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 JUNE 30, 2001 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ______________ to _______________ ---------- Commission file number 1-3187 RELIANT ENERGY, INCORPORATED (Exact name of registrant as specified in its charter)
2 THIS COMBINED QUARTERLY REPORT ON FORM 10-Q IS SEPARATELY FILED BY RELIANT ENERGY, INCORPORATED (RELIANT ENERGY) AND RELIANT ENERGY RESOURCES CORP. (RERC CORP). INFORMATION CONTAINED HEREIN RELATING TO RERC CORP. IS FILED BY RELIANT ENERGY AND SEPARATELY BY RERC CORP. ON ITS OWN BEHALF. RERC CORP. MAKES NO REPRESENTATION AS TO INFORMATION RELATING TO RELIANT ENERGY OR ANY OTHER AFFILIATE OR SUBSIDIARY OF RELIANT ENERGY (EXCEPT AS IT MAY RELATE TO RERC CORP. AND ITS SUBSIDIARIES). RELIANT ENERGY, INCORPORATED AND RELIANT ENERGY RESOURCES CORP. QUARTERLY REPORT ON FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 2001 TABLE OF CONTENTS
3 PART I. FINANCIAL INFORMATION RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED INCOME (THOUSANDS OF DOLLARS, EXCEPT PER SHARE AMOUNTS) (UNAUDITED)
4 RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (THOUSANDS OF DOLLARS) (UNAUDITED) ASSETS
5 RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS - (CONTINUED) (THOUSANDS OF DOLLARS) (UNAUDITED) LIABILITIES AND STOCKHOLDERS' EQUITY
6 RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED CASH FLOWS (THOUSANDS OF DOLLARS) (UNAUDITED)
7 RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (1) BASIS OF PRESENTATION Included in this combined Quarterly Report on Form 10-Q (Form 10-Q) for Reliant Energy, Incorporated (Reliant Energy), together with its subsidiaries (the Company), and for Reliant Energy Resources Corp. (RERC Corp.) and its subsidiaries (collectively, RERC) are Reliant Energy's and RERC Corp.'s consolidated interim financial statements and notes (Interim Financial Statements) including these companies' wholly owned and majority owned subsidiaries. The Interim Financial Statements are unaudited, omit certain financial statement disclosures and should be read with the combined Annual Report on Form 10-K of Reliant Energy (Reliant Energy Form 10-K) and RERC Corp. (RERC Corp. Form 10-K) for the year ended December 31, 2000 and the Quarterly Report on Form 10-Q of Reliant Energy (Reliant Energy First Quarter 10-Q) and RERC Corp. (RERC Corp. First Quarter 10-Q) for the quarter ended March 31, 2001. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The Interim Financial Statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective periods. Amounts reported in the Company's Statements of Consolidated Income are not necessarily indicative of amounts expected for a full year period due to the effects of, among other things, (a) seasonal fluctuations in demand for energy and energy services, (b) changes in energy commodity prices, (c) timing of maintenance and other expenditures and (d) acquisitions and dispositions of businesses, assets and other interests. In addition, certain amounts from the prior year have been reclassified to conform to the Company's presentation of financial statements in the current year. These reclassifications do not affect the earnings of the Company. The following notes to the consolidated financial statements in the Reliant Energy Form 10-K relate to certain contingencies. These notes, as updated herein, are incorporated herein by reference: Notes to Consolidated Financial Statements of Reliant Energy (Reliant Energy 10-K Notes): Note 2(f) (Summary of Significant Accounting Policies -- Regulatory Assets), Note 3 (Business Acquisitions), Note 4 (Regulatory Matters), Note 5 (Derivative Financial Instruments), Note 8 (Indexed Debt Securities (ACES and ZENS) and AOL Time Warner Securities), Note 14 (Commitments and Contingencies) and Note 20 (Subsequent Events). For information regarding certain legal, tax and regulatory proceedings and environmental matters, see Note 12. (2) NEW ACCOUNTING PRONOUNCEMENTS In July 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 141 "Business Combinations" (SFAS No. 141) and SFAS No. 142 "Goodwill and Other Intangible Assets" (SFAS No. 142). SFAS No. 141 requires business combinations initiated after June 30, 2001 to be accounted for using the purchase method of accounting, and broadens the criteria for recording intangible assets separate from goodwill. Recorded goodwill and intangibles will be evaluated against these new criteria and may result in certain intangibles being transferred to goodwill, or alternatively, amounts initially recorded as goodwill may be separately identified and recognized apart from goodwill. Under SFAS No. 142, a nonamortization approach, goodwill and certain intangibles with indefinite lives will not be amortized into results of operations, but instead would be reviewed periodically for impairment and written down and charged to results of operations only in the periods in which the recorded value of goodwill and certain intangibles with indefinite lives is more than its fair value. The provisions of each statement which apply to goodwill and intangible assets acquired prior to June 30, 2001 will be adopted by the Company on January 1, 2002. The Company is in the process of determining the effect of adoption of SFAS No. 141 and SFAS No. 142 on its consolidated financial statements. 5
8 (3) DERIVATIVE FINANCIAL INSTRUMENTS Adoption of SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities" as amended (SFAS No. 133) on January 1, 2001 resulted in an after-tax increase in net income of $61 million and a cumulative after-tax increase in accumulated other comprehensive loss of $252 million. The adoption also increased current assets, long-term assets, current liabilities and long-term liabilities by $703 million, $252 million, $805 million and $340 million, respectively, in the Company's Consolidated Balance Sheet. The Company also reclassified $788 million related to the Company's Zero-Premium Exchangeable Subordinated Notes (ZENS) due to the adoption from the current portion of long-term debt to indexed debt securities derivative. During the six months ended June 30, 2001, losses of $35 million of the initial transition adjustment recognized in other comprehensive income were realized in net income. For additional information regarding the adoption of SFAS No. 133 and the Company's accounting policies for derivative financial instruments, see Note 2 of Reliant Energy First Quarter 10-Q. The application of SFAS No. 133 is still evolving as the FASB clears issues submitted to the Derivatives Implementation Group for consideration. The FASB approved a number of issues regarding the normal purchases and normal sales exception in the second quarter. One issue concludes forward contracts with volumetric optionality do not qualify for the normal purchases and normal sales exception, while another issue applies exclusively to the electric industry and allows the normal purchases and normal sales exception for option-type contracts if certain criteria are met. The effective date for implementation of these decisions is July 1, 2001. The Company is currently assessing the impact of the recently cleared issues and does not believe they will have a material impact on the Company's Consolidated Financial Statements. Cash Flow Hedges. During the six months ended June 30, 2001, the Company entered into interest-rate swaps in order to adjust the interest rate on $1.6 billion of its floating rate debt. In addition, as of June 30, 2001, the Company's European Energy segment had entered into transactions to purchase approximately $103 million at fixed exchange rates in order to hedge future fuel purchases payable in U.S. dollars. During the six months ended June 30, 2001, the amount of hedge ineffectiveness recognized in earnings from derivatives that are designated and qualify as cash flow hedges was immaterial. No component of the derivative instruments' gain or loss was excluded from the assessment of effectiveness. During the six months ended June 30, 2001, there were no deferred gains or losses recognized in earnings as a result of the discontinuance of cash flow hedges because it was no longer probable that the forecasted transaction would occur. As of June 30, 2001, current non-trading derivative assets and liabilities and corresponding amounts in accumulated other comprehensive income are expected to be reclassified into net income during the next twelve months. The maximum length of time the Company is hedging its exposure to the variability in future cash flows for forecasted transactions is five years. Hedge of Net Investment in Foreign Subsidiaries. The Company has substantially hedged its net investment in its European Energy segment through a combination of Euro-denominated borrowings, foreign currency swaps and foreign currency forward contracts. These are designed to reduce the Company's exposure to changes in foreign currency rates. During the six months ended June 30, 2001, the derivative and non-derivative instruments designated as hedging the net investment in the Company's European Energy segment resulted in a gain of $227 million, which is included in the balance of the cumulative translation adjustment. Other Derivatives. Upon adoption of SFAS No. 133 effective January 1, 2001, the Company's indexed debt securities obligations related to its ZENS obligation was bifurcated into a debt component valued at $122 million and an embedded derivative component valued at $788 million. Changes in the fair value of the derivative component are recorded in the Company's Statements of Consolidated Income. During the six months ended June 30, 2001, the Company recorded a $464 million loss associated with the fair value of the derivative component of the indexed debt securities obligations. During the six months ended June 30, 2001, the Company recorded a $468 million gain on the Company's investment in AOL Time Warner Inc. common stock. Changes in the fair value of the Company's Investment in AOL Time Warner Inc. common stock should substantially offset changes in the fair value of the derivative component of the ZENS. In December 2000, the Dutch parliament adopted legislation allocating to the Dutch generation sector, including an indirect Dutch generating subsidiary of the Company, Reliant Energy Power Generation Benelux N.V. (REPGB), previously named N.V. UNA (UNA), financial responsibility for various stranded costs contracts and other liabilities. The legislation became effective in all material respects on January 1, 2001. In particular, the legislation allocated to the Dutch generation sector, including REPGB, financial responsibility to purchase electricity and gas under a gas supply contract and three electricity contracts. These contracts are derivatives pursuant to SFAS No. 133 due to the pricing indices. As of June 30, 2001, the Company has recognized $169 6
9 million in short-term and long-term non-trading derivative liabilities for REPGB's portion of these stranded costs contracts. For additional information regarding REPGB's stranded costs and the related indemnification by former shareholders of these stranded costs, see Note 12(e). (4) ACQUISITION OF RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC On May 12, 2000, an indirect subsidiary of the Company purchased entities owning electric power generating assets and development sites located in Pennsylvania, New Jersey and Maryland having an aggregate net generating capacity of approximately 4,262 megawatts (MW). With the exception of development entities that were sold to another subsidiary of the Company in July 2000, the assets of the entities acquired are held by Reliant Energy Mid-Atlantic Power Holdings, LLC (REMA). The purchase price for the May 2000 transaction was $2.1 billion, subject to post-closing adjustments which management does not believe will be material. The Company accounted for the acquisition as a purchase with assets and liabilities of REMA reflected at their estimated fair values. The Company's fair value adjustments related to the acquisition primarily included adjustments in property, plant and equipment, air emissions regulatory allowances, materials and supplies inventory, environmental reserves and related deferred taxes. The Company finalized these fair value adjustments in May 2001. There were no additional material modifications to the preliminary adjustments from December 31, 2000. For additional information regarding the acquisition of REMA, see Note 3(a) to Reliant Energy 10-K Notes. The Company's results of operations include the results of REMA only for the period beginning May 12, 2000. The following table presents selected actual financial information and pro forma information for the six months ended June 30, 2000, as if the acquisition had occurred on January 1, 2000. Pro forma amounts also give effect to the sale and leaseback of interests in three of the REMA generating plants, consummated in August 2000. For additional information regarding sale and leaseback transactions, see Note 14(c) to Reliant Energy 10-K Notes.
10 regarding the additional depreciation of electric utility generating assets and the redirection of transmission and distribution (T&D) depreciation to generation assets under the Transition Plan, see Note 2(g) to Reliant Energy 10-K Notes. In June 1999, the Texas legislature adopted the Texas Electric Choice Plan (Legislation), which substantially amended the regulatory structure governing electric utilities in Texas in order to allow retail electric competition beginning on January 1, 2002. The Legislation provides that depreciation expense for T&D related assets may be redirected to generation assets from 1999 through 2001 for regulatory purposes. Because the electric generation operations portion of Reliant Energy HL&P discontinued application of SFAS No. 71 effective June 30, 1999, such operations can no longer record additional or redirected depreciation for financial reporting purposes. However, for regulatory purposes, the Company continues to redirect T&D depreciation to generation assets. As of December 31, 2000 and June 30, 2001, the cumulative amount of redirected depreciation for regulatory purposes was $611 million and $725 million, respectively. In 1999, the Company determined that approximately $800 million of Reliant Energy HL&P's electric generation assets were impaired. The Legislation provides for recovery of this impairment through regulated cash flows. Therefore, a regulatory asset was recorded for an amount equal to the impairment in the Company's Consolidated Balance Sheets. The Company amortizes this regulatory asset as it is recovered from regulated cash flows. Amortization expense related to the recoverable impaired plant costs and other deferred debits created from discontinuing SFAS No. 71 was $95 million and $147 million for the quarter and six months ended June 30, 2000, respectively, compared to $87 million and $123 million for the same periods in 2001. (7) COMPREHENSIVE INCOME The following table summarizes the components of total comprehensive income:
11 The credit facilities contain covenants and requirements that must be met to borrow funds and obtain letters of credit, as applicable. Such covenants are not anticipated to materially restrict the borrowers from borrowing funds or obtaining letters of credit, as applicable, under such facilities. As of June 30, 2001, the borrowers are in compliance with the covenants under all of these credit agreements. (b) Long-term Debt. In February 2001, RERC Corp. issued $550 million aggregate principal amount of unsecured unsubordinated notes that bear interest at 7.75% per year and mature in February 2011. Net proceeds to RERC Corp. were $545 million. RERC Corp. used the net proceeds from the sale of the notes to pay a $400 million dividend to Reliant Energy, and for general corporate purposes. Reliant Energy used the $400 million proceeds from the dividend for general corporate purposes, including the repayment of short-term debt. (9) EARNINGS PER SHARE The following table presents Reliant Energy's basic and diluted earnings per share (EPS) calculation:
12 (1) For the three months ended June 30, 2000 and 2001, the computation of diluted EPS excludes 52,307 and 1,860,256 purchase options, respectively, for shares of common stock that have exercise prices (ranging from $28.72 to $32.22 per share and $45.57 to $50.00 per share for the second quarter 2000 and 2001, respectively) greater than the per share average market price for the period and would thus be anti-dilutive if exercised. For the six months ended June 30, 2000 and 2001, the computation of diluted EPS excludes 452,327 and 1,978,698 purchase options, respectively, for shares of common stock that have exercise prices (ranging from $25.81 to $32.22 per share and $41.69 to $50.00 per share for the first six months of 2000 and 2001, respectively) greater than the per share average market price for the period and would thus be anti-dilutive if exercised. (10) CAPITAL STOCK Common Stock. Reliant Energy has 700,000,000 authorized shares of common stock. At December 31, 2000, 299,914,791 shares of Reliant Energy common stock were issued and 286,464,709 shares of Reliant Energy common stock were outstanding. At June 30, 2001, 302,263,474 shares of Reliant Energy common stock were issued and 290,222,894 shares of Reliant Energy common stock were outstanding. Outstanding common shares exclude (a) shares pledged to secure a loan to Reliant Energy's Employee Stock Ownership Plan (8,638,889 and 7,528,889 at December 31, 2000 and June 30, 2001, respectively) and (b) treasury shares (4,811,193 and 4,511,691 at December 31, 2000 and June 30, 2001, respectively). Reliant Energy declared dividends of $0.375 per share in the second quarter of 2000 and 2001 and $0.75 per share in the first six months of 2000 and 2001. During the six months ended June 30, 2001, Reliant Energy issued 300,000 shares of Reliant Energy common stock out of its treasury stock. As of June 30, 2001, Reliant Energy was authorized to purchase up to $271 million of Reliant Energy common stock under its stock repurchase program. (11) TRUST PREFERRED SECURITIES (a) Reliant Energy. Statutory business trusts created by Reliant Energy have issued trust preferred securities, the terms of which, and the related series of junior subordinated debentures, are described below (in millions):
13 (b) RERC Corp. A statutory business trust created by RERC Corp. has issued convertible trust preferred securities, the terms of which, and the related series of convertible junior subordinated debentures, are described below (in millions):
14 California Wholesale Market. Reliant Energy, Reliant Energy Services, Inc. (a wholly owned subsidiary of Reliant Resources), Reliant Energy Power Generation, Inc. (a wholly owned subsidiary of Reliant Resources) and several other subsidiaries of Reliant Resources, as well as several officers of some of these companies, have been named as defendants in class action lawsuits and other lawsuits filed against a number of companies that own generation plants in California and other sellers of electricity in California markets. Pursuant to the terms of the master separation agreement between Reliant Energy and Reliant Resources (see Note 4(b) to Reliant Energy 10-K Notes), Reliant Resources has agreed to indemnify Reliant Energy for any damages arising under these lawsuits and may elect to defend these lawsuits at Reliant Resources' own expense. Three of these lawsuits were filed in the Superior Court of the State of California, San Diego County; two were filed in the Superior Court of San Francisco County; and one was filed in the Superior Court of Los Angeles County. While the plaintiffs allege various violations by the defendants of state antitrust laws and state laws against unfair and unlawful business practices, each of the lawsuits is grounded on the central allegation that defendants conspired to drive up the wholesale price of electricity. In addition to injunctive relief, the plaintiffs in these lawsuits seek treble the amount of damages alleged, restitution of alleged overpayments, disgorgement of alleged unlawful profits for sales of electricity, costs of suit and attorneys' fees. In one of the cases the plaintiffs allege aggregate damages of over $4 billion. Defendants sought to remove all of these cases to federal court. The Judicial Panel on Multidistrict Litigation issued an order consolidating and transferring them to the Honorable Robert H. Whaley, a U.S. District Court Judge from the Eastern District of Washington, sitting by designation in San Diego, California. On June 27, 2001, Judge Whaley heard argument on plaintiffs' motions to remand five of the six cases back to state court. A motion to remand the sixth case has not been filed at this time. Judge Whaley issued a ruling on July 30, 2001, remanding the five cases back to state court. On August 1, 2001, a motion to consolidate the remanded state court cases was filed. The ultimate outcome of the lawsuits cannot be predicted with any degree of certainty at this time. However, the Company believes, based on its analysis to date of the claims asserted in these lawsuits and the underlying facts, that resolution of these lawsuits will not have a material adverse effect on the Company's financial condition, results of operations or cash flows. (b) Environmental Matters. Clean Air Standards. The Company has participated in a lawsuit against the Texas Natural Resource Conservation Commission (TNRCC) regarding the limitation of the emission of oxides of nitrogen (NOx) in the Houston area. A settlement of the lawsuit was reached with the TNRCC in the second quarter of 2001. The settlement provides for an increase in allowable NOx emissions, compared to the original TNRCC requirements, through 2004. Further emission reduction requirements may or may not be required through 2007, depending upon the outcome of further investigations of regional air quality issues. Under the settlement, the Company will expend substantial funds to achieve significant reductions of NOx emissions. The Company anticipates investing up to $720 million in capital and other special project expenditures by 2004, and an additional $140 million between 2004 and 2007 to comply with this settlement. Manufactured Gas Plant Sites. RERC and its predecessors operated a manufactured gas plant (MGP) adjacent to the Mississippi River in Minnesota, formerly known as Minneapolis Gas Works (MGW) until 1960. RERC has substantially completed remediation of the main site other than ongoing water monitoring and treatment. The manufactured gas was stored in separate holders. RERC is negotiating clean-up of one such holder. There are six other former MGP sites in the Minnesota service territory. Remediation has been completed on one site. Of the remaining five sites, RERC believes that two were neither owned nor operated by RERC. RERC believes it has no liability with respect to the sites it neither owned nor operated. At June 30, 2001, RERC had accrued $19 million for remediation of the Minnesota sites. At June 30, 2001, the estimated range of possible remediation costs was $8 million to $36 million. The cost estimates of the MGW site are based on studies of that site. The remediation costs for the other sites are based on industry average costs for remediation of sites of similar size. The actual remediation costs will be dependent upon the number of sites remediated, the participation of other potentially responsible parties, if any, and the remediation methods used. Issues relating to the identification and remediation of MGPs are common in the natural gas distribution industry. RERC has received notices from the United States Environmental Protection Agency and others regarding its status as a potentially responsible party (PRP) for other sites. Based on current information, RERC has not been able to quantify a range of environmental expenditures for potential remediation expenditures with respect to other MGP sites. 12
15 Other Minnesota Matters. At June 30, 2001, RERC had recorded accruals of $4 million (with a maximum estimated exposure of approximately $17 million at June 30, 2001) for other environmental matters in Minnesota for which remediation may be required. Mercury Contamination. The Company's pipeline and distribution operations have in the past employed elemental mercury in measuring and regulating equipment. It is possible that small amounts of mercury may have been spilled in the course of normal maintenance and replacement operations and that these spills may have contaminated the immediate area with elemental mercury. The Company has found this type of contamination at some sites in the past, and the Company has conducted remediation at these sites. It is possible that other contaminated sites may exist and that remediation costs may be incurred for these sites. Although the total amount of these costs cannot be known at this time, based on experience of the Company and that of others in the natural gas industry to date and on the current regulations regarding remediation of these sites, the Company believes that the costs of any remediation of these sites will not be material to the Company's financial condition, results of operations or cash flows. REMA Ash Disposal Site Closures and Site Contaminations. Under the agreement to acquire REMA (see Note 3(a) to Reliant Energy 10-K Notes), the Company became responsible for liabilities associated with ash disposal site closures and site contamination at the acquired facilities in Pennsylvania and New Jersey prior to a plant closing, except for the first $6 million of remediation costs at the Seward generating station. A prior owner retained liabilities associated with the disposal of hazardous substances to off-site locations prior to November 24, 1999. As of June 30, 2001, REMA has liabilities associated with six ash disposal site closures and six site investigations and environmental remediations. The Company has recorded its estimate of these environmental liabilities in the amount of $36 million as of June 30, 2001. The Company expects approximately $13 million will be paid over the next five years. REPGB Asbestos Abatement and Soil Remediation. Prior to the Company's acquisition of REPGB (see Note 3(b) to Reliant Energy 10-K Notes), REPGB had a $25 million obligation primarily related to asbestos abatement, as required by Dutch law, and soil remediation at six sites. During 2000, the Company initiated a review of potential environmental matters associated with REPGB's properties. REPGB began remediation in 2000 of the properties identified to have exposed asbestos and soil contamination, as required by Dutch law and the terms of some leasehold agreements with municipalities in which the contaminated properties are located. All remediation efforts are expected to be fully completed by 2005. As of June 30, 2001, the estimated undiscounted liability for this asbestos abatement and soil remediation was $21 million. Other. From time to time the Company has received notices from regulatory authorities or others regarding its status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. In addition, the Company has been named as a defendant in litigation related to such sites and in recent years has been named, along with numerous others, as a defendant in several lawsuits filed by a large number of individuals who claim injury due to exposure to asbestos while working at sites along the Texas Gulf Coast. Most of these claimants have been workers who participated in construction of various industrial facilities, including power plants, and some of the claimants have worked at locations owned by the Company. The Company anticipates that additional claims like those received may be asserted in the future and intends to continue vigorously contesting claims that it does not consider to have merit. Although their ultimate outcome cannot be predicted at this time, the Company does not believe, based on its experience to date, that these matters, either individually or in the aggregate, will have a material adverse effect on the Company's financial condition, results of operations or cash flows. (c) Other Legal and Environmental Matters. The Company is involved in other legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. Some of these proceedings involve substantial amounts. The Company's management regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. The Company's management believes that the disposition of these matters will not have a material adverse effect on the Company's financial condition, results of operations or cash flows. (d) California Wholesale Market Uncertainty. During the summer and fall of 2000, and continuing into early 2001, prices for wholesale electricity in California increased dramatically as a result of a combination of factors, including higher natural gas prices and 13
16 emission allowance costs, reduction in available hydroelectric generation resources, increased demand, decreases in net electric imports, structural market flaws including over-reliance on the electric spot market, and limitations on supply as a result of maintenance and other outages. Although wholesale prices increased, California's deregulation legislation kept retail rates frozen below 1996 levels until rates were raised by the California Public Utilities Commission (CPUC) early this year. As of December 31, 2000, the Company was owed a total of $282 million by the California Power Exchange (Cal PX) and the California Independent System Operator (Cal ISO). In the fourth quarter of 2000, the Company recorded a pre-tax provision of $39 million against receivable balances related to energy sales in the California market. As of June 30, 2001, the Company was owed a total of $318 million by the Cal ISO, the Cal PX, the California Department of Water Resources (CDWR) and California Energy Resource Scheduling for energy sales in the California wholesale market during the fourth quarter of 2000 through June 30, 2001. In the first six months of 2001, the Company recorded a pre-tax provision of $37 million against receivable balances related to energy sales from January 1, 2001 through June 30, 2001 in the California market. Management will continue to assess the collectibility of these receivables based on further developments affecting the California electricity market and the market participants described herein. Additional provisions to the allowance may be warranted in the future. In response to the filing of a number of complaints challenging the level of wholesale prices, the Federal Energy Regulatory Commission (FERC) initiated a staff investigation and issued an order on December 15, 2000 implementing a series of wholesale market reforms, including an interim price review procedure for prices above a $150/MWh "breakpoint" on sales to the Cal ISO and through the Cal PX. The order did not prohibit sales above the "breakpoint," but the seller was subject to weekly reporting and monitoring requirements. For each reported transaction, potential refund liability extends for a period of 60 days following the date any such transaction is reported to the FERC. On March 9, 2001, the FERC issued an order outlining criteria for determining amounts subject to possible refund based on a monthly proxy market clearing price for transactions in the Cal ISO and Cal PX markets from January 1, 2001 through May 28, 2001. According to those criteria, approximately $12 million of the $125 million charged by the Company in January 2001 for sales in California to the Cal ISO and the Cal PX and approximately $7 million of the $47 million charged by the Company in February 2001 for sales in California to the Cal ISO are subject to possible refunds. In addition, approximately $370,000 of the $6.6 million charged by the Company from May 1 through May 28, 2001, for sales in California to the Cal ISO are subject to possible refund. The FERC found that the Company did not have any potential refund obligations associated with its sales in March or April 2001. In the March 9 order, the FERC set forth procedures for challenging possible refund obligations. On April 11 and 13 and May 11, the Company submitted cost or other justification for most of the January and February transactions designated as subject to refund. During the second quarter of 2001, the Company accrued refunds of $15 million of which $3 million had been previously reserved in the first quarter of 2001. On June 22, 2001, the Company notified the FERC that it agreed to refund amounts in excess of the proxy prices for May transactions in light of changes in environmental restrictions on the Company's generators. Any refunds the Company may ultimately be obligated to pay are to be credited against unpaid amounts owed to the Company for its sales in the Cal PX or to the Cal ISO. The December 15 order established that a refund condition would be in place for the period beginning October 2, 2000 through December 31, 2002. Motions for rehearing have been filed on a number of issues related to the December 15 order and such motions are still pending before the FERC. On April 26, 2001, the FERC issued an order establishing a market monitoring and mitigation plan for the California markets to replace the $150/MWh breakpoint plan. This plan became effective on May 29, 2001 and was to have lasted no more than one year. The plan retains the "breakpoint" approach to price mitigation, for bids in the real-time market during periods when power reserves fall below 7.5 percent (i.e., Stages 1, 2 and 3 emergencies in 14
17 the Cal ISO). The plan's breakpoint amount is based on variable cost calculations using data submitted confidentially by each gas-fired generator to the FERC and the Cal ISO. The Cal ISO is instructed to use this data and daily indices of natural gas and emissions allowance costs to establish the market-clearing price in real-time based on the marginal cost of the highest-cost generator called to run. The plan also increases the Cal ISO's authority to coordinate and control generating facility outages, subject to periodic reports to and review by the FERC; requires generators in California to offer all their available capacity for sale in the real-time market; and conditions sellers' market-based rate authority such that sellers violating certain conditions on their bids will be subject to increased scrutiny by the FERC, potential refunds and even revocation of their market-based rate authority. The FERC conditioned implementation of the market monitoring and mitigation plan on the Cal ISO and the three California public utilities filing a regional transmission organization proposal by June 1, 2001. On June 1, 2001, the Cal ISO and the three California public utilities made a filing purporting to meet this requirement. On June 19, 2001, the FERC issued an order modifying the market monitoring and mitigation plan adopted in its April 26 order, to apply price controls to all hours, instead of just hours of low operating reserve, and to extend the mitigation measures to other Western states in addition to California. The proxy market clearing price calculated by the Cal ISO will apply during reserve deficiencies to all sales in the Cal ISO and Western spot markets. The affected Western states are Arizona, Colorado, Idaho, Montana, Nevada, New Mexico, Oregon, Utah, Washington and Wyoming. The proxy market clearing price will include variable operations and maintenance costs ($6/MWh) and natural gas costs, while emissions costs and start-up fuel costs incurred in providing energy will be billed by suppliers directly to the Cal ISO. The Cal ISO will also add a 10 percent premium to market clearing prices to compensate sellers for credit uncertainty in California. In non-emergency hours in California, the maximum price in California and the West will be capped at 85 percent of the highest Cal ISO hourly market clearing price established during the hours when the last Stage 1 emergency was in effect. Sellers other than marketers will be allowed to bid higher than the maximum prices, but such bids are subject to justification and potential refund. Justification of higher prices is limited to establishing higher actual gas costs than the proxy calculation averages. Marketers cannot justify prices above the set maximum, but rather must be price takers. The plan requires that every non-hydroelectric generator located in California with available uncommitted capacity must bid into the Cal ISO's real-time market in every hour, and non-hydroelectric generators in other Western states that use the interstate transmission grid must likewise make their uncommitted capacity available to a spot market of their choice. The modified monitoring and mitigation plan went into effect June 20, 2001, and will terminate on September 30, 2002, covering two summer peak seasons, or approximately 16 months. The Company believes that while the mitigation plan will reduce volatility in the market, the Company will nevertheless be able to profitably operate its facilities in the West because the proxy market clearing price is based on the heat rate of the least efficient unit on-line during each hour. Additionally, as noted above, the mitigation plan allows sellers, such as the Company, to justify prices above the proxy price. Finally, any adverse impacts of the mitigation plan on the Company's operations would be mitigated, in part, by the Company's forward hedging activities. The FERC set July 2, 2001, as the refund effective date for mitigation of prices throughout the West. This means that transactions after that date may be subject to refund if found to be unjust or unreasonable. The order issued June 19 further requires all public utility sellers and buyers in the Cal ISO's markets to participate in settlement discussions to address past accounts and creditworthiness issues and to structure more long-term contracting. This conference convened on June 25, 2001, and continued through July 9, 2001 The settlement judge made his recommendations to the FERC regarding a proposed methodology for calculating possible refunds by sellers and procedures for resolving that and other outstanding issues on July 12, 2001. The FERC issued an order on July 25, 2001 adopting most of the settlement judge's recommendations, with modifications, and set an expedited hearing schedule. The Company cannot currently predict the amount of these potential refunds, if any, because the methodology used to calculate these refunds is dependent on information that is only known to the Cal ISO. The amounts of any refunds will be determined by the end of the expedited hearing process. This proceeding should be completed by September 24, 2001. The Company has not reserved any amounts for potential refunds as a reasonable estimate cannot currently be made. Any refunds that are determined in the FERC proceeding are to be offset against unpaid amounts owed to the Company for its prior sales. In addition to the FERC investigation discussed above, several state and other federal regulatory investigations and complaints have commenced in connection with the wholesale electricity prices in California and other neighboring Western states to determine the causes of the high prices and potentially to recommend remedial action. In California, the CPUC, the California Electricity Oversight Board, the California Bureau of State Audits, the California State Senate and the California Office of the Attorney General all have separate ongoing investigations into the high prices and their causes. The Washington and Oregon attorney generals have begun similar investigations. With the exception of a report by the California Bureau of State Audits, none of these investigations 15
18 has been completed and no findings have been made in connection with any of them. The California state audit report, released earlier this year, concluded that the foremost cause of the market disruptions in California was fundamental flaws in the structure of the power market. In addition, recently promulgated regulations may make the Company subject to additional reporting requirements to the California Energy Commission. Pursuant to a resolution by the California Senate Rules Committee, the California Senate has established a Select Committee on Price Manipulation of the Wholesale Market (Committee). On June 12, 2001, the Committee served on Reliant Energy Services, Inc., and Reliant Energy Power Generation, Inc., subpoenas for documents. On July 18, 2001, the Committee found that these two companies had not provided an adequate response to the subpoenas, and it voted to recommend that the Senate initiate contempt proceedings against those entities. The ultimate outcome of the Senate proceedings cannot be predicted with any degree of certainty at this time. In default on payments for wholesale power purchased through the Cal PX and from the Cal ISO, the credit ratings of two of California's public utilities, Pacific Gas and Electric (PG&E) and Southern California Edison Company (SCE), remain below investment grade. As a result, PG&E and SCE are no longer able to schedule power transactions through the Cal ISO, which has relied on its emergency dispatch authority to serve the load of PG&E and SCE that cannot be served by generation owned or under contract by PG&E or SCE. According to orders of the FERC, the Cal ISO may not make real-time power purchases or issue emergency dispatch orders to third-party suppliers to serve the utilities' net short load in the absence of a creditworthy counterparty to back the liabilities of PG&E or SCE. The bankruptcy court judge in the PG&E bankruptcy has also issued an injunction precluding the Cal ISO from making such purchases. The CDWR has acted as a creditworthy counterparty for certain real-time transactions on behalf of PG&E and SCE, but disputes its direct liability for some of the power obtained from third-party suppliers to serve the utilities' net short load. The issue of CDWR's liability for amounts due from PG&E and SCE is currently before the FERC. Since January 2000, pursuant to emergency legislation enacted by the California Legislature, the CDWR has negotiated and purchased power through short- and long-term contracts on behalf of PG&E and SCE. On May 10, 2001, the CDWR received authorization under state law to issue up to $13.4 billion in bonds to cover the costs of power purchased on behalf of PG&E and SCE. These funds may not, however, be used to pay for any past under-collections or to service existing debt of the utilities. In addition to creditworthiness and payment disputes regarding transactions through the Cal ISO, certain issues remain outstanding with regard to the defaults of PG&E and SCE in the markets operated by the Cal PX, which is now in Chapter 11 bankruptcy proceedings. The Cal PX initially allocated the utilities' defaults to other market participants, under a chargeback provision of the Cal PX tariff, which action was challenged in both federal court and at the FERC. Although the Cal PX's actions with regard to the chargebacks were ultimately stayed by the federal court and ordered by the FERC to be rescinded, the issue of how monies held in escrow by the Cal PX will be distributed among market participants is still outstanding. In addition, Reliant Energy Services, Inc. and the Cal PX have filed actions to recover payment from the state of California for its seizure of block forward contracts purchased by PG&E and SCE that secured the utilities' activities in the Cal PX markets. In May 2001, a bill was passed by the California Senate that proposed a tax on "windfall profits" earned by electric generators in California. The bill would impose a 100 percent tax on any electricity sold by California generators that exceeds a "just and reasonable price," such price to be set by the CPUC. This bill expired when the first extraordinary session ended. During the second extraordinary session of the California legislature, currently in progress, similar bills have been introduced in both the California Senate and the California Assembly. The Senate bill, which was introduced on May 17, would impose a tax equal to the portion of sales above the "cost based rates," which include "reasonable" profit margins and maintenance and operating expenses. This bill passed the Senate on May 17 and is currently in committee in the California Assembly. It must be voted on and passed by the California Assembly, and signed by the Governor, before it will become law. On May 15, the California Assembly also introduced a bill that would tax "excess" gross receipts from electrical energy distribution. The Assembly bill would impose a tax equal to 50% of all gross receipts higher than a base price but not more than 150% of the base price. For receipts between 150% and 200% of the base price, the tax is 70%, and for receipts over 200% of the base price, the tax is 90% of the gross receipts. The bill sets the base price at $60 per megawatt hour until the CPUC sets an appropriate price. This bill has not yet passed the California Assembly. If either bill is enacted into law in its current form, such a tax could significantly increase the cost of operating power generation facilities serving the California market and could have a material adverse effect on the Company's financial condition, results of operations and cash flows. 16
19 (e) Indemnification of Dutch Stranded Costs. In January 2001, the Dutch Electricity Production Sector Transitional Arrangements Act (Transition Act) became effective. The Transition Act, among other things, allocated to REPGB and the three other Dutch generation companies, a share of the assets, liabilities and stranded cost commitments of BV Nederlands Elektriciteit Administratiekantoor (formerly, N.V. Samenwerkende elecktriciteits-produktiebedrijven (SEP)). Prior to the enactment of the Transition Act, SEP acted as the national electricity pooling and coordinating body for the generation output of REPGB and the three other national Dutch generation companies. REPGB and the three other Dutch generation companies are shareholders of SEP. The Transition Act and related agreements specify that REPGB has a 22.5% share of SEP's assets, liabilities and stranded cost commitments. SEP's stranded cost commitments consisted primarily of various uneconomical or stranded cost investments and long-term gas supply and power contracts entered into prior to the liberalization of the Dutch wholesale electricity market. SEP's primary asset is its ownership interest in the Dutch national grid company, which is expected to be sold to the Dutch government in the fourth quarter of 2001 for approximately NLG 2.55 billion (approximately $982 million based on an exchange rate of 2.59 NLG per U.S. dollar as of June 30, 2001). Under the Transition Act, REPGB can either assume its 22.5% allocated interest in the contracts or, subject to the terms of the contracts, sell its interests to third parties. The Transition Act, as enacted, provided that, subject to the approval of the European Commission, the Dutch government will provide financial compensation to the Dutch generation companies, including REPGB, for certain liabilities associated with long-term district heating contracts entered into by the generation companies with various municipalities. In July 2001, the European Commission ruled that under certain conditions the Dutch government can provide financial compensation to the generation companies for the district heating contracts. However, at this point, it is unclear what the timing of this compensation will be or what form it will take. To the extent that this compensation is not ultimately provided to the generation companies by the Dutch government, REPGB will collect its compensation directly from the former shareholders as further discussed below. The former shareholders have agreed pursuant to a share purchase agreement to indemnify REPGB for up to NLG 1.9 billion in stranded cost liabilities (approximately $734 million based on an exchange rate of 2.59 NLG per U.S. dollar as of June 30, 2001). The indemnity obligation of the former shareholders and various provincial and municipal entities (including the city of Amsterdam), is secured by a NLG 900 million escrow account (approximately $347 million based on an exchange rate of 2.59 NLG per U.S. dollar as of June 30, 2001). In the first quarter of 2001, REPGB recorded a $544 million liability representing the estimated net present value of its statutorily allocated share of SEP's stranded cost gas and electric and district heating commitments over the life of the respective contracts. Pursuant to SFAS No. 133, the gas and electric contracts are marked to market. As of June 30, 2001, the Company has recorded a liability of $376 million for its stranded cost gas and electric and district heating commitments. In addition, the Company recorded a corresponding asset of equal amount for the indemnification of this obligation from REPGB's former shareholders and the Dutch government. The estimate of stranded cost liability is based on a number of assumptions, many of which are contingent upon the outcome of future events, such as fuel and energy prices, that are not known at this time. The actual amount of the ultimate stranded cost liability may be greater or smaller depending on the outcome of these assumptions. During the second quarter of 2001, the Company filed aggregate indemnity claims of NLG 64 million (approximately $25 million) for stranded cost liabilities associated with the district heating and gas and electricity contract losses incurred during the first quarter of 2001. Based on current market projections, the Company expects to file similar claims on a quarterly basis for the lifetime of these contracts. On May 31 and July 9, 2001, the former shareholders rejected REPGB's indemnity claims. The Company believes that the rejection of its indemnity claims is without merit and intends to vigorously pursue its claims against the former shareholders. During the second quarter of 2001, the Company recorded a $51 million pre-tax gain (NLG 125 million) recorded as equity income for the preacquisition gain contingency related to the acquisition of REPGB for the value of its equity investment in SEP. This gain was based on the Company's evaluation of SEP's financial position and fair value. Pursuant to the purchase agreement of REPGB, as amended, REPGB is entitled to a NLG 125 million (approximately $51 million) dividend from SEP under certain conditions. 17
20 (f) Reliant Energy HL&P Rate Matters. The Texas Utility Commission has issued an interim order on June 5, 2001 requiring Reliant Energy HL&P to reverse the amount of redirected depreciation and accelerated depreciation since it was in the Texas Utility Commission's estimation that the utility had overmitigated its stranded costs. The Company disagrees with certain positions prescribed in the interim order by the Texas Utility Commission and will determine future action based on the final order anticipated in August 2001. At June 30, 2001, cumulative redirected depreciation and cumulative accelerated depreciation for regulatory purposes totaled $725 million and approximately $1 billion, respectively. If implemented, the reversal of redirected depreciation would result in a lower rate for the transmission and distribution utility, and the accelerated depreciation being returned through credits over seven years would serve as offsets to the transmission and distribution utility's non-bypassable charges. The rates derived from the Texas Utility Commission's June 5, 2001 interim order will be used during the retail electric pilot project which began on July 31, 2001. The Company does not expect the final Reliant Energy HL&P transmission and distribution rate to be established until the end of August 2001 and implemented until January 1, 2002. The credits related to accelerated depreciation will begin on January 1, 2002. For information regarding redirected depreciation and accelerated depreciation, see Note 4(a) to Reliant Energy 10-K Notes. (g) Construction Agency Agreement. In April 2001, Reliant Resources, through several of its subsidiaries, entered into operative documents with special purpose entities to facilitate the development, construction, financing and leasing of several power generation projects. The special purpose entities have an aggregate financing commitment from equity and debt participants (Investors) of $2.5 billion. Reliant Resources, through several of its subsidiaries, acts as construction agent for the special purpose entities, and is responsible for completing construction of these projects by August 31, 2004, but has generally limited its risk related to construction completion to less than 90% of costs incurred to date, except in certain events. Upon completion of an individual project and exercise of the lease option, Reliant Resources' subsidiaries will be required to make lease payments in an amount sufficient to provide a return to the Investors. If Reliant Resources does not exercise its option to lease any project upon its completion, Reliant Resources must purchase the project or remarket the project on behalf of the special purpose entities. At the end of an individual project's operating lease term (approximately five years from construction completion), the lessees have the option to extend the lease at fair market value, purchase the project at a fixed amount equal to the original construction cost, or act as a remarketing agent and sell the project to an independent third party. If the lessees elect the remarketing option, they may be required to make a payment of up to 85% of the project cost if the proceeds from remarketing are not sufficient to repay the Investors. Reliant Resources has guaranteed the performance and payment of its subsidiaries' obligations during the construction periods and, if the lease option is exercised, the lessee's obligations during the lease period. (13) BENEFIT CURTAILMENT AND ENHANCEMENT CHARGE During the first quarter of 2001, the Company recognized a pre-tax, non-cash charge of $101 million relating to the redesign of some of Reliant Energy's benefit plans in anticipation of distributing to Reliant Energy's or its successor's shareholders the remaining common stock of its unregulated subsidiary, Reliant Resources. For information regarding this anticipated transaction, see Note 4(b) to Reliant Energy 10-K Notes. Effective March 1, 2001, the Company will no longer accrue benefits under a noncontributory pension plan for its domestic non-union employees of Reliant Resources and Reliant Energy Tegco, Inc. (Resources Participants). Effective March 1, 2001, each non-union Resources Participant's unvested pension account balance became fully vested and a one-time benefit enhancement was provided to some qualifying participants. During the first quarter of 2001, the Company incurred a charge to earnings of $84 million (pre-tax) for a one-time benefit enhancement and a gain of $23 million (pre-tax) related to the curtailment of Reliant Energy's pension plan. Effective March 1, 2001, the Company discontinued providing subsidized postretirement benefits to its domestic non-union employees of Reliant Resources and its participating subsidiaries and Reliant Energy Tegco, Inc. The Company incurred a pre-tax charge of $40 million during the first quarter of 2001 related to the curtailment of the Company's postretirement obligation. For additional information regarding these benefit plans, see Notes 12(b) and 12(d) to Reliant Energy 10-K Notes. 18
21 (14) REPORTABLE SEGMENTS The Company's determination of reportable segments considers the strategic operating units under which the Company manages sales, allocates resources and assesses performance of various products and services to wholesale or retail customers in differing regulatory environments. The Company has identified the following reportable segments: Electric Operations, Natural Gas Distribution, Pipelines and Gathering, Wholesale Energy, European Energy and Other Operations. For descriptions of these reporting segments, see Note 1 to Reliant Energy 10-K Notes. Financial data for the business segments are as follows:
22
23 (16) SUBSEQUENT EVENTS (a) Debt Refinancing. In July 2001, financing subsidiaries of Reliant Energy terminated several bank credit facilities and entered into new bank credit facilities which increased the aggregate amount of bank facilities at financing subsidiaries to $4.3 billion. The new bank facilities expire in July 2002 and are expected to support the issuance of commercial paper. In connection with the termination of a Euro 560 million bank facility, financing subsidiary bank loans of Euro 560 million were refinanced with U.S. dollar denominated commercial paper issued by a financing subsidiary. (b) Reliant Resources Stock Repurchase. During the third quarter of 2001, Reliant Resources purchased 840,000 shares of Reliant Resources common stock at an average price of $20.58 per share, or an aggregate purchase price of $17.3 million. These shares were purchased in anticipation of funding benefit plan obligations of Reliant Resources expected to be funded prior to the Distribution. The master separation agreement between Reliant Resources and Reliant Energy restricts the ability of Reliant Resources to issue shares of its common stock prior to the separation of the two companies without the prior consent of Reliant Energy. Accordingly, Reliant Resources may make future purchases of its common stock in anticipation of funding pre-Distribution employee benefit plan obligations. (c) Hedge of Net Investment in Foreign Subsidiaries. In July 2001, the Company has entered into foreign currency swaps on Euro 560 million (approximately $475 million based on an exchange rate of 0.8490 Euro per U.S. dollar as of June 30, 2001) to hedge its net investment in its European Energy segment, which expire in 2002. The Company has designated these derivative instruments as hedges. Changes in the fair value of the swaps will be recorded as foreign currency translation adjustments as a component of stockholders' equity. (d) Reliant Energy Communications. During the third quarter of 2001, the Company decided to evaluate strategic alternatives, including divestiture, partnerships with other market participants or other strategic alternatives, for the Company's Communications business which serves as a facility-based competitive local exchange carrier and Internet services provider as well as network operations centers and managed data centers in Houston and Austin. The Company does not believe the disposition or other strategic alternatives of this business will have a material adverse effect on its consolidated financial condition, results of operations or cash flows in 2001 and in future periods. 21
24 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF RELIANT ENERGY AND SUBSIDIARIES The following discussion and analysis should be read in combination with our Interim Financial Statements contained in this Form 10-Q. We are a diversified international energy services and energy delivery company that provides energy and energy services in North America and Europe. We operate one of the nation's largest electric utilities in terms of kilowatt-hour (KWh) sales, and our three natural gas distribution divisions together form one of the United States' largest natural gas distribution operations in terms of customers served. We invest in the acquisition, development and operation of domestic and international non-rate regulated power generation facilities. We own two interstate natural gas pipelines that provide gas transportation, supply, gathering and storage services, and we also engage in wholesale energy marketing and trading. In this section we discuss our results of operations on a consolidated basis and individually for each of our business segments. We also discuss our liquidity and capital resources. Our financial reporting segments include Electric Operations, Natural Gas Distribution, Pipelines and Gathering, Wholesale Energy, European Energy and Other Operations. For segment reporting information, please read Note 14 to our Interim Financial Statements. Effective December 1, 2000, our Board of Directors approved a plan to dispose of our Latin American business segment and sale of its assets. Accordingly, we are reporting the results of our Latin American business segment as discontinued operations for all periods presented in our Interim Financial Statements in accordance with Accounting Principles Board Opinion No. 30. For additional information regarding the disposal of our Latin American business segment, please read Note 19 to Reliant Energy 10-K Notes. In 2000, we submitted a business separation plan to the Texas Utility Commission that was later amended during the year to restructure our businesses into two separate publicly traded companies in order to separate our unregulated businesses from our regulated businesses. In December 2000, the plan was substantially approved by the Texas Utility Commission in its entirety and a final order was issued on April 10, 2001. For additional information regarding our business separation plan, please read Note 4(b) to Reliant Energy 10-K Notes. As part of the separation, Reliant Energy will undergo a restructuring of its corporate organization to achieve a new holding company structure. The new holding company will hold our regulated businesses. In connection with the formation of the new holding company, we will seek an exemption from the registration requirements of the Public Utility Holding Company Act of 1935 (1935 Act) or, if no exemption is available, the new holding company will register as a public utility holding company under the 1935 Act. The restructuring will require approval of the Securities and Exchange Commission, certain of the affected state commissions and the Nuclear Regulatory Commission. In connection with our business separation plan, we formed Reliant Resources, which owns and operates a substantial portion of our unregulated operations. In May 2001, Reliant Resources offered 59.8 million shares of its common stock to the public at an initial public offering (Offering) price of $30 per share and received net proceeds from the Offering of $1.7 billion. Pursuant to the master separation agreement, Reliant Resources used $147 million of the net proceeds to repay certain indebtedness owed to Reliant Energy. Reliant Energy expects to distribute the remaining common stock of Reliant Resources it owns to Reliant Energy's or its successor's shareholders within twelve months of the closing of the Reliant Resources initial public offering. On May 12, 2000, one of our subsidiaries purchased entities owning electric power generating assets and development sites located in Pennsylvania, New Jersey, and Maryland having an aggregate net generating capacity of approximately 4,262 MW. The purchase price for the May 2000 transaction was $2.1 billion. We accounted for the acquisition as a purchase, and accordingly, our results of operations include the results of operations for REMA only for the period after the acquisition date. For additional information about this acquisition, including our accounting treatment of the acquisition, please read Note 3(a) to Reliant Energy 10-K Notes and Note 4 to our Interim Financial Statements. 22
25 CONSOLIDATED RESULTS OF OPERATIONS
26 The effective tax rate for the second quarter of 2000 and 2001 was 32% and 35%, respectively. Six months ended June 30,2000 compared to six months ended June 30, 2001 We reported consolidated net income of $357 million ($1.25 per diluted share) for the six months ended June 30, 2000 compared to $536 million ($1.84 per diluted share) for the six months ended June 30, 2001. The 2000 results include a $20 million loss from discontinued operations in Latin America and an extraordinary gain of $7 million related to the early extinguishment of long-term debt. The 2001 results reflect a $7 million after-tax loss on the disposal of discontinued operations in Latin America, a $61 million after-tax cumulative effect of an accounting change from the adoption of SFAS No. 133, a $65 million after-tax non-cash charge relating to the redesign of the company's benefit plans for employees of our unregulated businesses and a $33 million after-tax gain recorded in equity income related to a preacquisition contingency for the value of SEP, offset by related minority interest of $6 million. Our consolidated net income, after adjusting for the items described above, was $370 million ($1.29 per diluted share) for the first six months of 2000 compared to $521 million ($1.79 per diluted share) for the first six months of 2001. The increase in adjusted earnings for this period was largely driven by strong performance from our Wholesale Energy businesses. For information regarding the adoption of SFAS No. 133, the discontinuance of our Latin American segment, the gain related to the preacquisition contingency and the benefit charge incurred in the first quarter of 2001, see Notes 3, 5, 12(e) and 13 to our Interim Financial Statements. For an explanation of changes in operating income for the first six months of 2000 versus 2001, see the discussion below of operating income (loss) by segment. Equity income from unconsolidated subsidiaries increased by $58 million during the first half of 2001 compared to 2000 primarily due to the pre-tax gain of $51 million related to a preacquisition contingency recorded by our European Energy segment, as discussed above, and increased earnings from unconsolidated subsidiaries of our Wholesale Energy segment. Our Wholesale Energy segment reported income from equity investments for the six months ended June 30, 2000 of $6 million compared to $14 million in the same period in 2001. The equity income in 2001 primarily resulted from an investment in an electric generation plant in Boulder City, Nevada. The plant became operational in May 2000. We incurred charges for interest expense and distribution on trust preferred securities of $374 million and $356 million for the first six months of 2000 and 2001, respectively. The decrease resulted from a combination of lower levels of both short-term borrowings and long-term debt and lower interest rates in the first six months of 2001 compared to the same period in 2000. Other income increased by $27 million during the first six months of 2001 compared to 2000 primarily due to increased interest income from our Electric Operations and Wholesale Energy segments and a pre-tax impairment loss of $22 million recorded in 2000 related to certain marketable securities, partially offset by a $15 million gain related to the sale of a development-stage project in 2000 and a federal tax refund in 2000. For additional information regarding our investment equity securities noted above, see Note 2(l) to Reliant Energy 10-K Notes. During the second quarter of 2001, we recorded minority interest expense of $23.8 million related to the minority interest in Reliant Resources. The effective tax rate for the first six months of 2000 and 2001 was 31% and 35%, respectively. As discussed in Note 12(e) to our Interim Financial Statements, the Transition Act allocated to the Dutch generation sector, including REPGB, financial responsibility for SEP's obligations to purchase electricity and gas under a gas supply contract and three electricity contracts. As a result of the above, we recorded an out-of-market, net stranded cost liability of $169 million and a related deferred tax asset of $61 million at June 30, 2001 for our statutorily allocated share of these gas supply and electricity contracts. We believe that the costs incurred by REPGB subsequent to the tax holiday ending in 2001 related to these contracts will be deductible for Dutch tax 24
27 purposes. However, due to the uncertainties related to the deductibility of these costs, we have recorded a reserve in other liabilities in our Interim Financial Statements of $61 million as of June 30, 2001. The table below shows operating income (loss) by segment:
28 growth and decreased amortization expense offset by a reduction in revenues due to milder weather and reduced rates for certain governmental agencies as mandated by Texas deregulation legislation and increased tax expenses. Base revenues decreased $18 million and $3 million for the quarter and six months ended June 30, 2001, respectively, primarily due to milder weather compared to prior year and a reduction in revenues due to reduced rates for certain governmental agencies as mandated by Texas deregulation legislation. These decreases were partially offset by customer growth. Reconcilable fuel revenues and fuel and purchased power expenses for the quarter and six months ended June 30, 2001 increased as a result of an increase in the price of natural gas ($3.59 and $4.85 per MMBtu in the second quarters of 2000 and 2001, respectively, and $3.25 and $5.64 per MMBtu for the first six months of 2000 and 2001, respectively). Operation and maintenance expenses and other operating expenses for the second quarter of 2001 decreased by $32 million and increased by $12 million, respectively, when compared to the same period in 2000. The decrease in operation and maintenance expenses is largely due to the timing of software and hardware maintenance costs and decreases in labor related costs and other operations and maintenance expenses. The increase in other operating expenses is primarily due to an increase in franchise tax requirements resulting from increased revenues. Operation and maintenance expenses and other operating expenses for the first six months of 2001 increased by $6 million and $25 million, respectively, when compared to the same period in 2000. The increase in operation and maintenance expense is primarily due to higher benefit costs partially offset by decreased legal fees. The increase in other operating expenses is primarily due to an increase in franchise tax requirements resulting from increased revenues. Depreciation and amortization expense for the quarter and six months ended June 30, 2001 decreased $15 million and $35 million, respectively, compared to the same periods in 2000. The decrease was primarily due to a decrease in amortization of the book impairment regulatory asset recorded in June 1999 and decreased amortization expense due to regulatory assets related to cancelled projects being fully amortized in June 2000. For information regarding items that affect depreciation and amortization expense of Electric Operations pursuant to the Legislation and the Transition Plan, see Notes 2(g) and 4(a) to Reliant Energy 10-K Notes. NATURAL GAS DISTRIBUTION Our Natural Gas Distribution segment's operations consist of intrastate natural gas sales to, and natural gas transportation for residential, commercial and industrial customers in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas and some non-rate regulated retail marketing of natural gas.
29 Our Natural Gas Distribution segment's operating loss increased $37 million and operating income decreased $7 million for the quarter and six months ended June 30, 2001 as compared to the same periods in 2000. The increase in the loss for the quarter was largely due to increased bad debt expense in addition to changes in estimates of unbilled revenues and recoverability of deferred gas accounts and other items. The decrease in income for the first six months in 2001 compared to the same period in 2000 is primarily due to increased bad debt expense, in addition to changes in estimates of unbilled revenues and recoverability of deferred gas accounts and other items, partially offset by improved margins from colder weather and reduced operation and maintenance expense due to exiting certain retail gas markets during 2000. PIPELINES AND GATHERING Our Pipelines and Gathering segment operates two interstate natural gas pipelines and provides gathering and pipeline services.
30
31 EUROPEAN ENERGY Our European Energy segment includes the operations of Reliant Energy Power Generation Benelux N.V. (REPGB) and its subsidiaries and our European trading, marketing and risk management operations. Our European Energy segment generates and sells power from its generation facilities in the Netherlands and participates in the emerging wholesale energy trading and marketing industry in Europe. Beginning January 1, 2001, the Dutch wholesale electric market was completely opened to competition. Consistent with our expectations at the time we made the acquisition, REPGB has experienced a significant decline in electric margins in 2001 attributable to the deregulation of the market. For additional information on these and other factors that may affect the future results of operations of European Energy, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations - Certain Factors Affecting Our Future Earnings - Competitive, Regulatory and Other Factors Affecting Our European Energy Operations" in the Reliant Energy Form 10-K, which information is incorporated herein by reference.
32 operations. For information regarding the benefit charge incurred in the first quarter of 2001, see Note 13 to our Interim Financial Statements. During the third quarter of 2001, we decided to evaluate strategic alternatives, including divestiture, partnerships with other market participants or other strategic alternatives, for our Communications business which serves as a facility-based competitive local exchange carrier and Internet services provider as well as network operations centers and managed data centers in Houston and Austin. We do not believe the disposition or other strategic alternatives of this business will have a material adverse effect on our consolidated financial condition, results of operations or cash flows in 2001 and in future periods. CERTAIN FACTORS AFFECTING OUR FUTURE EARNINGS GENERAL For information on other developments, factors and trends that may have an impact on our future earnings, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Certain Factors Affecting Our Future Earnings" in the Reliant Energy Form 10-K, which is incorporated herein by reference. For additional information regarding the California wholesale market and related litigation, please read Notes 12(a) and 12(d) to our Interim Financial Statements. ELECTRIC OPERATIONS In contemplation of open competition, our Electric Operations segment has been allowed since 1998 under our Transition Plan approved by the Texas Utility Commission and the Legislation to earn base revenues which produced earnings in excess of traditional regulated levels. These excess earnings have been utilized to mitigate stranded cost of generation plants by accelerating the depreciation of these assets for regulatory purposes. This transition to competition period is scheduled to end on December 31, 2001. At that time, and in accordance with the Legislation, we expect our Electric Operations segment will be unbundled pursuant to our business separation plan (please read Notes 4(a) and 4(b) to Reliant Energy 10-K Notes) into three distinct businesses: a transmission and distribution company, a power generation company and a retail company. New rates based on the allowed invested capital, or "rate base", of the transmission and distribution business will be implemented beginning on January 1, 2002. For more information regarding the interim rulings in the rate case for the transmission and distribution company, please read Note 12(f) to our Interim Financial Statements. The retail business will be conducted by a subsidiary of Reliant Resources. The generation business will sell power via capacity auctions at market rates. However, the Legislation provides that during the 2004 stranded cost true-up (please read Note 4(a) to Reliant Energy 10-K Notes), a true-up amount will be calculated which will be recovered from or returned to customers to adjust the market revenues earned from the capacity auctions to a level that would approximate a regulated return on the invested capital of the generation business. Thus, beginning in 2002, earnings of our Electric Operations segment will be reduced to near traditional regulated returns independent of any additional positive or negative cash flows which may result from implementation of competitive transition charges received from customers or other credits to customers, as applicable. Accordingly, the results of operations of our Electric Operations segment post-competition will significantly decline. FINANCIAL CONDITION The following table summarizes the net cash provided by (used in) operating, investing and financing activities for the six months ended June 30, 2000 and 2001.
33 Net cash provided by operating activities during the six months ended June 30, 2001 increased $400 million compared to the same period in 2000 primarily due to improved operating cash flows from Wholesale Energy and a decrease in margin deposits on energy trading activities partially offset by changes in working capital. Net cash used in investing activities decreased $2.9 billion during the six months ended June 30, 2001 compared to the same period in 2000 primarily due to the funding of the remaining purchase obligation for REPGB for $982 million on March 1, 2000 and the acquisition of REMA for $2.1 billion on May 12, 2000, partially offset by an increase in capital expenditures related to the construction of domestic power generation projects during the six months ended June 30, 2001. Cash flows provided by financing activities decreased $3.4 billion during the six months ended June 30, 2001 compared to the same period in 2000 primarily due to a decline in short-term borrowings, partially offset by $1.7 billion in net proceeds from the initial public offering of Reliant Resources. FUTURE SOURCES AND USES OF CASH FLOWS Credit Facilities. As of June 30, 2001, we had credit facilities in effect, including facilities of various financing subsidiaries and operating subsidiaries, which provided for an aggregate of $7.4 billion in committed credit, of which $4.0 billion was scheduled to expire in 2001. As of June 30, 2001, $4.4 billion was outstanding under these facilities including other borrowings of $3.8 billion and letters of credit of $0.6 billion. The remaining unused credit facilities totaled $3.0 billion. To the extent that we continue to need access to this amount of committed credit, we expect to extend or replace these facilities on normal commercial terms on a timely basis. In May 2001, aggregate bank facilities and aggregate amount of commercial paper that can be offered were reduced by $1.7 billion, the amount of net proceeds from the Offering. Debt Refinancing. In July 2001, various financing subsidiaries terminated several bank credit facilities and entered into new bank credit facilities which increased the aggregate amount of bank facilities at financing subsidiaries to $4.3 billion. The new bank facilities expire in July 2002 and are expected to support the issuance of commercial paper. In connection with the termination of a Euro 560 million bank facility, financing subsidiary bank loans of Euro 560 million were refinanced with U.S. dollar denominated commercial paper issued by a financing subsidiary. Shelf Registrations. At June 30, 2001, Reliant Energy had shelf registration statements providing for the issuance of $230 million aggregate liquidation value of our preferred stock, $580 million aggregate principal amount of our debt securities and $125 million of trust preferred securities and related junior subordinated debt securities. In addition, Reliant Energy had a shelf registration for 15 million shares of its common stock, which would have been worth $483 million as of June 30, 2001 based on the closing price of its common stock as of that date. In January 2001, RERC Corp. filed a shelf registration statement for $600 million of unsecured unsubordinated debt securities of which $550 million was issued in February 2001. RERC Corp. Debt Issuance. In February 2001, RERC Corp. issued $550 million aggregate principal amount of unsecured unsubordinated notes that bear interest at 7.75% per year and mature in February 2011. Net proceeds to RERC Corp. were $545 million. RERC Corp. used the net proceeds from the sale of the notes to pay a $400 million dividend to Reliant Energy, and for general corporate purposes. Reliant Energy used the $400 million proceeds from the dividend for general corporate purposes, including the repayment of short-term borrowings. Securitization. Reliant Energy HL&P filed an application with the Texas Utility Commission requesting a financing order authorizing the issuance by a special purpose entity organized by us, of transition bonds relating to Reliant Energy HL&P's generation related regulatory assets. In May 2000, the Texas Utility Commission issued a financing order to Reliant Energy authorizing the issuance of transition bonds for the recovery of costs associated with generation-related regulatory assets in the amount of $738 million plus issuance costs of up to $11 million. Payments on the transition bonds will be made out of funds derived from non-bypassable transition charges assessed to users of Reliant Energy HL&P's transmission and distribution services. The offering of the transition bonds is expected to be consummated during the third quarter of 2001. Fuel Filing. As of June 30, 2001, Reliant Energy HL&P was under-collected on fuel recovery by approximately $667 million. In two separate filings with the Texas Utility Commission in 2000, Reliant Energy 31
34 HL&P received approval to implement fuel surcharges to collect the under-recovery of fuel expenses, as well as to adjust the fuel factor to compensate for significant increases in the price of natural gas. On March 15, 2001, Reliant Energy HL&P filed with the Texas Utility Commission to revise its fuel factor and address its undercollected fuel costs of $389 million, which is the accumulated amount since September 2000 through February 2001, plus estimates for March and April 2001. Reliant Energy HL&P requested to revise its fixed fuel factor to be implemented with the May 2001 billing cycle and proposed to defer the collection of the $389 million until the 2004 stranded costs true-up proceeding. On April 16, 2001, the Texas Utility Commission issued an order approving interim rates effective with the May 2001 billing cycle. On June 21, 2001, Reliant Energy HL&P filed with the Texas Utility Commission to terminate the interim factor and return to the prior fuel factor due to the forecasted decline in natural gas prices. On July 20, 2001, the Texas Utility Commission issued an order of dismissal approving Reliant Energy HL&P's request that the interim rates approved on April 16, 2001, effective with Reliant Energy HL&P's May billing month, be terminated and Reliant Energy HL&P prospectively bill its customers using the prior fuel factor established in a previous order beginning with Reliant Energy HL&P's August billing month. The Texas Utility Commission also granted Reliant Energy HL&P a good cause exception in that Reliant Energy HL&P will not be required to refund amounts collected through the interim rates. Reliant Energy HL&P did not waive its right to collect any final fuel balance. Initial Public Offering of Reliant Resources. On July 27, 2000, Reliant Energy announced its intention to form Reliant Resources to own and operate a substantial portion of Reliant Energy's unregulated operations, and to offer no more than 20% of the common stock of Reliant Resources in the Offering in connection with our business separation plan. In May 2001, Reliant Resources completed its initial public offering of 59.8 million shares of its common stock and received net proceeds of $1.7 billion. Pursuant to the terms of the master separation agreement, Reliant Resources used $147 million of the net proceeds to repay certain indebtedness owed to Reliant Energy. Reliant Resources used the remainder of the net proceeds to increase its working capital. Reliant Energy expects the Offering to be followed by a distribution of the remaining common stock of Reliant Resources owned by Reliant Energy to Reliant Energy's or its successor's shareholders within twelve months of the Offering. For additional information regarding our business separation plan, please read Note 4(b) to Reliant Energy 10-K Notes. Reliant Resources Stock Repurchase. During the third quarter of 2001, Reliant Resources purchased 840,000 shares of Reliant Resources common stock at an average price of $20.58 per share, or an aggregate purchase price of $17.3 million. These shares were purchased in anticipation of funding benefit plan obligations expected to be funded prior to the Distribution. The master separation agreement between Reliant Resources and Reliant Energy restricts the ability of Reliant Resources to issue shares of common stock prior to the separation of the two companies without the prior consent of Reliant Energy. Accordingly, Reliant Resources may make future purchases of its common stock in anticipation of funding pre-Distribution employee benefit plan obligations. Acquisition of Mid-Atlantic Assets. On May 12, 2000, we completed the acquisition of our Mid-Atlantic assets from Sithe Energies, Inc. for an aggregate purchase price of $2.1 billion. The acquisition was originally financed through commercial paper borrowings at one of our financing subsidiaries. In August 2000, we entered into separate sale/leaseback transactions with each of the three owner-lessors for our respective 16.45%, 16.67% and 100% interests in the Conemaugh, Keystone and Shawville generating stations, respectively, which we acquired as part of the Mid-Atlantic acquisition. For additional discussion of these lease transactions, please read Notes 3(a) and 14(c) to Reliant Energy 10-K Notes. As consideration for the sale of our interest in the facilities, we received a total of $1.0 billion in cash that was used to repay commercial paper borrowings at one of our financing subsidiaries. We will continue to make lease payments through 2029. The lease terms expire in 2034. Channelview Project. Our 781 MW gas-fired, combined cycle, cogeneration plant located in Channelview, Texas, which is currently under construction, is expected to cost $463 million, including $129 million in commitments for the purchase of combustion turbines. Of this amount, $348 million had been incurred as of June 30, 2001. The project continues to be financed through funds received under the terms of a committed equity bridge facility, which totals $92 million, a non-recourse debt facility aggregating $369 million and projected construction revenues of $2 million. Other Generating Projects. As of June 30, 2001, we had three additional non-rate regulated generating facilities under construction. Total estimated costs of constructing these facilities are $1.2 billion, including $349 million in commitments for the purchase of combustion turbines. As of June 30, 2001, we had incurred $513 million of the 32
35 total projected costs of these projects, which were funded primarily through short-term borrowings from various financing subsidiaries of Reliant Energy. We believe that our level of cash, our borrowing capability and proceeds from the initial public offering of Reliant Resources as discussed above will be sufficient to fund these commitments. In addition, we have options to purchase additional combustion turbines for a total estimated cost of $296 million for future generation projects. We believe that our current level of cash, our borrowing capability and proceeds from the initial public offering will be sufficient to fund these options should we choose to exercise them. Construction Agency Agreement. In April 2001, Reliant Resources, through several of its subsidiaries, entered into operative documents with special purpose entities to facilitate the development, construction, financing and leasing of several power generation projects. The special purpose entities have an aggregate financing commitment from equity and debt participants (Investors) of $2.5 billion. Reliant Resources, through several of its subsidiaries, acts as construction agent for the special purpose entities, and is responsible for completing construction of these projects by August 31, 2004, but has generally limited Reliant Resources' risk related to construction completion to less than 90% of project costs incurred to date, except in certain events. Upon completion of an individual project and exercise of the lease option, Reliant Resources' subsidiaries will be required to make lease payments in an amount sufficient to provide a return to the Investors. If Reliant Resources does not exercise its option to lease any project upon its completion, it must purchase the project or remarket the project on behalf of the special purpose entities. At the end of an individual project's operating lease term (approximately five years from construction completion), the lessees have the option to extend the lease at fair market value, purchase the project at a fixed amount equal to the original construction cost, or act as remarketing agent and sell the project to an independent third party. If the lessees elect the remarketing option, they may be required to make a payment up to 85% of the project cost if the proceeds from remarketing are deficient to repay the Investors. Reliant Resources has guaranteed the performance and payment of its subsidiaries' obligations during the construction periods and, if the lease option is exercised, the lessee's obligations during the lease period. California Trade Receivables. During the summer and fall of 2000, and continuing into early 2001, prices for wholesale electricity in California increased dramatically as a result of a combination of factors, including higher natural gas prices and emissions allowance costs, reduction in available hydroelectric generation resources, increased demand, decreases in net electric imports, structural market flaws including over-reliance on the spot market, and limitations on supply as a result of maintenance and other outages. Although wholesale prices increased, California's deregulation legislation kept retail rates frozen below 1996 levels until rates were raised by the CPUC early this year. This caused two of California's public utilities, which are our customers based on our deliveries to the Cal PX and the Cal ISO, to accrue billions of dollars of unrecovered wholesale power costs and ultimately default in January and February 2001 on payments owed for wholesale power purchased through the Cal PX and from the Cal ISO, and in the case of Pacific Gas and Electric Company, to file a voluntary petition for bankruptcy. As of June 30, 2001, we were owed $318 million by the Cal ISO, the Cal PX, the CDWR and California Energy Resource Scheduling for energy sales in the California wholesale market during the fourth quarter of 2000 through June 30, 2001 and have recorded an allowance against such receivables of $76 million. From July 1, 2001 through August 6, 2001, we have collected none of these receivable balances. For additional information regarding uncertainties in the California wholesale market, please read Notes 12(a) and 12(d) to our Interim Financial Statements and Notes 14(g) and 14(h) to Reliant Energy 10-K Notes. Reliant Energy HL&P Rate Matters. The Texas Utility Commission has issued an interim order on June 5, 2001 requiring Reliant Energy HL&P to reverse the amount of redirected depreciation and accelerated depreciation since it was in the Texas Utility Commission's estimation that the utility had overmitigated its stranded costs. We disagree with certain positions prescribed in the interim order by the Texas Utility Commission and will determine future action based on the final order anticipated in August 2001. At June 30, 2001, cumulative redirected depreciation and cumulative accelerated depreciation for regulatory purposes totaled $725 million and approximately $1 billion, respectively. If implemented, the reversal of redirected depreciation would result in a lower rate for the transmission and distribution utility and the accelerated depreciation being returned through credits over seven years would serve as offsets to the transmission and distribution utility's non-bypassable charges. The rates derived from the Texas Utility Commission's June 5, 2001 interim order will be used during the retail electric pilot project which began on July 31, 2001. We do not expect the final Reliant Energy HL&P transmission and distribution rate to be established until the end of August 2001 and implemented until January 1, 2002. The credits related to accelerated depreciation will begin on January 1, 2002. For information regarding redirected depreciation and accelerated depreciation, see Note 4(a) to Reliant Energy 10-K Notes. Florida Tolling Arrangement. In the first quarter of 2001, our Wholesale Energy segment entered into tolling arrangements with a third party to purchase the rights to utilize and dispatch electric generating capacity of 33
36 approximately 1,100 MW. This electricity is expected to be generated by two gas-fired, simple-cycle peaking plants, with fuel oil backup, to be constructed by the tolling partner in Florida, which are anticipated to be completed by the summer of 2002, at which time we will commence tolling payments. Other Sources/Uses of Cash. Our liquidity and capital requirements are affected primarily by capital expenditures, debt service requirements and various working capital needs. We expect to continue to bid on future acquisitions of independent power projects and privatizations of generation facilities. We expect any resulting capital requirements to be met with excess cash flows from operations, as well as proceeds from debt and equity offerings, project financings and other borrowings. We also expect Reliant Resources to establish a commercial paper program in late 2001 or the first half of 2002. Additional capital expenditures depend upon the nature and extent of future project commitments, some of which may be substantial. We believe that our current level of cash, our borrowing capability and proceeds from the Reliant Resources initial public offering discussed above, along with future cash flows from operations, will be sufficient to meet the existing operational needs of our businesses for the next twelve months. NEW ACCOUNTING PRONOUNCEMENTS In July 2001, the FASB issued SFAS No. 141 and SFAS No. 142. SFAS No. 141 requires business combinations initiated after June 30, 2001 to be accounted for using the purchase method of accounting, and broadens the criteria for recording intangible assets separate from goodwill. Recorded goodwill and intangibles will be evaluated against these new criteria and may result in certain intangibles being transferred to goodwill, or alternatively, amounts initially recorded as goodwill may be separately identified and recognized apart from goodwill. Under SFAS No. 142, a nonamortization approach, goodwill and certain intangibles with indefinite lives will not be amortized into results of operations, but instead would be reviewed periodically for impairment and written down and charged to results of operations only in the periods in which the recorded value of goodwill and certain intangibles with indefinite lives is more than its fair value. The provisions of each statement which apply to goodwill and intangible assets acquired prior to June 30, 2001 will be adopted by us on January 1, 2002. We are in the process of determining the effect of adoption of SFAS No. 141 and SFAS No. 142 on our consolidated financial statements. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK INTEREST RATE RISK At June 30, 2001, we had issued fixed-rate debt and Trust Preferred Securities aggregating $5.6 billion in principal amount having a fair value of $6.1 billion. The fair value of these instruments would increase by approximately $541 million if interest rates were to decline by 10% from their levels at June 30, 2001. Our floating-rate obligations aggregated $4.1 billion at June 30, 2001 (please read Note 10 to Reliant Energy 10-K Notes) inclusive of (a) amounts borrowed under our short-term and long-term credit facilities (including the issuance of commercial paper supported by these facilities), (b) borrowings under a receivables facility and (c) amounts subject to a master leasing agreement under which lease payments vary depending on short-term interest rates. If the floating rates were to increase by 10% from June 30, 2001 levels, our consolidated interest expense and expense under operating leases would increase by a total of approximately $2 million each month in which such increase continued. In November 1998, RERC Corp. sold $500 million aggregate principal amount of its 6 3/8% Term Enhanced Remarketable Securities (TERM Notes) which included an embedded option to remarket the securities. The option is expected to be exercised in the event that the ten-year Treasury rate in 2003 is below 5.66%. At June 30, 2001, we could terminate the option at a cost of $18 million. A decrease of 10% in the June 30, 2001 level of interest rates would increase the cost of termination of the option by approximately $12 million. As discussed in Note 8(c) to Reliant Energy 10-K Notes, upon adoption of SFAS No. 133 effective January 1, 2001, the ZENS obligation was bifurcated into a debt component of $122 million and a derivative component of $788 million. Changes in the fair value of the derivative component will be recorded in our Statements of Consolidated Income and, therefore, we are exposed to changes in the fair value of the derivative component as a result of changes in the underlying risk-free interest rate. If the risk-free interest rate were to increase by 10% from June 30, 2001 levels, the fair value of the derivative component would increase by approximately $13 million, which would be recorded as a loss in our Statements of Consolidated Income. 34
37 During the six months ended June 30, 2001, we entered into interest rate swaps for the purpose of decreasing the amount of debt subject to interest rate fluctuations. At June 30, 2001, these interest rate swaps had an aggregate notional amount of $1.6 billion and a nominal fair value. A decrease of 10% in the June 30, 2001 level of interest rates would not increase the cost of termination of the swaps by a material amount. For information regarding the accounting for these interest rate swaps, see Note 3 to our Interim Financial Statements. EQUITY MARKET RISK As discussed in Note 8 to Reliant Energy 10-K Notes, we own approximately 26 million shares of AOL Time Warner Inc. common stock (AOL TW Common), which we hold to facilitate our ability to meet our obligations under the ZENS. Please read Note 8 to Reliant Energy 10-K Notes for a discussion of the effect of adoption of SFAS No. 133 on our ZENS obligation and our historical accounting treatment of our ZENS obligation. Subsequent to adoption of SFAS No. 133, a decrease of 10% from the June 30, 2001 market value of AOL TW Common would result in a loss of approximately $3 million, which would be recorded as a loss in our Statements of Consolidated Income. FOREIGN CURRENCY EXCHANGE RATE RISK As of June 30, 2001, we had entered into foreign currency swaps and foreign exchange forward contracts and have issued Euro-denominated debt to hedge our net European investment. Changes in the value of the swaps, forwards and debt are recorded as foreign currency translation adjustments as a component of accumulated other comprehensive income (loss) in stockholders' equity. As of June 30, 2001, we had recorded a $3 million gain in cumulative net translation adjustments. The cumulative translation adjustments will be realized in earnings and cash flows only upon the disposition of the related investments. As of June 30, 2001, our European Energy segment had entered into transactions to purchase approximately $103 million at fixed exchange rates in order to hedge future fuel purchases payable in U.S. dollars. As of June 30, 2001, the fair value of these financial instruments was a $3 million asset. An increase in the value of the Euro of 10% compared to the U.S. dollar from its June 30, 2001 level would result in an additional loss in the fair value of these foreign currency financial instruments of $8 million. For information regarding the accounting for these financial instruments, see Note 3 to our Interim Financial Statements. COMMODITY PRICE RISK We assess the risk of our non-trading derivatives (Energy Derivatives) using a sensitivity analysis method, and we assess the risk of our trading derivatives (Trading Derivatives) using the value-at-risk (VAR) method, in order to maintain our total exposure within management-prescribed limits. The sensitivity analysis performed on our Energy Derivatives measures the potential loss in earnings based on a hypothetical 10% movement in energy prices. An increase of 10% in the market prices of energy commodities from their June 30, 2001 levels would have decreased the fair value of our Energy Derivatives from their levels on those respective dates by $50 million. We utilize the variance/covariance model of VAR, which is a probabilistic model that measures the estimated risk of loss to earnings in market sensitive instruments based on historical experience. With respect to Trading Derivatives, our highest, lowest and average monthly VAR were $8 million, $4 million and $6 million, respectively, during the second quarter of 2001 and $12 million, $4 million and $7 million, respectively, during the first six months of 2001 based on a 95% confidence level and a one day holding period. During the second quarter of 2000, our highest, lowest and average monthly VAR were $9 million, $2 million and $4 million, respectively, and during the first six months of 2000, our highest, lowest and average monthly VAR were $9 million, $1 million and $3 million, respectively, based on a 95% confidence level and a one day holding period. We cannot assure you that market volatility, failure of counterparties to meet their contractual obligations, transactions entered into after the date of this Form 10-Q or a failure of risk controls will not lead to significant losses from our marketing and risk management activities. 35
38 RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES (A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED) STATEMENTS OF CONSOLIDATED OPERATIONS (THOUSANDS OF DOLLARS) (UNAUDITED)
39 RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES (A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED) CONSOLIDATED BALANCE SHEETS (THOUSANDS OF DOLLARS) (UNAUDITED) ASSETS
40 RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES (A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED) CONSOLIDATED BALANCE SHEETS (THOUSANDS OF DOLLARS) -- (CONTINUED) (UNAUDITED) LIABILITIES AND STOCKHOLDER'S EQUITY
41 RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES (A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED) STATEMENTS OF CONSOLIDATED CASH FLOWS (THOUSANDS OF DOLLARS) (UNAUDITED)
42 RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (1) BASIS OF PRESENTATION See Note 1 to Reliant Energy's Interim Financial Statements. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. RERC's Interim Financial Statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective periods. Amounts reported in RERC's Statements of Consolidated Operations are not necessarily indicative of amounts expected for a full year period due to the effects of, among other things, (a) seasonal variations in energy consumption, (b) timing of maintenance and other expenditures and (c) acquisitions and dispositions of assets and other interests. In addition, certain amounts from the prior year have been reclassified to conform to RERC's presentation of financial statements in the current year. These reclassifications do not affect earnings of RERC. RERC's Interim Financial Statements are unaudited, omit certain financial statement disclosures and should be read with the combined Annual Report on Form 10-K of Reliant Energy (Reliant Energy Form 10-K) and RERC Corp. (RERC Corp. Form 10-K) for the year ended December 31, 2000, Reliant Energy First Quarter 10-Q and RERC Corp. First Quarter 10-Q. The following notes to the financial statements in the RERC Corp. Form 10-K relate to certain contingencies. These notes, as updated herein, are incorporated herein by reference: Notes to Consolidated Financial Statements (RERC Corp. 10-K Notes): Note 2(f) (Regulatory Assets), Note 4 (Derivative Financial Instruments) and Note 9 (Commitments and Contingencies). For information regarding environmental matters and legal proceedings, see Note 11 to RERC's Interim Financial Statements. (2) NEW ACCOUNTING PRONOUNCEMENTS In July 2001 the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 141 "Business Combinations" (SFAS No. 141) and SFAS No. 142 "Goodwill and Other Intangible Assets " (SFAS No. 142). SFAS No. 141 requires business combinations initiated after June 30, 2001 to be accounted for using the purchase method of accounting, and broadens the criteria for recording intangible assets separate from goodwill. Recorded goodwill and intangibles will be evaluated against these new criteria and may result in certain intangibles being transferred to goodwill, or alternatively, amounts initially recorded as goodwill may be separately identified and recognized apart from goodwill. Under SFAS No. 142, a nonamortization approach, goodwill and certain intangibles with indefinite lives will not be amortized into results of operations, but instead would be reviewed periodically for impairment and written down and charged to results of operations only in the periods in which the recorded value of goodwill and certain intangibles with indefinite lives is more than its fair value. The provisions of each statement which apply to goodwill and intangible assets acquired prior to June 30, 2001 will be adopted by RERC on January 1, 2002. RERC is in the process of determining the effect of adoption of SFAS No. 141 and SFAS No. 142 on its consolidated financial statements. (3) DERIVATIVE FINANCIAL INSTRUMENTS Adoption of SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities" as amended (SFAS No. 133) on January 1, 2001 resulted in a cumulative after-tax decrease in accumulated other comprehensive loss of $38 million. The adoption also increased current assets, long-term assets, current liabilities and long-term liabilities by $88 million, $5 million, $53 million and $2 million, respectively, in RERC's Consolidated Balance Sheet. During the six months ended June 30, 2001, $27 million of the initial transition adjustment recognized in other comprehensive income (loss) was realized in net income. 40
43 The application of SFAS No. 133 is still evolving as the FASB clears issues submitted to the Derivatives Implementation Group for consideration. The FASB approved a number of issues regarding the normal purchases and normal sales exception in the second quarter. One issue concludes forward contracts with volumetric optionality do not qualify for the normal purchases and normal sales exception, while another issue applies exclusively to the electric industry and allows the normal purchases and normal sales exception for option-type contracts if certain criteria are met. The effective date for implementation of these decisions is July 1, 2001. RERC is currently assessing the impact of the recently cleared issues and does not believe they will have a material impact on RERC's Consolidated Financial Statements. Cash Flow Hedges. During the six months ended June 30, 2001, the amount of hedge ineffectiveness recognized in earnings from derivatives that are designated and qualify as cash flow hedges was immaterial. No component of the derivative instruments' gain or loss was excluded from the assessment of effectiveness. During the six months ended June 30, 2001, there were no deferred gains or losses recognized in earnings as a result of the discontinuance of cash flow hedges because it was no longer probable that the forecasted transaction would occur. As of June 30, 2001, current non-trading derivative assets and liabilities and corresponding amounts in accumulated other comprehensive loss are expected to be reclassified into net income during the next twelve months. The maximum length of time RERC is hedging its exposure to the variability in future cash flows for forecasted transactions is two years. (4) RELIANT ENERGY'S SEPARATION PLAN In 2000, Reliant Energy announced its intention to divide into two publicly traded companies in order to separate its unregulated businesses from its regulated businesses. In August 2000, Reliant Energy formed Reliant Resources to own and operate a substantial portion of Reliant Energy's unregulated operations and to offer no more than 20% of Reliant Resources' common stock in an initial public offering. In May 2001, Reliant Resources offered 59.8 million shares of its common stock to the public in an initial public offering and received net proceeds of $1.7 billion. Reliant Energy expects to distribute the remaining common stock of Reliant Resources it owns to Reliant Energy's or its successor's shareholders within twelve months after the completion of Reliant Resources' initial public offering. On December 31, 2000, RERC Corp. transferred all of the outstanding stock of Reliant Energy Services International, Inc. (RESI), Arkla Finance Corporation (Arkla Finance) and Reliant Energy Europe Trading & Marketing, Inc. (RE Europe Trading), all wholly owned subsidiaries of RERC Corp., to Reliant Resources (collectively, the Stock Transfer). Both RERC Corp. and Reliant Resources are subsidiaries of Reliant Energy. As a result of the Stock Transfer, RESI, Arkla Finance and RE Europe Trading each became a wholly owned subsidiary of Reliant Resources. Also, on December 31, 2000, a wholly owned subsidiary of Reliant Resources merged with and into Reliant Energy Services, Inc. (Reliant Energy Services), a wholly owned subsidiary of RERC Corp., with Reliant Energy Services as the surviving corporation (Merger). As a result of the Merger, Reliant Energy Services became a wholly owned subsidiary of Reliant Resources. As consideration for the Merger, Reliant Resources paid $94 million to RERC Corp. Prior to January 1, 2001, Reliant Energy Services, RESI and RE Europe Trading conducted the trading, marketing, power origination and risk management business and operations of RERC. Arkla Finance is a company that holds an investment in marketable equity securities. The Stock Transfer and the Merger are part of Reliant Energy's previously announced restructuring. RERC is reporting the results of RE Europe Trading as discontinued operations for all periods presented in RERC's Interim Financial Statements in accordance with Accounting Principles Board Opinion No. 30 (APB No. 30). 41
44 (5) DISCONTINUED OPERATIONS As discussed in Note 4, on December 31, 2000, RERC transferred all of the outstanding stock of RE Europe Trading to Reliant Resources. As a result of the transfer, RERC is reporting the results of RE Europe Trading as discontinued operations for all periods presented in RERC's Interim Financial Statements in accordance with APB No. 30. Below is a table of the operating results of RE Europe Trading for the three and six months ended June 30, 2000.
45 (9) COMPREHENSIVE INCOME The following table summarizes the components of total comprehensive (loss) income.
46 (11) ENVIRONMENTAL MATTERS AND LEGAL PROCEEDINGS (a) Environmental Matters. Manufactured Gas Plant Sites. RERC and its predecessors operated a manufactured gas plant (MGP) adjacent to the Mississippi River in Minnesota formerly known as Minneapolis Gas Works (MGW) until 1960. RERC has substantially completed remediation of the main site other than ongoing water monitoring and treatment. The manufactured gas was stored in separate holders. RERC is negotiating cleanup of one such holder. There are six other former MGP sites in the Minnesota service territory. Remediation has been completed on one site. Of the remaining five sites, RERC believes that two were neither owned nor operated by RERC. RERC believes it has no liability with respect to the sites it neither owned nor operated. At June 30, 2001, RERC had accrued $19 million for remediation of the Minnesota sites. At June 30, 2001, the estimated range of possible remediation costs was $8 million to $36 million. The cost estimates of the MGW site are based on studies of that site. The remediation costs for the other sites are based on industry average costs for remediation of sites of similar size. The actual remediation costs will be dependent upon the number of sites remediated, the participation of other potentially responsible parties, if any, and the remediation methods used. Issues relating to the identification and remediation of MGPs are common in the natural gas distribution industry. RERC has received notices from the United States Environmental Protection Agency and others regarding its status as a potentially responsible party (PRP) for other sites. Based on current information, RERC has not been able to quantify a range of environmental expenditures for potential remediation expenditures with respect to other MGP sites. Other Minnesota Matters. At June 30, 2001, RERC had recorded accruals of $4 million (with a maximum estimated exposure for these accruals of approximately $17 million at June 30, 2001) for other environmental matters in Minnesota for which remediation may be required. Mercury Contamination. RERC's pipeline and distribution operations have in the past employed elemental mercury in measuring and regulating equipment. It is possible that small amounts of mercury may have been spilled in the course of normal maintenance and replacement operations and that these spills may have contaminated the immediate area with elemental mercury. This type of contamination has been found by RERC at some sites in the past, and RERC has conducted remediation at these sites. It is possible that other contaminated sites may exist and that remediation costs may be incurred for these sites. Although the total amount of these costs cannot be known at this time, based on experience of RERC and that of others in the natural gas industry to date and on the current regulations regarding remediation of these sites, RERC believes that the costs of any remediation of these sites will not be material to RERC's financial condition, results of operations or cash flows. Potentially Responsible Party Notifications. From time to time RERC has received notices from regulatory authorities or others regarding its status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. Considering the information currently known about such sites and the involvement of RERC in activities at these sites, RERC does not believe that these matters will have a material adverse effect on RERC's financial condition, results of operations or cash flows. (b) Other Legal Matters. California Wholesale Market. Reliant Energy, Reliant Energy Services, Inc. (a wholly owned subsidiary of Reliant Resources), Reliant Energy Power Generation, Inc. (a wholly owned subsidiary of Reliant Resources) and several other indirect subsidiaries of Reliant Energy, as well as several officers of some of these companies, have been named as defendants in class action lawsuits and other lawsuits filed against a number of companies that own generation plants in California and other sellers of electricity in California markets. RERC Corp. has also been named as a defendant in one of the lawsuits. Pursuant to the terms of the master separation agreement between Reliant Energy and Reliant Resources (see Note 4(b) to Reliant Energy 10-K Notes), Reliant Resources has agreed to indemnify Reliant Energy and RERC Corp. for any damages arising under these lawsuits and may elect to defend these lawsuits at Reliant Resources' own expense. Three of these lawsuits were filed in the Superior Court of the State of California, San Diego County; two were filed in the Superior Court in San Francisco County; and one was filed in the Superior Court of Los Angeles County. While the plaintiffs allege various violations by the defendants of state antitrust laws and state laws against unfair and unlawful business practices, each of the lawsuits is grounded 44
47 on the central allegation that defendants conspired to drive up the wholesale price of electricity. In addition to injunctive relief, the plaintiffs in these lawsuits seek treble the amount of damages alleged, restitution of alleged overpayments, disgorgement of alleged unlawful profits for sales of electricity, costs of suit and attorneys' fees. In one of the cases the plaintiffs allege aggregate damages of over $4 billion. Defendants have removed all of these cases to federal court. The Judicial Panel on Multidistrict Litigation recently issued an order consolidating and transferring them to the Honorable Robert H. Whaley, a U.S. District Court Judge from the Eastern District of Washington, who is sitting by designation in San Diego, California. Judge Whaley was selected, in part, because the federal judges in California are potentially disqualified because they are ratepayers. The judges previously assigned to the cases in the Southern District and the Northern District of California recused themselves on these grounds. On June 27, 2001, Judge Whaley heard argument on plaintiffs' motions to remand five of the six cases back to state court. A motion to remand the sixth case has not been filed at this time. Judge Whaley issued a ruling on July 30, 2001, remanding the five cases back to state court. The ultimate outcome of the lawsuits cannot be predicted with any degree of certainty at this time. However, RERC believes, based on its analysis to date of the claims asserted in these lawsuits and the underlying facts, that resolution of these lawsuits will not have a material adverse effect on RERC's financial condition, results of operations or cash flows. Other. RERC is a party to litigation (other than that specifically noted) which arises in the normal course of business. Management regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. Management believes that the effects, if any, from the disposition of these matters will not have a material adverse effect on RERC's financial condition, results of operations or cash flows. (12) TRANSFER OF BENEFIT ASSETS AND LIABILITIES During the first quarter of 2001, RERC Corp. had net distributions to Reliant Energy related to benefit assets and obligations, net of deferred taxes, of $62 million. (13) REPORTABLE SEGMENTS Because RERC Corp. is a wholly owned subsidiary of Reliant Energy, RERC's determination of reportable segments considers the strategic operating units under which Reliant Energy manages sales, allocates resources and assesses performance of various products and services to wholesale or retail customers in differing regulatory environments. Segment financial data includes information for Reliant Energy and RERC on a combined basis, except for Reliant Energy segments that have no RERC operations in the applicable period. Reconciling items included under the caption "Elimination of Non-RERC Operations" reduce the consolidated Reliant Energy amounts by those operations not conducted within the RERC legal entity. Operations not owned or operated by RERC, but included in segment information before elimination include primarily the operations and assets of Reliant Energy's non-rate regulated power generation business in 2000 and Reliant Energy's investment in AOL Time Warner securities, retail electric start-up business and non-RERC corporate expenses in 2000 and 2001. Reliant Energy has identified the following reportable segments in which RERC has operations: Wholesale Energy, Natural Gas Distribution, Pipelines and Gathering and Other Operations. For descriptions of the financial reporting segments, see Note 12 to RERC Corp. 10-K Notes. The following table summarizes financial data for the business segments:
48
49 MANAGEMENT'S NARRATIVE ANALYSIS OF THE RESULTS OF OPERATIONS OF RERC CORP. AND SUBSIDIARIES The following narrative analysis should be read in combination with RERC Corp.'s Interim Financial Statements and notes contained in this Form 10-Q. RERC Corp. meets the conditions specified in General Instruction H(1)(a) and (b) to Form 10-Q and is therefore permitted to use the reduced disclosure format for wholly owned subsidiaries of reporting companies. Accordingly, RERC Corp. has omitted from this report the information called for by Item 3 (Quantitative and Qualitative Disclosures About Market Risk) of Part I and the following Part II items of Form 10-Q: Item 2 (Changes in Securities and Use of Proceeds), Item 3 (Defaults Upon Senior Securities) and Item 4 (Submission of Matters to a Vote of Security Holders). The following discussion explains material changes in the amount of revenue and expense items of RERC between the quarter and six months ended June 30, 2001 and the quarter and six months ended June 30, 2000. Reference is made to Management's Narrative Analysis of the Results of Operations in Item 7 of the RERC Corp. Form 10-K and the RERC Corp. 10-K Notes and RERC Corp. First Quarter 10-Q referred to herein. On July 27, 2000, Reliant Energy announced its intention to form Reliant Resources to own and operate a substantial portion of Reliant Energy's unregulated operations, and to offer no more than 20% of the common stock of Reliant Resources in an initial public offering (Offering) in connection with the Company's business separation plan. In May 2001, Reliant Resources completed its initial public offering of 59.8 million shares of its common stock and received net proceeds of $1.7 billion. Reliant Energy expects the Offering to be followed by a distribution of the remaining common stock of Reliant Resources owned by Reliant Energy to Reliant Energy's or its successor's stockholders within twelve months of the Offering (Distribution). As part of the separation, our parent company, Reliant Energy will undergo a restructuring of its corporate organization to achieve a new holding company structure. The new holding company will hold our regulated businesses. In connection with the formation of the new holding company, Reliant Energy will seek an exemption from the registration requirements of the 1935 Act or, if no exemption is available, the new holding company will register as a public utility holding company under the 1935 Act. The restructuring will require approval of the Securities and Exchange Commission, certain of the affected state commissions and the Nuclear Regulatory Commission. The Distribution is subject to further corporate approvals, market and other conditions, and government actions, including receipt of a favorable Internal Revenue Service ruling that the Distribution would be tax-free to Reliant Energy or its successor and its shareholders for U.S. federal income tax purposes, as applicable. There can be no assurance that the Distribution will be completed as described or within the time periods outlined above. On December 31, 2000, RERC Corp. transferred all of the outstanding stock of RESI, Arkla Finance and RE Europe Trading, all wholly owned subsidiaries of RERC Corp., to Reliant Resources (Stock Transfer). Both RERC Corp. and Reliant Resources are subsidiaries of Reliant Energy. As a result of the Stock Transfer, RESI, Arkla Finance and RE Europe Trading each became a wholly owned subsidiary of Reliant Resources. Also, on December 31, 2000, a wholly owned subsidiary of Reliant Resources merged with and into Reliant Energy Services, a wholly owned subsidiary of RERC Corp., with Reliant Energy Services as the surviving corporation (Merger). As a result of the Merger, Reliant Energy Services became a wholly owned subsidiary of Reliant Resources. As consideration of the Merger, Reliant Resources paid $94 million to RERC Corp. Reliant Energy Services, together with RESI and RE Europe Trading, conduct the trading, marketing, power origination and risk management business and operations of Reliant Energy. Arkla Finance is a company that held an investment in marketable equity securities. The Stock Transfer and the Merger are part of Reliant Energy's previously announced restructuring. RERC is reporting the results of RE Europe Trading as discontinued operations for all periods presented in the consolidated financial statements in accordance with APB No. 30. 47
50 CONSOLIDATED RESULTS OF OPERATIONS
51 decreases were partially offset by an increase in revenues related to the Natural Gas Distribution and Pipelines and Gathering segments resulting from an increase in the costs of natural gas and to a lesser extent the effect of cooler weather on the operations of the Natural Gas Distribution segment. Total operating expenses decreased by $3.0 billion and $3.7 billion for the quarter and six months ended June 30, 2001, respectively, as compared to the same periods in 2000. These decreases were primarily due to the same reasons for the decreases in revenues discussed above. RERC's effective tax rate for the first six months of 2000 and 2001 was 48% and 49%, respectively. RERC is reporting the results of RE Europe Trading as discontinued operations for all periods presented in RERC's consolidated financial statements in accordance with APB No. 30. For additional information regarding the operating results of the other entities transferred to Reliant Resources, please read Note 13 to RERC Corp. 10-K Notes and Notes 4 and 5 to RERC's Interim Financial Statements. Seasonality and Other Factors. RERC's results of operations are affected by seasonal fluctuations in the demand for and, to a lesser extent, the price of natural gas. RERC's results of operations are also affected by, among other things, the actions of various federal and state governmental authorities having jurisdiction over rates charged by RERC, competition in RERC's various business operations, debt service costs and income tax expense. For a discussion of certain other factors that may affect RERC's future earnings please read "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Certain Factors Affecting Our Future Earnings -- Competitive and Other Factors Affecting RERC Operations" "--Environmental Expenditures" and "-- Other Contingencies" in the Reliant Energy Form 10-K. NEW ACCOUNTING PRONOUNCEMENTS In July 2001, the FASB issued SFAS No. 141 and SFAS No. 142. SFAS No. 141 requires business combinations initiated after June 30, 2001 to be accounted for using the purchase method of accounting, and broadens the criteria for recording intangible assets separate from goodwill. Recorded goodwill and intangibles will be evaluated against these new criteria and may result in certain intangibles being transferred to goodwill, or alternatively, amounts initially recorded as goodwill may be separately identified and recognized apart from goodwill. Under SFAS No. 142, a nonamortization approach, goodwill and certain intangibles with indefinite lives will not be amortized into results of operations, but instead would be reviewed periodically for impairment and written down and charged to results of operations only in the periods in which the recorded value of goodwill and certain intangibles with indefinite lives is more than its fair value. The provisions of each statement which apply to goodwill and intangible assets acquired prior to June 30, 2001 will be adopted by us on January 1, 2002. We are in the process of determining the effect of adoption of SFAS No. 141 and SFAS No. 142 on our consolidated financial statements. 49
52 PART II. OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS. Reliant Energy: For a description of legal proceedings affecting Reliant Energy, please read Note 12 to Reliant Energy's Interim Financial Statements, Item 3 of the Reliant Energy Form 10-K and Notes 4 and 14 to Reliant Energy 10-K Notes, all of which are incorporated herein by reference. RERC Corp.: For a description of legal proceedings affecting RERC, please review Note 11 to RERC's Interim Financial Statements, Item 3 of the RERC Corp. Form 10-K and Note 9 to RERC Corp. 10-K Notes, which are incorporated herein by reference. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. Reliant Energy: At the annual meeting of Reliant Energy's shareholders held on May 2, 2001, the matters voted upon and the number of votes cast for, against or withheld, as well as the number of abstentions and broker non-votes as to such matters (including a separate tabulation with respect to each nominee for office) were as stated below: The following three nominees for Class II directors were elected to serve three-year terms expiring 2004 (there were no broker non-votes for any of the directors):
53 ITEM 5. OTHER INFORMATION. Forward-Looking Statements. From time to time, Reliant Energy and RERC Corp. make statements concerning their respective expectations, beliefs, plans, objectives, goals, strategies, future events or performance and underlying assumptions and other statements, which are not historical facts. These statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Although Reliant Energy and RERC Corp. believe that the expectations and the underlying assumptions reflected in their respective forward-looking statements are reasonable, they cannot assure you that these expectations will prove to be correct. Forward-looking statements involve a number of risks and uncertainties, and actual results may differ materially from the results discussed in the forward-looking statements. The following are some of the factors that could cause actual results to differ materially from those expressed or implied in forward-looking statements: o state, federal and international legislative and regulatory developments, including deregulation; re-regulation and restructuring of the electric utility industry; and changes in, or application of environmental and other laws and regulations to which we are subject, o the timing of the implementation of our business separation plan, o the effects of competition, including the extent and timing of the entry of additional competitors in our markets, o industrial, commercial and residential growth in our service territories, o our pursuit of potential business strategies, including acquisitions or dispositions of assets or the development of additional power generation facilities, o state, federal and other rate regulations in the United States and in foreign countries in which we operate or into which we might expand our operations, o the timing and extent of changes in commodity prices and interest rates, o weather variations and other natural phenomena, o political, legal and economic conditions and developments in the United States and in foreign countries in which we operate or into which we might expand our operations, including the effects of fluctuations in foreign currency exchange rates, o financial market conditions and the results of our financing efforts, o the performance of our projects, and o other factors we discuss in this and other filings by Reliant Energy and RERC Corp. with the Securities and Exchange Commission. When used in Reliant Energy's or RERC Corp.'s documents or oral presentations, the words "anticipate," "estimate," "believe," "continue," "could," "intend," "may," "plan," "potential," "predict," "should," "will," "expect," "objective," "projection," "forecast," "goal" and similar words are intended to identify forward-looking statements. 51
54 ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K. (a) Exhibits. Reliant Energy: Exhibit 3(a) Statement of Resolution Establishing Series of Shares designated as Series W Preference Stock. Exhibit 3(b) Statement of Resolution Establishing Series of Shares designated as Series X Preference Stock. Exhibit 99(a) Items incorporated by reference from the Reliant Energy Form 10-K: Item 3 "Legal Proceedings," Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations - Certain Factors Affecting Our Future Earnings" and Notes 2(f) (Summary of Significant Accounting Policies - Regulatory Assets), 3 (Business Acquisitions), 4 (Regulatory Matters), 5 (Derivative Financial Instruments), 8 (Indexed Debt Securities (ACES and ZENS) and AOL Time Warner Securities), 14 (Commitments and Contingencies) and 20 (Subsequent Events) of the Reliant Energy 10-K Notes. Exhibit 99(b) Items incorporated by reference from Reliant Energy March 31, 2001 Form 10-Q: Note 2 (Derivative Financial Instruments). RERC Corp.: Exhibit 99 Items incorporated by reference from the Reliant Energy Form 10-K: Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations - Certain Factors Affecting Our Future Earnings." Items incorporated by reference from the RERC Corp. Form 10-K: Item 3 "Legal Proceedings," Item 7 "Management's Narrative Analysis of the Results of Operations of RERC and its Consolidated Subsidiaries" and Notes 2(f) (Regulatory Assets), 4 (Derivative Financial Instruments) and 9 (Commitments and Contingencies) of the RERC Corp. 10-K Notes. (b) Reports on Form 8-K. Reliant Energy: None RERC Corp.: None 52
55 SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. RELIANT ENERGY, INCORPORATED (Registrant) By: /s/ Mary P. Ricciardello ---------------------------------------------- Mary P. Ricciardello Senior Vice President and Chief Accounting Officer Date: August 9, 2001 53
56 SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. RELIANT ENERGY RESOURCES CORP. (Registrant) By: /s/ Mary P. Ricciardello ----------------------------------------- Mary P. Ricciardello Senior Vice President Date: August 9, 2001 54
57 INDEX TO EXHIBITS
1 EXHIBIT 3(a) STATEMENT OF RESOLUTION ESTABLISHING SERIES OF SHARES designated SERIES W PREFERENCE STOCK of RELIANT ENERGY, INCORPORATED Pursuant to Article 2.13D of the Texas Business Corporation Act Pursuant to the provisions of Article 2.13D of the Texas Business Corporation Act, the undersigned corporation submits the following statement for the purpose of establishing and designating a series of shares of its Preference Stock, without par value, designated "Series W Preference Stock" and fixing and determining the relative rights and preferences thereof: 1. The name of the corporation is RELIANT ENERGY, INCORPORATED (the "Company"). 2. The following resolution establishing and designating a series of shares and fixing and determining the relative rights and preferences thereof, was duly adopted by all necessary action on the part of the Company on June 28, 2001: RESOLVED, that pursuant to the authority vested in the Finance Committee and the Preference Stock Committee, acting separately and/or concurrently, by the Board of Directors of this Company in accordance with the provisions of the Restated Articles of Incorporation, a series of Preference Stock, without par value, of the Company be and hereby is created, and that the designation and number of shares thereof and the preferences, limitations and relative rights, including voting rights, of the shares of such series and the qualifications, limitations and restrictions thereof are as follows: SERIES W PREFERENCE STOCK 1. Designation and Amount. There shall be a series of Preference Stock that shall be designated as "Series W Preference Stock," and the number of shares constituting such series shall be 26,300. Such number of shares may be increased or decreased by resolution of the Finance Committee and the Preference Stock Committee, acting separately and/or concurrently; provided, however, that no decrease shall reduce the number of shares of Series W Preference Stock to less than the number of shares then issued and outstanding plus the number of shares issuable upon exercise of outstanding rights, options or warrants or upon conversion of outstanding securities issued by the Company. -1-
2 2. Certain Defined Terms. Capitalized terms not otherwise defined herein shall have the respective meanings ascribed to them in that certain Senior A Credit Agreement (the "Senior A Credit Agreement") to be entered into among Houston Industries FinanceCo, LP, a Delaware limited partnership to be the Borrower thereunder, the Company, the lenders parties thereto and The Chase Manhattan Bank, as the Administrative Agent, on or after July 13, 2001. In addition, the following terms are used herein as defined below: (i) "Computed Dividend Portion" means, within any Dividend Interval Period, an amount equal to the interest expense accrued on the indebtedness for borrowed money of the Borrower from the prior Dividend Payment Date to the Determination Date for the current Dividend Interval Period. (ii) "Determination Date" means the date occurring five Business Days prior to a Dividend Declaration Date. (iii) "Dividend" means the dividend on the Series W Preference Stock declared by the Company's Board of Directors with respect to a Dividend Interval Period. (iv) "Dividend Declaration Amount" means, as of any Determination Date, the Preliminary Dividend Amount, less the sum of (a) the Interest Reconciliation Amount, (b) the Support Agreement Reconciliation Amount, and (c) the Other Sources Reconciliation Amount. The Dividend Declaration Amount may be greater than or less than the Preliminary Dividend Amount. (v) "Dividend Declaration Date" means the date on which Dividends on the Series W Preference Stock are declared (or would have been declared but for the fact that the amount of the Dividend determined in accordance herewith would have been zero) during a Dividend Interval Period by the Company's Board of Directors. (vi) "Dividend Interval Period" means the period beginning on a Dividend Payment Date and extending to the next Dividend Payment Date. (vii) "Dividend Payment Date" means the date occurring five Business Days after a Dividend Declaration Date. (viii) "Interest Reconciliation Amount" means an amount equal to (a) the Preliminary Dividend Amount computed for the prior Dividend Interval Period, less (b) the actual interest expense accrued on the indebtedness for borrowed money of the Borrower during such period. (ix) "Other Sources Reconciliation Amount" means the sum of (a) to the extent applied to pay interest on the indebtedness for borrowed money of the Borrower or available in cash on the current Determination Date therefor, the amount of income or cash proceeds received by the Borrower from sources other than pursuant to the Support Agreement (including, without limitation, interest received on loans to Affiliates), and (b) the cash proceeds of new borrowings under the Credit Agreement or any other Permitted -2-
3 Facility that are utilized to pay interest on outstanding borrowings thereunder, from the Determination Date occurring in the Prior Dividend Interval Period to the Determination Date occurring in the current Dividend Interval Period. (x) "Preliminary Dividend Amount" means the sum of the Computed Dividend Portion and the Projected Dividend Portion. (xi) "Projected Dividend Portion" means, within any Dividend Interval Period, an amount equal to the projected interest expense that will be accrued on the indebtedness for borrowed money of the Borrower from the Determination Date for such Dividend Interval Period to the Dividend Payment Date. (xii) "Support Agreement Reconciliation Amount" means the amount of cash payments made pursuant to the Support Agreement by the Company to the Borrower from the Determination Date occurring in the immediately prior Dividend Interval Period to the Determination Date occurring in the current Dividend Interval Period. 3. Dividends and Distributions. (A) Subject to the prior and superior rights of the holders of (i) any shares of any series of Preference Stock ranking prior and superior to the shares of Series W Preference Stock with respect to dividends and (ii) any shares of Preferred Stock, the holders of shares of Series W Preference Stock, in preference to the holders of shares of any class or series of stock of the Company ranking junior to the Series W Preference Stock, shall be entitled to receive the amounts set forth below, when, as and if declared by the Board of Directors in the manner described below out of assets of the Company legally available for the purpose: (i) On every regularly scheduled meeting of the Company's Board of Directors while any shares of Series W Preference Stock remain outstanding, the Board of Directors shall declare an aggregate Dividend (if a positive amount) equal to the lesser of (a) the Dividend Declaration Amount or (b) the Excess Cash Flow projected to be available as of the applicable Dividend Payment Date with respect to the then current Dividend Interval Period. (ii) If, with respect to any Dividend Interval Period, the aggregate Dividend declared by the Company's Board of Directors is less than the Dividend Declaration Amount for such Dividend Interval Period because the Excess Cash Flow projected to be available as of the applicable Dividend Payment Date is less than the Dividend Declaration Amount, the amount of such deficiency shall be added to the Dividend Declaration Amount computed for the next Dividend Interval Period and such aggregate amount shall become the Dividend Declaration Amount for such period. The Dividend for such succeeding Dividend Interval Period shall equal the Dividend Declaration Amount unless such amount would exceed the Excess Cash Flow projected to be available as of the applicable Dividend Payment Date, in which case the Dividend shall be the amount of the projected Excess Cash Flow. -3-
4 (iii) The aggregate Dividends paid on the shares of Series W Preference Stock in accordance with this Section 3(A) shall be allocated pro rata on a share-by-share basis among all such shares at the time outstanding. (B) Accrued but unpaid dividends shall not bear interest. The Board of Directors may fix a record date for the determination of holders of shares of Series W Preference Stock entitled to receive payment of a dividend or distribution declared thereon. 4. Voting Rights. Except as otherwise required by law or the Restated Articles of Incorporation of the Company or as otherwise provided herein, the holders of shares of Series W Preference Stock shall have no voting rights. 5. Certain Restrictions. At any time when dividends or distributions payable on the Series W Preference Stock as provided in Section 3 are in arrears, thereafter and until all accrued and unpaid dividends and distributions, whether or not declared, on shares of Series W Preference Stock outstanding shall have been paid in full, the Company shall not: (i) declare dividends on, or redeem or purchase or otherwise acquire for consideration any shares of stock ranking junior (either as to dividends or upon liquidation, dissolution or winding up) to the Series W Preference Stock; or (ii) declare dividends on any shares of stock ranking on a parity (either as to dividends or upon liquidation, dissolution or winding up) with the Series W Preference Stock, except dividends declared ratably on the Series W Preference Stock and all such parity stock on which dividends are payable or in arrears in proportion to the total amounts to which the holders of all such shares are then entitled. 6. Reacquired Shares. Any shares of Series W Preference Stock purchased or otherwise acquired by the Company in any manner whatsoever shall be retired and canceled promptly after the acquisition thereof. All such shares shall upon their cancellation become authorized but unissued shares of Preference Stock and may be reissued as part of a new series of Preference Stock to be created by resolution or resolutions of the Board of Directors, subject to any conditions and restrictions on issuance set forth herein. 7. Liquidation, Dissolution or Winding Up. (A) Upon any liquidation (voluntary or otherwise), dissolution or winding up of the Company, no distribution shall be made to the holders of shares of stock ranking junior (either as to dividends or upon liquidation, dissolution or winding up) to the Series W Preference Stock unless, prior thereto, the holders of shares of Series W Preference Stock shall have received $100,000 per share, plus an amount equal to accrued and unpaid dividends and distributions thereon, whether or not declared, to the date of such payment (the "Series W Liquidation Preference"). Following the payment of the full amount of the Series W Liquidation Preference, no additional distributions shall be made to the holders of shares of Series W Preference Stock. (B) In the event that there are not sufficient assets available to permit payment in full of the Series W Liquidation Preference and the liquidation preferences of all other series -4-
5 of Preference Stock, if any, that rank on a parity with the Series W Preference Stock, then such remaining assets shall be distributed ratably to the holders of such parity shares in proportion to their respective liquidation preferences. (C) Neither the merger or consolidation of the Company into or with another corporation nor the merger or consolidation of any other corporation into or with the Company shall be deemed to be a liquidation, dissolution or winding up of the Company within the meaning of this Section 7, but the sale, lease or conveyance of all or substantially all of the Company's assets shall be deemed to be a liquidation, dissolution or winding up of the Company within the meaning of this Section 7. 8. Redemption. (A) The Company, at its option, may redeem shares of the Series W Preference Stock in whole at any time and in part from time to time, at a redemption price equal to $100,000 per share plus, in the event all outstanding shares of the Series W Preference Stock are to be redeemed, unpaid accumulated dividends to the date of redemption. (B) In the event that fewer than all the outstanding shares of the Series W Preference Stock are to be redeemed, the number of shares to be redeemed shall be determined by the Board of Directors and the shares to be redeemed shall be determined by lot or pro rata as may be determined by the Board of Directors or by any other method that may be determined by the Board of Directors in its sole discretion to be equitable. (C) Except to the extent notice is waived in accordance with applicable law, notice of any such redemption shall be given by mailing to the holders of the shares of Series W Preference Stock to be redeemed a notice of such redemption, first class postage prepaid, not later than the twentieth day and not earlier than the sixtieth day before the date fixed for redemption, at their last address as the same shall appear upon the books of the Company. Each such notice shall state: (i) the redemption date; (ii) the number of shares to be redeemed and, if fewer than all the shares held by such holder are to be redeemed, the number of such shares to be redeemed from such holder; (iii) the redemption price; (iv) the place or places where certificates for such shares are to be surrendered for payment of the redemption price; and (v) that dividends on the shares to be redeemed will cease to accrue on the close of business on such redemption date. Any notice that is mailed in the manner herein provided shall be conclusively presumed to have been duly given, whether or not the shareholder received such notice, and failure duly to give such notice by mail, or any defect in such notice, to any holder of Series W Preference Stock shall not affect the validity of the proceedings for the redemption of any other shares of Series W Preference Stock that are to be redeemed. On or after the date fixed for redemption as stated in such notice, each holder of the shares called for redemption shall surrender the certificate evidencing such shares to the Company at the place designated in such notice and shall thereupon be entitled to receive payment of the redemption price. If fewer than all the shares represented by any such surrendered certificate are redeemed, a new certificate shall be issued representing the unredeemed shares. (D) The shares of Series W Preference Stock shall not be subject to the operation of any purchase, retirement or sinking fund. -5-
6 9. Ranking. The Series W Preference Stock shall rank junior to all series of the Company's Preferred Stock and pari passu with all other series of the Company's Preference Stock (other than any such series of Preference Stock the terms of which shall provide otherwise) in respect to dividend and liquidation rights and shall rank senior to the Common Stock as to such matters. 10. Amendment. At any time that any shares of Series W Preference Stock are outstanding, the Restated Articles of Incorporation of the Company shall not be amended in any manner which would materially alter or change the powers, preferences or special rights of the Series W Preference Stock so as to affect them adversely without the affirmative vote of the holders of two-thirds or more of the outstanding shares of Series W Preference Stock, voting separately as a class. 11. Fractional Shares. Series W Preference Stock may be issued in fractions of a share that shall entitle the holder, in proportion to such holder's fractional shares, to exercise any voting rights, receive dividends, participate in distributions and to have the benefit of all other rights of holders of Series W Preference Stock. REMAINDER OF THIS PAGE INTENTIONALLY LEFT BLANK -6-
7 IN WITNESS WHEREOF, RELIANT ENERGY, INCORPORATED has caused this Statement to be executed on its behalf by the undersigned officer this 11 day of July, 2001. RELIANT ENERGY, INCORPORATED /s/ MARC KILBRIDE --------------------------------------- Name: Marc Kilbride Title: Treasurer -7-
1 EXHIBIT 3(b) STATEMENT OF RESOLUTION ESTABLISHING SERIES OF SHARES designated SERIES X PREFERENCE STOCK of RELIANT ENERGY, INCORPORATED Pursuant to Article 2.13D of the Texas Business Corporation Act Pursuant to the provisions of Article 2.13D of the Texas Business Corporation Act, the undersigned corporation submits the following statement for the purpose of establishing and designating a series of shares of its Preference Stock, without par value, designated "Series X Preference Stock" and fixing and determining the relative rights and preferences thereof: 1. The name of the corporation is RELIANT ENERGY, INCORPORATED (the "Company"). 2. The following resolution establishing and designating a series of shares and fixing and determining the relative rights and preferences thereof, was duly adopted by all necessary action on the part of the Company on June 28, 2001: RESOLVED, that pursuant to the authority vested in the Finance Committee and the Preference Stock Committee, acting separately and/or concurrently, by the Board of Directors of this Company in accordance with the provisions of the Restated Articles of Incorporation, a series of Preference Stock, without par value, of the Company be and hereby is created, and that the designation and number of shares thereof and the preferences, limitations and relative rights, including voting rights, of the shares of such series and the qualifications, limitations and restrictions thereof are as follows: SERIES X PREFERENCE STOCK 1. Designation and Amount. There shall be a series of Preference Stock that shall be designated as "Series X Preference Stock," and the number of shares constituting such series shall be 18,950. Such number of shares may be increased or decreased by resolution of the Finance Committee and the Preference Stock Committee, acting separately and/or concurrently; provided, however, that no decrease shall reduce the number of shares of Series X Preference Stock to less than the number of shares then issued and outstanding plus the number of shares issuable upon exercise of outstanding rights, options or warrants or upon conversion of outstanding securities issued by the Company. -1-
2 2. Certain Defined Terms. Capitalized terms not otherwise defined herein shall have the respective meanings ascribed to them in that certain Senior B Credit Agreement (the "Senior B Credit Agreement") to be entered into among Houston Industries FinanceCo, LP, a Delaware limited partnership to be the Borrower thereunder, the Company, the lenders parties thereto and The Chase Manhattan Bank, as the Administrative Agent, on or after July 13, 2001. In addition, the following terms are used herein as defined below: (i) "Computed Dividend Portion" means, within any Dividend Interval Period, an amount equal to the interest expense accrued on the indebtedness for borrowed money of the Borrower from the prior Dividend Payment Date to the Determination Date for the current Dividend Interval Period. (ii) "Determination Date" means the date occurring five Business Days prior to a Dividend Declaration Date. (iii) "Dividend" means the dividend on the Series X Preference Stock declared by the Company's Board of Directors with respect to a Dividend Interval Period. (iv) "Dividend Declaration Amount" means, as of any Determination Date, the Preliminary Dividend Amount, less the sum of (a) the Interest Reconciliation Amount, (b) the Support Agreement Reconciliation Amount, and (c) the Other Sources Reconciliation Amount. The Dividend Declaration Amount may be greater than or less than the Preliminary Dividend Amount. (v) "Dividend Declaration Date" means the date on which Dividends on the Series X Preference Stock are declared (or would have been declared but for the fact that the amount of the Dividend determined in accordance herewith would have been zero) during a Dividend Interval Period by the Company's Board of Directors. (vi) "Dividend Interval Period" means the period beginning on a Dividend Payment Date and extending to the next Dividend Payment Date. (vii) "Dividend Payment Date" means the date occurring five Business Days after a Dividend Declaration Date. (viii) "Interest Reconciliation Amount" means an amount equal to (a) the Preliminary Dividend Amount computed for the prior Dividend Interval Period, less (b) the actual interest expense accrued on the indebtedness for borrowed money of the Borrower during such period. (ix) "Other Sources Reconciliation Amount" means the sum of (a) to the extent applied to pay interest on the indebtedness for borrowed money of the Borrower or available in cash on the current Determination Date therefor, the amount of income or cash proceeds received by the Borrower from sources other than pursuant to the Support Agreement (including, without limitation, interest received on loans to Affiliates), and (b) the cash proceeds of new borrowings under the Credit Agreement or any other Permitted -2-
3 Facility that are utilized to pay interest on outstanding borrowings thereunder, from the Determination Date occurring in the Prior Dividend Interval Period to the Determination Date occurring in the current Dividend Interval Period. (x) "Preliminary Dividend Amount" means the sum of the Computed Dividend Portion and the Projected Dividend Portion. (xi) "Projected Dividend Portion" means, within any Dividend Interval Period, an amount equal to the projected interest expense that will be accrued on the indebtedness for borrowed money of the Borrower from the Determination Date for such Dividend Interval Period to the Dividend Payment Date. (xii) "Support Agreement Reconciliation Amount" means the amount of cash payments made pursuant to the Support Agreement by the Company to the Borrower from the Determination Date occurring in the immediately prior Dividend Interval Period to the Determination Date occurring in the current Dividend Interval Period. 3. Dividends and Distributions. (A) Subject to the prior and superior rights of the holders of (i) any shares of any series of Preference Stock ranking prior and superior to the shares of Series X Preference Stock with respect to dividends and (ii) any shares of Preferred Stock, the holders of shares of Series X Preference Stock, in preference to the holders of shares of any class or series of stock of the Company ranking junior to the Series X Preference Stock, shall be entitled to receive the amounts set forth below, when, as and if declared by the Board of Directors in the manner described below out of assets of the Company legally available for the purpose: (i) On every regularly scheduled meeting of the Company's Board of Directors while any shares of Series X Preference Stock remain outstanding, the Board of Directors shall declare an aggregate Dividend (if a positive amount) equal to the lesser of (a) the Dividend Declaration Amount or (b) the Excess Cash Flow projected to be available as of the applicable Dividend Payment Date with respect to the then current Dividend Interval Period. (ii) If, with respect to any Dividend Interval Period, the aggregate Dividend declared by the Company's Board of Directors is less than the Dividend Declaration Amount for such Dividend Interval Period because the Excess Cash Flow projected to be available as of the applicable Dividend Payment Date is less than the Dividend Declaration Amount, the amount of such deficiency shall be added to the Dividend Declaration Amount computed for the next Dividend Interval Period and such aggregate amount shall become the Dividend Declaration Amount for such period. The Dividend for such succeeding Dividend Interval Period shall equal the Dividend Declaration Amount unless such amount would exceed the Excess Cash Flow projected to be available as of the applicable Dividend Payment Date, in which case the Dividend shall be the amount of the projected Excess Cash Flow. -3-
4 (iii) The aggregate Dividends paid on the shares of Series X Preference Stock in accordance with this Section 3(A) shall be allocated pro rata on a share-by-share basis among all such shares at the time outstanding. (B) Accrued but unpaid dividends shall not bear interest. The Board of Directors may fix a record date for the determination of holders of shares of Series X Preference Stock entitled to receive payment of a dividend or distribution declared thereon. 4. Voting Rights. Except as otherwise required by law or the Restated Articles of Incorporation of the Company or as otherwise provided herein, the holders of shares of Series X Preference Stock shall have no voting rights. 5. Certain Restrictions. At any time when dividends or distributions payable on the Series X Preference Stock as provided in Section 3 are in arrears, thereafter and until all accrued and unpaid dividends and distributions, whether or not declared, on shares of Series X Preference Stock outstanding shall have been paid in full, the Company shall not: (i) declare dividends on, or redeem or purchase or otherwise acquire for consideration any shares of stock ranking junior (either as to dividends or upon liquidation, dissolution or winding up) to the Series X Preference Stock; or (ii) declare dividends on any shares of stock ranking on a parity (either as to dividends or upon liquidation, dissolution or winding up) with the Series X Preference Stock, except dividends declared ratably on the Series X Preference Stock and all such parity stock on which dividends are payable or in arrears in proportion to the total amounts to which the holders of all such shares are then entitled. 6. Reacquired Shares. Any shares of Series X Preference Stock purchased or otherwise acquired by the Company in any manner whatsoever shall be retired and canceled promptly after the acquisition thereof. All such shares shall upon their cancellation become authorized but unissued shares of Preference Stock and may be reissued as part of a new series of Preference Stock to be created by resolution or resolutions of the Board of Directors, subject to any conditions and restrictions on issuance set forth herein. 7. Liquidation, Dissolution or Winding Up. (A) Upon any liquidation (voluntary or otherwise), dissolution or winding up of the Company, no distribution shall be made to the holders of shares of stock ranking junior (either as to dividends or upon liquidation, dissolution or winding up) to the Series X Preference Stock unless, prior thereto, the holders of shares of Series X Preference Stock shall have received $100,000 per share, plus an amount equal to accrued and unpaid dividends and distributions thereon, whether or not declared, to the date of such payment (the "Series X Liquidation Preference"). Following the payment of the full amount of the Series X Liquidation Preference, no additional distributions shall be made to the holders of shares of Series X Preference Stock. (B) In the event that there are not sufficient assets available to permit payment in full of the Series X Liquidation Preference and the liquidation preferences of all other series of Preference Stock, if any, that rank on a parity with the Series X Preference Stock, then such -4-
5 remaining assets shall be distributed ratably to the holders of such parity shares in proportion to their respective liquidation preferences. (C) Neither the merger or consolidation of the Company into or with another corporation nor the merger or consolidation of any other corporation into or with the Company shall be deemed to be a liquidation, dissolution or winding up of the Company within the meaning of this Section 7, but the sale, lease or conveyance of all or substantially all of the Company's assets shall be deemed to be a liquidation, dissolution or winding up of the Company within the meaning of this Section 7. 8. Redemption. (A) The Company, at its option, may redeem shares of the Series X Preference Stock in whole at any time and in part from time to time, at a redemption price equal to $100,000 per share plus, in the event all outstanding shares of the Series X Preference Stock are to be redeemed, unpaid accumulated dividends to the date of redemption. (B) In the event that fewer than all the outstanding shares of the Series X Preference Stock are to be redeemed, the number of shares to be redeemed shall be determined by the Board of Directors and the shares to be redeemed shall be determined by lot or pro rata as may be determined by the Board of Directors or by any other method that may be determined by the Board of Directors in its sole discretion to be equitable. (C) Except to the extent notice is waived in accordance with applicable law, notice of any such redemption shall be given by mailing to the holders of the shares of Series X Preference Stock to be redeemed a notice of such redemption, first class postage prepaid, not later than the twentieth day and not earlier than the sixtieth day before the date fixed for redemption, at their last address as the same shall appear upon the books of the Company. Each such notice shall state: (i) the redemption date; (ii) the number of shares to be redeemed and, if fewer than all the shares held by such holder are to be redeemed, the number of such shares to be redeemed from such holder; (iii) the redemption price; (iv) the place or places where certificates for such shares are to be surrendered for payment of the redemption price; and (v) that dividends on the shares to be redeemed will cease to accrue on the close of business on such redemption date. Any notice that is mailed in the manner herein provided shall be conclusively presumed to have been duly given, whether or not the shareholder received such notice, and failure duly to give such notice by mail, or any defect in such notice, to any holder of Series X Preference Stock shall not affect the validity of the proceedings for the redemption of any other shares of Series X Preference Stock that are to be redeemed. On or after the date fixed for redemption as stated in such notice, each holder of the shares called for redemption shall surrender the certificate evidencing such shares to the Company at the place designated in such notice and shall thereupon be entitled to receive payment of the redemption price. If fewer than all the shares represented by any such surrendered certificate are redeemed, a new certificate shall be issued representing the unredeemed shares. (D) The shares of Series X Preference Stock shall not be subject to the operation of any purchase, retirement or sinking fund. -5-
6 9. Ranking. The Series X Preference Stock shall rank junior to all series of the Company's Preferred Stock and pari passu with all other series of the Company's Preference Stock (other than any such series of Preference Stock the terms of which shall provide otherwise) in respect to dividend and liquidation rights and shall rank senior to the Common Stock as to such matters. 10. Amendment. At any time that any shares of Series X Preference Stock are outstanding, the Restated Articles of Incorporation of the Company shall not be amended in any manner which would materially alter or change the powers, preferences or special rights of the Series X Preference Stock so as to affect them adversely without the affirmative vote of the holders of two-thirds or more of the outstanding shares of Series X Preference Stock, voting separately as a class. 11. Fractional Shares. Series X Preference Stock may be issued in fractions of a share that shall entitle the holder, in proportion to such holder's fractional shares, to exercise any voting rights, receive dividends, participate in distributions and to have the benefit of all other rights of holders of Series X Preference Stock. REMAINDER OF THIS PAGE INTENTIONALLY LEFT BLANK -6-
7 IN WITNESS WHEREOF, RELIANT ENERGY, INCORPORATED has caused this Statement to be executed on its behalf by the undersigned officer this 11 day of July, 2001. RELIANT ENERGY, INCORPORATED /s/ MARC KILBRIDE -------------------------------------------- Name: Marc Kilbride Title: Treasurer -7-
1 EXHIBIT 99(a).REI RELIANT ENERGY, INCORPORATED ITEMS INCORPORATED BY REFERENCE ITEMS INCORPORATED BY REFERENCE FROM THE RELIANT ENERGY FORM 10-K o ITEM 3. LEGAL PROCEEDINGS. (a) RELIANT ENERGY. For a description of certain legal and regulatory proceedings affecting Reliant Energy, see Notes 4, 14(g), 14(h) and 14(i) to our consolidated financial statements, which notes are incorporated herein by reference. o ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- CERTAIN FACTORS AFFECTING OUR FUTURE EARNINGS Our earnings for the past three years are not necessarily indicative of our future earnings and results. The level of our future earnings depends on numerous factors including: - state and federal legislative, as well as international regulatory developments, including deregulation, re-regulation and restructuring of the electric utility industry and changes in or application of environmental and other laws and regulations to which we are subject, - the timing of the implementation of our Business Separation Plan, - industrial, commercial and residential growth in our service territories, - our pursuit of potential business strategies, including acquisitions or dispositions of assets or the development of additional power generation facilities, - state, federal and other rate regulations in the United States and in foreign countries in which we operate or into which we might expand our operations, - the timing and extent of changes in commodity prices and interest rates, - weather variations and other natural phenomena, - our ability to cost-effectively finance and refinance, - the determination of the amount of our Texas generating assets' stranded costs and the recovery of these costs, - the ability to consummate and the timing of the consummation of acquisitions and dispositions, - the performance of our generation projects undertaken, - the successful operation of deregulating power markets, including the resolution of the crisis in the California market, and - risks incidental to our overseas operations, including the effects of fluctuations in foreign currency exchange rates. In order to adapt to the increasingly competitive environment, we continue to evaluate a wide array of potential business strategies, including business combinations or acquisitions involving other utility or non-utility businesses or properties, dispositions of currently owned businesses, as well as developing new generation projects, products, services and customer strategies. 1
2 BUSINESS SEPARATION AND RESTRUCTURING In anticipation of electric deregulation in Texas, and pursuant to the Legislation, we submitted a business separation plan in January 2000 to the Texas Utility Commission. Pursuant to the Business Separation Plan, we will restructure our businesses into two separate publicly traded companies in order to separate our unregulated businesses from our rate-regulated businesses. Reliant Resources holds substantially all of our unregulated businesses. We expect Reliant Resources will conduct the Offering in 2001. Also, we anticipate that the Regulated Holding Company will conduct the Distribution within 12 months of the completion of the Offering, subject to receipt of a favorable tax ruling and other regulatory approvals. For additional information regarding the Business Separation Plan and the Restructuring, please read "Business -- Our Business -- Restructuring" in Item 1 of this Form 10-K and Note 4(b) to our consolidated financial statements. We have sought a ruling from the Internal Revenue Service that the Distribution will be tax-free to the Regulated Holding Company and its shareholders. At this time, we do not have a ruling from the Internal Revenue Service regarding the tax treatment of the Distribution. If we do not obtain a favorable tax ruling, the Distribution is not likely to be made in the expected time frame or, perhaps, at all. In order for the Distribution to be tax-free, various requirements must be met, including ownership by its parent of at least 80% of all classes of Reliant Resources' outstanding capital stock at the time of the Distribution. Additionally, in connection with the Distribution, Reliant Energy plans to restructure its remaining businesses to achieve a public utility holding company structure and to register the Regulated Holding Company as a public utility holding company under the 1935 Act. Creation of the Regulated Holding Company will require the approval of Reliant Energy's shareholders. For additional information regarding the Regulated Holding Company, please read "Business -- Our Business -- Restructuring" in Item 1 of this Form 10-K and Note 4(b) to our consolidated financial statements. The Restructuring will also require the approval of the Louisiana Public Service Commission and the Nuclear Regulatory Commission. We cannot assure you that those approvals will be obtained. After the Restructuring, the Regulated Holding Company will become a registered public utility holding company under the 1935 Act. COMPETITIVE, REGULATORY AND OTHER FACTORS AFFECTING OUR ELECTRIC OPERATIONS Competition and Deregulation. In June 1999, the Texas legislature adopted the Legislation, which substantially amended the regulatory structure governing electric utilities in Texas in order to allow retail competition. Retail pilot projects for up to 5% of each utility's load in all customer classes will begin in June 2001 and retail electric competition for all other customers will begin on January 1, 2002. Our retail operations will be conducted by indirect wholly owned subsidiaries of Reliant Resources. Under the market framework established by the Legislation, we will initially be required to sell electricity to Houston area residential and small commercial customers at a specified price, which is referred to in the Legislation as the "price to beat," whereas other retail electric providers will be allowed to sell electricity to these same customers at any price. We will not be permitted to offer electricity to these customers at a price other than the price to beat until January 1, 2005, unless before that date the Texas Utility Commission determines that 40% or more of the amount of electric power that was consumed in 2000 by residential or small commercial customers, as applicable, within the affiliated transmission and distribution utility's certificated service territory, as of January 1, 2002, is committed to be served by other retail electric providers. In addition, as long as we continue to provide retail service, the Legislation requires us to make the price to beat available to residential and small commercial customers in Reliant Energy HL&P's service territory through January 1, 2007. Because we will not be able to compete for residential and small commercial customers on the basis of price in Reliant Energy HL&P's service area, and because we expect that the retail market framework established by the Legislation will encourage competition from new retail electric providers, we could lose a significant number of these customers to other providers. When the pilot projects begin in June 2001, and until full retail electric competition begins, the Legislation provides that 5% of our customers may elect to purchase electricity from other retail electric providers. Our affiliated retail electric providers cannot participate in the pilot projects in Reliant Energy HL&P's service area. Reliant Energy HL&P will collect from retail electric providers the rates approved from its Wires Case to cover the cost of providing transmission and distribution service and any other non-bypassable charges. 2
3 Generally, retail electric providers will procure or buy electricity from the wholesale generators at unregulated rates, sell electricity at retail to their customers and pay the transmission and distribution utility a regulated tariffed rate for delivering the electricity to their customers. The results of our retail electric operations will be largely dependent upon the amount of gross margin, or "headroom," available in the "price to beat." The available headroom will equal the difference between the price to beat and the sum of the charges, fees and transmission and distribution utility rate approved by the Texas Utility Commission and the price we pay for power to meet our price to beat load. The larger the amount of headroom, the more incentive new market entrants should have to provide retail electric services in Reliant Energy HL&P's service territory. The Texas Utility Commission's regulations allow us to adjust our price to beat fuel factor based on the percentage change in the price of natural gas. In addition, we may also request an adjustment as a result of changes in our price of purchased energy. In such a request, we may adjust the fuel factor to the extent necessary to restore the amount of headroom that existed at the time our initial price to beat fuel factor was set by the Texas Utility Commission. We may not request that our price to beat be adjusted more than twice a year. Currently, we do not know nor can we estimate the amount of headroom in our initial price to beat or in the initial price to beat for the affiliated retail electric provider in each other Texas retail electric market. Similarly, we cannot estimate with any certainty the magnitude and frequency of the adjustments required, if any, and the eventual impact of such adjustments on the amount of headroom. In preparation for this competition, we expect to make significant changes in the electric utility operations currently conducted through Reliant Energy HL&P. For additional information regarding these changes, the Legislation, retail competition, its application to our Electric Operations segment and the "price to beat," please read "Business -- Our Business -- Deregulation and Competition," "-- Restructuring," "-- Electric Operations" and "Business -- Regulation -- State and Local Regulations -- Texas -- Electric Operations -- The Legislation" in Item 1 of this Form 10-K and Note 4 to our consolidated financial statements. Also, market volatility in the price of fuel for our generation operations, as well as in the price of purchased power, could have an effect on our cost to generate or acquire power. For additional information regarding commodity prices and supplies, please read "-- Competitive, Regulatory and Other Factors Affecting Our Wholesale Energy Operations -- Price Volatility." Other Regulatory Factors. Pursuant to the Legislation, Reliant Energy HL&P will be entitled to recover its stranded costs (i.e., the excess of net book value of generation assets, as defined by the Legislation, over the market value of those assets) and its regulatory assets related to generation. The Legislation prescribes specific methods for determining the amount of stranded costs and the details for their recovery. However, during the base rate freeze period from 1999 through 2001, earnings above the utility's authorized rate of return formula may be applied in a manner to accelerate depreciation of generation related plant assets for regulatory purposes. In addition, depreciation expense for transmission and distribution related assets may be redirected to generation assets for regulatory purposes during that period. The Legislation also provides for Reliant Energy HL&P, or a special purpose entity, to issue securitization bonds for the recovery of generation related regulatory assets and a portion of stranded costs. Any stranded costs not recovered through the sale of securitization bonds may be recovered through a non-bypassable charge to transmission and distribution customers. For additional information regarding these securitization bonds, please read "-- Liquidity and Capital Resources -- Future Sources and Uses of Cash -- Securitization." The Texas Utility Commission recently stated on record that it would consider requiring electric utilities to reverse the amount of redirected depreciation and accelerated depreciation previously taken if in its estimation the utility has overmitigated its stranded costs. The reversal could occur through a lower rate for the transmission and distribution utility and/or through credits contained in the transmission and distribution utility's rate. Any order requiring the reversal of these amounts would likely be included in the Texas Utility Commission proceeding establishing the initial rate of the transmission and distribution utility or in the case of our Electric Operations segment, the Wires Case. We do not expect the final transmission and distribution rate in the Wires Case to be established until August 2001. For more information regarding the Wires Case, see "Business -- Regulation -- State and Local Regulations -- Texas -- Electric Operations -- Rate Case." 3
4 At June 30, 1999, we performed an impairment test of Reliant Energy HL&P's previously regulated electric generation assets pursuant to SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" (SFAS No. 121), on a plant specific basis. Under SFAS No. 121, an asset is considered impaired, and should be written down to fair value, if the future undiscounted net cash flows expected to be generated by the use of the asset are insufficient to recover the carrying amount of the asset. For assets that are impaired pursuant to SFAS No. 121, we determined the fair value for each generating plant by estimating the net present value of future cash inflows and outflows over the estimated life of each plant. The difference between fair value and net book value was recorded as a reduction in the current book value. We determined that $797 million of electric generation assets were impaired as of June 30, 1999. Of these amounts, $745 million related to the South Texas Project and $52 million related to two gas-fired generation plants. The Legislation provides for recovery of this impairment through regulated cash flows during the transition period and through non-bypassable charges to transmission and distribution customers. As such, a regulatory asset has been recorded for an amount equal to the impairment loss. We recorded amortization expense related to the recoverable impaired plant costs and other assets created from discontinuing regulatory accounting of $221 million in the third and fourth quarters of 1999 and $329 million in 2000. We expect to fully amortize this regulatory asset as it is recovered from regulated cash flows in 2001. The impairment analysis requires estimates of possible future market prices, load growth, competition and many other factors over the lives of the plants. The resulting impairment loss is highly dependent on these underlying assumptions. In addition, after January 10, 2004, Reliant Energy HL&P must finalize and reconcile stranded costs (as defined by the Legislation) in a filing with the Texas Utility Commission. Any positive difference between the regulatory net book value and the fair market value of the generation assets (as defined by the Legislation) will be collected through future non-bypassable charges. Any over-mitigation of stranded costs may be refunded through future non-bypassable charges. This final reconciliation allows alternative methods of third party valuation of the fair market value of these assets, including outright sale, stock valuations and asset exchanges. Because generally accepted accounting principles require us to estimate fair market values on a plant-by-plant basis in advance of the final reconciliation, the financial impacts of the Legislation with respect to the final determination of stranded costs in 2004 are subject to material changes. Factors affecting such change may include estimation risk, uncertainty of future energy and commodity prices and the economic lives of the plants. If events occur that make the recovery of all or a portion of the regulatory assets associated with the generation plant impairment loss and other assets created from discontinuance of regulatory accounting pursuant to the Legislation no longer probable, we will write off the corresponding balance of these assets as a non-cash charge against earnings. One of the results of discontinuing the application of regulatory accounting for the generation operations is the elimination of the regulatory accounting effects of excess deferred income taxes and investment tax credits related to these operations. We believe it is probable that some parties will seek to return these amounts to ratepayers and, accordingly, we have recorded an offsetting liability. In accordance with the Legislation, beginning on January 1, 2002, and ending at December 31, 2003, any difference between market power prices received in the generation capacity auction and the Texas Utility Commission's earlier estimates of those market prices will be included in the 2004 stranded costs true-up. The Texas Utility Commission's estimate serves as a preliminary identification of stranded costs for recovery through securitization. This component of the true-up is intended to ensure that neither the customers nor we are disadvantaged economically as a result of the two-year transition period by providing this pricing structure. Since the time of our original impairment calculation in June 1999 when we discontinued application of SFAS No. 71 for our generation operations, natural gas prices have risen 295% from June 1999 to December 31, 2000 resulting in increases in estimated market prices for power during 2002 and 2003. Generally, for Reliant Energy HL&P's generation portfolio, sustained increases in natural gas prices result in an increase in the fair value of Reliant Energy HL&P's generation portfolio, due to our mix of lower variable cost of electric generation. Therefore, as electric power prices increase, the amount of our estimated stranded costs decline and the estimate of our 2002 and 2003 capacity true-up amounts which may be owed to customers increases. 4
5 For additional information regarding the impairment of regulatory assets and electric generating plant and equipment as well as the recovery of stranded costs, please read Note 4(a) to our consolidated financial statements. For additional information regarding our filings to recover under-recovered fuel costs, please read Note 4(d) to our consolidated financial statements. Other. For additional information regarding litigation over franchise fees, please read Note 14(g) to our consolidated financial statements. COMPETITIVE, REGULATORY AND OTHER FACTORS AFFECTING OUR WHOLESALE ENERGY OPERATIONS Competition. As of December 31, 2000, our Wholesale Energy business segment owned and operated 9,231 MW of electric generation assets that serve wholesale energy markets located in the Mid-Atlantic, Southwest and Midcontinent regions of the United States and the states of Florida and Texas. Competitive factors affecting the results of operations of these generation assets include new market entrants and construction by others of more efficient generation assets. The wholesale power industry has numerous competitors, some of which may have more operating experience, more acquisition and development experience, larger staffs and/or greater financial resources than we do. Like us, many of our competitors are seeking attractive opportunities to acquire or develop power generation facilities, both in the United States and abroad. This competition may adversely affect our ability to make investments or acquisitions. Also, industry restructuring requires or encourages the disaggregation of many vertically-integrated utilities into separate generation, transmission and distribution, and retail businesses. As a result, a significant number of additional competitors could become active in the wholesale power generation segment of our industry. Furthermore, other competitors operate power generation projects in the regions where we have invested in electric generation assets. While demand for electric energy services is generally increasing throughout the United States, the rate of construction and development of new, more efficient electric generation facilities may exceed increases in demand in some regional electric markets. Although local permitting and siting issues often reduce the risk of a rapid growth in supply of generation capacity in any particular region, projects are likely to be built over time. The commencement of commercial operation of these new facilities in the regional markets where we have facilities will likely increase the competitiveness of the wholesale power market in those regions, which could have a material effect on our business and lower the value of some of our electric generation assets. Finally, our trading, marketing, power origination and risk management operations compete with other energy merchants based on the ability to aggregate supplies at competitive prices from different sources and locations and to efficiently utilize transportation from third-party pipelines and transmission from electric utilities. These operations also compete against other energy marketers on the basis of their relative skills, financial position and access to credit sources. This competitive factor reflects the tendency of energy customers, wholesale energy suppliers and transporters to seek financial guarantees and other assurances that their energy contracts will be satisfied. As pricing information becomes increasingly available in the energy trading and marketing business and as deregulation in the electricity markets continues to accelerate, we anticipate that our trading, marketing, power origination and risk management operations will experience greater competition and downward pressure on per-unit profit margins. Regulation. The regulatory environment applicable to the electric power industry has recently undergone substantial changes as a result of restructuring initiatives at both the state and federal levels. These initiatives have had a significant impact on the nature of the industry and the manner in which its participants conduct their business. Our Wholesale Energy segment has targeted the deregulating wholesale and retail segments of the electric power industry created by these initiatives. These changes are ongoing and we cannot predict the future development of deregulation in these markets or the ultimate effect that this changing regulatory environment will have on our business. 5
6 Moreover, existing regulations may be revised or reinterpreted, new laws and regulations may be adopted or become applicable to us or our facilities, and future changes in laws and regulations may have a detrimental effect on our business. Certain restructured markets, particularly California, have recently experienced supply problems and price volatility. These supply problems and volatility have been the subject of a significant amount of press coverage, much of which has been critical of the restructuring initiatives. In some markets, including California (please read "-- California" below), proposals have been made by governmental agencies and/or other interested parties to slow the pace of deregulation or to re-regulate areas of these markets that have previously been deregulated. If the current trend towards competitive restructuring of the wholesale and retail power markets is reversed, discontinued or delayed, the business growth prospects of our Wholesale Energy segment would be slowed and the financial outlook for our existing positions could be impacted. If RTOs are established as envisioned by FERC Order 2000, "rate pancaking," or multiple transmission charges that apply to a single point-to-point delivery of energy, will be eliminated within a region, and wholesale transactions within the region, and between regions will be facilitated. The end result could be a more competitive, transparent market for the sale of energy and a more economic and efficient use and allocation of resources. For additional information regarding FERC Order 2000 affecting these RTOs, please read "Business -- Regulation -- Federal Energy Regulatory Commission" in Item 1 of this Form 10-K. Price Volatility. Our Wholesale Energy business segment sells electricity from our non-Texas power generation facilities into the spot market or other competitive power markets or on a contractual basis. Our Wholesale Energy business segment is not guaranteed any rate of return on our capital investments through mandated rates, and our revenues and results of operations are likely to depend, in large part, upon prevailing market prices for electricity and fuel in our regional markets and other competitive markets. These market prices may fluctuate substantially over relatively short periods of time. In addition, the FERC, which has jurisdiction over wholesale power rates, as well as independent system operators that oversee some of these markets, may impose price limitations, bidding rules and other mechanisms to address some of the volatility in these markets. Most of our Wholesale Energy business segment's domestic power generation facilities purchase fuel under short-term contracts or on the spot market. Fuel prices may also be volatile, and the price we can obtain for power sales may not change at the same rate as changes in fuel costs. These factors could have an adverse impact on our revenues and results of operations. Volatility in market prices for fuel and electricity may result from: - weather conditions, - seasonality, - electricity usage, - illiquid markets, - transmission or transportation constraints or inefficiencies, - availability of competitively priced alternative energy sources, - demand for energy commodities, - natural gas, crude oil and refined products, and coal production levels, - natural disasters, wars, embargoes and other catastrophic events, and - federal, state and foreign energy and environmental regulation and legislation. Trading, Marketing, Power Origination and Risk Management Operations. To lower our Wholesale Energy business segment's financial exposure related to commodity price fluctuations, its trading, marketing, power origination and risk management operations routinely enter into contracts to hedge a portion of its purchase and sale commitments, weather positions, fuel requirements and inventories of natural gas, coal, crude oil and refined products, and other commodities. As part of this strategy, our Wholesale Energy business segment routinely utilizes fixed-price forward physical purchase and sales contracts, futures, financial swaps 6
7 and option contracts traded in the over-the-counter markets or on exchanges. However, our Wholesale Energy business segment does not expect to cover the entire exposure of its assets or its positions to market price volatility and the coverage will vary over time. To the extent our Wholesale Energy business segment has unhedged positions, fluctuating commodity prices can impact our financial results and financial position, either favorably or unfavorably. At times, our Wholesale Energy business segment has open trading positions in the market, within established guidelines, resulting from the management of its trading portfolio. To the extent open trading positions exist, fluctuating commodity prices can impact our financial results and financial position, either favorably or unfavorably. The risk management procedures our Wholesale Energy business segment has in place may not always be followed or may not always work as planned. As a result of these and other factors, we cannot predict with precision the impact that our risk management decisions may have on our businesses, operating results or financial position. Although our Wholesale Energy business segment devotes a considerable amount of management effort to these issues, their outcome is uncertain. Our trading, marketing, power origination and risk management operations are also exposed to the risk that counterparties who owe it money or physical commodities, such as energy or gas, as a result of market transactions will not perform their obligations. Should the counterparties to these arrangements fail to perform, our trading, marketing, power origination and risk management operations might be forced to acquire alternative hedging arrangements or replace the underlying commitment at then-current market prices. In this event, our trading, marketing, power origination and risk management operations might incur additional losses to the extent of amounts, if any, already paid to the counterparties. California. During the summer and fall of 2000, prices for wholesale electricity in California increased dramatically as a result of a combination of factors, including higher natural gas prices and emission allowance costs, reduction in available hydroelectric generation resources, increased demand, decreases in net electric imports, structural market flaws including over-reliance on the electric spot market, and limitations on supply as a result of maintenance and other outages. Although wholesale prices increased, California's deregulation legislation kept retail rates frozen below 1996 levels. This caused two of California's public utilities, which are our customers based on our deliveries to the Cal PX and the Cal ISO, to amass billions of dollars of uncollected wholesale power costs and to ultimately default in January and February 2001 on payments owed for wholesale power purchased through the Cal PX and from the Cal ISO. As of December 31, 2000, we were owed $101 million by the Cal PX and $181 million by the Cal ISO. In the fourth quarter of 2000, we recorded a pre-tax provision of $39 million against receivable balances related to energy sales in the California market. From January 1, 2001 through February 28, 2001, we have collected $105 million of these receivable balances. As of March 1, 2001, we were owed a total of $358 million by the Cal ISO, the Cal PX, the CDWR and California Energy Resources Scheduling for energy sales in the California wholesale market from the fourth quarter of 2000 through February 28, 2001. Management will continue to assess the collectibility of these receivables based on further developments affecting the California electricity market and the market participants described herein. Additional provisions to the allowance may be warranted in the future. In response to the filing of a number of complaints challenging the level of wholesale prices, the FERC initiated a staff investigation and issued an order on December 15, 2000 implementing a series of wholesale market reforms, including an interim price review procedure for prices above a $150/MWh "breakpoint" on sales to the Cal ISO and through the Cal PX. The order does not prohibit sales above the "breakpoint," but the seller is subject to weekly reporting and monitoring requirements. For each reported transaction, potential refund liability extends for a period of 60 days following the date any such transaction is reported to the FERC. On March 9, 2001, the FERC issued a further order establishing a proxy market clearing price of $273/MWh for January 2001, and on March 16, 2001 the FERC issued a further order adjusting the proxy market clearing price to $430/MWh for February 2001. New market monitoring and mitigation measures to replace the $150/MWh breakpoint and reporting obligation are being developed by the FERC to take effect on May 1, 2001. 7
8 In the FERC's March 9 and March 16 orders, the FERC outlined criteria for determining amounts subject to possible refund based on the proxy market clearing price for January and February 2001 and indicated that approximately $12 million of the $125 million charged by us in January 2001 in California to the Cal ISO and the Cal PX and approximately $7 million of the $47 million charged by us in February 2001 in California to the Cal ISO and the Cal PX were subject to possible refunds. In the March 9 and March 16 orders, the FERC set forth procedures for challenging possible refund obligations. Because we believe that there is cost or other justification for prices charged above the proxy market clearing prices established in the March 9 and March 16 orders, we intend to pursue such a challenge with respect to our potential refund amounts identified in such orders. Any refunds we may ultimately be obligated to pay are to be credited against unpaid amounts owed to us for our sales in the Cal PX or to the Cal ISO. The December 15 order established that a refund condition would be in place for the period beginning October 2, 2000 through December 31, 2002. The December 15 order also eliminated the requirement that California's public utilities sell all of their generation into and purchase all of their power from the Cal PX and directed that the Cal PX wholesale tariffs be terminated effective April 2001. The Cal PX has since suspended its day-ahead and day-of markets and filed for bankruptcy protection on March 9, 2001. Motions for rehearing have been filed on a number of issues related to the December 15 order and such motions are still pending before the FERC. In addition to the FERC investigation discussed above, several state and other federal regulatory investigations and complaints have commenced in connection with the wholesale electricity prices in California and other neighboring Western states to determine the causes of the high prices and potentially to recommend remedial action. In California, the California Public Utilities Commission, the California Electricity Oversight Board, the California Bureau of State Audits and the California Office of the Attorney General all have separate ongoing investigations into the high prices and their causes. None of these investigations have been completed and no findings have been made in connection with any of them. Despite the market restructuring ordered under the December 15 order, the California public utilities have continued to accrue unrecovered wholesale costs. As a result, the credit ratings of two of these public utilities were severely downgraded to below investment grade in January 2001. As their credit lines became unavailable, the two utilities defaulted on payments due to the Cal PX and the Cal ISO, which operate financially as pass-through entities, coordinating payments from buyers and sellers of electricity. As a result, the Cal PX and Cal ISO were not able to pay final invoices to market participants totaling over $1 billion. The default of two of California's public utilities on amounts owed the Cal PX and the Cal ISO for purchased power has further exacerbated the current crisis in the California wholesale markets and resulted in substantial uncollected receivables owed to us by the Cal ISO and the Cal PX. The Cal PX's efforts to recover the available collateral of the utilities, in the form of block forward contracts, have been frustrated by the emergency acts of California's Governor, who seized control of the contracts upon the expiration of temporary restraining orders prohibiting such action. Although obligated to pay reasonable value for the contracts, the state of California has not yet made any payment for the contracts. Various actions have been filed challenging the Governor's ability to seize these contracts. Upon the default of the two utilities of amounts due to the Cal PX, the Cal PX issued "charge-backs" allocating the utilities' defaults to the other market participants. Proceedings were brought both in federal court and at the FERC seeking a suspension of the charge-backs and challenging the reasonableness of the Cal PX's actions. The Cal PX has since agreed to a preliminary injunction suspending any of its charge-back activities in order to allow the FERC to address the charge-back issues. Amounts owed to us were debited in invoices by the Cal PX for charge-backs in the amount of $29 million and, on February 14, 2001, we filed our own lawsuit against the Cal PX in the United States District Court for the Central District of California, seeking a recovery of those amounts and a stay of any further charge-backs by the Cal PX. The filing of bankruptcy by the Cal PX will automatically stay for some period the various court and administrative cases against the Cal PX. The two defaulting utilities have both filed lawsuits challenging the refusal of state regulators to allow wholesale power costs to be passed through to retail customers under the "filed rate doctrine." The filed rate doctrine provides that wholesale power costs approved by the FERC are entitled to be recovered through rates. 8
9 Additionally, to address the failing financial condition of the two defaulting utilities and the utilities' potential bankruptcy, the California Legislature passed emergency legislation, effective January 18, 2001 and February 2, 2001, appropriating funds to be used by the CDWR for the purchase of wholesale electricity on behalf of the utilities and authorizing the sale of bonds to fund future purchases under long-term power contracts with wholesale generators. The CDWR began the process of soliciting bids from generators for long-term contracts and continued the purchasing of short-term power contracts. No bonds have yet been issued by the CDWR to support long-term power purchases or to provide credit support for short-term purchases. As noted above, two of California's public utilities have defaulted in their payment obligations to the Cal PX and the Cal ISO as a result of the refusal of state regulators to allow them to recover their wholesale power costs. This refusal by state regulators has also caused the utilities to default on numerous other financial obligations, which could result in either the voluntary or involuntary bankruptcy of the utilities. While a bankruptcy filing would result in further post-petition purchases of wholesale electricity being considered administrative expenses of the debtor, a substantial delay could be experienced in the payment of pre-petition receivables pending the confirmation of a reorganization plan. The California Legislature is currently considering legislation under which a state entity would be formed to purchase and operate a substantial share of the transmission lines in California in an effort to provide cash to the utilities and thereby avoid potential bankruptcy filings by the utilities. A number of the creditors for the two California public utilities have indicated, however, that unless California moves quickly with such a plan, an involuntary bankruptcy filing may be made by one or more of such creditors. Because California's power reserves remain at low levels, in part as a result of the lack of creditworthy buyers of power given the defaults of the California utilities, the Cal ISO has relied on emergency dispatch orders requiring generators to provide at the Cal ISO's direction all power not already under contract. The power supplied to the Cal ISO has been used to meet the needs of the customers of the utilities, even though two of those utilities do not have the credit required to receive such power and may be unable to pay for it. We have contested the obligation to provide power under these circumstances. The Cal ISO sought a temporary restraining order compelling us to continue to comply with the emergency dispatch orders despite the utilities' defaults. Although the payment issue is still disputed, on February 21, 2001, we and the CDWR entered into a contract expiring March 23, 2001 for the purchase of all of our available capacity not already under contract and the litigation has been temporarily stayed. The CDWR is current in its payments under this contract, but we are still owed $108 million for power provided in compliance with the emergency dispatch orders for the six weeks prior to the agreement. Depending on the outcome of the court proceedings initiated by the Cal ISO seeking to enjoin us from ceasing power deliveries to the Cal ISO, we may be forced to continue selling power without the guarantee of payment. Additionally, we are seeking a prompt FERC determination that the Cal ISO is not complying with the credit provisions of its tariff and a related order of the FERC issued on February 14, 2001, requiring the Cal ISO not to make purchases in the real time market unless a creditworthy purchaser is responsible for such purchases. For additional information regarding the situation in California, please read "Business -- Wholesale Energy -- Power Generation Operations -- Southwest Region" and "Business -- Regulation -- State and Local Regulations -- California" in Item 1 of this Form 10-K, "-- Results of Operations by Business Segment -- Wholesale Energy -- 2000 Compared to 1999," as well as Notes 14(g) and 14(h) to our consolidated financial statements. COMPETITIVE, REGULATORY AND OTHER FACTORS AFFECTING OUR EUROPEAN ENERGY OPERATIONS Competition. The European energy market is highly competitive. In addition, over the next several years, we expect an increasing consolidation of the participants in the European generating market. Our European wholesale operations compete in the Netherlands, primarily against the three other largest Dutch generating companies, various cogenerators of electric power, various alternate sources of power and non-Dutch generators of electric power, primarily from France and Germany. In 2000, UNA and the three other largest Dutch generating companies supplied approximately 50% of the electricity consumed in the 9
10 Netherlands. Smaller Dutch producers supplied about 25% of the consumed electricity, and the remainder was imported. At present, the Dutch electricity system has three operational interconnection points with Germany and two interconnection points with Belgium. There are also a number of projects that are at various stages of development and that may increase the number of interconnections in the future (post 2005) including interconnections with Norway and the United Kingdom. The Belgian interconnections are used to import electricity from France, but a larger portion of Dutch electricity imports comes from Germany. Our European trading and marketing operations will also be subject to increasing levels of competition. As of December 31, 2000, there were 32 trading and marketing companies registered with the Amsterdam Power Exchange. Competition among power generators for customers is intense, and we expect competition to increase with the deregulation of the market. Please read "-- Regulation." The primary elements of competition affecting both the generation and trading and marketing operations of our European Energy business segment are price, credit support, and supply and delivery reliability. Deregulation. The Dutch electricity market was opened to limited wholesale and retail competition on January 1, 1999 as retail competition for large industrial customers began. The Dutch wholesale electric market was completely opened to competition on January 1, 2001. Consistent with our expectations at the time we made the acquisition, we anticipate that our European Energy business segment may experience a significant decline in gross margin in 2001 attributable to the deregulation of the market and termination of an agreement with the other Dutch generators and the Dutch distributors. The next customer segment, composed primarily of commercial customers, will be liberalized by 2002. The remainder of the market, mainly residential, will be open to competition by 2003. The timing of these market openings is subject to change, however, at the discretion of the Dutch Minister of Economic Affairs. In addition, the results of our European Energy segment will be negatively impacted beginning in 2002 due to the imposition of a standard Dutch corporate income tax rate, which is currently 35%, on the income of UNA. In 2000 and prior years, UNA's Dutch corporate income tax rate was zero percent. Other. Another factor that could have a significant impact on the Dutch energy industry, including the operations of our European Energy business segment, is the ultimate resolution of stranded costs issues in the Netherlands. Prior to 2001, UNA and the other Dutch generators sold their generating output through the coordinating body for the Dutch electricity generating sector, B.V. Nederlands Elektriciteit Administratiekantor (NEA). Over the years, NEA has incurred "stranded" costs as a result of, among other things, a perceived need to cover anticipated shortages in energy production supply. NEA stranded costs consist primarily of investments in alternative energy sources and fuel and power purchase contracts currently estimated to be uneconomical. Legislation has been approved by the Dutch parliament which would transfer the liability for the stranded costs from NEA to its four shareholders, one of which is UNA. For information regarding this legislation, please read Note 14(i) to our consolidated financial statements. In connection with our acquisition of UNA, the selling shareholders of UNA agreed to indemnify UNA for some stranded costs in an amount not to exceed NLG 1.4 billion ($599 million based on an exchange rate of 2.34 NLG per U.S. dollar as of December 31, 2000), which may be increased in some circumstances at our option up to NLG 1.9 billion ($812 million). Of the total consideration we paid for the shares of UNA, NLG 900 million ($385 million) has been placed by the selling shareholders under the direction of the Dutch Minister of Economic Affairs in an escrow account to secure the indemnity obligations by the former shareholders of UNA. Although our management believes that the indemnity provision will be sufficient to fully satisfy UNA's ultimate share of any stranded costs obligation, this judgment is based on numerous assumptions regarding the ultimate outcome and timing of the resolution of the stranded cost issue, the former shareholders' timely performance of their obligations under the indemnity arrangement, and the amount of stranded costs, which at present is not determinable. Any shortfall in the indemnity provision could have a material adverse effect on our results of operations. Our European operations are subject to various risks incidental to investing or operating in foreign countries. These risks include economic risks, such as fluctuations in currency exchange rates, restrictions on the repatriation of foreign earnings and/or restrictions on the conversion of local currency earnings into U.S. dollars. For example, we estimate that the impact of the devaluation of the Euro relative to the 10
11 U.S. dollar during 2000 negatively impacted U.S. dollar net income in the amount of approximately $8 million. Impact of Currency Fluctuations on Company Earnings. For information about our exposure through our investment in Europe to losses resulting from fluctuations in currency rates, please read "Quantitative and Qualitative Disclosures About Market Risk" in Item 7A of this Form 10-K. COMPETITIVE AND OTHER FACTORS AFFECTING RERC OPERATIONS Natural Gas Distribution. Our Natural Gas Distribution business segment competes primarily with alternate energy sources such as electricity and other fuel sources. In some areas, intrastate pipelines, other gas distributors and marketers also compete directly with our Natural Gas Distribution business segment for gas sales to end-users. In addition, as a result of federal regulatory changes affecting interstate pipelines, natural gas marketers operating on these pipelines may be able to bypass our Natural Gas Distribution business segment's facilities and market, sell and/or transport natural gas directly to commercial and industrial customers. Generally, the regulations of the states in which our Natural Gas Distribution business segment operates allow us to pass through changes in the costs of natural gas to our customers through purchased gas adjustment provisions in rates. There is, however, an inherent timing difference between our purchases of natural gas and the ultimate recovery of these costs. Consequently, we may incur additional "carrying" costs as a result of this timing difference and the resulting, temporary under-recovery of our purchased gas costs. To a large extent, these additional carrying costs are not recovered from our customers. Pipelines and Gathering. Our Pipelines and Gathering segment competes with other interstate and intrastate pipelines in the transportation and storage of natural gas. The principal elements of competition among pipelines are rates, terms of service, and flexibility and reliability of service. Our Pipelines and Gathering segment competes indirectly with other forms of energy available to its customers, including electricity, coal and fuel oils. The primary competitive factor is price. Changes in the availability of energy and pipeline capacity, the level of business activity, conservation and governmental regulations, the capability to convert to alternative fuels, and other factors, including weather, affect the demand for natural gas in areas we serve and the level of competition for transportation and storage services. Since FERC Order No. 636, REGT's and MRT's commodity sales activity has been minimal. Commodity transactions are usually related to system management activity which we have been able to manage with little exposure. We have not been nor do we anticipate to be, negatively impacted from the recent price levels and the tightening of supply. In addition, competition for our gathering operations is impacted by commodity pricing levels in its markets because these prices influence the level of drilling activity in those markets. Natural Gas Pipeline Company of America has proposed, and is soliciting customers for a 30" pipeline paralleling MRT's East Line in Illinois to a point 17 miles East of St. Louis Metro, with a proposed in-service date of June 2002. MRT has renewed or is engaged in negotiations to renew service agreements under multi-year terms, including service and potential expansion needs along MRT's existing East Line in Illinois. Our Pipelines and Gathering business segment derives approximately 14% of its revenues from its contract with Laclede, which has been under an annual evergreen term provision since 1999. In the event we are not able to renegotiate a long-term extension to the contract with Laclede, and Laclede engages another pipeline for the transportation services it currently obtains from us, the operating and financial results of our Pipelines and Gathering business segment would be materially adversely affected. FLUCTUATIONS IN COMMODITY PRICES AND DERIVATIVE INSTRUMENTS For information regarding our exposure to risk as a result of fluctuations in commodity prices and derivative instruments, please read "Quantitative and Qualitative Disclosures About Market Risk" in Item 7A of this Form 10-K. 11
12 INDEXED DEBT SECURITIES (ZENS) AND OUR AOL TIME WARNER INVESTMENT For information on our indexed debt securities and our investment in AOL Time Warner common stock, please read "Quantitative and Qualitative Disclosures About Market Risk" in Item 7A of this Form 10-K and Note 8 to our consolidated financial statements. ENVIRONMENTAL EXPENDITURES We are subject to numerous environmental laws and regulations, which require us to incur substantial costs to operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past operations on the environment. For additional information regarding environmental contingencies, please read Note 14(g) to our consolidated financial statements. Clean Air Act Expenditures. We expect the majority of capital expenditures associated with environmental matters to be incurred by our Electric Operations and Wholesale Energy business segments in connection with emission limitations for NOx under the Clean Air Act, or to enhance operational flexibility under Clean Air Act requirements. In 2000, emission reduction requirements for NOx were finalized for our electric generating facilities in Texas and the Mid-Atlantic region. We currently estimate that up to $534 million will be required to comply with the requirements through the end of 2003, with an estimated $215 million to be incurred in 2001. The Texas regulations require additional reductions that must be completed by March 2007. Estimates for the Texas units for the period 2004 through 2007 have not been defined, but could be up to $230 million. We are currently litigating the economic and technical viability of the Texas post-2004 reduction requirements, but cannot predict the outcome of this litigation. In addition, the Legislation created a program mandating air emissions reductions for some generating facilities of our Electric Operations segment. The Legislation provides for stranded costs recovery for costs associated with this obligation incurred before May 1, 2003. For additional information regarding the Legislation, please read Note 4(a) to our consolidated financial statements. Additional NOx emission controls for our generating units located in California may result in expenditures of up to $30 million through 2002. For additional information regarding environmental regulation of air emissions, please read "Business -- Environmental Matters -- Air Emissions" in Item 1 of this Form 10-K. Site Remediation Expenditures. From time to time we have received notices from regulatory authorities or others regarding our status as a potentially responsible party in connection with sites found to require remediation due to the presence of environmental contaminants. Based on currently available information, we believe that remediation costs will not materially affect our financial position, results of operations or cash flows. There can be no assurance, however, that future developments, including additional information about existing sites or the identification of new sites, will not require material revisions to our estimates. For information about specific sites that are the subject of remediation claims, please read Note 14(g) to our consolidated financial statements and Note 9(c) to RERC's consolidated financial statements. Water, Mercury and Other Expenditures. As discussed under "Business -- Environmental Matters -- Water Issues" in Item 1 of this Form 10-K, regulatory authorities are in the process of implementing regulations and quality standards in connection with the discharge of pollutants into waterways. Once these regulations and quality standards are enacted, we will be able to determine if our operations are in compliance, or if we will have to incur costs in order to comply with the quality standards and regulations. Until that time, however, we are not able to predict the amount of these expenditures, if any. To date, however, our expenditures associated with respect to permits, registrations and authorizations for operation of facilities under the statutes regulating the discharge of pollutants into surface water have not been material. With regard to mercury remediation and other environmental matters, such as the disposal of solid wastes, our expenditures have not been, and are not expected to be material, based on our experiences and that of others in our industries. Please read "Business -- Environmental Matters -- Mercury Contamination" and "-- Other" in Item 1 of this Form 10-K. 12
13 OTHER CONTINGENCIES For a description of other legal and regulatory proceedings affecting us, please read Notes 4 and 14 to our consolidated financial statements and Note 9 to RERC's consolidated financial statements. ITEMS INCORPORATED BY REFERENCE FROM THE RELIANT ENERGY 10-K NOTES o (2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (f) Regulatory Assets. The Company applies the accounting policies established in Statement of Financial Accounting Standards (SFAS) No. 71 (SFAS No. 71) to the accounts of transmission and distribution operations of Reliant Energy HL&P and the utility operations of Natural Gas Distribution and to some of the accounts of Pipelines and Gathering. For information regarding Reliant Energy HL&P's electric generation operations' discontinuance of the application of SFAS No. 71 in 1999 and the effect on its regulatory assets and the Texas Electric Choice Plan (Legislation), see Note 4(a). The following is a list of regulatory assets/liabilities reflected on the Company's Consolidated Balance Sheets as of December 31, 1999 and 2000.
14 For additional information regarding recoverable impaired plant costs and recoverable electric generation related assets and the related amortization during 1999 and 2000, see Notes 2(g) and 4(a). If, as a result of changes in regulation or competition, the Company's ability to recover these assets and liabilities would not be assured, then pursuant to SFAS No. 101, "Regulated Enterprises Accounting for the Discontinuation of Application of SFAS No. 71" (SFAS No. 101) and SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" (SFAS No. 121), the Company would be required to write off or write down these regulatory assets and liabilities. In addition, the Company would be required to determine any impairment to the carrying costs of plant and inventory assets. o (3) BUSINESS ACQUISITIONS (a) Reliant Energy Mid-Atlantic Power Holdings, LLC. On May 12, 2000, a subsidiary of the Company purchased entities owning electric power generating assets and development sites located in Pennsylvania, New Jersey and Maryland having an aggregate net generating capacity of approximately 4,262 megawatts (MW). With the exception of development entities that were sold to another subsidiary of the Company in July 2000, the assets of the entities acquired are held by Reliant Energy Mid-Atlantic Power Holdings, LLC (REMA). The purchase price for the May 2000 transaction was $2.1 billion, subject to post-closing adjustments which management does not believe will be material. The Company accounted for the acquisition as a purchase with assets and liabilities of REMA reflected at their estimated fair values. On a preliminary basis, the Company's fair value adjustments related to the acquisition primarily included adjustments in property, plant and equipment, air emissions regulatory allowances, materials and supplies inventory, environmental reserves and related deferred taxes. The air emissions regulatory allowances of $153 million are being amortized on a units-of-production basis as utilized. The excess of the purchase price over the fair value of net assets acquired of $7 million was recorded as goodwill and is being amortized over 35 years. The Company expects to finalize these fair value adjustments no later than May 2001, based on valuation reports of property, plant and equipment and intangible assets, and does not anticipate additional material modifications to the preliminary adjustments. Funds for the acquisition of REMA were made available through commercial paper borrowings by a finance subsidiary, which borrowings were supported by bank credit facilities. The net purchase price of REMA was allocated and the fair value adjustments to the seller's book value are as follows (in millions):
15 the sale of the Company's interest in the facilities, the Company received $1.0 billion in cash. The Company used the $1.0 billion of sale proceeds to repay commercial paper referred to above. The Company's results of operations include the results of REMA only for the period beginning May 12, 2000. Prior to November 24, 1999, the acquired entities' operations were fully integrated with, and their results of operations were consolidated into, the regulated electric utility operations of a prior owner of the facilities. In addition, prior to November 24, 1999, the electric output of the facilities was sold based on rates set by regulatory authorities and is not indicative of REMA's future results. The following table presents selected actual financial information and unaudited pro forma information for 1999 and 2000, as if the acquisition had occurred on November 24, 1999 and January 1, 2000, as applicable. Pro forma information prior to November 24, 1999 would not be meaningful since historical financial results of the business and the revenue generating activities underlying that period as described above are substantially different from the wholesale generation activities that REMA has been engaged in after November 24, 1999. Pro forma amounts also give effect to the sale and leaseback of interests in three of the REMA generating plants, which were consummated in August 2000.
16 shareholders agreed to reimburse UNA for some obligations incurred prior to the purchase of UNA. Adjustments to property, plant and equipment are based primarily on valuation reports prepared by independent appraisers and consultants. The excess of the purchase price over the fair value of net assets acquired of $897 million was recorded as goodwill and will be amortized on a straight-line basis over 30 years. The Company finalized these fair value adjustments during September 2000. The Company finalized a severance plan (UNA Plan) in connection with the UNA acquisition in September 2000 (commitment date) and in accordance with EITF 95-3 "Recognition of Liabilities in Connection with a Purchase Business Combination," recorded this liability of $19 million in the third quarter of 2000. Payments under the UNA Plan will be primarily made in mid-2001. In connection with the acquisition of UNA, the Company developed a comprehensive business process reengineering and employee severance plan intended to make UNA competitive in the deregulated Dutch electricity market that began January 1, 2001. The UNA Plan's initial conceptual formulation was initiated prior to the acquisition of UNA in October 1999. The finalization of the UNA Plan was approved and completed in September 2000. The Company identified 195 employees who will be involuntarily terminated in UNA's following functional areas: plant operations and maintenance, procurement, inventory, general and administrative, legal, finance and support. The Company has notified all employees identified under the severance component of the UNA Plan that they are subject to involuntary termination and that the majority of terminations will occur over a period not to exceed twelve months from the date of finalization of the UNA Plan. The termination benefits under the UNA Plan are governed by UNA's Social Plan, a collective bargaining agreement between UNA and its various representative labor unions signed in 1998. The Social Plan provides defined benefits for involuntarily severed employees, depending upon age, tenure and other factors, and was agreed to by the management of UNA as a result of the anticipated deregulation of the Dutch electricity market. The Social Plan is still in force and binding on the current management of the Company and UNA. The Company is currently executing the UNA Plan as of the date of these Consolidated Financial Statements. The net purchase price of UNA was allocated and the fair value adjustments to the seller's book value are as follows (in millions):
17 interest expense and the effects on depreciation and amortization of the assessed fair value of some of UNA's net assets and liabilities.
18 business will continue to be subject to cost-of-service rate regulation and will be responsible for the delivery of electricity to retail customers. Generation. Power generators will sell electric energy to wholesale purchasers, including retail electric providers, at unregulated rates beginning January 1, 2002. To facilitate a competitive market, each power generation company affiliated with a transmission and distribution utility will be required to sell at auction 15% of the output of its installed generating capacity. The first auction will be held on or before September 1, 2001 for power delivered after January 1, 2002. This obligation continues until January 1, 2007 unless before that date the Texas Utility Commission determines at least 40% of the quantity of electric power consumed in 2000 by residential and small commercial load in the electric utility's service area is being served by retail electric providers other than the affiliated retail electric provider. See Note 4(b) for information regarding the capacity auctions and the effect of the Business Separation Plan on the Company. The Legislation also creates a program mandating air emissions reductions for non-permitted generating facilities. The Company anticipates that any stranded costs associated with this obligation incurred before May 1, 2003 will be recoverable through the stranded costs recovery mechanisms contained in the Legislation. Rates. Base rates charged by Reliant Energy HL&P on September 1, 1999 will be frozen until January 1, 2002. Pursuant to Texas Utility Commission regulations, effective January 1, 2002, retail rates charged to residential and small commercial customers by the utility's affiliated retail electric provider will be reduced by 6% from the average rates (on a bundled basis) in effect on January 1, 1999 (adjusted for fuel charges). That reduced rate will be known as the "price to beat" and will be charged by the affiliated retail electric provider to residential and small commercial customers in the utility's service area who have not elected service from another retail electric provider. The affiliated retail electric provider may not offer different rates to residential or small commercial customer classes in the utility's service area until the earlier of the date the Texas Utility Commission determines that 40% of power consumed by that class in the affiliated transmission and distribution utility's service area is being served by non-affiliated retail electric providers or January 1, 2005. In addition, the affiliated retail electric provider must make the price to beat available to eligible consumers until January 1, 2007. Stranded Costs. Reliant Energy HL&P will be entitled to recover its stranded costs (i.e., the excess of net book value of generation assets (as defined by the Legislation) over the market value of those assets) and its regulatory assets related to generation. The Legislation prescribes specific methods for determining the amount of stranded costs and the details for their recovery. However, during the base rate freeze period from 1999 through 2001, earnings above the utility's authorized return formula will be applied in a manner to accelerate depreciation of generation related plant assets for regulatory purposes. In addition, depreciation expense for transmission and distribution related assets may be redirected to generation assets for regulatory purposes during that period. The Texas Utility Commission has recently stated on record that it would consider requiring electric utilities to reverse the amount of redirected depreciation and accelerated depreciation previously taken if in its estimation the utility has overmitigated its stranded costs. The reversal could occur through a lower rate for the transmission and distribution utility and/or through credits contained in the transmission and distribution utility's rate. Any order requiring the reversal of these amounts would likely be included in the Texas Utility Commission proceeding establishing the initial rate of the transmission and distribution utility. The Company does not expect the final Reliant Energy HL&P transmission and distribution rate to be established until August 2001. For information regarding redirected depreciation, see "Accounting" in this Note 4(a). The Legislation provides for Reliant Energy HL&P, or a special purpose entity, to issue securitization bonds for the recovery of generation related regulatory assets and a portion of stranded costs. These bonds will be sold to third parties and will be amortized through non-bypassable charges to transmission and distribution customers. Any stranded costs not recovered through the securitization bonds will be recovered through a non-bypassable charge to transmission and distribution customers. Costs associated with nuclear decommissioning that have not been recovered as of January 1, 2002, will continue to be subject to cost-of-service rate regulation and will be included in a non-bypassable charge to transmission and distribution customers. For 18
19 further discussion of the effect of the Business Separation Plan on funding of the nuclear decommissioning trust fund, see Note 4(b). In May 2000, the Texas Utility Commission issued a financing order to the Company authorizing the issuance of transition bonds in an amount not to exceed $740 million plus actual up-front qualified costs. Payments on the transition bonds will be made out of funds derived from non-bypassable transition charges to Reliant Energy HL&P's transmission and distribution customers. The offering of the transition bonds will be registered under the Securities Act of 1933 and is expected to be consummated during 2001. Capacity Auction True-up. In accordance with the Legislation, beginning on January 1, 2002, and ending when the true-up proceeding is completed, any difference between market power prices received in the generation capacity auction and the Texas Utility Commission's earlier estimates of those market prices will be included in the 2004 stranded costs true-up, as further discussed below. This component of the true-up is intended to ensure that neither the customers nor the Company are disadvantaged economically as a result of the two-year transition period by providing this pricing structure. For information regarding the effect of the Business Separation Plan on the generation capacity auctions, see Note 4(b). Accounting. Historically, Reliant Energy HL&P has applied the accounting policies established in SFAS No. 71. In general, SFAS No. 71 permits a company with cost-based rates to defer some costs that would otherwise be expensed to the extent that it meets the following requirements: (a) its rates are regulated by a third-party; (b) its rates are cost-based; and (c) there exists a reasonable assumption that all costs will be recoverable from customers through rates. When a company determines that it no longer meets the requirements of SFAS No. 71, pursuant to SFAS No. 101 and SFAS No. 121, it is required to write off regulatory assets and liabilities unless some form of recovery continues through rates established and collected from remaining regulated operations. In addition, such company is required to determine any impairment to the carrying costs of deregulated plant and inventory assets in accordance with SFAS No. 121. In July 1997, the EITF reached a consensus on Issue No. 97-4, "Deregulation of the Pricing of Electricity -- Issues Related to the Application of FASB Statements No. 71, Accounting for the Effects of Certain Types of Regulation, and No. 101, Regulated Enterprises Accounting for the Discontinuation of Application of FASB Statement No. 71" (EITF No. 97-4). EITF No. 97-4 concluded that a company should no longer apply SFAS No. 71 to a segment which is subject to a deregulation plan at the time the deregulation legislation or enabling rate order contains sufficient detail for the utility to reasonably determine how the plan will affect the segment to be deregulated. In addition, EITF No. 97-4 requires that regulatory assets and liabilities be allocated to the applicable portion of the electric utility from which the source of the regulated cash flows will be derived. The Company believes that the Legislation provides sufficient detail regarding the deregulation of the Company's electric generation operations to require it to discontinue the use of SFAS No. 71 for those operations. Effective June 30, 1999, the Company applied SFAS No. 101 to Reliant Energy HL&P's electric generation operations. Reliant Energy HL&P's transmission and distribution operations continue to meet the criteria of SFAS No. 71. In 1999, the Company evaluated the effects that the Legislation would have on the recovery of its generation related regulatory assets and liabilities. The Company determined that a pre-tax accounting loss of $282 million existed because it believes only the economic value of its generation related regulatory assets (as defined by the Legislation) will be recovered. Therefore, the Company recorded a $183 million after-tax extraordinary loss in the fourth quarter of 1999. If events were to occur that made the recovery of some of the remaining generation related regulatory assets no longer probable, the Company would write off the remaining balance of such assets as a non-cash charge against earnings. Pursuant to EITF No. 97-4, the remaining recoverable regulatory assets will not be written off and will become associated with the transmission and distribution portion of the Company's electric utility business. For details regarding Reliant Energy HL&P's regulatory assets, see Note 2(f). At June 30, 1999, the Company performed an impairment test of its previously regulated electric generation assets pursuant to SFAS No. 121 on a plant specific basis. Under SFAS No. 121, an asset is 19
20 considered impaired, and should be written down to fair value, if the future undiscounted net cash flows expected to be generated by the use of the asset are insufficient to recover the carrying amount of the asset. For assets that are impaired pursuant to SFAS No. 121, the Company determined the fair value for each generating plant by estimating the net present value of future cash inflows and outflows over the estimated life of each plant. The difference between fair value and net book value was recorded as a reduction in the current book value. The Company determined that $797 million of electric generation assets were impaired as of June 30, 1999. Of these amounts, $745 million related to the South Texas Project and $52 million related to two gas-fired generation plants. The Legislation provides for recovery of this impairment through regulated cash flows during the transition period and through non-bypassable charges to transmission and distribution customers. As such, a regulatory asset has been recorded for an amount equal to the impairment loss and is included on the Company's Consolidated Balance Sheets as a regulatory asset. The Company recorded amortization expense related to the recoverable impaired plant costs and other assets created from discontinuing SFAS No. 71 of $221 million in the third and fourth quarters of 1999 and $329 million in 2000. The Company expects to fully amortize this regulatory asset as it is recovered from regulated cash flows in 2001. The impairment analysis requires estimates of possible future market prices, load growth, competition and many other factors over the lives of the plants. The resulting impairment loss is highly dependent on these underlying assumptions. In addition, after January 10, 2004, Reliant Energy HL&P must finalize and reconcile stranded costs (as defined by the Legislation) in a filing with the Texas Utility Commission. Any positive difference between the regulatory net book value and the fair market value of the generation assets (as defined by the Legislation) will be collected through future non-bypassable charges. Any over-mitigation of stranded costs may be refunded through future non-bypassable charges. This final reconciliation allows alternative methods of third party valuation of the fair market value of these assets, including outright sale, stock valuations and asset exchanges. Because generally accepted accounting principles require the Company to estimate fair market values on a plant-by-plant basis in advance of the final reconciliation, the financial impacts of the Legislation with respect to the final determination of stranded costs in 2004 are subject to material changes. Factors affecting such change may include estimation risk, uncertainty of future energy and commodity prices and the economic lives of the plants. If events occur that make the recovery of all or a portion of the regulatory assets associated with the generation plant impairment loss and other assets created from discontinuance of SFAS No. 71 pursuant to the Legislation no longer probable, the Company will write off the corresponding balance of these assets as a non-cash charge against earnings. One of the results of discontinuing the application of SFAS No. 71 for the generation operations is the elimination of the regulatory accounting effects of excess deferred income taxes and investment tax credits related to these operations. The Company believes it is probable that some parties will seek to return these amounts to ratepayers and accordingly, the Company has recorded an offsetting liability. In order to reduce potential exposure to stranded costs related to generation assets, Reliant Energy HL&P redirected $195 million and $99 million of depreciation in 1998 and for the six months ended June 30, 1999, respectively, from transmission and distribution related plant assets to generation assets for regulatory and financial reporting purposes. This redirection was in accordance with the Company's Transition Plan. See Note 4(c) for additional information regarding the Transition Plan. The Legislation provides that depreciation expense for transmission and distribution related assets may be redirected to generation assets during the base rate freeze period from 1999 through 2001. For regulatory purposes, the Company has continued to redirect transmission and distribution depreciation to generation assets. Beginning June 30, 1999, redirected depreciation expense cannot be recorded by the electric generation operations portion of Reliant Energy HL&P for financial reporting purposes as this portion of electric operations is no longer accounted for under SFAS No. 71. During the six months ended December 31, 1999 and during 2000, $99 million and $218 million in depreciation expense, respectively, has been redirected from transmission and distribution for regulatory purposes and has been established as an embedded regulatory asset included in transmission and distribution related plant and equipment balances. As of December 31, 1999 and 2000, the cumulative amount of redirected depreciation for regulatory purposes is $393 million and $611 million, respectively. 20
21 The Company has reviewed its long-term purchase power contracts and fuel contracts for potential loss in accordance with SFAS No. 5, "Accounting for Contingencies" and Accounting Research Bulletin No. 43, Chapter 4, "Inventory Pricing." Based on projections of future market prices for wholesale electricity, the analysis indicated no loss recognition is appropriate at this time. Other Accounting Policy Changes. As a result of discontinuing SFAS No. 71, the accounting policies discussed below related to Electric Operations' generation operations have been changed effective July 1, 1999. Allowance for funds used during construction will no longer be accrued on generation related construction projects. Instead, interest will be capitalized on these projects in accordance with SFAS No. 34, "Capitalization of Interest Cost." Previously, in accordance with SFAS No. 71, Reliant Energy HL&P deferred the premiums and expenses that arose when long-term debt was redeemed and amortized these costs over the life of the new debt. If no new debt was issued, these costs were amortized over the remaining original life of the retired debt. Effective July 1, 1999, costs resulting from the retirement of debt attributable to the generation operations of Reliant Energy HL&P will be recorded in accordance with SFAS No. 4, "Reporting Gains and Losses from Extinguishment of Debt," unless these costs will be recovered through regulated cash flows. In that case, these costs will be deferred and recorded as a regulatory asset by the entity through which the source of the regulated cash flows will be derived. (b) Business Separation Plan. General. As required by the Legislation, Reliant Energy submitted the Business Separation Plan in 2000 to the Texas Utility Commission. The Business Separation Plan was later amended to provide for the restructuring of the Company's businesses into two separate and publicly traded companies in order to separate its unregulated businesses from its regulated businesses. In December 2000, the plan was approved by the Texas Utility Commission. Reliant Resources holds Reliant Energy's unregulated businesses, including the Wholesale Energy segment, European Energy segment, communications business, eBusiness group, new ventures group and retail electric business. As further described below, Reliant Energy will undergo a restructuring of the Company's corporate organization to achieve a holding company structure. This holding company will hold primarily what are currently Reliant Energy's rate-regulated businesses. Reliant Resources expects to conduct the Offering in 2001. After the Offering, Reliant Energy will own approximately 80% of Reliant Resources common stock. Reliant Energy expects the Offering to be followed by a distribution to Reliant Energy's or its successor's shareholders of the remaining common stock of Reliant Resources within 12 months of the Offering (the Distribution Date). The Offering and the Distribution are subject to further corporate approvals, market and other conditions, and government actions, including receipt of a favorable Internal Revenue Service ruling that the Distribution would be tax-free to Reliant Energy or its successor and its shareholders for U.S. federal income tax purposes, as applicable. There can be no assurance that the Offering and the Distribution will be completed as described or within the time periods outlined above. Restructuring of Regulated Entities. Under the Business Separation Plan, Reliant Energy will restructure its regulated operations into a holding company structure in which a new corporate entity (Regulated Holding Company) will be formed as the parent with the Company's regulated businesses as subsidiaries. This Regulated Holding Company is expected to own (a) the Company's electric transmission and distribution operations, (b) its natural gas distribution businesses, (c) initially, its regulated electric generating assets in Texas, (d) its interstate pipelines, gas gathering and pipeline services operations, and (e) its interests in energy companies in Latin America until disposition of these investments (see Note 19). In these Notes, references to Reliant Energy in connection with events occurring or the performance of agreements after the restructuring generally refer to the Regulated Holding Company. In connection with the formation of the new holding company for regulated businesses, Reliant Energy expects to transfer the stock of all of its subsidiaries to the new holding company and will transfer its regulated electric generating assets in Texas to an indirect wholly owned partnership (Texas Genco) until the stranded costs associated with those assets are valued in 2004. At that time, Reliant Resources will have the right to 21
22 exercise an option to acquire those assets, as further discussed below. As a result of the stock and asset transfers described above, Reliant Energy will become solely a transmission and distribution company, with its other businesses becoming subsidiaries of the new holding company. Reliant Energy expects that the regulated holding company will be required to assume all of Reliant Energy's debt other than its first mortgage bonds, which would remain with Reliant Energy. The indebtedness of some wholly owned financing subsidiaries is expected to be refinanced by the regulated holding company by the end of 2002. Reliant Energy has made and will continue to make internal asset and stock transfers intended to allocate the assets and liabilities of Reliant Energy in accordance with regulatory requirements and as contemplated by the Business Separation Plan. Forms of each of the intercompany agreements described below have been prepared and will be entered into by Reliant Energy and Reliant Resources prior to the Offering. Aspects of the restructuring of Reliant Energy's regulated businesses are subject to the approval of Reliant Energy's shareholders and lenders and approvals from the SEC under the Public Utility Holding Company Act and from the United States Nuclear Regulatory Commission (NRC). There can be no assurance that the restructuring of the Company's regulated businesses will be completed as described above. Agreements Related to Texas Generating Assets. Pursuant to the Business Separation Plan, Reliant Energy expects to cause Texas Genco to either issue and sell in an initial public offering or to distribute to its shareholders no more than 20% of the common stock of Texas Genco by June 30, 2002. In connection with the separation of its unregulated businesses from its regulated businesses, Reliant Energy will grant Reliant Resources an option to purchase all of the shares of capital stock of Texas Genco that will be owned by Reliant Energy after the initial public offering or distribution. The Texas Genco option may be exercised between January 10, 2004 and January 24, 2004. The per share exercise price under the option will be the average daily closing price on the national exchange for publicly held shares of common stock of Texas Genco for the 30 consecutive trading days with the highest average closing price during the 120 trading days immediately preceding January 10, 2004, plus a control premium, up to a maximum of 10%, to the extent a control premium is included in the valuation determination made by the Texas Utility Commission relating to the market value of Texas Genco's common stock equity. The exercise price is also subject to adjustment based on the difference between the per share dividends paid during the period there is a public ownership interest in Texas Genco and Texas Genco's per share earnings during that period. If the disposition to the public of common stock of Texas Genco is by means of a primary or secondary public offering, the public offering may be of as little as 17% (rather than 19%) of Texas Genco's outstanding common stock, in which case Reliant Energy will have the right to subsequently reduce its interest to a level not less than 80%. Reliant Resources will agree that if it exercises the Texas Genco Option and purchases the shares of Texas Genco common stock, Reliant Resources will also purchase all notes and other receivables from Texas Genco then held by Reliant Energy, at their principal amount plus accrued interest. Similarly, if Texas Genco holds notes or receivables from the Company, Reliant Resources will assume those obligations in exchange for a payment to Reliant Resources by the Company of an amount equal to the principal plus accrued interest. Exercise of the Texas Genco option by Reliant Resources will be subject to various regulatory approvals, including Hart-Scott-Rodino antitrust clearance and Nuclear Regulatory Commission license transfer approval. The option will be exercisable only if Reliant Energy or its successor distributes all of the shares of Reliant Resources common stock it owns to its shareholders. The Texas Genco option agreement will require Reliant Energy to take commercially reasonable action as may be appropriate to cause Texas Genco to have a capital structure appropriate, in the judgment of Reliant Energy's Board of Directors, for the satisfactory marketing of Texas Genco common stock in an initial public offering or to establish a satisfactory trading market for Texas Genco common stock following a distribution of shares to Reliant Energy's shareholders. It also will contain covenants relating to the operation of the Texas Genco assets prior to the exercise or expiration of the option and require that Reliant Energy maintain ownership of all equity of Texas Genco until exercise or expiration of the Texas Genco option, subject to the initial public offering or distribution obligation. Reliant Resources will provide engineering and technical support services and environmental, safety and industrial health services to support the operations and maintenance of Texas Genco's facilities. Reliant 22
23 Resources will also provide systems, technical, programming and consulting support services and hardware maintenance (but excluding plant-specific hardware) necessary to provide dispatch planning, dispatch and settlement and communication with the independent system operator. The fees charged for these services will be designed to allow Reliant Resources to recover its fully allocated direct and indirect costs and reimbursement of out-of-pocket expenses. Expenses associated with capital investment in systems and software that benefit both the operation of Texas Genco's facilities and Reliant Resources' facilities in other regions will be allocated on an installed megawatt basis. The term of the technical services agreement will begin at the Distribution Date. The term of this agreement will end on the first to occur of (a) the closing date of the Reliant Resources' Texas Genco option, (b) Reliant Energy's sale of Texas Genco, or all or substantially all of the assets of Texas Genco, if Reliant Resources does not exercise the Texas Genco option, or (c) December 31, 2004, provided the Texas Genco option is not exercised. Texas Genco may extend the term of this agreement until December 31, 2005. Pursuant to the Legislation, Texas Genco will be required to sell at auction 15% of the output of its installed generating capacity beginning January 1, 2002. The first auction will be held on or before September 1, 2001 for power delivered after January 1, 2002. This obligation continues until January 1, 2007, unless before that date the Texas Utility Commission determines that at least 40% of the quantity of electric power consumed in 2000 by residential and small commercial customers in the Reliant Energy HL&P traditional service area is being served by retail electric providers other than subsidiaries of Reliant Resources. Texas Genco plans to auction all of its remaining output during the time period prior to Reliant Resources' exercise of the Texas Genco option. Pursuant to the Business Separation Plan, Reliant Resources is entitled to purchase, at prices established in these auctions, up to 50% of the remaining capacity, energy and ancillary services auctioned by Texas Genco. When Texas Genco is organized, it will become the beneficiary of the decommissioning trust that has been established to provide funding for decontamination and decommissioning of a nuclear electric generation station in which Reliant Energy owns a 30.8% interest (see Note 6). The master separation agreement will provide that Reliant Energy will collect through rates or other authorized charges to its electric utility customers amounts designated for funding the decommissioning trust, and will pay the amounts to Texas Genco. Texas Genco will in turn be required to deposit these amounts received from Reliant Energy into the decommissioning trust. Upon decommissioning of the facility, in the event funds from the trust are inadequate, Reliant Energy will be required to collect through rates or other authorized charges to customers as contemplated by the Texas Utilities Code all additional amounts required to fund Texas Genco's obligations relating to the decommissioning of the facility. Following the completion of the decommissioning, if surplus funds remain in the decommissioning trust, the excess will be refunded to Reliant Energy's ratepayers. Retail Agreement between Reliant Energy and Reliant Resources. Under a retail agreement, Reliant Resources will provide customer service call center operations, credit and collections and revenue reporting services for Reliant Energy's electric utility division and receiving and processing payments for the accounts of Reliant Energy's electric utility division and two of Reliant Energy's natural gas distribution divisions. Reliant Energy will provide the office space and equipment for Reliant Resources to perform these services. These services will terminate on January 1, 2002. The charges Reliant Energy will pay Reliant Resources for these services are generally intended to allow Reliant Resources to recover its fully allocated costs of providing the services, plus out-of-pocket costs and expenses. Service Agreements between Reliant Energy and Reliant Resources. Reliant Resources plans to enter into agreements with Reliant Energy under which Reliant Energy will provide Reliant Resources, on an interim basis, with various corporate support services (including accounting, finance, investor relations, planning, legal, communications, governmental and regulatory affairs and human resources), information technology services and other previously shared services such as corporate security, facilities management, accounts receivable, accounts payable and payroll, office support services and purchasing and logistics. These arrangements will continue after the Offering under a transition services agreement providing for their continuation until December 31, 2004, or, in the case of some corporate support services, until the 23
24 Distribution Date. The charges Reliant Resources will pay Reliant Energy for these services are generally intended to allow Reliant Energy to recover its fully allocated costs of providing the services, plus out-of-pocket costs and expenses. In each case, Reliant Resources will have the right to terminate categories of services at an earlier date. Pursuant to a lease agreement, Reliant Energy will lease Reliant Resources office space in its headquarters building in Houston, Texas for an interim period. Other Agreements. In connection with the separation of Reliant Resources' businesses from those of Reliant Energy, Reliant Resources will also enter into other agreements providing, among other things, for mutual indemnities and releases with respect to Reliant Resources' respective businesses and operations, matters relating to corporate governance, matters relating to responsibility for employee compensation and benefits, and allocation of tax liabilities. In addition, Reliant Resources and Reliant Energy will enter into various agreements relating to ongoing commercial arrangements, including among other things the leasing of optical fiber and related maintenance activities, rights to build fiber networks along existing rights of way, and the provision of local exchange telecommunications and data services in the greater Houston metropolitan area and long distance telecommunications services. Reliant Energy will agree that $1.9 billion of intercompany indebtedness owed by Reliant Resources and its subsidiaries prior to the closing of the Offering will be converted into equity as a capital contribution to Reliant Resources. (c) Transition Plan. In June 1998, the Texas Utility Commission issued an order in Docket No. 18465 approving the Company's Transition Plan filed by Reliant Energy HL&P in December 1997. The Transition Plan included base rate credits to residential customers of 4% in 1998 and an additional 2% in 1999. Commercial customers whose monthly billing is 1,000 kva or less were entitled to receive base rate credits of 2% in each of 1998 and 1999. The Company implemented the Transition Plan effective January 1, 1998. (d) Reliant Energy HL&P Filings. As of December 31, 2000, Reliant Energy HL&P had recorded as a regulatory asset under-recovered fuel cost of $558 million. In two separate filings in 2000, Reliant Energy HL&P filed and received approval to implement a fuel surcharge to collect the under recovery of fuel expenses, as well as to adjust the fuel factor to compensate for significant increases in the price of natural gas. On March 15, 2001, Reliant Energy HL&P filed to revise its fuel factor and address the Company's undercollected fuel costs of $389 million, which is the accumulated amount since September 2000 through February 2001 plus estimates for March and April, 2001. Reliant Energy HL&P is requesting to revise its fixed fuel factor to be implemented with the May 2001 billing cycle and has proposed to defer the collection of the $389 million until the 2004 stranded costs true-up proceeding, discussed in Note 4(a) above. o (5) DERIVATIVE FINANCIAL INSTRUMENTS (a) Price Risk Management and Trading Activities. The Company offers energy price risk management services primarily related to natural gas, electric power and other energy related commodities. The Company provides these services by utilizing a variety of derivative financial instruments, including (a) fixed and variable-priced physical forward contracts, (b) fixed and variable-priced swap agreements, (c) options traded in the over-the-counter financial markets and (d) exchange-traded energy futures and option contracts (Trading Derivatives). Fixed-price swap agreements require payments to, or receipts of payments from, counterparties based on the differential between a fixed and variable price for the commodity. Variable-price swap agreements require payments to, or receipts of payments from, counterparties based on the differential between industry pricing publications or exchange quotations. 24
25 The Company applies mark-to-market accounting for all of its energy trading, marketing and price risk management operations. Accordingly, these Trading Derivatives are recorded at fair value with realized and unrealized gains (losses) recorded as a component of revenues. The recognized, unrealized balances are included in price risk management assets/liabilities. The notional quantities, maximum terms and the estimated fair value of Trading Derivatives at December 31, 1999 and 2000 are presented below (volumes in billions of British thermal units equivalent (Bbtue) and dollars in millions):
26 conditions, market liquidity and the Company's risk management portfolio needs and strategies. Terms regarding cash settlements of these contracts vary with respect to the actual timing of cash receipts and payments. In addition to the risk associated with price movements, credit risk is also inherent in the Company's risk management activities. Credit risk relates to the risk of loss resulting from non-performance of contractual obligations by a counterparty. The following table shows the composition of the total price risk management assets of the Company as of December 31, 1999 and 2000.
27 In connection with the Company's acquisition of UNA in 1999, the Company entered into call option agreements with several banks to hedge the impact of foreign exchange movements on the Dutch guilder. These call options provided the right, but not the obligation, to purchase NLG 695 million from specific banks at specific strike prices. The total premium paid, classified as other expense on the Company's Statement of Consolidated Operations, for all of the options that were to expire on October 26, 1999, was $8 million. On October 12, 1999, the Company sold the remaining value in the call options for $0.6 million. The proceeds were reflected in the Company's results of operations as a reduction of other expense. As of December 31, 1999 and 2000, the Company had outstanding foreign currency swaps for 258 million and Euros 671 million, respectively (approximately $228 million and $632 million), terminating in September 2000 and January 2001, respectively. The Company also issued Euro-denominated debt, maturing in March and June 2001. The foreign currency swaps and Euro-denominated debt hedge the Company's net investment in UNA. In January 2001, the Company entered into foreign currency swaps for Euros 671 million (approximately $633 million) to replace the foreign currency swaps that expired in January 2001. These foreign currency swaps terminate in January 2002. In January and March 2001, the Company entered into foreign currency forward contracts for Euros 159 million (approximately $150 million) to adjust the hedge of its net investment in UNA. These forward contracts expire in January 2002. The Company records changes in the value of the hedging instruments and debt as foreign currency translation adjustments as a component of stockholders' equity and accumulated other comprehensive loss. The effectiveness of the hedging instruments can be measured by the net change in foreign currency translation adjustments attributed to the net investment in UNA. These amounts generally offset amounts recorded in stockholders' equity as adjustments resulting from translation of the hedged investment into U.S. dollars. As of December 31, 1999 and 2000, the net carrying value of the currency swaps was a $6 million receivable and $62 million obligation, respectively, and was recorded in other current assets and other current liabilities in the Company's Consolidated Balance Sheets. During 2000, European Energy entered into financial instruments to purchase approximately $120 million to hedge future fuel purchases payable in U.S. dollars. As of December 31, 2000, the fair value of these financial instruments was a $6 million liability. Unrealized changes in the market value of these financial instruments are not recognized in the Company's Statements of Consolidated Operations until the underlying hedged transaction occurs. For transactions involving either Energy Derivatives or foreign currency derivatives, hedge accounting is applied only if the derivative reduces the risk of the underlying hedged item and is designated as a hedge at its inception. Additionally, the derivatives must be expected to result in financial impacts that are inversely correlated to those of the item(s) to be hedged. This correlation, a measure of hedge effectiveness, is measured both at the inception of the hedge and on an ongoing basis, with an acceptable level of correlation of at least 80% for hedge designation. If and when correlation ceases to exist at an acceptable level, hedge accounting ceases and mark-to-market accounting is applied. At December 31, 1999, the Company was a fixed-price payor and a fixed-price receiver in Energy Derivatives covering 33,108 Bbtu and 5,481 Bbtu of natural gas, respectively. At December 31, 2000, the Company was a fixed-price payor and a fixed-price receiver in Energy Derivatives covering 198,001 Bbtu and 22,874 Bbtu of natural gas, respectively, and 486 Bbtu and zero Bbtu of oil, respectively. In addition to the fixed-price notional volumes above, the Company also has variable-priced agreements totaling 44,958 Bbtu and 174,900 Bbtu of natural gas at December 31, 1999 and 2000, respectively. The weighted average maturity of these instruments is less than two years. The notional amount is intended to be indicative of the Company's level of activity in these derivatives. However, the amounts at risk are significantly smaller because, in view of the price movement correlation required for hedge accounting, changes in the market value of these derivatives generally are offset by changes in the value associated with the underlying physical transactions or in other derivatives. When Energy Derivatives are closed out in advance of the underlying commitment or anticipated transaction, however, the market value changes may not offset due to the fact that price movement correlation ceases to exist when the 27
28 positions are closed, as further discussed above. Under these circumstances, gains (losses) are deferred and recognized as a component of income when the underlying hedged item is recognized in income. The average maturity discussed above and the fair value discussed in Note 15 are not necessarily indicative of likely future cash flows as these positions may be changed by new transactions in the trading portfolio at any time in response to changing market conditions, market liquidity and the Company's risk management portfolio needs and strategies. Terms regarding cash settlements of these contracts vary with respect to the actual timing of cash receipts and payments. (c) Trading and Non-trading -- General Policy. In addition to the risk associated with price movements, credit risk is also inherent in the Company's risk management activities. Credit risk relates to the risk of loss resulting from non-performance of contractual obligations by a counterparty. The Company has off-balance sheet risk to the extent that the counterparties to these transactions may fail to perform as required by the terms of each contract. In order to minimize this risk, the Company enters into these contracts primarily with counterparties having a minimum investment grade index rating, i.e. a Standard & Poor's or Moody's rating of BBB- or Baa3, respectively. For long-term arrangements, the Company periodically reviews the financial condition of these firms in addition to monitoring the effectiveness of these financial contracts in achieving the Company's objectives. If the counterparties to these arrangements fail to perform, the Company would seek to compel performance at law or otherwise obtain compensatory damages. The Company might be forced to acquire alternative hedging arrangements or be required to replace the underlying commitment at then-current market prices. In this event, the Company might incur additional losses to the extent of amounts, if any, already paid to the counterparties. For information regarding credit risk related to the California wholesale electricity market, see Note 14(h). The Company's policies prohibit the use of leveraged financial instruments. A leveraged financial instrument, for this purpose, is a transaction involving a derivative whose financial impact will be based on an amount other than the notional amount or volume of the instrument. The Company has established a Risk Oversight Committee, comprised of corporate and business segment officers that oversees all commodity price and credit risk activities, including the Company's trading, marketing, power origination and risk management activities. The committee's duties are to establish the Company's commodity risk policies, allocate risk capital within limits established by the Company's Board of Directors, approve trading of new products and commodities, monitor risk positions and ensure compliance with the Company's risk management policies and procedures and trading limits established by the Company's Board of Directors. o (8) INDEXED DEBT SECURITIES (ACES AND ZENS) AND AOL TIME WARNER SECURITIES (a) Original Investment in Time Warner Securities. On July 6, 1999, the Company converted its 11 million shares of Time Warner Inc. (TW) convertible preferred stock (TW Preferred) into 45.8 million shares of Time Warner common stock (TW Common). Prior to the conversion, the Company's investment in the TW Preferred was accounted for under the cost method at a value of $990 million in the Company's Consolidated Balance Sheets. The TW Preferred was redeemable after July 6, 2000, had an aggregate liquidation preference of $100 per share (plus accrued and unpaid dividends), was entitled to annual dividends of $3.75 per share until July 6, 1999 and was convertible by the Company. The Company recorded pre-tax dividend income with respect to the TW Preferred of $21 million in 1999 prior to the conversion and $41 million in 1998. Effective on the conversion date, the shares of TW Common were classified as trading securities under SFAS No. 115 and an unrealized gain was recorded in the amount of $2.4 billion ($1.5 billion after-tax) to reflect the cumulative appreciation in the fair value of the Company's investment in Time Warner securities. 28
29 (b) ACES. In July 1997, in order to monetize a portion of the cash value of its investment in TW Preferred, the Company issued 22.9 million of its unsecured 7% Automatic Common Exchange Securities (ACES) having an original principal amount of $1.052 billion and maturing July 1, 2000. The market value of ACES was indexed to the market value of TW Common. On the July 1, 2000 maturity date, the Company tendered 37.9 million shares of TW Common to fully settle its obligations in connection with its unsecured 7% ACES having a value of $2.9 billion. (c) ZENS. On September 21, 1999, the Company issued approximately 17.2 million of its 2.0% Zero-Premium Exchangeable Subordinated Notes due 2029 (ZENS) having an original principal amount of $1.0 billion. The original principal amount per ZENS will increase each quarter to the extent that the sum of the quarterly cash dividends and the interest paid during a quarter on the reference shares attributable to one ZENS is less than $.045, so that the annual yield to investors from the date the Company issued the ZENS to the date of computation of the contingent principal amount is not less than 2.309%. At maturity the holders of the ZENS will receive in cash the higher of the original principal amount of the ZENS (subject to adjustment as discussed above) or an amount based on the then-current market value of TW Common, or other securities distributed with respect to TW Common (one share of TW Common and such other securities, if any, are referred to as reference shares). Each ZENS has an original principal amount of $58.25 (the closing market price of the TW Common on September 15, 1999) and is exchangeable at any time at the option of the holder for cash equal to 95% (100% in some cases) of the market value of the reference shares attributable to one ZENS. The Company pays interest on each ZENS at an annual rate of 2% plus the amount of any quarterly cash dividends paid in respect of the quarterly interest period on the reference shares attributable to each ZENS. Subject to some conditions, the Company has the right to defer interest payments from time to time on the ZENS for up to 20 consecutive quarterly periods. As of December 31, 2000, no interest payments on the ZENS had been deferred. On January 11, 2001, TW and America Online, Inc. combined to form AOL Time Warner Inc. (AOL TW). As a result of the combination each share of TW Common was converted into 1.5 shares of AOL TW Common Stock (AOL TW Common) and the Company now holds 25.8 million shares of AOL TW Common. As a result of the combination, the reference shares attributable to one ZENS is 1.5 shares of AOL TW Common. The Company used $537 million of the net proceeds from the offering of the ZENS to purchase 9.2 million shares of TW Common, which are classified as trading securities under SFAS No. 115. Unrealized gains and losses resulting from changes in the market value of the TW Common are recorded in the Company's Statements of Consolidated Operations. Prior to January 1, 2001, an increase above $58.25 (subject to some adjustments) in the market value per share of TW Common resulted in an increase in the Company's liability for the ZENS. However, as the market value per share of TW Common declined below $58.25 (subject to some adjustments), the liability for the ZENS did not decline below the original principal amount. As of December 31, 1999 and 2000, the market value of TW Common was $72.31 and $52.24, respectively. Therefore, during 2000, the Company recorded a pre-tax net unrealized loss on its investment in TW Common and its obligation on its indexed debt securities of $103 million. Prior to the purchase of additional shares of TW Common on September 21, 1999, the Company owned approximately 8 million shares of TW Common that were in excess of the 38 million shares needed to economically hedge its ACES obligation. For the period from July 6, 1999 to the ZENS issuance date, losses (due to the decline in the market value of the TW Common during such period) on these 8 million shares were $122 million ($79 million after-tax). The 8 million shares of TW Common combined with the additional 9.2 million shares purchased are expected to be held to facilitate the Company's ability to meet its obligation under the ZENS. 29
30 The following table sets forth summarized financial information regarding the Company's investment in TW securities and the Company's ACES and ZENS obligations.
31 (b) Fuel and Purchased Power. Reliant Energy HL&P is a party to several long-term coal, lignite and natural gas contracts, which have various quantity requirements and durations. Minimum payment obligations for coal and transportation agreements that extend through 2011 are approximately $280 million in 2001, $281 million in 2002 and $274 million in 2003. Purchase commitments related to lignite mining and lease agreements, natural gas purchases and storage contracts, and purchased power are not material to the operations of the Company. Currently, Reliant Energy HL&P is allowed recovery of these costs through base rates for electric service. As of December 31, 2000, some of these contracts are above market. The Company anticipates that stranded costs associated with these obligations will be recoverable through the stranded costs recovery mechanisms contained in the Legislation. For information regarding the Legislation, see Note 4(a). REMA is a party to several long-term fuel supply contracts which have various quantity requirements and durations. Minimum payment obligations under these agreements that extend through 2004 are as follows as of December 31, 2000 (in millions):
32 Total lease expense for all operating leases was $10 million, $13 million and $46 million during 1998, 1999 and 2000, respectively. (d) Cross Border Leases. During the period from 1994 through 1997, under cross border lease transactions, UNA leased several of its power plants and related equipment and turbines to non-Netherlands based investors (the head leases) and concurrently leased the facilities back under sublease arrangements with remaining terms as of December 31, 2000, of 1 to 24 years. UNA utilized proceeds from the head lease transactions to prepay its sublease obligations and to provide a source for payment of end of term purchase options and other financial undertakings. The initial sublease obligations totaled $2.4 billion of which $1.7 billion remained outstanding as of December 31, 2000. These transactions involve UNA providing to a foreign investor an ownership right in (but not necessarily title to) an asset, with a leaseback of that asset. The net proceeds to UNA of the transactions were recorded as a deferred gain and are currently being amortized to income over the lease terms. At December 31, 1999 and 2000, the unamortized deferred gain on these transactions totaled $87 million and $77 million, respectively. The power plants, related equipment and turbines remain on the financial statements of UNA and continue to be depreciated. UNA is required to maintain minimum insurance coverages, perform minimum annual maintenance and, in specified situations, post letters of credit. UNA's shareholder is subject to some restrictions with respect to the liquidation of UNA's shares. In the case of early termination of these contracts, UNA would be contingently liable for some payments to the sublessors, which at December 31, 2000, are estimated to be $274 million. Starting in March 2000, UNA was required by some of the lease agreements to obtain standby letters of credit in favor of the sublessors in the event of early termination. The amount of the required letters of credit was $274 million as of December 31, 2000. Commitments for these letters of credit have been obtained as of December 31, 2000. (e) Naming Rights to Houston Sports Complex. In October 2000, the Company acquired the naming rights for the new football stadium for the Houston Texans, the National Football League's newest franchise. In addition, the naming rights cover the entertainment and convention facilities included in the stadium complex. The agreement extends for 32 years. In addition to naming rights, the agreement provides the Company with significant sponsorship rights. The aggregate cost of the naming rights will be approximately $300 million. During the fourth quarter of 2000, the Company incurred an obligation to pay $12 million in order to secure the long-term commitment and for the initial advertising of which $10 million was expensed in the Company's Statement of Consolidated Operations in 2000. Starting in 2002, when the new stadium is operational, the Company will pay $10 million each year through 2032 for annual advertising under this agreement. (f) Transportation Agreement. A subsidiary of RERC Corp. had an agreement (ANR Agreement) with ANR Pipeline Company (ANR) that contemplated that this subsidiary would transfer to ANR an interest in some of RERC Corp.'s pipeline and related assets. As of December 31, 1999 and 2000, the Company had recorded $41 million in other long-term liabilities in the Company's Consolidated Balance Sheets to reflect the Company's obligation to ANR for the use of 130 Mmcf/day of capacity in some of the Company's transportation facilities. The level of transportation will decline to 100 Mmcf/day in the year 2003 with a refund of $5 million to ANR. The ANR Agreement will terminate in 2005 with a refund of $36 million. (g) Legal, Environmental and Other Regulatory Matters. LEGAL MATTERS. Reliant Energy HL&P Municipal Franchise Fee Lawsuits. In February 1996, the cities of Wharton, Galveston and Pasadena filed suit, for themselves and a proposed class of all similarly situated cities in Reliant Energy HL&P's service area, against Reliant Energy and Houston Industries Finance, Inc. (formerly a wholly 32
33 owned subsidiary of Reliant Energy) alleging underpayment of municipal franchise fees. Plaintiffs claim that they are entitled to 4% of all receipts of any kind for business conducted within these cities over the previous four decades. Because the franchise ordinances at issue affecting Reliant Energy HL&P expressly impose fees only on its own receipts and only from sales of electricity for consumption within a city, the Company regards all of plaintiffs' allegations as spurious and is vigorously contesting the case. The plaintiffs' pleadings asserted that their damages exceeded $250 million. The 269th Judicial District Court for Harris County granted partial summary judgment in favor of Reliant Energy dismissing all claims for franchise fees based on sales tax collections. Other motions for partial summary judgment were denied. A six-week jury trial of the original claimant cities (but not the class of cities) ended on April 4, 2000 (three cities case). Although the jury found for Reliant Energy on many issues, they found in favor of the original claimant cities on three issues, and assessed a total of $4 million in actual and $30 million in punitive damages. However, the jury also found in favor of Reliant Energy on the affirmative defense of laches, a defense similar to a statute of limitations defense, due to the original claimant cities having unreasonably delayed bringing their claims during the 43 years since the alleged wrongs began. The trial court in the three cities case granted most of Reliant Energy's motions to disregard the jury's findings. The trial court's rulings reduced the judgment to $1.7 million, including interest, plus an award of $13.7 million in legal fees. In addition, the trial court granted Reliant Energy's motion to decertify the class and vacated its prior orders certifying a class. Following this ruling, 45 cities filed individual suits against Reliant Energy in the District Court of Harris County. The extent to which issues in the three cities case may affect the claims of the other cities served by Reliant Energy HL&P cannot be assessed until judgments are final and no longer subject to appeal. However, the trial court's rulings disregarding most of the jury's findings are consistent with Texas Supreme Court opinions over the past decade. The Company estimates the range of possible outcomes for the plaintiffs to be between zero and $17 million inclusive of interest and attorneys' fees. The three cities case has been appealed. The Company believes that the $1.7 million damage award resulted from serious errors of law and that it will be set aside by the Texas appellate courts. In addition, the Company believes that because of an agreement between the parties limiting fees to a percentage of the damages, reversal of the award of $13.7 million in attorneys' fees in the three cities case is probable. California Wholesale Market. Reliant Energy and Reliant Energy Services, Inc. have been named as defendants in class action lawsuits and other lawsuits filed against a number of companies that own generation plants in California and other sellers of electricity in California markets. RERC Corp. has also been named as a defendant on one of the lawsuits. Pursuant to the terms of the master separation agreement between Reliant Energy and Reliant Resources (see Note 4(b)), Reliant Resources will agree to indemnify RERC Corp. for any damages arising under this lawsuit, and will agree to indemnify Reliant Energy for damages arising under any of these lawsuits, and may elect to defend these lawsuits at Reliant Resources' own expense. Three of these lawsuits were filed in the Superior Court of the State of California, San Diego County; two were filed in the Superior Court in San Francisco County. While the plaintiffs allege various violations by the defendants of state antitrust laws and state laws against unfair and unlawful business practices, each of the lawsuits is grounded on the central allegation that defendants conspired to drive up the wholesale price of electricity. In addition to injunctive relief, the plaintiffs in these lawsuits seek treble the amount of damages alleged, restitution of alleged overpayments, disgorgement of alleged unlawful profits for sales of electricity during all or portions of 2000, costs of suit and attorneys' fees. In one of the cases the plaintiffs allege aggregate damages of over $4 billion. Defendants have filed petitions to remove the cases to federal court. Furthermore, defendants have filed a motion with the Panel on Multidistrict Litigation seeking transfer and consolidation of all the cases. These lawsuits have only recently been filed. Therefore, the ultimate outcome of the lawsuits cannot be predicted with any degree of certainty at this time. However, the Company does not believe, based on its analysis to date of the claims asserted in these lawsuits and the underlying facts, that resolution of these lawsuits will have a material adverse effect on the Company's financial condition, results of operations or cash flows. 33
34 ENVIRONMENTAL MATTERS. Manufactured Gas Plant Sites. RERC Corp. and its subsidiaries (RERC) and its predecessors operated a manufactured gas plant (MGP) adjacent to the Mississippi River in Minnesota, formerly known as Minneapolis Gas Works (MGW) until 1960. RERC has substantially completed remediation of the main site other than ongoing water monitoring and treatment. The manufactured gas was stored in separate holders. RERC is negotiating clean-up of one such holder. There are six other former MGP sites in the Minnesota service territory. Remediation has been completed on one site. Of the remaining five sites, RERC believes that two were neither owned nor operated by RERC. RERC believes it has no liability with respect to the sites it neither owned nor operated. At December 31, 1999 and 2000, RERC had accrued $19 million and $17 million, respectively, for remediation of the Minnesota sites. At December 31, 2000, the estimated range of possible remediation costs was $8 million to $36 million. The cost estimates of the MGW site are based on studies of that site. The remediation costs for the other sites are based on industry average costs for remediation of sites of similar size. The actual remediation costs will be dependent upon the number of sites remediated, the participation of other potentially responsible parties, if any, and the remediation methods used. Other Minnesota Matters. At December 31, 1999 and 2000, RERC had recorded accruals of $1 million and $2 million, respectively (with a maximum estimated exposure of approximately $13 million and $17 million at December 31, 1999 and 2000, respectively), for other environmental matters in Minnesota for which remediation may be required. Issues relating to the identification and remediation of MGPs are common in the natural gas distribution industry. The Company has received notices from the United States Environmental Protection Agency and others regarding its status as a potentially responsible party (PRP) for other sites. Based on current information, the Company has not been able to quantify a range of environmental expenditures for potential remediation expenditures with respect to other MGP sites. Mercury Contamination. The Company's pipeline and distribution operations have in the past employed elemental mercury in measuring and regulating equipment. It is possible that small amounts of mercury may have been spilled in the course of normal maintenance and replacement operations and that these spills may have contaminated the immediate area with elemental mercury. This type of contamination has been found by the Company at some sites in the past, and the Company has conducted remediation at sites found to be contaminated. Although the Company is not aware of additional specific sites, it is possible that other contaminated sites may exist and that remediation costs may be incurred for these sites. Although the total amount of these costs cannot be known at this time, based on experience by the Company and that of others in the natural gas industry to date and on the current regulations regarding remediation of these sites, the Company believes that the costs of any remediation of these sites will not be material to the Company's financial position, results of operations or cash flows. REMA Ash Disposal Site Closures and Site Contaminations. Under the agreement to acquire REMA (see Note 3(a)), the Company became responsible for liabilities associated with ash disposal site closures and site contamination at the acquired facilities in Pennsylvania and New Jersey prior to a plant closing, except for the first $6 million of remediation costs at the Seward Generating Station. A prior owner retained liabilities associated with the disposal of hazardous substances to off-site locations prior to November 24, 1999. As of December 31, 2000, REMA has liabilities associated with six ash disposal site closures and six site investigations and environmental remediations. The Company has recorded its estimate of these environmental liabilities in the amount of $36 million as of December 31, 2000. The Company expects approximately $13 million will be paid over the next five years. UNA Asbestos Abatement and Soil Remediation. Prior to the Company's acquisition of UNA (see Note 3(b)), UNA had a $25 million obligation primarily related to asbestos abatement, as required by Dutch law, and soil remediation at six sites. During 2000, the Company initiated a review of potential environmental matters associated with UNA's properties. UNA began remediation in 2000 of the properties identified to have exposed asbestos and soil contamination, as required by Dutch law and the terms of some leasehold 34
35 agreements with municipalities in which the contaminated properties are located. All remediation efforts are to be fully completed by 2005. As of December 31, 2000, the estimated undiscounted liability for this asbestos abatement and soil remediation was $24 million. Other. From time to time the Company has received notices from regulatory authorities or others regarding its status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. In addition, the Company has been named as a defendant in litigation related to such sites and in recent years has been named, along with numerous others, as a defendant in several lawsuits filed by a large number of individuals who claim injury due to exposure to asbestos while working at sites along the Texas Gulf Coast. Most of these claimants have been workers who participated in construction of various industrial facilities, including power plants, and some of the claimants have worked at locations owned by the Company. The Company anticipates that additional claims like those received may be asserted in the future and intends to continue vigorously contesting claims which it does not consider to have merit. Although their ultimate outcome cannot be predicted at this time, the Company does not believe, based on its experience to date, that these matters, either individually or in the aggregate, will have a material adverse effect on the Company's financial position, results of operations or cash flows. OTHER MATTERS. The Company is involved in other legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. Some of these proceedings involve substantial amounts. The Company's management regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. The Company's management believes that the disposition of these matters will not have a material adverse effect on the Company's financial condition, results of operations or cash flows. (h) California Wholesale Market Uncertainty. During the summer and fall of 2000, prices for wholesale electricity in California increased dramatically as a result of a combination of factors, including higher natural gas prices and emission allowance costs, reduction in available hydroelectric generation resources, increased demand, decreases in net electric imports, structural market flaws including over-reliance on the electric spot market, and limitations on supply as a result of maintenance and other outages. Although wholesale prices increased, California's deregulation legislation kept retail rates frozen below 1996 levels. This caused two of California's public utilities, which are the Company's customers based on its deliveries to the Cal PX and the Cal ISO, to amass billions of dollars of uncollected wholesale power costs and to ultimately default in January and February 2001 on payments owed for wholesale power purchased through the Cal PX and from the Cal ISO. As of December 31, 2000, the Company was owed $101 million by the Cal PX and $181 million by the Cal ISO. In the fourth quarter of 2000, the Company recorded a pre-tax provision of $39 million against receivable balances related to energy sales in the California market. From January 1, 2001 through February 28, 2001, the Company has collected $105 million of these receivable balances. As of March 1, 2001, the Company was owed a total of $358 million by the Cal ISO, the Cal PX, the California Department of Water Resources (CDWR) and California Energy Resource Scheduling, for energy sales in the California wholesale market from the fourth quarter of 2000 through February 28, 2001. Management will continue to assess the collectibility of these receivables based on further developments affecting the California electricity market and the market participants described herein. Additional provisions to the allowance may be warranted in the future. In response to the filing of a number of complaints challenging the level of wholesale prices, the FERC initiated a staff investigation and issued an order on December 15, 2000 implementing a series of wholesale market reforms, including an interim price review procedure for prices above a $150/MWh "breakpoint" on sales to the Cal ISO and through the Cal PX. The order does not prohibit sales above the "breakpoint," but the seller is subject to weekly reporting and monitoring requirements. For each reported transaction, potential refund liability extends for a period of 60 days following the date any such transaction is reported to the FERC. On March 9, 2001, the FERC issued a further order establishing a proxy market 35
36 clearing price of $273/MWh for January 2001, and on March 16, 2001 the FERC issued a further order adjusting the proxy market clearing price to $430/MWh for February 2001. New market monitoring and mitigation measures to replace the $150/MWh breakpoint and reporting obligation are being developed by the FERC to take effect on May 1, 2001. In the FERC's March 9 and March 16 orders, the FERC outlined criteria for determining amounts subject to possible refund based on the proxy market clearing price for January and February 2001 and indicated that approximately $12 million of the $125 million charged by the Company in January 2001 in California to the Cal ISO and the Cal PX and approximately $7 million of the $47 million charged by the Company in February 2001 in California to the Cal ISO and the Cal PX were subject to possible refunds. In the March 9 and March 16 orders, the FERC set forth procedures for challenging possible refund obligations. Because the Company believes that there is cost or other justification for prices charged above the proxy market clearing prices established in the March 9 and March 16 orders, the Company intends to pursue such a challenge with respect to the Company's potential refund amounts identified in such orders. Any refunds the Company may ultimately be obligated to pay are to be credited against unpaid amounts owed to the Company for its sales in the Cal PX or to the Cal ISO. The December 15 order established that a refund condition would be in place for the period beginning October 2, 2000 through December 31, 2002. The December 15 order also eliminated the requirement that California's public utilities sell all of their generation into and purchase all of their power from the Cal PX and directed that the Cal PX wholesale tariffs be terminated effective April 2001. The Cal PX has since suspended its day-ahead and day-of markets and filed for bankruptcy protection on March 9, 2001. Motions for rehearing have been filed on a number of issues related to the December 15 order and such motions are still pending before the FERC. In addition to the FERC investigation discussed above, several state and other federal regulatory investigations and complaints have commenced in connection with the wholesale electricity prices in California and other neighboring Western states to determine the causes of the high prices and potentially to recommend remedial action. In California, the California Public Utilities Commission, the California Electricity Oversight Board, the California Bureau of State Audits and the California Office of the Attorney General all have separate ongoing investigations into the high prices and their causes. None of these investigations have been completed and no findings have been made in connection with any of them. Despite the market restructuring ordered under the December 15 order, the California public utilities have continued to accrue unrecovered wholesale costs. As a result, the credit ratings of two of these public utilities were severely downgraded to below investment grade in January 2001. As their credit lines became unavailable, the two utilities defaulted on payments due to the Cal PX and the Cal ISO, which operate financially as pass-through entities, coordinating payments from buyers and sellers of electricity. As a result, the Cal PX and Cal ISO were not able to pay final invoices to market participants totaling over $1 billion. The default of two of California's public utilities on amounts owed the Cal PX and the Cal ISO for purchased power has further exacerbated the current crisis in the California wholesale markets and resulted in substantial uncollected receivables owed to the Company by the Cal ISO and the Cal PX. The Cal PX's efforts to recover the available collateral of the utilities, in the form of block forward contracts, have been frustrated by the emergency acts of California's Governor, who seized control of the contracts upon the expiration of temporary restraining orders prohibiting such action. Although obligated to pay reasonable value for the contracts, the state of California has not yet made any payment for the contracts. Various actions have been filed challenging the Governor's ability to seize these contracts. Upon the default of the two utilities of amounts due to the Cal PX, the Cal PX issued "charge-backs" allocating the utilities' defaults to the other market participants. Proceedings were brought both in federal court and at the FERC seeking a suspension of the charge-backs and challenging the reasonableness of the Cal PX's actions. The Cal PX has since agreed to a preliminary injunction suspending any of its charge-back activities in order to allow the FERC to address the charge-back issues. Amounts owed to the Company were debited in invoices by the Cal PX for charge-backs in the amount of $29 million and, on February 14, 2001, the Company filed its own lawsuit against the Cal PX in the United States District Court for the Central District of California, seeking a recovery of those amounts and a stay of any further charge-backs by the Cal 36
37 PX. The filing of bankruptcy by the Cal PX will automatically stay for some period the various court and administrative cases against the Cal PX. The two defaulting utilities have both filed lawsuits challenging the refusal of state regulators to allow wholesale power costs to be passed through to retail customers under the "filed rate doctrine". The filed rate doctrine provides that wholesale power costs approved by the FERC are entitled to be recovered through rates. Additionally, to address the failing financial condition of the two defaulting utilities and the utilities' potential bankruptcy, the California Legislature passed emergency legislation, effective January 18, 2001 and February 2, 2001, appropriating funds to be used by the CDWR for the purchase of wholesale electricity on behalf of the utilities and authorizing the sale of bonds to fund future purchases under long-term power contracts with wholesale generators. The CDWR began the process of soliciting bids from generators for long-term contracts and continued the purchasing of short-term power contracts. No bonds have yet been issued by the CDWR to support long-term power purchases or to provide credit support for short-term purchases. As noted above two of California's public utilities have defaulted in their payment obligations to the Cal PX and the Cal ISO as a result of the refusal of state regulators to allow them to recover their wholesale power costs. This refusal by state regulators has also caused the utilities to default on numerous other financial obligations, which could result in either the voluntary or involuntary bankruptcy of the utilities. While a bankruptcy filing would result in further post-petition purchases of wholesale electricity being considered administrative expenses of the debtor, a substantial delay could be experienced in the payment of pre-petition receivables pending the confirmation of a reorganization plan. The California Legislature is currently considering legislation under which a state entity would be formed to purchase and operate a substantial share of the transmission lines in California in an effort to provide cash to the utilities and thereby avoid potential bankruptcy filings by the utilities. A number of the creditors for the two California public utilities have indicated, however, that unless California moves quickly with such a plan, an involuntary bankruptcy filing may be made by one or more of such creditors. Because California's power reserves remain at low levels, in part as a result of the lack of creditworthy buyers of power given the defaults of the California utilities, the Cal ISO has relied on emergency dispatch orders requiring generators to provide at the Cal ISO's direction all power not already under contract. The power supplied to the Cal ISO has been used to meet the needs of the customers of the utilities, even though two of those utilities do not have the credit required to receive such power and may be unable to pay for it. The Company has contested the obligation to provide power under these circumstances. The Cal ISO sought a temporary restraining order compelling the Company to continue to comply with the emergency dispatch orders despite the utilities' defaults. Although the payment issue is still disputed, on February 21, 2001, the Company and the CDWR entered into a contract expiring March 23, 2001 for the purchase of all of the Company's available capacity not already under contract and the litigation has been temporarily stayed. The CDWR is current in its payments under this contract, but the Company is still owed $108 million for power provided in compliance with the emergency dispatch orders for the six weeks prior to the agreement. Depending on the outcome of the court proceedings initiated by the Cal ISO seeking to enjoin us from ceasing power deliveries to the Cal ISO, the Company may be forced to continue selling power without the guarantee of payment. Additionally, the Company is seeking a prompt FERC determination that the Cal ISO is not complying with the credit provisions of its tariff and a related order of the FERC issued on February 14, 2001, requiring the Cal ISO not to make purchases in the real time market unless a creditworthy purchaser is responsible for such purchases. (i) Indemnification of Stranded Costs. The stranded costs in the Dutch electricity market are considered to be the liabilities, uneconomical contractual commitments, and other costs associated with obligations entered into by the coordinating body for the Dutch electricity generating sector, N.V. Samenwerkende elecktriciteits-produktiebedrijven (SEP), plus some district heating contracts with some municipalities in Holland. As of December 29, 2000, SEP changed its name to BV Nederlands Elektriciteit Administratiekantoor. 37
38 SEP was incorporated as the coordinating body for four of the large-scale Dutch electricity generation companies, including UNA, which currently has an equity interest in SEP of 25%. Among other things, SEP prior to 2001 owned and managed the dispatch for the national transmission grid, coordinated the fuel supply, managed the import and the export of electricity, and settled production costs for the electricity generation companies. Under the Cooperation Agreement (OvS Agreement), UNA and the other Dutch generators agreed to sell their generating output through SEP. Over the years, SEP incurred stranded costs as a result of a perceived need to cover anticipated shortages in energy production supply. SEP stranded costs consist primarily of investments in alternative energy sources and fuel and power purchase contracts currently estimated to be uneconomical. In December 2000, the Dutch parliament adopted legislation, The Electricity Production Sector Transitional Arrangements Act (Transition Act), allocating to the Dutch generation sector, including UNA, financial responsibility for various stranded costs contracts and other liabilities of SEP. The Transition Act also authorizes the government to purchase from SEP at least a majority of the shares in the Dutch national transmission grid company. The legislation became effective in all material respects on January 1, 2001. The Transition Act allocates financial responsibility to the individual Dutch generators based on their average share in the costs and revenues under the OvS Agreement during the past ten years. UNA's allocated share of these costs has been set at 22.5%. In particular, the Transition Act allocates to the four Dutch generation companies, including UNA, financial responsibility for SEP's obligations to purchase electricity and gas under an import gas supply contract and three electricity import contracts. The gas import contract expires in 2015 and provides for gas imports aggregating 2.283 billion cubic meters per year. The three electricity contracts have the following capacities and terms: (a) 300 MW through 2005, (b) 600 MW through 2005 and (c) 600 MW through 2002 and 750 MW through 2009. The generators have the option of assuming their pro rata interests in the contracts or, subject to the assignment terms of the contracts, selling their interests to third parties. The Transition Act provides that, subject to the approval of the European Commission, the Dutch government will make financial compensations to the Dutch generation sector for the out of market costs associated with two stranded cost items: an experimental coal facility and district heating contracts. The four Dutch generation companies and SEP are in discussions with the Dutch Ministry of Economic Affairs regarding the implementation of the Transition Act. The parties have reached an agreement in principle with the Dutch Ministry of Economic Affairs regarding the compensation to be paid to SEP for the national transmission grid company. The proposed compensation amount is NLG 2.55 billion (approximately $1.1 billion based on an exchange rate of 2.34 NLG per U.S. dollar as of December 31, 2000). Although the Transition Act clarifies many issues regarding the anticipated resolution of the stranded costs debate in the Netherlands, there remain considerable uncertainties regarding the exact manner in which the Transition Act will be implemented and the potential for third parties to challenge the Transition Act on legal and constitutional grounds. In connection with the acquisition of UNA, the selling shareholders of UNA agreed to indemnify UNA for some stranded costs in an amount not to exceed NLG 1.4 billion (approximately $599 million based on an exchange rate of 2.34 NLG per U.S. dollar as of December 31, 2000), which may be increased in some circumstances at the option of the Company up to NLG 1.9 billion (approximately $812 million). Of the total consideration paid by the Company for the shares of UNA, NLG 900 million (approximately $385 million) has been placed by the selling shareholders in an escrow account under the direction of the Dutch Ministry of Economic Affairs to secure the indemnity obligations. Although the Company's management believes that the indemnity provision will be sufficient to fully satisfy UNA's ultimate share of any stranded costs obligation, this judgment is based on numerous assumptions regarding the ultimate outcome and timing of the resolution of the stranded cost issue, the former shareholders' timely performance of their obligations under the indemnity arrangement, and the amount of stranded costs which at present is not determinable. 38
39 (j) Operations Agreement with City of San Antonio. As part of the 1996 settlement of certain litigation claims asserted by the City of San Antonio with respect to the South Texas Project, the Company entered into a 10-year joint operations agreement under which the Company and the City of San Antonio, acting through the City Public Service Board of San Antonio (CPS), share savings resulting from the joint dispatching of their respective generating assets in order to take advantage of each system's lower cost resources. In January 2000, the contract term was extended for three years and is expected to terminate in 2009. Under the terms of the joint operations agreement entered into between CPS and Electric Operations, the Company has guaranteed CPS minimum annual savings of $10 million up to a total cumulative savings of $150 million over the term of the agreement. It is anticipated that the cumulative obligation will be met in the first quarter of 2001. In 1998, 1999 and 2000, savings generated for CPS' account were $14 million, $14 million and $60 million, respectively. Through December 31, 2000, cumulative savings generated for CPS' account were $124 million. (k) Nuclear Insurance. The Company and the other owners of the South Texas Project maintain nuclear property and nuclear liability insurance coverage as required by law and periodically review available limits and coverage for additional protection. The owners of the South Texas Project currently maintain $2.75 billion in property damage insurance coverage, which is above the legally required minimum, but is less than the total amount of insurance currently available for such losses. Pursuant to the Price Anderson Act, the maximum liability to the public of owners of nuclear power plants was $9.3 billion as of December 31, 2000. Owners are required under the Price Anderson Act to insure their liability for nuclear incidents and protective evacuations. The Company and the other owners of the South Texas Project currently maintain the required nuclear liability insurance and participate in the industry retrospective rating plan. There can be no assurance that all potential losses or liabilities will be insurable, or that the amount of insurance will be sufficient to cover them. Any substantial losses not covered by insurance would have a material effect on the Company's financial condition, results of operations and cash flows. (l) Nuclear Decommissioning. The Company contributes $14.8 million per year to a trust established to fund its share of the decommissioning costs for the South Texas Project. For a discussion of the accounting treatment for the securities held in the Company's nuclear decommissioning trust, see Note 2(l). In July 1999, an outside consultant estimated the Company's portion of decommissioning costs to be approximately $363 million. While the current and projected funding levels currently exceed minimum NRC requirements, no assurance can be given that the amounts held in trust will be adequate to cover the actual decommissioning costs of the South Texas Project. Such costs may vary because of changes in the assumed date of decommissioning and changes in regulatory requirements, technology and costs of labor, materials and equipment. Pursuant to the Legislation, costs associated with nuclear decommissioning that have not been recovered as of January 1, 2002, will continue to be subject to cost-of-service rate regulation and will be included in a non-bypassable charge to transmission and distribution customers. For information regarding the effect of the Business Separation Plan on funding of the nuclear decommissioning trust fund, see Note 4(b). o (20) SUBSEQUENT EVENTS (a) Credit Facilities. Between December 2000 and March 2001, Reliant Resources entered into eleven bilateral credit facilities with financial institutions, which provide for an aggregate of $1.6 billion in committed credit. The facilities became effective subsequent to December 31, 2000 and expire on October 2, 2001. Concurrent with the effectiveness of these facilities, $500 million of the facilities of a financing subsidiary were canceled. Interest rates on the borrowings are based on LIBOR plus a margin, a base rate or a rate determined through a bidding 39
40 process. These facilities contain various business and financial covenants requiring Reliant Resources to, among other things, maintain a ratio of net debt to the sum of net debt, subordinated affiliate debt and shareholders' equity not to exceed 0.60 to 1.00. These covenants are not anticipated to materially restrict Reliant Resources from borrowing funds or obtaining letters of credit under these facilities. The credit facilities are subject to commitment and usage fees that are calculated based on the amount of the facility and/or the amounts outstanding under the facilities, respectively. (b) RERC Corp. Debt Issuance. In February 2001, RERC Corp. issued $550 million of unsecured notes that bear interest at 7.75% per year and mature in February 2011. Net proceeds to RERC Corp. were $545 million. RERC Corp. used the net proceeds from the sale of the notes to pay a $400 million dividend to Reliant Energy, and for general corporate purposes. Reliant Energy used the $400 million proceeds from the dividend for general corporate purposes, including the repayment of short-term borrowings. (c) Florida Tolling Arrangement. In the first quarter 2001, the Company entered into tolling arrangements with a third party to purchase the right to utilize and dispatch electric generating capacity of approximately 1,100 MW. This electricity is expected to be generated by two gas-fired, simple-cycle peaking plants, with fuel oil backup, to be constructed by the tolling partner in Florida, which are anticipated to be completed by the summer of 2002, at which time the Company will commence tolling payments. 40
1 EXHIBIT 99(b).REI ITEMS INCORPORATED BY REFERENCE FROM RELIANT ENERGY MARCH 31, 2001 FORM 10-Q (2) DERIVATIVE FINANCIAL INSTRUMENTS Effective January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended (SFAS No. 133), which establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. This statement requires that derivatives be recognized at fair value in the balance sheet and that changes in fair value be recognized either currently in earnings or deferred as a component of other comprehensive income, depending on the intended use of the derivative, its resulting designation and its effectiveness. If certain conditions are met, an entity may designate a derivative instrument as hedging (a) the exposure to changes in the fair value of an asset or liability (Fair Value Hedge), (b) the exposure to variability in expected future cash flows (Cash Flow Hedge) or (c) the foreign currency exposure of a net investment in a foreign operation. For a derivative not designated as a hedging instrument, the gain or loss is recognized in earnings in the period it occurs. Adoption of SFAS No. 133 on January 1, 2001 resulted in an after-tax increase in net income of $61 million and a cumulative after-tax increase in accumulated other comprehensive loss of $252 million. The adoption also increased current assets, long-term assets, current liabilities and long-term liabilities by $703 million, $252 million, $805 million and $340 million, respectively, in the Company's Consolidated Balance Sheet. The Company also 41
2 reclassified $788 million related to the Company's Zero-Premium Exchangeable Subordinated Notes (ZENS) due to the adoption from the current portion of long-term debt to indexed debt securities derivative. During the three months ended March 31, 2001, less than $1 million of the initial transition adjustment recognized in other comprehensive income was realized in net income. The application of SFAS No. 133 is still evolving and further guidance from the Financial Accounting Standards Board (FASB) is expected. The FASB released tentative guidance in April 2001 on three issues that impact our industry. The FASB concluded in its tentative guidance that contracts subject to "bookouts," a scheduling convenience used when two utilities have offsetting transactions, cannot qualify for the normal purchases and sales exception. The FASB also released tentative guidance that will prohibit option contracts on electricity to qualify for the normal purchases and normal sales exception. Lastly, the FASB issued tentative guidance that forward contracts containing optionality features which modify the quantity delivered cannot qualify for the normal purchases and sales exception. The tentative guidance issued by the FASB is subject to a comment period which ends on June 1, 2001. If the tentative guidance is unchanged, the Company is required to adopt this guidance as of July 1, 2001. The Company is in the process of determining the effect of adoption. The Company is exposed to various market risks. These risks are inherent in the Company's financial statements and arise from transactions entered into in the normal course of business. The Company utilizes derivative financial instruments to mitigate the impact of changes in electricity, natural gas and fuel prices on its operating results and cash flows. The Company utilizes cross-currency swaps and options to hedge its net investments in foreign subsidiaries, interest rate swaps to mitigate the impact of changes in interest rates and other financial instruments to manage various other market risks. Trading and marketing operations often involve market risks associated with managing energy commodities and establishing open positions in the energy markets, primarily on a short-term basis. These risks fall into three different categories: price and volume volatility, credit risk of trading counterparties and adequacy of the control environment for trading. The Company routinely enters into futures, forward contracts, swaps and options to hedge purchase and sale commitments, fuel requirements and inventories of natural gas, coal, electricity, oil, emission allowances, weather derivatives and other commodities and to minimize the risk of market fluctuations in its trading, marketing, power origination and risk management operations. (a) Energy Trading, Marketing and Price Risk Management Activities. The Company offers energy price risk management services primarily related to natural gas, electric power and other energy related commodities. The Company provides these services by utilizing a variety of derivative financial instruments, including (a) fixed and variable-priced physical forward contracts, (b) fixed and variable-priced swap agreements, (c) options traded in the over-the-counter financial markets and (d) exchange-traded energy futures and option contracts (Trading Derivatives). Fixed-price swap agreements require payments to, or receipts of payments from, counterparties based on the differential between a fixed and variable price for the commodity. Variable-price swap agreements require payments to, or receipts of payments from, counterparties based on the differential between industry pricing publications or exchange quotations. The Company applies mark-to-market accounting for all of its energy trading, marketing and price risk management operations. Accordingly, these Trading Derivatives are recorded at fair value with net realized and unrealized gains (losses) recorded as a component of revenues. The recognized, unrealized balances are included in price risk management assets/liabilities. (b) Non-Trading Activities. Cash Flow Hedges. To reduce the risk from market fluctuations in revenues and the resulting cash flows derived from the sale of electric power and natural gas and related transportation, the Company enters into futures transactions, forward contracts, swaps and options (Energy Derivatives) in order to hedge some expected purchases of electric power, natural gas and other commodities and sales of electric power and natural gas (a portion of which are firm commitments at the inception of the hedge). Energy Derivatives are also utilized to fix the price of compressor fuel or other future operational gas requirements and to protect natural gas distribution earnings and cash flows against unseasonably warm weather during peak gas heating months, although usage to date for this purpose 42
3 has not been material. The Energy Derivative portfolios are managed to complement the physical transaction portfolio, reducing overall risks within management-prescribed limits. During the three months ended March 31, 2001, the Company entered into interest-rate swaps in order to adjust the interest rate on $375 million of its floating rate debt. In addition, as of March 31, 2001, the Company's European Energy segment has entered into financial instruments to purchase approximately $120 million to hedge future fuel purchases payable in U.S. dollars. The Company applies hedge accounting for its derivative financial instruments utilized in non-trading activities only if there is a high correlation between price movements in the derivative and the item designated as being hedged. This correlation, a measure of hedge effectiveness, is measured both at the inception of the hedge and on an ongoing basis, with an acceptable level of correlation of at least 80% for hedge designation. If and when correlation ceases to exist at an acceptable level, hedge accounting ceases and mark-to-market accounting is applied. During the three months ended March 31, 2001, the amount of hedge ineffectiveness recognized in earnings from derivatives that are designated and qualify as cash flow hedges was immaterial. No component of the derivative instruments' gain or loss was excluded from the assessment of effectiveness. If it becomes probable that an anticipated transaction will not occur, the Company realizes in net income the deferred gains and losses recognized in accumulated other comprehensive loss. During the three months ended March 31, 2001, there were no deferred gains or losses recognized in earnings as a result of the discontinuance of cash flow hedges because it was no longer probable that the forecasted transaction would occur. Once the anticipated transaction occurs, the accumulated deferred gain or loss recognized in accumulated other comprehensive loss is reclassified to net income and included in the Company's Statements of Consolidated Income under the captions (a) fuel expenses, in the case of natural gas transactions, (b) purchased power, in the case of electric power purchase transactions, (c) revenues, in the case of electric power sales transactions and (d) interest expense, in the case of interest rate swap transactions. Cash flows resulting from these transactions in Energy Derivatives are included in the Company's Statements of Consolidated Cash Flows in the same category as the item being hedged. As of March 31, 2001, current non-trading derivative assets and liabilities and corresponding amounts in accumulated other comprehensive loss are expected to be reclassified to net income during the next twelve months. The maximum length of time the Company is hedging its exposure to the variability in future cash flows for forecasted transactions excluding the payment of variable interest on existing financial instruments is five years. The maximum length of time the Company is hedging its exposure to the payment of variable interest rates is approximately five years. Hedge of Net Investment in Foreign Subsidiaries. The Company has substantially hedged its net investment in its European subsidiaries through a combination of Euro-denominated borrowings, foreign currency swaps and foreign currency forward contracts to reduce the Company's exposure to changes in foreign currency rates. During the normal course of business, the Company reviews its currency hedging strategies and determines the hedging approach deemed appropriate based upon the circumstances of each situation. The Company records the changes in the value of the foreign currency hedging instruments and Euro-denominated borrowings as foreign currency translation adjustments as a component of stockholders' equity and accumulated other comprehensive loss. The effectiveness of the hedging instruments can be measured by the net change in foreign currency translation adjustments attributed to the Company's net investment in its European subsidiaries. These amounts generally offset amounts recorded in stockholders' equity as adjustments resulting from translation of the hedged investment into U.S. dollars. During the three months ended March 31, 2001, the derivative and nonderivative instruments designated as hedging the net investment in its European subsidiaries resulted in a gain of $155 million which is included in the balance of the cumulative translation adjustment. Other Derivatives. Upon adoption of SFAS No. 133 effective January 1, 2001, the Company's indexed debt securities obligations related to its ZENS obligation was bifurcated into a debt component valued at $122 million and an embedded derivative component valued at $788 million. Changes in the fair value of the derivative component are recorded in the Company's Statements of Consolidated Income. Changes in the fair value of the Company's Investment in AOL Time Warner Inc. common stock should substantially offset changes in the fair value of the derivative component of the ZENS. 43
4 In December 2000, the Dutch parliament adopted legislation allocating to the Dutch generation sector, including a subsidiary of the Company, N.V. UNA (UNA), financial responsibility for various stranded costs contracts and other liabilities. The legislation became effective in all material respects on January 1, 2001. In particular, the legislation allocated to the four Dutch generation companies, including UNA, financial responsibility to purchase electricity and gas under an import gas supply contract and three electricity import contracts. The gas import contract expires in 2015 and provides for gas imports aggregating 2.283 billion cubic meters per year. These contracts are derivatives pursuant to SFAS No. 133 due to the pricing indices. As of March 31, 2001, the Company has recognized $326 million in long-term non-trading derivative liabilities for UNA's portion of these stranded costs contracts. For additional information regarding UNA's stranded costs and the related indemnification by former shareholders of these stranded costs, see Note 11(e). Subsequent to March 31, 2001, the Company has entered into interest rate swaps to fix the rate on $1.3 billion of the Company's floating rate debt, which expire in 2002. The Company has not designated these derivative instruments as hedges. Changes in the fair value of the swaps will be recorded in the Company's Statements of Consolidated Income. 44