury in meters used on its pipelines. Although the mercury has now been removed from the meters, it is possible that small amounts of mercury have been spilled at some of those sites in the course of normal maintenance and replacement operations and that such spills have contaminated the immediate area around the meters with elemental mercury. Such contamination has been found by Resources at some sites in the past, and Resources has conducted remediation at sites found to be contaminated. Although Resources is not aware of additional specific sites, it is possible that other contaminated sites exist and that remediation costs will be incurred for such sites. Although the total amount of such costs cannot be known at this time, based on experience of Resources and others in the natural gas industry to date and on the current regulations regarding remediation of such sites, the Company and Resources believe that the cost of any remediation of such sites will not be material to the Company's or Resources' financial position, results of operations or cash flows. Other. 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 its practice of 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 CONTINGENCIES For a description of certain other legal and regulatory proceedings affecting the Company and its subsidiaries, see Notes 3, 4, 5 and 12 to the Company's Consolidated Financial Statements and Note 8 to Resources' Consolidated Financial Statements, which notes are incorporated herein by reference. 8
9 NEW ACCOUNTING ISSUES In 1998, the Company and Resources adopted SFAS No. 130, "Reporting Comprehensive Income" (SFAS No. 130), SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information" (SFAS No. 131) and SFAS No. 132, "Employers Disclosures about Pensions and Other Postretirement Benefits" (SFAS No. 132). For further discussion of these accounting statements, see Note 15 to the Company's Consolidated Financial Statements and Note 9 to Resources' Consolidated Financial Statements. In 2000, the Company and Resources expect to adopt SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133), which establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities. The Company is in the process of determining the effect of adoption of SFAS No. 133 on its consolidated financial statements. In December 1998, The Emerging Issues Task Force of the Financial Accounting Standards Board reached consensus on Issue 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (EITF Issue 98-10). EITF Issue 98-10 requires energy trading contracts to be recorded at fair value on the balance sheet, with the changes in fair value included in earnings. EITF Issue 98-10 is effective for fiscal years beginning after December 15, 1998. The Company expects to adopt EITF Issue 98-10 in the first quarter of 1999. The Company does not expect the implementation of EITF Issue 98-10 to be material to its consolidated financial statements. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK INTEREST RATE RISK The Company and its subsidiaries have long-term debt, Company/ Resources obligated mandatorily redeemable preferred securities of subsidiary trusts holding solely junior subordinated debentures of the Company/Resources (Trust Securities), securities held in the Company's nuclear decommissioning trust, bank facilities, certain lease obligations and interest rate swaps which subject the Company, Resources and certain of their subsidiaries to the risk of loss associated with movements in market interest rates. At December 31, 1998, the Company and certain of its subsidiaries had issued fixed-rate long-term debt (excluding ACES) and Trust Securities aggregating $5.0 billion in principal amount and having a fair value of $5.2 billion. These instruments are fixed-rate and, therefore, do not expose the Company and its subsidiaries to the risk of earnings loss due to changes in market interest rates (see Notes 8 and 9 to the Company's Consolidated Financial Statements). However, the fair value of these instruments would increase by approximately $260.6 million if interest rates were to decline by 10% from their levels at December 31, 1998. In general, such an increase in fair value would impact earnings and cash flows only if the Company and its subsidiaries were to reacquire all or a portion of these instruments in the open market prior to their maturity. The Company and certain of its subsidiaries' floating-rate obligations aggregated $1.8 billion at December 31, 1998 (see Note 8 to the Company's Consolidated Financial Statements), inclusive of (i) amounts borrowed under short-term and long-term credit facilities of the Company and its subsidiaries (including the issuance of commercial paper supported by such facilities), (ii) borrowings underlying Resources' receivables facility and (iii) amounts subject to a master leasing agreement of Resources under which lease payments vary depending on short-term interest rates. These floating-rate obligations expose the Company, Resources and their subsidiaries to the risk of increased interest and lease expense in the event of increases in short-term interest rates. If the floating rates were to increase by 10% from December 31, 1998 levels, the Company's consolidated interest expense and expense under operating leases would increase by a total of approximately $0.9 million each month in which such increase continued. As discussed in Notes 1(o), 4(c) and 13 to the Company's Consolidated Financial Statements, the Company contributes $14.8 million per year to a trust established to fund the Company's share of the decommissioning costs for the South Texas Project. The securities held by the trust for decommissioning costs had an estimated fair value of $119.1 million as of December 31, 1998, of which approximately 44% were fixed-rate debt securities that subject the Company to risk of loss of fair value with movements in market interest rates. If interest rates were to increase by 10% from their levels at December 31, 1998, the decrease in fair value of the fixed-rate debt securities would not be material to the Company. In addition, the risk of an economic loss is mitigated at this time as a result of the Company's regulated status. Any unrealized gains or losses are accounted for in accordance with SFAS No. 71 as a regulatory asset/liability because the Company believes that its future contributions which are currently recovered through the rate-making process will be adjusted for these gains and losses. 9
10 Certain subsidiaries of the Company have entered into interest rate swaps for the purpose of decreasing the amount of debt subject to interest rate fluctuations. At December 31, 1998, these interest rate swaps had an aggregate notional amount of $75.4 million, which the Company could terminate at a cost of $3.2 million (see Notes 2 and 13 to the Company's Consolidated Financial Statements). An increase of 10% in the December 31, 1998 level of interest rates would not increase the cost of termination of the swaps by a material amount to the Company. Swap termination costs would impact the Company's and its subsidiaries' earnings and cash flows only if all or a portion of the swap instruments were terminated prior to their expiration. As discussed in Note 8(h) to the Company's Consolidated Financial Statements, Resources sold $500 million aggregate principal amount of its 6 3/8% 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 December 31, 1998, the Company could terminate the option at a cost of $30.7 million. A decrease of 10% in the December 31, 1998 level of interest rates would not increase the cost of termination of the option by a material amount to the Company. The change in exposure to loss in earnings and cash flows related to interest rate risk from December 31, 1997 to December 31, 1998 is not material to the Company. EQUITY MARKET RISK The Company holds an investment in TW Preferred which is convertible into Time Warner common stock (TW Common) as described in "Management's Discussion and Analysis of Financial Condition and Results of Operations of the Company -- Certain Factors Affecting Future Earnings of the Company and its Subsidiaries -- Accounting Treatment of ACES" in Item 7 of this Form 10-K. As a result, the Company is exposed to losses in the fair value of this security. For purposes of analyzing market risk in this Item 7A, the Company assumed that the TW Preferred was converted into TW Common. In addition, Resources' investment in the common stock of Itron, Inc. (Itron) exposes the Company and Resources to losses in the fair value of Itron common stock. A 10% decline in the market value per share of TW Common and Itron common stock from the December 31, 1998 levels would result in a loss in fair value of approximately $284.4 million and $1.1 million, respectively. The Company's and its subsidiaries' ability to realize gains and losses related to the TW Preferred and the Itron common stock is limited by the following: (i) the TW Preferred is not publicly traded and its sale is subject to certain limitations and (ii) the market for the common stock of Itron is fairly illiquid. The ACES expose the Company to accounting losses as the Company is required to record in Other Income (Expense) an unrealized accounting loss equal to (i) the aggregate amount of the increase in the market price of TW Common above $27.7922 as applicable to all ACES multiplied by (ii) 0.8264. Prior to the conversion of the TW Preferred into TW Common, such loss would affect earnings. After conversion, such loss would be recognized as an adjustment to common stock equity through a reduction of other comprehensive income. However, there would be an offsetting increase in common stock equity through an increase in accumulated other comprehensive income on the Company's Statements of Consolidated Retained Earnings and Comprehensive Income for the fair value increase in the investment in TW Common. For additional information on the accounting treatment of the ACES and related accounting losses recorded in 1998, see Note 1(n) to the Company's Consolidated Financial Statements. An increase of 15% in the price of the TW Common above its December 31, 1998 market value of $62.062 per share would result in the recognition of an additional unrealized accounting loss (net of tax) of approximately $229.1 million. The Company believes that this additional unrealized loss for the ACES would be more than economically hedged by the unrecorded unrealized gain relating to the increase in the fair value of the TW Common underlying the investment in TW Preferred since the date of its acquisition. For a discussion of the non-cash, unrealized accounting loss recorded in 1998 and 1997 related to the ACES, see "-- Certain Factors Affecting Future Earnings of the Company and its Subsidiaries -- Accounting Treatment of ACES" in Item 7 of this Form 10-K. As discussed above under "-- Interest Rate Risk," the Company contributes to a trust established to fund the Company's share of the decommissioning costs for the South Texas Project which held debt and equity securities as of December 31, 1998. The equity securities expose the Company to losses in fair value. If the market prices of the individual equity securities were to decrease by 10% from their levels at December 31, 1998, the resulting loss in fair value of these securities would not be material to the Company. Currently, the risk of an economic loss is mitigated as a result of the Company's regulated status as discussed above under "--Interest Rate Risk." 10
11 FOREIGN CURRENCY EXCHANGE RATE RISK As further described in "Certain Factors Affecting Future Earnings of the Company and Its Subsidiaries -- Risks of International Operations" in Item 7 of this Form 10-K, the Company, through Reliant Energy International invests in certain foreign operations which to date have been primarily in South America. As of December 31, 1998, the Company's Consolidated Balance Sheets reflected $1.1 billion of foreign investments, a substantial portion of which represent investments accounted for under the equity method. These foreign investments expose the Company to risk of loss in earnings and cash flows due to the fluctuation in foreign currencies relative to the Company's consolidated reporting currency, the U.S. dollar. The Company accounts for adjustments resulting from translation of its investments with functional currencies other than the U.S. dollar as a charge or credit directly to a separate component of stockholders' equity. For further discussion of the accounting for foreign currency adjustments, see Note 1(p) in the Notes to the Company's Consolidated Financial Statements. The cumulative translation loss of $34 million, recorded as of December 31, 1998, will be realized as a loss in earnings and cash flows only upon the disposition of the related investment. The foreign currency loss in earnings and cash flows related to debt obligations held by foreign operations in currencies other than their own functional currencies was not material to the Company as of December 31, 1997. In addition, certain of Reliant Energy International's foreign operations have entered into obligations in currencies other than their own functional currencies which expose the Company to a loss in earnings. In such cases, as the respective investment's functional currency devalues relative to the non-local currencies, the Company will record its proportionate share of its investments' foreign currency transaction losses related to the non-local currency denominated debt. At December 31, 1998, Light and Metropolitana had borrowings of approximately $3.2 billion denominated in non-local currencies. Because of the devaluation of the Brazilian real subsequent to December 31, 1998, Light and Metropolitana are expected to record a charge to earnings for the quarter ended March 31, 1999, primarily related to foreign currency transaction losses on their non-local currency denominated debt. For further discussion and analysis of the possible effect on the Company's Consolidated Financial Statements, see "Certain Factors Affecting Future Earnings of the Company and Its Subsidiaries - -- Risks of International Operations" in Item 7 of this Form 10-K. The company attempts to manage and mitigate this foreign risk by properly balancing the higher cost of financing with local denominated debt against the risk of devaluation of that local currency and including a measure of the risk of devaluation in all its financial plans. In addition, where possible, Reliant Energy International attempts to structure its tariffs and revenue contracts to ensure some measure of adjustment due to changes in inflation and currency exchange rates; however, there can be no assurance that such efforts will compensate for the full effect of currency devaluation, if any. ENERGY COMMODITY PRICE RISK As further described in Note 2 to the Company's Consolidated Financial Statements, certain of the Company's subsidiaries utilize a variety of derivative financial instruments (Derivatives), including swaps and exchange-traded futures and options, as part of the Company's overall hedging strategies and for trading purposes. To reduce the risk from the adverse effect of market fluctuations in the price of electric power, natural gas, crude oil and refined products and related transportation, Resources and certain subsidiaries of the Company and Resources enter into futures transactions, forward contracts, swaps and options (Energy Derivatives) in order to hedge certain commodities in storage, as well as certain expected purchases, sales and transportation of energy commodities (a portion of which are firm commitments at the inception of the hedge). The Company's policies prohibit the use of leveraged financial instruments. In addition, Reliant Energy Services, a subsidiary of Resources, maintains a portfolio of Energy Derivatives to provide price risk management services and for trading purposes (Trading Derivatives). The Company uses value-at-risk and a sensitivity analysis method for assessing the market risk of its derivatives. 11
12 With respect to the Energy Derivatives (other than Trading Derivatives) held by subsidiaries of the Company and Resources as of December 31, 1998, a decrease of 10% in the market prices of natural gas and electric power from year-end levels would decrease the fair value of these instruments by approximately $3 million. As of December 31, 1997, a decrease of 10% in the prices of natural gas would have resulted in a loss of $7 million in fair values of the Energy Derivatives (other than for trading purposes). The above analysis of the Energy Derivatives utilized for hedging purposes does not include the favorable impact that the same hypothetical price movement would have on the Company's and its subsidiaries' physical purchases and sales of natural gas and electric power to which the hedges relate. The portfolio of Energy Derivatives held for hedging purposes is no greater than the notional quantity of the expected or committed transaction volume of physical commodities with equal and opposite commodity price risk for the same time periods. Furthermore, the Energy Derivative portfolio is managed to complement the physical transaction portfolio, reducing overall risks within limits. Therefore, the adverse impact to the fair value of the portfolio of Energy Derivatives held for hedging purposes associated with the hypothetical changes in commodity prices referenced above would be offset by a favorable impact on the underlying hedged physical transactions, assuming (i) the Energy Derivatives are not closed out in advance of their expected term, (ii) the Energy Derivatives continue to function effectively as hedges of the underlying risk and (iii) as applicable, anticipated transactions occur as expected. The disclosure with respect to the Energy Derivatives relies on the assumption that the contracts will exist parallel to the underlying physical transactions. If the underlying transactions or positions are liquidated prior to the maturity of the Energy Derivatives, a loss on the financial instruments may occur, or the options might be worthless as determined by the prevailing market value on their termination or maturity date, whichever comes first. With respect to the Trading Derivatives held by Reliant Energy Services, consisting of natural gas, electric power, crude oil and refined products, physical forwards, swaps, options and exchange-traded futures, this subsidiary is exposed to losses in fair value due to changes in the price and volatility of the underlying derivatives. During the year ended December 31, 1998 and 1997, the highest, lowest and average monthly value-at-risk in the Trading Derivative portfolio was less than $5 million at a 95% confidence level and for a holding period of one business day. The Company uses the variance/covariance method for calculating the value-at-risk and includes the delta approximation for options positions. The Company has established a Corporate Risk Oversight Committee comprised of corporate and business segment officers that oversees all corporate price and credit risk activities, including derivative trading activities discussed above. The committee's duties are to establish the Company's policies and to monitor and ensure compliance with risk management policies and procedures and the trading limits established by the Company's board of directors. 12
13 ITEM 7. MANAGEMENT'S NARRATIVE ANALYSIS OF THE RESULTS OF OPERATIONS OF RELIANT ENERGY RESOURCES CORP. AND CONSOLIDATED SUBSIDIARIES. The following narrative and analysis should be read in combination with the consolidated financial statements and notes (Resources' Consolidated Financial Statements) of Reliant Energy Resources Corp. (formerly NorAm Energy Corp.) (Resources) contained in Item 8 of the Form 10-K of Resources. RELIANT ENERGY RESOURCES CORP. On August 6, 1997 (Acquisition Date), the former parent corporation (Former Parent) of Houston Industries Incorporated d/b/a Reliant Energy, Incorporated (Reliant Energy) merged with and into Reliant Energy, and NorAm Energy Corp. (Former Resources) merged with and into Resources. Effective upon the mergers (collectively, the Merger), each outstanding share of common stock of Former Parent was converted into one share of common stock (including associated preference stock purchase rights) of Reliant Energy, and each outstanding share of common stock of Former Resources was converted into the right to receive $16.3051 cash or 0.74963 shares of common stock of Reliant Energy. The aggregate consideration paid to Former Resources stockholders in connection with the Merger consisted of $1.4 billion in cash and 47.8 million shares of Reliant Energy's common stock valued at approximately $1.0 billion. The overall transaction was valued at $4.0 billion consisting of $2.4 billion for Former Resources' common stock and common stock equivalents and $1.6 billion of Former Resources debt ($1.3 billion of which was long-term debt.) The Merger was recorded under the purchase method of accounting with assets and liabilities of Resources reflected at their estimated fair values as of the Acquisition Date, resulting in a "new basis" of accounting. In Resources' Consolidated Financial Statements, periods which reflect the new basis of accounting are labeled as "Current Resources" and periods which do not reflect the new basis of accounting are labeled as "Former Resources." Former Resources' Statement of Consolidated Income for the seven months ended July 31, 1997 included certain adjustments from August 1, 1997 to the Acquisition Date for pre-merger transactions. Effective January 1, 1998, Resources adopted SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information" (SFAS No. 131). Because Resources is a wholly owned subsidiary of Reliant Energy, Resources' determination of reportable segments considers the strategic operating units under which Reliant Energy manages sales of various products and services to wholesale or retail customers in differing regulatory environments. In accordance with SFAS No. 131, Reliant Energy has identified the following reportable segments: Electric Operations, Natural Gas Distribution, Interstate Pipelines, Wholesale Energy Marketing and Generation (Wholesale Energy), International and Corporate. Of these segments, the following operations are conducted by Resources: Natural Gas Distribution, Interstate Pipelines, Wholesale Energy (which includes the energy trading and marketing operations and natural gas gathering operations of the Wholesale Energy segment but excludes the operations of Reliant Energy Power Generation, Inc.) and Corporate (excluding the impact of ACES). Resources meets the conditions specified in General Instruction I to Form 10-K and is thereby permitted to use the reduced disclosure format for wholly owned subsidiaries of reporting companies specified therein. Accordingly, Resources has omitted from this Combined Annual Report 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 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, Resources 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 Resources between 1998 and 1997. Reference is hereby made to Item 1 (business), Item 2 (properties), Item 3 (legal proceedings), Item 5 (market for 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 Annual Report for additional information regarding Resources required by the reduced disclosure format of General Instruction I to Form 10-K. CONSOLIDATED RESULTS OF OPERATIONS Seasonality and Other Factors. Resources' results of operations are affected by seasonal fluctuations in the demand for and, to a lesser extent, the price of natural gas. Resources' results of operations are also affected by,
14 among other things, the actions of various federal and state governmental authorities having jurisdiction over rates charged by Resources and its subsidiaries, competition in Resources' various business operations, debt service costs and income tax expense. For a discussion of certain other factors that may affect Resources' future earnings see "Management's Discussion and Analysis of Financial Condition and Results of Operations of the Company -- Certain Factors Affecting Future Earnings of the Company and its Subsidiaries - -- Competition -- Other Operations"; "-- Impact of the Year 2000 Issue and Other System Implementation Issues" and "-- Environmental Expenditures -- Mercury Contamination" in Item 7 of Reliant Energy's Form 10-K. Accounting Impact of the Merger. The Merger created a new basis of accounting for Resources, resulting in new carrying values for certain of Resources' assets, liabilities and equity commencing upon the Acquisition Date. Resources' financial statements for periods subsequent to the Acquisition Date are not comparable to prior periods because of the following purchase accounting adjustments: 1. The impact of the amortization of newly-recognized goodwill ($39.4 million); 2. The amortization (to interest expense) of the revaluation of long-term debt ($9.8 million); 3. The removal of the amortization (to operating expense) previously associated with the pension and postretirement obligations ($2.1 million); and 4. The deferred income tax expense associated with these adjustments ($4.9 million). Interest expense and related debt incurred by Reliant Energy to fund the cash portion of the purchase consideration has not been pushed down to Resources and its subsidiaries. Because results of operations and other financial information for periods before and after the Acquisition Date are not comparable, Resources is presenting certain financial data on: (i) an actual basis for Resources for 1998 and 1997 and (ii) a pro forma basis for 1997 as if the Merger had taken place at the beginning of the period. These results do not necessarily reflect the results which would have been obtained if the Merger had actually occurred on the dates indicated or the results that may be expected in the future. The following table sets forth selected financial and operating data on an actual and pro forma basis for the years ended December 31, 1998 and 1997, followed by a discussion of significant variances in period-to-period results: SELECTED FINANCIAL RESULTS: UNAUDITED ACTUAL PRO FORMA (1) --------------------------------------------- -------------- YEAR FIVE MONTHS SEVEN MONTHS YEAR ACTUAL TO ENDED ENDED ENDED ENDED PRO FORMA DECEMBER 31, DECEMBER 31, JULY 31, DECEMBER 31, PERCENTAGE ----------- ----------- ----------- ----------- CHANGE 1998 1997 1997 1997 ----------- ----------- ----------- ----------- (THOUSANDS OF DOLLARS) Operating Revenues .................. $ 6,758,412 $ 2,526,182 $ 3,313,591 $ 5,839,773 16% Operating Expenses .................. 6,448,107 2,434,282 3,141,295 5,597,716 15% Operating Income .................... 310,305 91,900 172,296 242,057 28% Merger Transaction Costs (2) ........ 1,144 17,256 Consolidated ........................ 310,305 90,756 155,040 242,057 28% Interest Expense, Net ............... 111,337 47,490 78,660 112,996 (1%) Distributions on Subsidiary Trust Securities .......................... 632 279 6,317 1,479 (57%) Other (Income) and Deductions ....... (7,318) (2,243) (7,210) (9,453) (23%) Income Tax Expense .................. 111,830 24,383 31,398 71,093 57% Extraordinary (Gain), Less Taxes .... (237) ----------- ----------- ----------- ----------- Net Income ........................ $ 93,824 $ 20,847 $ 46,112 $ 65,942 42% =========== =========== =========== =========== 2
15 - ---------- (1) Pro forma results reflect purchase accounting adjustments as if the Merger had occurred on January 1, 1997. (2) For expenses associated with the completion of the business combination with Reliant Energy, see Note 1(o) to Resources' Consolidated Financial Statements. 1998 Compared to 1997 (Actual). Resources' consolidated net income for 1998 was $94 million compared to consolidated net income of $67 million in 1997. The increase in net income for 1998 as compared to 1997 was due to increased operating income from several business segments as discussed below, partially offset by a decrease in operating income from Resources' Natural Gas Distribution segment due to the effects of warm weather. Also contributing to the increase in net income was a reduction in interest expense due to the refinancing of debt and reduced interest expense due to debt fair value devaluation at the time of the Merger. Resources operating revenues for 1998 were $6.8 billion as compared to $5.8 billion in 1997. The $900 million, or 16% increase was primarily attributable to a $1.4 billion increase in wholesale trading revenue. Wholesale trading revenue increased due to increased power and natural gas trading volumes. The increase in trading revenues was offset by reduced revenues at Resources' Natural Gas Distribution unit of approximately $400 million, principally due to warmer weather. Resources operating expenses for 1998 were $6.4 billion compared to $5.6 billion in 1997. The $800 million, or 16% increase was primarily due to increased natural gas and purchased power expenses associated with increased wholesale trading activities. The increase in operating expenses was offset by decreased natural gas purchases at Resources' Natural Gas Distribution unit because of lower volumes resulting from the warmer weather. Operating income increased in 1998 by $65 million over 1997 due to improved operating results at Interstate Pipelines, Corporate retail operations and Wholesale Energy, partially offset by the unfavorable effects of warm weather on the operations of Natural Gas Distribution. Operating income for 1997 included approximately $18 million of merger-related costs that did not recur in 1998. Improved results at Interstate Pipelines were due to continued cost control initiatives and reduced benefits expenses, as well as the effects of a rate case settlement and a dispute settlement which contributed to the increase in operating income. In addition, margins at Wholesale Energy improved over margins in 1997; however, this effect was partially offset by increased staffing expenses to support increased sales and marketing efforts and an increase in credit reserves. Improved results at Wholesale Energy were also due to the fact that operating income in 1997 for Wholesale Energy was negatively impacted by hedging losses associated with sales under peaking contracts and losses from the sale of natural gas held in storage and unhedged in the first quarter of 1997 totaling $17 million. 1998 (Actual) Compared to 1997 (Pro Forma). Resources' consolidated net income for 1998 was $94 million compared to pro forma net income of $66 million in 1997. The increase in earnings for 1998 as compared to pro forma 1997 was due to increased operating income from several business segments, as discussed below, offset by the effects of unfavorable weather at Resources' Natural Gas Distribution unit. Also contributing to the increase in earnings is a reduction in interest expense due to the refinancing of debt. Resources operating revenues for 1998 were $6.8 billion compared to pro forma operating revenues of $5.8 billion in 1997. The $919 million, or 16% increase was primarily attributable to an $1.4 billion increase in wholesale trading revenue. Wholesale trading revenue increased due to increased electric and natural gas trading volumes. The increase in trading revenues was offset by reduced revenues at Resources' Natural Gas Distribution unit of approximately $400 million, principally due to warmer weather. Resources operating expenses for 1998 were $6.4 billion compared to pro forma operating expense of $5.6 billion in 1997. The $800 million, or 16% increase was primarily due to increased natural gas and purchased power expenses associated with increased wholesale trading activities. The increase in operating expense was offset by decreased natural gas purchases at Resources' Natural Gas Distribution unit because of lower volumes resulting from warmer weather. 3
16 Operating income increased in 1998 by $68 million over pro forma 1997 due to improved operating results at Interstate Pipelines, Corporate retail operations and Wholesale Energy, partially offset by the unfavorable effects of Warm weather on the operations of Natural Gas Distribution. Improved results at Interstate Pipelines are due to continued cost control initiatives and reduced benefits expenses as well as the effects of a rate case settlement and a dispute settlement. In addition, margins at Wholesale Energy improved over margins in 1997, however, this effect was partially offset by increased staffing expenses to support increased sales and marketing efforts and an increase in credit reserves at Wholesale Energy also contributed to the increase in operating income. Operating income in 1997 for Wholesale Energy was negatively impacted by hedging losses associated with sales under peaking contracts and losses from the sale of natural gas held in storage and unhedged in the first quarter of 1997 totaling $17 million. Resources estimates that its total direct cost of resolving the Year 2000 issues will be between $5 and $6 million. This estimate includes approximately $3.4 million spent through year-end 1998. For additional information regarding Year 2000 issues, see "Management's Discussion and Analysis of Financial Condition and Results of Operations of the Company -- Certain Factors Affecting Future Earnings of the Company and its Subsidiaries -- Impact of the Year 2000 Issue and Other System Implementation Issues" in Item 7 of the Form 10-K of Reliant Energy, which has been jointly filed with the Resources Form 10-K. NEW ACCOUNTING ISSUES Reference is made to "Management's Discussion and Analysis of Financial Condition and Results of Operations of the Company -- New Accounting Issues" in Item 7 of the Form 10-K of Reliant Energy, which has been jointly filed with the Resources Form 10-K, for discussion of certain new accounting issues. RESOURCES 10-K NOTES (1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (c) Regulatory Assets and Regulation. In general, Resources' Interstate Pipelines operations are subject to regulation by the Federal Energy Regulatory Commission, while its Natural Gas Distribution operations are subject to regulation at the state or municipal level. Historically, all of Resources' rate-regulated businesses have followed the accounting guidance contained in Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71). Resources discontinued application of SFAS No. 71 to REGT in 1992. As a result of the continued application of SFAS No. 71 to MRT and the Natural Gas Distribution operations, Resources' financial statements contain assets and liabilities which would not be recognized by unregulated entities. At December 31, 1998 Resources' Consolidated Balance Sheet included approximately $12 million in regulatory assets recorded as deferred debits. These assets represent probable future revenue to Resources associated with certain incurred costs as these costs are recovered through the rate making process. These costs are being recovered through rates over varying periods up to 40 years. (2) DERIVATIVE FINANCIAL INSTRUMENTS (a) Price Risk Management and Trading Activities. Resources, through its subsidiary, Reliant Energy Services, offers energy price risk management services primarily in the natural gas, electric and crude oil and refined product industries. Reliant Energy Services provides these services by utilizing a variety of derivative financial instruments, including fixed and variable-priced physical forward contracts, fixed-price swap agreements, variable-price swap agreements, exchange-traded energy futures and option contracts, and swaps and options traded in the over-the-counter financial markets (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. Prior to 1998 Reliant Energy Services applied hedge accounting to certain physical commodity activities that qualified for hedge accounting. In 1998, Reliant Energy Services adopted mark-to-market accounting for all of its price risk management and trading activities. Accordingly, as of such date, such Trading Derivatives are recorded at fair value with realized and unrealized gains (losses) recorded as a component of operating revenues in Resources' Consolidated Statements of Income. The recognized, unrealized balance is recorded as price risk management assets/liabilities and deferred debits/credits on Resources' Consolidated Balance Sheets (See Note 1(r)). The notional quantities, maximum terms and the estimated fair value of Trading Derivatives at December 31, 1998 are presented below (volumes in billions of British thermal units equivalent (BBtue) and dollars in millions): VOLUME-FIXED VOLUME-FIXED PRICE MAXIMUM 1998 PRICE PAYOR RECEIVER TERM (YEARS) ---- ----------- -------- ------------ Natural gas.................................................. 937,264 977,293 9 Electricity.................................................. 122,950 124,878 3 Crude oil and products....................................... 205,499 204,223 3 4
17 AVERAGE FAIR FAIR VALUE VALUE (a) --------------------------- --------------------------- 1998 ASSETS LIABILITIES ASSETS LIABILITIES ---- ------ ----------- ------ ----------- Natural gas.............................................. $ 224 $ 213 $ 124 $ 108 Electricity.............................................. 34 33 186 186 Crude oil and products................................... 29 23 21 17 --------- --------- --------- --------- $ 287 $ 269 $ 331 $ 311 The notional quantities, maximum terms and the estimated fair value of derivative financial instruments at December 31, 1997 are presented below (volumes in BBtue and dollars in millions): VOLUME-FIXED VOLUME-FIXED PRICE MAXIMUM 1997 PRICE PAYOR RECEIVER TERM (YEARS) ---- Natural gas.................................................. 85,701 64,890 4 Electricity.................................................. 40,511 42,976 1 AVERAGE FAIR FAIR VALUE VALUE (A) --------------------------- --------------------------- 1997 ASSETS LIABILITIES ASSETS LIABILITIES ---- ------ ----------- ------ ----------- Natural gas.............................................. $ 46 $ 39 $ 56 $ 48 Electricity.............................................. 6 6 3 2 ------- ------- ------- ------- $ 52 $ 45 $ 59 $ 50 - --------- (a) Computed using the ending balance of each month. In addition to the fixed-price notional volumes above, Reliant Energy Services also has variable-priced agreements, as discussed above, totaling 1,702,977 and 101,465 BBtue as of December 31, 1998 and 1997, respectively. Notional amounts reflect the volume of transactions but do not represent the amounts exchanged by the parties to the financial instruments. Accordingly, notional amounts do not accurately measure Resources' exposure to market or credit risks. All of the fair values shown in the table above at December 31, 1998 and substantially all at December 31, 1997 have been recognized in income. The fair value as of December 31, 1998 and 1997 was estimated using quoted prices where available and considering the liquidity of the market for the Trading Derivatives. The prices are subject to significant changes based on changing market conditions. At December 31, 1998, $22 million of the fair value of the assets and $41 million of the fair value of the liabilities are recorded as long-term in deferred debits and deferred credits, respectively, on Resources' Consolidated Balance Sheets. 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 Resources' 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 Resources', and its subsidiaries' 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 Reliant Energy Services as of December 31, 1998. 5
18 INVESTMENT GRADE (1) TOTAL ----------------- ----------------- (THOUSANDS OF DOLLARS) Energy marketers.......................................................... $ 102,458 $ 123,779 Financial institutions.................................................... 61,572 61,572 Gas and electric utilities................................................ 46,880 48,015 Oil and gas producers..................................................... 7,197 8,323 Industrials............................................................... 1,807 3,233 Independent power producers............................................... 1,452 1,463 Others.................................................................... 45,421 46,696 ------------- ------------- Total................................................................ $ 266,787 293,081 ============= Credit and other reserves................................................. (6,464) ------------- Energy price risk management assets(2).................................... $ 286,617 ============= - --------- (1) "Investment Grade" is primarily determined using publicly available credit ratings along with the consideration of credit support (e.g., parent company guarantees) and collateral, which encompass cash and standby letters of credit. (2) Resources has credit risk exposure with respect to two investment grade customers, each of which represents an amount greater than 5% but less than 10% of Price Risk Management Assets. (b) Non-Trading Activities. To reduce the risk from market fluctuations in the price of electric power, natural gas and related transportation, Resources and certain of its subsidiaries enter into futures transactions, swaps and options (Energy Derivatives) in order to hedge certain natural gas in storage, as well as certain expected purchases, sales and transportation of natural gas and electric power (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, although usage to date for this purpose has not been material. Resources applies hedge accounting with respect to its derivative financial instruments. Certain subsidiaries of Resources also utilize interest rate derivatives (principally interest rate swaps) in order to adjust the portion of its overall borrowings which are subject to interest rate risk and also utilize such derivatives to effectively fix the interest rate on debt expected to be issued for refunding purposes. For transactions involving either Energy Derivatives or interest rate derivatives, hedge accounting is applied only if the derivative (i) reduces the price risk of the underlying hedged item and (ii) is designated as a hedge at its inception. Additionally, the derivatives must be expected to result in financial impacts which 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. In the case of interest rate swaps associated with existing obligations, cash flows and expenses associated with the interest rate derivative transactions are matched with the cash flows and interest expense of the obligation being hedged, resulting in an adjustment to the effective interest rate. When interest rate swaps are utilized to effectively fix the interest rate for an anticipated debt issuance, changes in the market value of the interest rate derivatives are deferred and recognized as an adjustment to the effective interest rate on the newly issued debt. Unrealized changes in the market value of Energy Derivatives utilized as hedges are not generally recognized in Resources' Consolidated Statements of Income until the underlying hedged transaction occurs. Once it becomes 6
19 probable that an anticipated transaction will not occur, deferred gains and losses are recognized. In general, the financial impact of transactions involving these Energy Derivatives is included in Resources' Statements of Consolidated Income under the captions (i) fuel expenses, in the case of natural gas transactions and (ii) purchased power, in the case of electric power transactions. Cash flows resulting from these transactions in Energy Derivatives are included in Resources' Statements of Consolidated Cash Flows in the same category as the item being hedged. At December 31, 1998, subsidiaries of Resources were fixed-price payors and fixed-price receivers in Energy Derivatives covering 42,498 billion British thermal units (BBtu) and 3,930 BBtu of natural gas, respectively. At December 31, 1997, subsidiaries of Resources were fixed-price payors and fixed-price receivers in Energy Derivatives covering 38,754 BBtu and 7,647 BBtu of natural gas, respectively. Also, at December 31, 1998 and 1997, subsidiaries of Resources were parties to variable-priced Energy Derivatives totaling 21,437 BBtu and 3,630 BBtu of natural gas, respectively. The weighted average maturity of these instruments is less than one year. The notional amount is intended to be indicative of Resources' and its subsidiaries' level of activity in such derivatives, although 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 below. Under such 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 in the trading portfolio at any time in response to changing market conditions, market liquidity and Resources' 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 Resources' and its subsidiaries' risk management activities. Credit risk relates to the risk of loss resulting from non-performance of contractual obligations by a counterparty. While as yet Resources and its subsidiaries have experienced only minor losses due to the credit risk associated with these arrangements, Resources 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 such contract. In order to minimize this risk, Resources and/or its subsidiaries, as the case may be, enter into such contracts primarily with those counterparties with a minimum Standard & Poor's or Moody's rating of BBB- or Baa3, respectively. For long-term arrangements, Resources and its subsidiaries periodically review the financial condition of such firms in addition to monitoring the effectiveness of these financial contracts in achieving Resources' objectives. Should the counterparties to these arrangements fail to perform, Resources would seek to compel performance at law or otherwise or obtain compensatory damages in lieu thereof. Resources might be forced to acquire alternative hedging arrangements or be required to honor the underlying commitment at then-current market prices. In such event, Resources might incur additional loss to the extent of amounts, if any, already paid to the counterparties. In view of its criteria for selecting counterparties, its process for monitoring the financial strength of these counterparties and its experience to date in successfully completing these transactions, Resources believes that the risk of incurring a significant financial statement loss due to the non-performance of counterparties to these transactions is minimal. Resources' policies prohibit the use of leveraged financial instruments. (4) LONG-TERM AND SHORT-TERM FINANCING (a) Short-term Financing. In 1998, Resources met its short-term financing needs primarily through a bank facility, bank lines of credit, a receivables facility and the issuance of commercial paper. In March 1998, Resources replaced its $400 million revolving credit facility with a five-year $350 million revolving credit facility (Resources Credit Facility). Borrowings under the Resources Credit Facility are unsecured and bear interest at a rate based upon either the London interbank offered rate (LIBOR) plus a margin, a base rate or a rate determined through a bidding process. The Resources Credit Facility is used to support Resources' issuance of up to $350 million of commercial paper. There were no commercial paper borrowings and no loans outstanding under the Resources Credit Facility at December 31, 1998. Borrowings under Resources' prior credit facility at December 31, 1997 were $340 million. In addition, Resources had $50 million of outstanding loans under uncommitted lines of credit at December 31, 1997 having a weighted average interest rate of 6.82%. 7
20 A $65 million committed bank facility under which Resources obtained letters of credit and all of Resources' uncommitted lines of credit were terminated in 1998. Subsequent to the December 1998 termination, Resources obtained letters of credit under an uncommitted line. Resources expects to amend the Resources Credit Facility in March 1999 to add a $65 million letter of credit subfacility. Under a trade receivables facility (Receivables Facility) which expires in August 1999, Resources sells, with limited recourse, an undivided interest (limited to a maximum of $300 million) in a designated pool of accounts receivable. The amount of receivables sold and uncollected was $300 million at December 31, 1998 and at December 31, 1997. The weighted average interest rate was approximately 5.54% at December 31, 1998 and 5.65% at December 31, 1997. Certain of Resources' remaining receivables serve as collateral for receivables sold and represent the maximum exposure to Resources should all receivables sold prove ultimately uncollectible. Resources has retained servicing responsibility under the Receivables Facility for which it is paid a servicing fee. Pursuant to SFAS No. 125, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities", Resources accounts for amounts transferred pursuant to the Receivables Facility as collateralized borrowings. As a result, these receivables are recorded as assets on Resources' Consolidated Balance Sheet and amounts received by Resources pursuant to this facility are recorded as a current liability under the caption "Receivables Facility." (b) Long-term Debt. Resources' consolidated long-term debt outstanding, which is summarized in the following table, is noncallable and without sinking fund requirements except as noted. Carrying amounts and amounts due in one year reflect $33.2 million and $3.4 million, respectively, for fair value adjustments recorded in connection with the Merger. DECEMBER 31, 1998 -------------------------------------------------------- CARRYING AMOUNTS ---------------------------- EFFECTIVE PRINCIPAL NON-CURRENT CURRENT RATE AMOUNT PORTION PORTION ---- ------ ------- ------- (MILLIONS OF DOLLARS) Medium-term notes, Series A and B due through 2001, weighted average rate of 8.96% at December 31, 1998................................... 6.4% $ 165.6 $ 177.6 8.875% Series due 1999................................. 6.3% 200.0 $ 202.7 7.5% Series due 2000................................... 6.4% 200.0 203.1 8.9% Series due 2006................................... 6.8% 145.1 163.4 6% Convertible Subordinated Debentures due 2012........ 6.5% 109.6 104.6 10% Series due 2019(1)................................. 8.8% 42.8 47.6 6 1/2% Series due 2008................................. 6.5% 300.0 300.0 6 %% Series due 2003................................... 6.4% 517.0 517.0 Other.................................................. 0.7 ---------- ---------- ---------- $ 1,680.1 $ 1,513.3 $ 203.4 ========== ========== ========== DECEMBER 31, 1997 -------------------------------------------------------- CARRYING AMOUNTS ---------------------------- EFFECTIVE PRINCIPAL NON-CURRENT CURRENT RATE AMOUNT PORTION PORTION ---- ------ ------- ------- (MILLIONS OF DOLLARS) Medium-term notes, Series A and B due through 2001, weighted average rate of 8.90% at December 31, 1997............................ 6.4% $ 241.6 $ 183.8 $ 78.8 Bank Term Loan due 1998................................ 6.2% 150.0 153.3 8.875% Series due 1999................................. 6.3% 200.0 207.2 7.5% Series due 2000................................... 6.4% 200.0 205.0 8.9% Series due 2006................................... 6.8% 145.1 165.1 6% Convertible Subordinated Debentures due 2012........ 6.5% 116.3 107.2 10% Series due 2019(1)................................. 8.8% 42.8 47.8 Other.................................................. 4.1% 0.6 0.6 ---------- ---------- ----------- $ 1,096.4 $ 916.7 $ 232.1 ========== ========== =========== - ---------- (1) In the fourth quarter of 1997 Resources purchased $101.4 million aggregate principal amount of its 10% Debentures due 2019 at an average price of 111.98% plus accrued interest. Because Resources' debt was stated at fair market value as of the Acquisition Date, the loss on the reacquisition of these debentures was not material. 8
21 Consolidated maturities of long-term debt and sinking fund requirements for Resources are approximately $207 million for 1999, $228 million in 2000, $151 million in 2001, $7 million in 2002 and $7 million in 2003. Resources' retirements and reacquisitions of long-term debt are summarized in the following table. In cases where premiums were paid or discounts were realized in association with these reacquisitions and retirements, such amounts are reported in Resources' Statements of Consolidated Income as "Extraordinary gain (loss) on early retirement of debt, less taxes" and are net of taxes of $0.1 million and ($2.5) million in 1997 and 1996, respectively. For retirements and reacquisitions after the Acquisition Date, gains or losses on early retirement are immaterial since the carrying amounts reflect the fair value adjustments described above. YEAR ENDED DECEMBER 31, ------------------------------------ 1998(1) 1997(1) ------- ------- Reacquisition of 10% Debentures due 2019................................. $ 101.4 Reacquisition of 6% Convertible Subordinated Debentures due 2012(2)...... $ 6.7 5.8 Retirement, at maturity, of Medium Term Notes(3)......................... 76.0 52.0 Retirement of Bank Term Loan due 2000.................................... 150.0 Retirement of 9.875% Notes due 1997...................................... 225.0 Net (gain) loss on reacquisition of debt, less taxes..................... (0.2) -------------- -------------- $ 232.7 $ 384.0 ============== ============== - ---------- (1) Excludes the conversion of 6% Convertible Subordinated Debentures due 2012 in the amount of approximately $0 and $.7 million at December 31, 1998 and December 31, 1997, respectively. (2) These reacquired debentures may be credited against sinking fund requirements. (3) Weighted average interest rate of 8.75% and 9.25% in 1998 and 1997, respectively. In June 1996, Resources exercised its right to exchange the $130 million principal amount of its $3.00 Convertible Exchangeable Preferred Stock, Series A for its 6% Convertible Subordinated Debentures due 2012 (Subordinated Debentures). The holders of the Subordinated Debentures receive interest quarterly and have the right at any time on or before the maturity date thereof to convert each Subordinated Debenture into 0.65 shares of common stock of Reliant Energy and $14.24 in cash. The Subordinated Debentures are callable beginning in 1999 at redemption prices beginning at 105.0% and declining to par in November 2009. Resources is required to make annual sinking fund payments of $6.5 million on the Subordinated Debentures which began on March 15, 1997 and will continue on each succeeding March 15 up to and including March 15, 2011. Resources (i) may credit against the sinking fund requirements any Subordinated Debentures redeemed by Resources and Subordinated Debentures which have been converted at the option of the holder and (ii) may deliver purchased Subordinated Debentures in satisfaction of the sinking fund requirements. Resources satisfied its 1998 sinking fund requirement of $6.5 million by delivering Subordinated Debentures purchased in 1996 and 1997. In February 1998, Resources issued $300 million principal amount of 6.5% debentures due February 1, 2008. The proceeds from the sale of the debentures were used to repay short-term indebtedness of Resources, including the indebtedness incurred in connection with the 1997 purchase of $101 million aggregate principal amount of its 10% debentures and the repayment of $53 million aggregate principal amount of Resources debt that matured in December 1997 and January 1998. In connection with the issuance of the 6.5% debentures, Resources received approximately $1 million upon unwinding a $300 million treasury rate lock agreement, which was tied to the interest rate on 10-year treasury bonds. The rate lock agreement was executed in January 1998, and proceeds from the unwind will be amortized over the 10 year life of Resources' 6.5% debentures. In November 1998, Resources sold $500 million aggregate principal amount of its 6 3/8% Term Enhanced ReMarketable Securities (TERM Notes). Included within the TERM Notes is an embedded option sold to an investment bank which gives the investment bank the right to remarket the TERM Notes in 2003 if it chooses to exercise the option. The net proceeds of $514 million from the offering of the TERM Notes were used for general corporate purposes, including the repayment of (i) $178.5 million of Resources' outstanding commercial paper and (ii) a $150 million term loan of Resources that matured on November 13, 1998. The TERM Notes are unsecured obligations of Resources which bear interest at an annual rate of 6 3/8% through November 1, 2003. On November 1, 2003, the holders of the TERM Notes are required to tender their notes at 100% of their principal amount. The portion of the proceeds attributable to the option premium will be amortized over the stated term of the securities. If the option is not exercised, Resources will repurchase the TERM Notes at 100% of their principal amount on November 1, 2003. If the option is exercised, the TERM Notes will be remarketed on a date, selected by Resources, within the 52-week period beginning November 1, 2003. During such period and prior to remarketing, the TERM Notes will bear interest at rates, adjusted weekly, based on an index selected by Resources. If the TERM Notes are 9
22 remarketed, the final maturity date of the TERM Notes will be November 1, 2013, subject to adjustment, and the effective interest rate on the remarketed TERM Notes will be 5.66% plus Resources' applicable credit spread at the time of such remarketing. (b) Restrictions on Debt. Under the provisions of the Resources Credit Facility, Resources' total debt is limited to 55% of its total capitalization. This provision did not significantly restrict Resources' ability to issue debt or to pay dividends in 1998. At December 31, 1998, Resources' total debt to total capitalization equaled 40%. (5) TRUST SECURITIES In June 1996, a Delaware statutory business trust (Resources Trust) established by Resources issued in a public offering $172.5 million of convertible preferred securities and sold approximately $5.3 million of Resources Trust common stock (106,720 shares, representing 100% of the Resources Trust's common equity) to Resources. The convertible preferred securities have a distribution rate of 6.25% payable quarterly in arrears, a stated liquidation amount of $50 per convertible preferred security and must be redeemed by 2026. The proceeds from the sale of the preferred and common securities were used by Resources Trust to purchase $177.8 million of 6.25% Convertible Junior Subordinated Debentures from Resources having an interest rate corresponding to the distribution rate of the convertible preferred securities and a maturity date corresponding to the mandatory redemption date of the convertible preferred securities. Under existing law, interest payments made by Resources for the junior subordinated debentures are deductible for federal income tax purposes. Resources has the right at any time and from time to time to defer interest payments on the junior subordinated debentures for successive periods not to exceed 20 consecutive quarters for each such extension period. In such case, (1) quarterly distributions on the junior subordinated debentures would also be deferred and (2) Resources has agreed to not declare or pay any dividend on any common or preferred stock, except in certain instances. The Resources Trust is accounted for as a wholly owned consolidated subsidiary of Resources. The junior subordinated debentures are the sole assets of the Resources Trust. Resources has fully and unconditionally guaranteed, on a subordinated basis, the Resources Trust's obligations, including the payment of distributions and all other payments, with respect to the convertible preferred securities. The convertible preferred securities are mandatorily redeemable upon the repayment of the related junior subordinated debentures at their stated maturity or earlier redemption. Each convertible preferred security is convertible at the option of the holder into $33.62 of cash and 1.55 shares of Reliant Energy common stock. During 1998, convertible preferred securities aggregating $15.5 million were converted, leaving $0.9 million liquidation amount of convertible preferred securities outstanding at December 31, 1998. (8) COMMITMENTS AND CONTINGENCIES (a) Lease Commitments. The following table sets forth certain information concerning Resources' obligations under operating leases: Minimum Lease Commitments at December 31, 1998(1) (millions of dollars) 1999........................................................................ $ 19 2000........................................................................ 15 2001........................................................................ 14 2002........................................................................ 10 2003........................................................................ 9 2004 and beyond............................................................. 61 ---------- Total......................................................................... $ 128 ========== - ---------- (1) Principally consisting of rental agreements for building space and data processing equipment and vehicles (including major work equipment); approximately $16 million represents rental agreements with Reliant Energy. 10
23 Resources 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, 1998, the unamortized value of equipment covered by the master leasing agreement was $26.9 million. Resources does not expect to lease additional property under this lease agreement. Total rental expense for all leases was $25.0 million, $24.0 million and $33.4 million in 1998, 1997 and 1996, respectively. (b) Letters of Credit. At December 31, 1998, Resources had letters of credit incidental to its ordinary business operations totaling approximately $30 million under which Resources is obligated to reimburse drawings, if any. (c) Indemnity Provisions. At December 31, 1998, Resources had a $5.8 million accounting reserve on its Consolidated Balance Sheets in "Estimated obligations under indemnification provisions of sale agreements" for possible indemnity claims asserted in connection with its disposition of former subsidiaries or divisions, including the sale of (i) Louisiana Intrastate Gas Corporation, a former subsidiary engaged in the intrastate pipeline and liquids extraction business (1992); (ii) Arkla Exploration Company, a former subsidiary engaged in oil and gas exploration and production activities (June 1991); and (iii) Dyco Petroleum Company, a former subsidiary engaged in oil and gas exploration and production (1991). (d) Sale of Receivables. Certain of Resources' receivables are collateral for receivables which have been sold pursuant to the terms of the Receivables Facility. For information regarding these receivables, see Note 4(a). (e) Gas Purchase Claims. In conjunction with settlements of "take-or-pay" claims, Resources has prepaid for certain volumes of gas, which prepayments have been recorded at their net realizable value and, to the extent that Resources is unable to realize at least the carrying amount as the gas is delivered and sold, Resources' earnings will be reduced, although such reduction is not expected to be material. In addition to these prepayments, Resources is a party to a number of agreements which require it to either purchase or sell gas in the future at prices which may differ from then prevailing market prices or which require it to deliver gas at a point other than the expected receipt point for volumes to be purchased. To the extent that Resources expects that these commitments will result in losses over the contract term, Resources has established reserves equal to such expected losses. As of December 31, 1998, these reserves were not material. (f) Transportation Agreement. Resources had an agreement (ANR Agreement) with ANR Pipeline Company (ANR) which contemplated that Resources would transfer to ANR an interest in certain of Resources' pipeline and related assets. The interest represented capacity of 250 Mmcf/day. Under the ANR Agreement, an ANR affiliate advanced $125 million to Resources. Subsequently, the parties restructured the ANR Agreement and Resources refunded in 1995 and 1993, respectively, $50 million and $34 million to ANR or an affiliate. Resources recorded $41 million as a liability reflecting ANR's or its affiliates' use of 130 Mmcf/ day of capacity in certain of Resources' 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 remaining balance. (g) Environmental Matters. To the extent that potential environmental remediation costs are quantified within a range, Resources establishes reserves equal to the most likely level of costs within the range and adjusts such accruals as better information becomes available. In determining the amount of the liability, future costs are not discounted to their present value and the liability is not offset by expected insurance recoveries. If justified by circumstances within Resources' business subject to SFAS No. 71, corresponding regulatory assets are recorded in anticipation of recovery through the rate making process. Manufactured Gas Plant Sites. Resources and its predecessors operated a manufactured gas plant (MGP) adjacent to the Mississippi River in Minnesota formerly known as Minneapolis Gas Works (FMGW) until 1960. Resources has substantially completed remediation of the main site other than ongoing water monitoring and treatment. There are six other former MGP sites in the Minnesota service territory. Remediation has been completed on one site. Of the remaining five sites, Resources believes that two were neither owned nor operated by Resources; two were owned by Resources at one time but were operated by others and are currently owned by others; and one site was previously owned and operated by Resources but is currently owned by others. Resources believes it has no liability with respect to the sites it neither owned nor operated. At December 31, 1998, Resources had estimated a range of $12 million to $70 million for possible remediation of the Minnesota sites. The low end of the range was determined based on only those sites presently owned or known to have been operated by Resources, assuming use of Resources' proposed remediation methods. The upper end of the range was determined based on the sites once owned by Resources, whether or not operated by Resources. The cost estimates of the FMGW 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. 11
24 At December 31, 1998 and 1997, Resources had recorded accruals of $5.4 million and $3.3 million, respectively (with a maximum estimated exposure of approximately $8 million and $18 million at December 31, 1998 and 1997, respectively) and an offsetting regulatory asset for environmental matters in connection with a former fire training facility, a landfill and an underground gas storage facility for which future remediation may be required. This accrual is in addition to the accrual for MGP sites as previously discussed. In its 1995 rate case, Reliant Energy Minnegasco was allowed to recover approximately $7 million annually for remediation costs. In 1998, Reliant Energy Minnegasco received approval to reduce its annual recovery rate to zero. Remediation costs are subject to a true-up mechanism whereby any over or under recovered amounts, net of certain insurance recoveries, plus carrying charges, would be deferred for recovery or refund in the next rate case. At December 31, 1998 and 1997, Reliant Energy Minnegasco had over recovered $13 million and $1.8 million, respectively. At December 31, 1998 and 1997, Minnegasco had recorded a liability of $20.7 million and $21.7 million, respectively, to cover the cost of future remediation. In addition, at December 31, 1998, Minnegasco had receivables from insurance settlements of $.6 million. These insurance settlements will be collected in 1999. Minnegasco expects that approximately 43% of its accrual as of December 31, 1998 will be expended within the next five years. The remainder will be expended on an ongoing basis for an estimated 40 years. In accordance with the provisions of SFAS No. 71, a regulatory asset has been recorded equal to the liability accrued. Minnegasco is continuing to pursue recovery of at least a portion of these costs from insurers. Minnegasco believes the difference between any cash expenditures for these costs and the amount recovered in rates during any year will not be material to Resources' overall cash requirements, results of operations or cash flows. Issues relating to the identification and remediation of MGPs are common in the natural gas distribution industry. Resources has received notices from the United States Environmental Protection Agency (EPA) and others regarding its status as a potentially responsible party (PRP) for other sites. Based on current information, Resources has not been able to quantify a range of environmental expenditures for potential remediation expenditures with respect to other MGP sites. Mercury Contamination. Like other natural gas pipelines, Resources' pipeline operations have in the past employed elemental mercury in meters used on its pipelines. Although the mercury has now been removed from the meters, it is possible that small amounts of mercury have been spilled at some of those sites in the course of normal maintenance and replacement operations and that such spills have contaminated the immediate area around the meters with elemental mercury. Such contamination has been found by Resources at some sites in the past, and Resources has conducted remediation at sites found to be contaminated. Although Resources is not aware of additional specific sites, it is possible that other contaminated sites exist and that remediation costs will be incurred for such sites. Although the total amount of such costs cannot be known at this time, based on experience by Resources and others in the natural gas industry to date and on the current regulations regarding remediation of such sites, Resources believes that the cost of any remediation of such sites will not be material to Resources' financial position, results of operation or cash flows. Potentially Responsible Party Notifications. From time to time Resources and its subsidiaries have been notified that they are PRP's with respect to properties which environmental authorities have determined warrant remediation under state or federal environmental laws and regulations. In October 1994 the EPA issued such a notice with respect to the South 8th Street landfill site in West Memphis, Arkansas, and in December 1995, the Louisiana Department of Environmental Quality advised that one of Resources' subsidiaries had been identified as a PRP with respect to a hazardous waste site in Shreveport, Louisiana. In 1998, MRT received a notice of potential liability from the EPA regarding MRT's PRP status with respect to the Gurley Pit Superfund Site. The notice stated that MRT is a PRP for the response costs at this site because MRT allegedly generated materials that were disposed of at the site. MRT subsequently notified the EPA that it does not believe that it has liability because it did not have operations in the state from which the material was allegedly hauled. In December 1998, MRT learned that the South 8th Street Superfund Site Group and the EPA reached a tentative settlement regarding the South 8th Street and Gurley Pit Superfund Sites. Considering the information currently known about such sites and the involvement of Resources or its subsidiaries in activities at these sites, Resources does not believe that these matters will have a material adverse effect on Resources' financial position, results of operation or cash flows. Resources 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 effect on Resources' Consolidated Financial Statements, if any, from the disposition of these matters will not be material. 12
25 RESOURCES FIRST QUARTER 10-Q NOTES (9) LONG-TERM DEBT AND SHORT-TERM FINANCING (b) Resources. As of March 31, 1999, Resources had outstanding $2.0 billion of long-term and short-term debt. Consolidated maturities of long-term debt and sinking fund requirements for Resources are approximately $200 million for the remainder of 1999. In the first quarter of 1999, Resources purchased $6.04 million of its 6% convertible subordinated debentures due 2012 at an average purchase price of 98.3% of the aggregate principal amount, plus accrued interest. Resources plans to use the purchased debentures to satisfy March 2000 and 2001 sinking fund requirements of the 6% convertible subordinated debentures. For more information regarding Resources' financing arrangements, lease commitments and letters of credit, see Notes 4 and 8 (a) and (b) of the Resources 10-K Notes. For information regarding Resources' $300 million receivables facility, see Note 4(a) of the Resources 10-K Notes. At March 31, 1999, Resources had sold $300 million of receivables under the facility. The weighted average interest rate was 4.88%. For information regarding Resources' $350 million revolving credit facility, see Note 4(a) of the Resources 10-K Notes. In March 1999, this facility was amended to include a $65 million sub-facility under which letters of credit may be obtained. At March 31, 1999, there were no commercial paper borrowings or loans outstanding under the facility and letters of credit issued under the facility aggregated $14.6 million. 13