EX-99.A 3 h92033ex99-a.txt ITEMS FROM RELIANT ENERGY FORM 10-K EXHIBIT 99(a).REI RELIANT ENERGY, INCORPORATED ITEMS INCORPORATED BY REFERENCE ITEMS INCORPORATED BY REFERENCE FROM THE RELIANT ENERGY FORM 10-K o ITEM 3. LEGAL PROCEEDINGS. (a) RELIANT ENERGY. For a description of certain legal and regulatory proceedings affecting Reliant Energy, see Notes 4, 14(g), 14(h) and 14(i) to our consolidated financial statements, which notes are incorporated herein by reference. o ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- CERTAIN FACTORS AFFECTING OUR FUTURE EARNINGS Our earnings for the past three years are not necessarily indicative of our future earnings and results. The level of our future earnings depends on numerous factors including: - state and federal legislative, as well as international regulatory developments, including deregulation, re-regulation and restructuring of the electric utility industry and changes in or application of environmental and other laws and regulations to which we are subject, - the timing of the implementation of our Business Separation Plan, - industrial, commercial and residential growth in our service territories, - our pursuit of potential business strategies, including acquisitions or dispositions of assets or the development of additional power generation facilities, - state, federal and other rate regulations in the United States and in foreign countries in which we operate or into which we might expand our operations, - the timing and extent of changes in commodity prices and interest rates, - weather variations and other natural phenomena, - our ability to cost-effectively finance and refinance, - the determination of the amount of our Texas generating assets' stranded costs and the recovery of these costs, - the ability to consummate and the timing of the consummation of acquisitions and dispositions, - the performance of our generation projects undertaken, - the successful operation of deregulating power markets, including the resolution of the crisis in the California market, and - risks incidental to our overseas operations, including the effects of fluctuations in foreign currency exchange rates. In order to adapt to the increasingly competitive environment, we continue to evaluate a wide array of potential business strategies, including business combinations or acquisitions involving other utility or non-utility businesses or properties, dispositions of currently owned businesses, as well as developing new generation projects, products, services and customer strategies. 1 BUSINESS SEPARATION AND RESTRUCTURING In anticipation of electric deregulation in Texas, and pursuant to the Legislation, we submitted a business separation plan in January 2000 to the Texas Utility Commission. Pursuant to the Business Separation Plan, we will restructure our businesses into two separate publicly traded companies in order to separate our unregulated businesses from our rate-regulated businesses. Reliant Resources holds substantially all of our unregulated businesses. We expect Reliant Resources will conduct the Offering in 2001. Also, we anticipate that the Regulated Holding Company will conduct the Distribution within 12 months of the completion of the Offering, subject to receipt of a favorable tax ruling and other regulatory approvals. For additional information regarding the Business Separation Plan and the Restructuring, please read "Business -- Our Business -- Restructuring" in Item 1 of this Form 10-K and Note 4(b) to our consolidated financial statements. We have sought a ruling from the Internal Revenue Service that the Distribution will be tax-free to the Regulated Holding Company and its shareholders. At this time, we do not have a ruling from the Internal Revenue Service regarding the tax treatment of the Distribution. If we do not obtain a favorable tax ruling, the Distribution is not likely to be made in the expected time frame or, perhaps, at all. In order for the Distribution to be tax-free, various requirements must be met, including ownership by its parent of at least 80% of all classes of Reliant Resources' outstanding capital stock at the time of the Distribution. Additionally, in connection with the Distribution, Reliant Energy plans to restructure its remaining businesses to achieve a public utility holding company structure and to register the Regulated Holding Company as a public utility holding company under the 1935 Act. Creation of the Regulated Holding Company will require the approval of Reliant Energy's shareholders. For additional information regarding the Regulated Holding Company, please read "Business -- Our Business -- Restructuring" in Item 1 of this Form 10-K and Note 4(b) to our consolidated financial statements. The Restructuring will also require the approval of the Louisiana Public Service Commission and the Nuclear Regulatory Commission. We cannot assure you that those approvals will be obtained. After the Restructuring, the Regulated Holding Company will become a registered public utility holding company under the 1935 Act. COMPETITIVE, REGULATORY AND OTHER FACTORS AFFECTING OUR ELECTRIC OPERATIONS Competition and Deregulation. In June 1999, the Texas legislature adopted the Legislation, which substantially amended the regulatory structure governing electric utilities in Texas in order to allow retail competition. Retail pilot projects for up to 5% of each utility's load in all customer classes will begin in June 2001 and retail electric competition for all other customers will begin on January 1, 2002. Our retail operations will be conducted by indirect wholly owned subsidiaries of Reliant Resources. Under the market framework established by the Legislation, we will initially be required to sell electricity to Houston area residential and small commercial customers at a specified price, which is referred to in the Legislation as the "price to beat," whereas other retail electric providers will be allowed to sell electricity to these same customers at any price. We will not be permitted to offer electricity to these customers at a price other than the price to beat until January 1, 2005, unless before that date the Texas Utility Commission determines that 40% or more of the amount of electric power that was consumed in 2000 by residential or small commercial customers, as applicable, within the affiliated transmission and distribution utility's certificated service territory, as of January 1, 2002, is committed to be served by other retail electric providers. In addition, as long as we continue to provide retail service, the Legislation requires us to make the price to beat available to residential and small commercial customers in Reliant Energy HL&P's service territory through January 1, 2007. Because we will not be able to compete for residential and small commercial customers on the basis of price in Reliant Energy HL&P's service area, and because we expect that the retail market framework established by the Legislation will encourage competition from new retail electric providers, we could lose a significant number of these customers to other providers. When the pilot projects begin in June 2001, and until full retail electric competition begins, the Legislation provides that 5% of our customers may elect to purchase electricity from other retail electric providers. Our affiliated retail electric providers cannot participate in the pilot projects in Reliant Energy HL&P's service area. Reliant Energy HL&P will collect from retail electric providers the rates approved from its Wires Case to cover the cost of providing transmission and distribution service and any other non-bypassable charges. 2 Generally, retail electric providers will procure or buy electricity from the wholesale generators at unregulated rates, sell electricity at retail to their customers and pay the transmission and distribution utility a regulated tariffed rate for delivering the electricity to their customers. The results of our retail electric operations will be largely dependent upon the amount of gross margin, or "headroom," available in the "price to beat." The available headroom will equal the difference between the price to beat and the sum of the charges, fees and transmission and distribution utility rate approved by the Texas Utility Commission and the price we pay for power to meet our price to beat load. The larger the amount of headroom, the more incentive new market entrants should have to provide retail electric services in Reliant Energy HL&P's service territory. The Texas Utility Commission's regulations allow us to adjust our price to beat fuel factor based on the percentage change in the price of natural gas. In addition, we may also request an adjustment as a result of changes in our price of purchased energy. In such a request, we may adjust the fuel factor to the extent necessary to restore the amount of headroom that existed at the time our initial price to beat fuel factor was set by the Texas Utility Commission. We may not request that our price to beat be adjusted more than twice a year. Currently, we do not know nor can we estimate the amount of headroom in our initial price to beat or in the initial price to beat for the affiliated retail electric provider in each other Texas retail electric market. Similarly, we cannot estimate with any certainty the magnitude and frequency of the adjustments required, if any, and the eventual impact of such adjustments on the amount of headroom. In preparation for this competition, we expect to make significant changes in the electric utility operations currently conducted through Reliant Energy HL&P. For additional information regarding these changes, the Legislation, retail competition, its application to our Electric Operations segment and the "price to beat," please read "Business -- Our Business -- Deregulation and Competition," "-- Restructuring," "-- Electric Operations" and "Business -- Regulation -- State and Local Regulations -- Texas -- Electric Operations -- The Legislation" in Item 1 of this Form 10-K and Note 4 to our consolidated financial statements. Also, market volatility in the price of fuel for our generation operations, as well as in the price of purchased power, could have an effect on our cost to generate or acquire power. For additional information regarding commodity prices and supplies, please read "-- Competitive, Regulatory and Other Factors Affecting Our Wholesale Energy Operations -- Price Volatility." Other Regulatory Factors. Pursuant to the Legislation, Reliant Energy HL&P will be entitled to recover its stranded costs (i.e., the excess of net book value of generation assets, as defined by the Legislation, over the market value of those assets) and its regulatory assets related to generation. The Legislation prescribes specific methods for determining the amount of stranded costs and the details for their recovery. However, during the base rate freeze period from 1999 through 2001, earnings above the utility's authorized rate of return formula may be applied in a manner to accelerate depreciation of generation related plant assets for regulatory purposes. In addition, depreciation expense for transmission and distribution related assets may be redirected to generation assets for regulatory purposes during that period. The Legislation also provides for Reliant Energy HL&P, or a special purpose entity, to issue securitization bonds for the recovery of generation related regulatory assets and a portion of stranded costs. Any stranded costs not recovered through the sale of securitization bonds may be recovered through a non-bypassable charge to transmission and distribution customers. For additional information regarding these securitization bonds, please read "-- Liquidity and Capital Resources -- Future Sources and Uses of Cash -- Securitization." The Texas Utility Commission recently stated on record that it would consider requiring electric utilities to reverse the amount of redirected depreciation and accelerated depreciation previously taken if in its estimation the utility has overmitigated its stranded costs. The reversal could occur through a lower rate for the transmission and distribution utility and/or through credits contained in the transmission and distribution utility's rate. Any order requiring the reversal of these amounts would likely be included in the Texas Utility Commission proceeding establishing the initial rate of the transmission and distribution utility or in the case of our Electric Operations segment, the Wires Case. We do not expect the final transmission and distribution rate in the Wires Case to be established until August 2001. For more information regarding the Wires Case, see "Business -- Regulation -- State and Local Regulations -- Texas -- Electric Operations -- Rate Case." 3 At June 30, 1999, we performed an impairment test of Reliant Energy HL&P's previously regulated electric generation assets pursuant to SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" (SFAS No. 121), on a plant specific basis. Under SFAS No. 121, an asset is considered impaired, and should be written down to fair value, if the future undiscounted net cash flows expected to be generated by the use of the asset are insufficient to recover the carrying amount of the asset. For assets that are impaired pursuant to SFAS No. 121, we determined the fair value for each generating plant by estimating the net present value of future cash inflows and outflows over the estimated life of each plant. The difference between fair value and net book value was recorded as a reduction in the current book value. We determined that $797 million of electric generation assets were impaired as of June 30, 1999. Of these amounts, $745 million related to the South Texas Project and $52 million related to two gas-fired generation plants. The Legislation provides for recovery of this impairment through regulated cash flows during the transition period and through non-bypassable charges to transmission and distribution customers. As such, a regulatory asset has been recorded for an amount equal to the impairment loss. We recorded amortization expense related to the recoverable impaired plant costs and other assets created from discontinuing regulatory accounting of $221 million in the third and fourth quarters of 1999 and $329 million in 2000. We expect to fully amortize this regulatory asset as it is recovered from regulated cash flows in 2001. The impairment analysis requires estimates of possible future market prices, load growth, competition and many other factors over the lives of the plants. The resulting impairment loss is highly dependent on these underlying assumptions. In addition, after January 10, 2004, Reliant Energy HL&P must finalize and reconcile stranded costs (as defined by the Legislation) in a filing with the Texas Utility Commission. Any positive difference between the regulatory net book value and the fair market value of the generation assets (as defined by the Legislation) will be collected through future non-bypassable charges. Any over-mitigation of stranded costs may be refunded through future non-bypassable charges. This final reconciliation allows alternative methods of third party valuation of the fair market value of these assets, including outright sale, stock valuations and asset exchanges. Because generally accepted accounting principles require us to estimate fair market values on a plant-by-plant basis in advance of the final reconciliation, the financial impacts of the Legislation with respect to the final determination of stranded costs in 2004 are subject to material changes. Factors affecting such change may include estimation risk, uncertainty of future energy and commodity prices and the economic lives of the plants. If events occur that make the recovery of all or a portion of the regulatory assets associated with the generation plant impairment loss and other assets created from discontinuance of regulatory accounting pursuant to the Legislation no longer probable, we will write off the corresponding balance of these assets as a non-cash charge against earnings. One of the results of discontinuing the application of regulatory accounting for the generation operations is the elimination of the regulatory accounting effects of excess deferred income taxes and investment tax credits related to these operations. We believe it is probable that some parties will seek to return these amounts to ratepayers and, accordingly, we have recorded an offsetting liability. In accordance with the Legislation, beginning on January 1, 2002, and ending at December 31, 2003, any difference between market power prices received in the generation capacity auction and the Texas Utility Commission's earlier estimates of those market prices will be included in the 2004 stranded costs true-up. The Texas Utility Commission's estimate serves as a preliminary identification of stranded costs for recovery through securitization. This component of the true-up is intended to ensure that neither the customers nor we are disadvantaged economically as a result of the two-year transition period by providing this pricing structure. Since the time of our original impairment calculation in June 1999 when we discontinued application of SFAS No. 71 for our generation operations, natural gas prices have risen 295% from June 1999 to December 31, 2000 resulting in increases in estimated market prices for power during 2002 and 2003. Generally, for Reliant Energy HL&P's generation portfolio, sustained increases in natural gas prices result in an increase in the fair value of Reliant Energy HL&P's generation portfolio, due to our mix of lower variable cost of electric generation. Therefore, as electric power prices increase, the amount of our estimated stranded costs decline and the estimate of our 2002 and 2003 capacity true-up amounts which may be owed to customers increases. 4 For additional information regarding the impairment of regulatory assets and electric generating plant and equipment as well as the recovery of stranded costs, please read Note 4(a) to our consolidated financial statements. For additional information regarding our filings to recover under-recovered fuel costs, please read Note 4(d) to our consolidated financial statements. Other. For additional information regarding litigation over franchise fees, please read Note 14(g) to our consolidated financial statements. COMPETITIVE, REGULATORY AND OTHER FACTORS AFFECTING OUR WHOLESALE ENERGY OPERATIONS Competition. As of December 31, 2000, our Wholesale Energy business segment owned and operated 9,231 MW of electric generation assets that serve wholesale energy markets located in the Mid-Atlantic, Southwest and Midcontinent regions of the United States and the states of Florida and Texas. Competitive factors affecting the results of operations of these generation assets include new market entrants and construction by others of more efficient generation assets. The wholesale power industry has numerous competitors, some of which may have more operating experience, more acquisition and development experience, larger staffs and/or greater financial resources than we do. Like us, many of our competitors are seeking attractive opportunities to acquire or develop power generation facilities, both in the United States and abroad. This competition may adversely affect our ability to make investments or acquisitions. Also, industry restructuring requires or encourages the disaggregation of many vertically-integrated utilities into separate generation, transmission and distribution, and retail businesses. As a result, a significant number of additional competitors could become active in the wholesale power generation segment of our industry. Furthermore, other competitors operate power generation projects in the regions where we have invested in electric generation assets. While demand for electric energy services is generally increasing throughout the United States, the rate of construction and development of new, more efficient electric generation facilities may exceed increases in demand in some regional electric markets. Although local permitting and siting issues often reduce the risk of a rapid growth in supply of generation capacity in any particular region, projects are likely to be built over time. The commencement of commercial operation of these new facilities in the regional markets where we have facilities will likely increase the competitiveness of the wholesale power market in those regions, which could have a material effect on our business and lower the value of some of our electric generation assets. Finally, our trading, marketing, power origination and risk management operations compete with other energy merchants based on the ability to aggregate supplies at competitive prices from different sources and locations and to efficiently utilize transportation from third-party pipelines and transmission from electric utilities. These operations also compete against other energy marketers on the basis of their relative skills, financial position and access to credit sources. This competitive factor reflects the tendency of energy customers, wholesale energy suppliers and transporters to seek financial guarantees and other assurances that their energy contracts will be satisfied. As pricing information becomes increasingly available in the energy trading and marketing business and as deregulation in the electricity markets continues to accelerate, we anticipate that our trading, marketing, power origination and risk management operations will experience greater competition and downward pressure on per-unit profit margins. Regulation. The regulatory environment applicable to the electric power industry has recently undergone substantial changes as a result of restructuring initiatives at both the state and federal levels. These initiatives have had a significant impact on the nature of the industry and the manner in which its participants conduct their business. Our Wholesale Energy segment has targeted the deregulating wholesale and retail segments of the electric power industry created by these initiatives. These changes are ongoing and we cannot predict the future development of deregulation in these markets or the ultimate effect that this changing regulatory environment will have on our business. 5 Moreover, existing regulations may be revised or reinterpreted, new laws and regulations may be adopted or become applicable to us or our facilities, and future changes in laws and regulations may have a detrimental effect on our business. Certain restructured markets, particularly California, have recently experienced supply problems and price volatility. These supply problems and volatility have been the subject of a significant amount of press coverage, much of which has been critical of the restructuring initiatives. In some markets, including California (please read "-- California" below), proposals have been made by governmental agencies and/or other interested parties to slow the pace of deregulation or to re-regulate areas of these markets that have previously been deregulated. If the current trend towards competitive restructuring of the wholesale and retail power markets is reversed, discontinued or delayed, the business growth prospects of our Wholesale Energy segment would be slowed and the financial outlook for our existing positions could be impacted. If RTOs are established as envisioned by FERC Order 2000, "rate pancaking," or multiple transmission charges that apply to a single point-to-point delivery of energy, will be eliminated within a region, and wholesale transactions within the region, and between regions will be facilitated. The end result could be a more competitive, transparent market for the sale of energy and a more economic and efficient use and allocation of resources. For additional information regarding FERC Order 2000 affecting these RTOs, please read "Business -- Regulation -- Federal Energy Regulatory Commission" in Item 1 of this Form 10-K. Price Volatility. Our Wholesale Energy business segment sells electricity from our non-Texas power generation facilities into the spot market or other competitive power markets or on a contractual basis. Our Wholesale Energy business segment is not guaranteed any rate of return on our capital investments through mandated rates, and our revenues and results of operations are likely to depend, in large part, upon prevailing market prices for electricity and fuel in our regional markets and other competitive markets. These market prices may fluctuate substantially over relatively short periods of time. In addition, the FERC, which has jurisdiction over wholesale power rates, as well as independent system operators that oversee some of these markets, may impose price limitations, bidding rules and other mechanisms to address some of the volatility in these markets. Most of our Wholesale Energy business segment's domestic power generation facilities purchase fuel under short-term contracts or on the spot market. Fuel prices may also be volatile, and the price we can obtain for power sales may not change at the same rate as changes in fuel costs. These factors could have an adverse impact on our revenues and results of operations. Volatility in market prices for fuel and electricity may result from: - weather conditions, - seasonality, - electricity usage, - illiquid markets, - transmission or transportation constraints or inefficiencies, - availability of competitively priced alternative energy sources, - demand for energy commodities, - natural gas, crude oil and refined products, and coal production levels, - natural disasters, wars, embargoes and other catastrophic events, and - federal, state and foreign energy and environmental regulation and legislation. Trading, Marketing, Power Origination and Risk Management Operations. To lower our Wholesale Energy business segment's financial exposure related to commodity price fluctuations, its trading, marketing, power origination and risk management operations routinely enter into contracts to hedge a portion of its purchase and sale commitments, weather positions, fuel requirements and inventories of natural gas, coal, crude oil and refined products, and other commodities. As part of this strategy, our Wholesale Energy business segment routinely utilizes fixed-price forward physical purchase and sales contracts, futures, financial swaps 6 and option contracts traded in the over-the-counter markets or on exchanges. However, our Wholesale Energy business segment does not expect to cover the entire exposure of its assets or its positions to market price volatility and the coverage will vary over time. To the extent our Wholesale Energy business segment has unhedged positions, fluctuating commodity prices can impact our financial results and financial position, either favorably or unfavorably. At times, our Wholesale Energy business segment has open trading positions in the market, within established guidelines, resulting from the management of its trading portfolio. To the extent open trading positions exist, fluctuating commodity prices can impact our financial results and financial position, either favorably or unfavorably. The risk management procedures our Wholesale Energy business segment has in place may not always be followed or may not always work as planned. As a result of these and other factors, we cannot predict with precision the impact that our risk management decisions may have on our businesses, operating results or financial position. Although our Wholesale Energy business segment devotes a considerable amount of management effort to these issues, their outcome is uncertain. Our trading, marketing, power origination and risk management operations are also exposed to the risk that counterparties who owe it money or physical commodities, such as energy or gas, as a result of market transactions will not perform their obligations. Should the counterparties to these arrangements fail to perform, our trading, marketing, power origination and risk management operations might be forced to acquire alternative hedging arrangements or replace the underlying commitment at then-current market prices. In this event, our trading, marketing, power origination and risk management operations might incur additional losses to the extent of amounts, if any, already paid to the counterparties. California. During the summer and fall of 2000, prices for wholesale electricity in California increased dramatically as a result of a combination of factors, including higher natural gas prices and emission allowance costs, reduction in available hydroelectric generation resources, increased demand, decreases in net electric imports, structural market flaws including over-reliance on the electric spot market, and limitations on supply as a result of maintenance and other outages. Although wholesale prices increased, California's deregulation legislation kept retail rates frozen below 1996 levels. This caused two of California's public utilities, which are our customers based on our deliveries to the Cal PX and the Cal ISO, to amass billions of dollars of uncollected wholesale power costs and to ultimately default in January and February 2001 on payments owed for wholesale power purchased through the Cal PX and from the Cal ISO. As of December 31, 2000, we were owed $101 million by the Cal PX and $181 million by the Cal ISO. In the fourth quarter of 2000, we recorded a pre-tax provision of $39 million against receivable balances related to energy sales in the California market. From January 1, 2001 through February 28, 2001, we have collected $105 million of these receivable balances. As of March 1, 2001, we were owed a total of $358 million by the Cal ISO, the Cal PX, the CDWR and California Energy Resources Scheduling for energy sales in the California wholesale market from the fourth quarter of 2000 through February 28, 2001. Management will continue to assess the collectibility of these receivables based on further developments affecting the California electricity market and the market participants described herein. Additional provisions to the allowance may be warranted in the future. In response to the filing of a number of complaints challenging the level of wholesale prices, the FERC initiated a staff investigation and issued an order on December 15, 2000 implementing a series of wholesale market reforms, including an interim price review procedure for prices above a $150/MWh "breakpoint" on sales to the Cal ISO and through the Cal PX. The order does not prohibit sales above the "breakpoint," but the seller is subject to weekly reporting and monitoring requirements. For each reported transaction, potential refund liability extends for a period of 60 days following the date any such transaction is reported to the FERC. On March 9, 2001, the FERC issued a further order establishing a proxy market clearing price of $273/MWh for January 2001, and on March 16, 2001 the FERC issued a further order adjusting the proxy market clearing price to $430/MWh for February 2001. New market monitoring and mitigation measures to replace the $150/MWh breakpoint and reporting obligation are being developed by the FERC to take effect on May 1, 2001. 7 In the FERC's March 9 and March 16 orders, the FERC outlined criteria for determining amounts subject to possible refund based on the proxy market clearing price for January and February 2001 and indicated that approximately $12 million of the $125 million charged by us in January 2001 in California to the Cal ISO and the Cal PX and approximately $7 million of the $47 million charged by us in February 2001 in California to the Cal ISO and the Cal PX were subject to possible refunds. In the March 9 and March 16 orders, the FERC set forth procedures for challenging possible refund obligations. Because we believe that there is cost or other justification for prices charged above the proxy market clearing prices established in the March 9 and March 16 orders, we intend to pursue such a challenge with respect to our potential refund amounts identified in such orders. Any refunds we may ultimately be obligated to pay are to be credited against unpaid amounts owed to us for our sales in the Cal PX or to the Cal ISO. The December 15 order established that a refund condition would be in place for the period beginning October 2, 2000 through December 31, 2002. The December 15 order also eliminated the requirement that California's public utilities sell all of their generation into and purchase all of their power from the Cal PX and directed that the Cal PX wholesale tariffs be terminated effective April 2001. The Cal PX has since suspended its day-ahead and day-of markets and filed for bankruptcy protection on March 9, 2001. Motions for rehearing have been filed on a number of issues related to the December 15 order and such motions are still pending before the FERC. In addition to the FERC investigation discussed above, several state and other federal regulatory investigations and complaints have commenced in connection with the wholesale electricity prices in California and other neighboring Western states to determine the causes of the high prices and potentially to recommend remedial action. In California, the California Public Utilities Commission, the California Electricity Oversight Board, the California Bureau of State Audits and the California Office of the Attorney General all have separate ongoing investigations into the high prices and their causes. None of these investigations have been completed and no findings have been made in connection with any of them. Despite the market restructuring ordered under the December 15 order, the California public utilities have continued to accrue unrecovered wholesale costs. As a result, the credit ratings of two of these public utilities were severely downgraded to below investment grade in January 2001. As their credit lines became unavailable, the two utilities defaulted on payments due to the Cal PX and the Cal ISO, which operate financially as pass-through entities, coordinating payments from buyers and sellers of electricity. As a result, the Cal PX and Cal ISO were not able to pay final invoices to market participants totaling over $1 billion. The default of two of California's public utilities on amounts owed the Cal PX and the Cal ISO for purchased power has further exacerbated the current crisis in the California wholesale markets and resulted in substantial uncollected receivables owed to us by the Cal ISO and the Cal PX. The Cal PX's efforts to recover the available collateral of the utilities, in the form of block forward contracts, have been frustrated by the emergency acts of California's Governor, who seized control of the contracts upon the expiration of temporary restraining orders prohibiting such action. Although obligated to pay reasonable value for the contracts, the state of California has not yet made any payment for the contracts. Various actions have been filed challenging the Governor's ability to seize these contracts. Upon the default of the two utilities of amounts due to the Cal PX, the Cal PX issued "charge-backs" allocating the utilities' defaults to the other market participants. Proceedings were brought both in federal court and at the FERC seeking a suspension of the charge-backs and challenging the reasonableness of the Cal PX's actions. The Cal PX has since agreed to a preliminary injunction suspending any of its charge-back activities in order to allow the FERC to address the charge-back issues. Amounts owed to us were debited in invoices by the Cal PX for charge-backs in the amount of $29 million and, on February 14, 2001, we filed our own lawsuit against the Cal PX in the United States District Court for the Central District of California, seeking a recovery of those amounts and a stay of any further charge-backs by the Cal PX. The filing of bankruptcy by the Cal PX will automatically stay for some period the various court and administrative cases against the Cal PX. The two defaulting utilities have both filed lawsuits challenging the refusal of state regulators to allow wholesale power costs to be passed through to retail customers under the "filed rate doctrine." The filed rate doctrine provides that wholesale power costs approved by the FERC are entitled to be recovered through rates. 8 Additionally, to address the failing financial condition of the two defaulting utilities and the utilities' potential bankruptcy, the California Legislature passed emergency legislation, effective January 18, 2001 and February 2, 2001, appropriating funds to be used by the CDWR for the purchase of wholesale electricity on behalf of the utilities and authorizing the sale of bonds to fund future purchases under long-term power contracts with wholesale generators. The CDWR began the process of soliciting bids from generators for long-term contracts and continued the purchasing of short-term power contracts. No bonds have yet been issued by the CDWR to support long-term power purchases or to provide credit support for short-term purchases. As noted above, two of California's public utilities have defaulted in their payment obligations to the Cal PX and the Cal ISO as a result of the refusal of state regulators to allow them to recover their wholesale power costs. This refusal by state regulators has also caused the utilities to default on numerous other financial obligations, which could result in either the voluntary or involuntary bankruptcy of the utilities. While a bankruptcy filing would result in further post-petition purchases of wholesale electricity being considered administrative expenses of the debtor, a substantial delay could be experienced in the payment of pre-petition receivables pending the confirmation of a reorganization plan. The California Legislature is currently considering legislation under which a state entity would be formed to purchase and operate a substantial share of the transmission lines in California in an effort to provide cash to the utilities and thereby avoid potential bankruptcy filings by the utilities. A number of the creditors for the two California public utilities have indicated, however, that unless California moves quickly with such a plan, an involuntary bankruptcy filing may be made by one or more of such creditors. Because California's power reserves remain at low levels, in part as a result of the lack of creditworthy buyers of power given the defaults of the California utilities, the Cal ISO has relied on emergency dispatch orders requiring generators to provide at the Cal ISO's direction all power not already under contract. The power supplied to the Cal ISO has been used to meet the needs of the customers of the utilities, even though two of those utilities do not have the credit required to receive such power and may be unable to pay for it. We have contested the obligation to provide power under these circumstances. The Cal ISO sought a temporary restraining order compelling us to continue to comply with the emergency dispatch orders despite the utilities' defaults. Although the payment issue is still disputed, on February 21, 2001, we and the CDWR entered into a contract expiring March 23, 2001 for the purchase of all of our available capacity not already under contract and the litigation has been temporarily stayed. The CDWR is current in its payments under this contract, but we are still owed $108 million for power provided in compliance with the emergency dispatch orders for the six weeks prior to the agreement. Depending on the outcome of the court proceedings initiated by the Cal ISO seeking to enjoin us from ceasing power deliveries to the Cal ISO, we may be forced to continue selling power without the guarantee of payment. Additionally, we are seeking a prompt FERC determination that the Cal ISO is not complying with the credit provisions of its tariff and a related order of the FERC issued on February 14, 2001, requiring the Cal ISO not to make purchases in the real time market unless a creditworthy purchaser is responsible for such purchases. For additional information regarding the situation in California, please read "Business -- Wholesale Energy -- Power Generation Operations -- Southwest Region" and "Business -- Regulation -- State and Local Regulations -- California" in Item 1 of this Form 10-K, "-- Results of Operations by Business Segment -- Wholesale Energy -- 2000 Compared to 1999," as well as Notes 14(g) and 14(h) to our consolidated financial statements. COMPETITIVE, REGULATORY AND OTHER FACTORS AFFECTING OUR EUROPEAN ENERGY OPERATIONS Competition. The European energy market is highly competitive. In addition, over the next several years, we expect an increasing consolidation of the participants in the European generating market. Our European wholesale operations compete in the Netherlands, primarily against the three other largest Dutch generating companies, various cogenerators of electric power, various alternate sources of power and non-Dutch generators of electric power, primarily from France and Germany. In 2000, UNA and the three other largest Dutch generating companies supplied approximately 50% of the electricity consumed in the 9 Netherlands. Smaller Dutch producers supplied about 25% of the consumed electricity, and the remainder was imported. At present, the Dutch electricity system has three operational interconnection points with Germany and two interconnection points with Belgium. There are also a number of projects that are at various stages of development and that may increase the number of interconnections in the future (post 2005) including interconnections with Norway and the United Kingdom. The Belgian interconnections are used to import electricity from France, but a larger portion of Dutch electricity imports comes from Germany. Our European trading and marketing operations will also be subject to increasing levels of competition. As of December 31, 2000, there were 32 trading and marketing companies registered with the Amsterdam Power Exchange. Competition among power generators for customers is intense, and we expect competition to increase with the deregulation of the market. Please read "-- Regulation." The primary elements of competition affecting both the generation and trading and marketing operations of our European Energy business segment are price, credit support, and supply and delivery reliability. Deregulation. The Dutch electricity market was opened to limited wholesale and retail competition on January 1, 1999 as retail competition for large industrial customers began. The Dutch wholesale electric market was completely opened to competition on January 1, 2001. Consistent with our expectations at the time we made the acquisition, we anticipate that our European Energy business segment may experience a significant decline in gross margin in 2001 attributable to the deregulation of the market and termination of an agreement with the other Dutch generators and the Dutch distributors. The next customer segment, composed primarily of commercial customers, will be liberalized by 2002. The remainder of the market, mainly residential, will be open to competition by 2003. The timing of these market openings is subject to change, however, at the discretion of the Dutch Minister of Economic Affairs. In addition, the results of our European Energy segment will be negatively impacted beginning in 2002 due to the imposition of a standard Dutch corporate income tax rate, which is currently 35%, on the income of UNA. In 2000 and prior years, UNA's Dutch corporate income tax rate was zero percent. Other. Another factor that could have a significant impact on the Dutch energy industry, including the operations of our European Energy business segment, is the ultimate resolution of stranded costs issues in the Netherlands. Prior to 2001, UNA and the other Dutch generators sold their generating output through the coordinating body for the Dutch electricity generating sector, B.V. Nederlands Elektriciteit Administratiekantor (NEA). Over the years, NEA has incurred "stranded" costs as a result of, among other things, a perceived need to cover anticipated shortages in energy production supply. NEA stranded costs consist primarily of investments in alternative energy sources and fuel and power purchase contracts currently estimated to be uneconomical. Legislation has been approved by the Dutch parliament which would transfer the liability for the stranded costs from NEA to its four shareholders, one of which is UNA. For information regarding this legislation, please read Note 14(i) to our consolidated financial statements. In connection with our acquisition of UNA, the selling shareholders of UNA agreed to indemnify UNA for some stranded costs in an amount not to exceed NLG 1.4 billion ($599 million based on an exchange rate of 2.34 NLG per U.S. dollar as of December 31, 2000), which may be increased in some circumstances at our option up to NLG 1.9 billion ($812 million). Of the total consideration we paid for the shares of UNA, NLG 900 million ($385 million) has been placed by the selling shareholders under the direction of the Dutch Minister of Economic Affairs in an escrow account to secure the indemnity obligations by the former shareholders of UNA. Although our management believes that the indemnity provision will be sufficient to fully satisfy UNA's ultimate share of any stranded costs obligation, this judgment is based on numerous assumptions regarding the ultimate outcome and timing of the resolution of the stranded cost issue, the former shareholders' timely performance of their obligations under the indemnity arrangement, and the amount of stranded costs, which at present is not determinable. Any shortfall in the indemnity provision could have a material adverse effect on our results of operations. Our European operations are subject to various risks incidental to investing or operating in foreign countries. These risks include economic risks, such as fluctuations in currency exchange rates, restrictions on the repatriation of foreign earnings and/or restrictions on the conversion of local currency earnings into U.S. dollars. For example, we estimate that the impact of the devaluation of the Euro relative to the 10 U.S. dollar during 2000 negatively impacted U.S. dollar net income in the amount of approximately $8 million. Impact of Currency Fluctuations on Company Earnings. For information about our exposure through our investment in Europe to losses resulting from fluctuations in currency rates, please read "Quantitative and Qualitative Disclosures About Market Risk" in Item 7A of this Form 10-K. COMPETITIVE AND OTHER FACTORS AFFECTING RERC OPERATIONS Natural Gas Distribution. Our Natural Gas Distribution business segment competes primarily with alternate energy sources such as electricity and other fuel sources. In some areas, intrastate pipelines, other gas distributors and marketers also compete directly with our Natural Gas Distribution business segment for gas sales to end-users. In addition, as a result of federal regulatory changes affecting interstate pipelines, natural gas marketers operating on these pipelines may be able to bypass our Natural Gas Distribution business segment's facilities and market, sell and/or transport natural gas directly to commercial and industrial customers. Generally, the regulations of the states in which our Natural Gas Distribution business segment operates allow us to pass through changes in the costs of natural gas to our customers through purchased gas adjustment provisions in rates. There is, however, an inherent timing difference between our purchases of natural gas and the ultimate recovery of these costs. Consequently, we may incur additional "carrying" costs as a result of this timing difference and the resulting, temporary under-recovery of our purchased gas costs. To a large extent, these additional carrying costs are not recovered from our customers. Pipelines and Gathering. Our Pipelines and Gathering segment competes with other interstate and intrastate pipelines in the transportation and storage of natural gas. The principal elements of competition among pipelines are rates, terms of service, and flexibility and reliability of service. Our Pipelines and Gathering segment competes indirectly with other forms of energy available to its customers, including electricity, coal and fuel oils. The primary competitive factor is price. Changes in the availability of energy and pipeline capacity, the level of business activity, conservation and governmental regulations, the capability to convert to alternative fuels, and other factors, including weather, affect the demand for natural gas in areas we serve and the level of competition for transportation and storage services. Since FERC Order No. 636, REGT's and MRT's commodity sales activity has been minimal. Commodity transactions are usually related to system management activity which we have been able to manage with little exposure. We have not been nor do we anticipate to be, negatively impacted from the recent price levels and the tightening of supply. In addition, competition for our gathering operations is impacted by commodity pricing levels in its markets because these prices influence the level of drilling activity in those markets. Natural Gas Pipeline Company of America has proposed, and is soliciting customers for a 30" pipeline paralleling MRT's East Line in Illinois to a point 17 miles East of St. Louis Metro, with a proposed in-service date of June 2002. MRT has renewed or is engaged in negotiations to renew service agreements under multi-year terms, including service and potential expansion needs along MRT's existing East Line in Illinois. Our Pipelines and Gathering business segment derives approximately 14% of its revenues from its contract with Laclede, which has been under an annual evergreen term provision since 1999. In the event we are not able to renegotiate a long-term extension to the contract with Laclede, and Laclede engages another pipeline for the transportation services it currently obtains from us, the operating and financial results of our Pipelines and Gathering business segment would be materially adversely affected. FLUCTUATIONS IN COMMODITY PRICES AND DERIVATIVE INSTRUMENTS For information regarding our exposure to risk as a result of fluctuations in commodity prices and derivative instruments, please read "Quantitative and Qualitative Disclosures About Market Risk" in Item 7A of this Form 10-K. 11 INDEXED DEBT SECURITIES (ZENS) AND OUR AOL TIME WARNER INVESTMENT For information on our indexed debt securities and our investment in AOL Time Warner common stock, please read "Quantitative and Qualitative Disclosures About Market Risk" in Item 7A of this Form 10-K and Note 8 to our consolidated financial statements. ENVIRONMENTAL EXPENDITURES We are subject to numerous environmental laws and regulations, which require us to incur substantial costs to operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past operations on the environment. For additional information regarding environmental contingencies, please read Note 14(g) to our consolidated financial statements. Clean Air Act Expenditures. We expect the majority of capital expenditures associated with environmental matters to be incurred by our Electric Operations and Wholesale Energy business segments in connection with emission limitations for NOx under the Clean Air Act, or to enhance operational flexibility under Clean Air Act requirements. In 2000, emission reduction requirements for NOx were finalized for our electric generating facilities in Texas and the Mid-Atlantic region. We currently estimate that up to $534 million will be required to comply with the requirements through the end of 2003, with an estimated $215 million to be incurred in 2001. The Texas regulations require additional reductions that must be completed by March 2007. Estimates for the Texas units for the period 2004 through 2007 have not been defined, but could be up to $230 million. We are currently litigating the economic and technical viability of the Texas post-2004 reduction requirements, but cannot predict the outcome of this litigation. In addition, the Legislation created a program mandating air emissions reductions for some generating facilities of our Electric Operations segment. The Legislation provides for stranded costs recovery for costs associated with this obligation incurred before May 1, 2003. For additional information regarding the Legislation, please read Note 4(a) to our consolidated financial statements. Additional NOx emission controls for our generating units located in California may result in expenditures of up to $30 million through 2002. For additional information regarding environmental regulation of air emissions, please read "Business -- Environmental Matters -- Air Emissions" in Item 1 of this Form 10-K. Site Remediation Expenditures. From time to time we have received notices from regulatory authorities or others regarding our status as a potentially responsible party in connection with sites found to require remediation due to the presence of environmental contaminants. Based on currently available information, we believe that remediation costs will not materially affect our financial position, results of operations or cash flows. There can be no assurance, however, that future developments, including additional information about existing sites or the identification of new sites, will not require material revisions to our estimates. For information about specific sites that are the subject of remediation claims, please read Note 14(g) to our consolidated financial statements and Note 9(c) to RERC's consolidated financial statements. Water, Mercury and Other Expenditures. As discussed under "Business -- Environmental Matters -- Water Issues" in Item 1 of this Form 10-K, regulatory authorities are in the process of implementing regulations and quality standards in connection with the discharge of pollutants into waterways. Once these regulations and quality standards are enacted, we will be able to determine if our operations are in compliance, or if we will have to incur costs in order to comply with the quality standards and regulations. Until that time, however, we are not able to predict the amount of these expenditures, if any. To date, however, our expenditures associated with respect to permits, registrations and authorizations for operation of facilities under the statutes regulating the discharge of pollutants into surface water have not been material. With regard to mercury remediation and other environmental matters, such as the disposal of solid wastes, our expenditures have not been, and are not expected to be material, based on our experiences and that of others in our industries. Please read "Business -- Environmental Matters -- Mercury Contamination" and "-- Other" in Item 1 of this Form 10-K. 12 OTHER CONTINGENCIES For a description of other legal and regulatory proceedings affecting us, please read Notes 4 and 14 to our consolidated financial statements and Note 9 to RERC's consolidated financial statements. ITEMS INCORPORATED BY REFERENCE FROM THE RELIANT ENERGY 10-K NOTES o (2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (f) Regulatory Assets. The Company applies the accounting policies established in Statement of Financial Accounting Standards (SFAS) No. 71 (SFAS No. 71) to the accounts of transmission and distribution operations of Reliant Energy HL&P and the utility operations of Natural Gas Distribution and to some of the accounts of Pipelines and Gathering. For information regarding Reliant Energy HL&P's electric generation operations' discontinuance of the application of SFAS No. 71 in 1999 and the effect on its regulatory assets and the Texas Electric Choice Plan (Legislation), see Note 4(a). The following is a list of regulatory assets/liabilities reflected on the Company's Consolidated Balance Sheets as of December 31, 1999 and 2000.
DECEMBER 31, --------------- 1999 2000 ------ ------ (IN MILLIONS) Recoverable impaired plant costs, net....................... $ 587 $ 281 Recoverable electric generation related regulatory assets, net....................................................... 952 1,385 Regulatory tax liability, net............................... (45) (49) Unamortized loss on reacquired debt......................... 69 66 Other long-term assets/liabilities.......................... (14) 6 ------ ------ Total............................................. $1,549 $1,689 ====== ======
Included in the above table are $191 million and $237 million of regulatory liabilities recorded as other long-term liabilities in the Company's Consolidated Balance Sheets as of December 31, 1999 and 2000, respectively, which primarily relate to the recovery of fuel costs as of December 31, 1999, and gains on nuclear decommissioning trust funds, regulatory tax liabilities and excess deferred income taxes as of December 31, 1999 and 2000. Under a "deferred accounting" plan authorized by the Public Utility Commission of Texas (Texas Utility Commission), Electric Operations was permitted for regulatory purposes to accrue carrying costs in the form of allowance for funds used during construction (AFUDC) on its investment in the South Texas Project Electric Generating Station (South Texas Project) and to defer and capitalize depreciation and other operating costs on its investment after commercial operation until these costs were reflected in rates. In addition, the Texas Utility Commission authorized Electric Operations to defer allowable costs (including return) for future recovery. Pursuant to SFAS No. 92, "Regulated Enterprises -- Accounting for Phase-in Plans," the Company deferred these costs. These costs are included in recoverable electric generation related regulatory assets. The amortization of all deferred plant costs (which totaled $26 million for 1998) is included in the Company's Statements of Consolidated Operations as depreciation and amortization expense. Pursuant to the Legislation, see Note 4(a), the Company discontinued amortizing deferred plant costs effective January 1, 1999. In 1998, 1999 and 2000, the Company, as permitted by the 1995 rate case settlement (Rate Case Settlement), also amortized $4 million, $22 million and $11 million, respectively, of its investment in lignite reserves associated with a canceled generating station. The investment in these reserves was fully amortized during 2000. 13 For additional information regarding recoverable impaired plant costs and recoverable electric generation related assets and the related amortization during 1999 and 2000, see Notes 2(g) and 4(a). If, as a result of changes in regulation or competition, the Company's ability to recover these assets and liabilities would not be assured, then pursuant to SFAS No. 101, "Regulated Enterprises Accounting for the Discontinuation of Application of SFAS No. 71" (SFAS No. 101) and SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" (SFAS No. 121), the Company would be required to write off or write down these regulatory assets and liabilities. In addition, the Company would be required to determine any impairment to the carrying costs of plant and inventory assets. o (3) BUSINESS ACQUISITIONS (a) Reliant Energy Mid-Atlantic Power Holdings, LLC. On May 12, 2000, a subsidiary of the Company purchased entities owning electric power generating assets and development sites located in Pennsylvania, New Jersey and Maryland having an aggregate net generating capacity of approximately 4,262 megawatts (MW). With the exception of development entities that were sold to another subsidiary of the Company in July 2000, the assets of the entities acquired are held by Reliant Energy Mid-Atlantic Power Holdings, LLC (REMA). The purchase price for the May 2000 transaction was $2.1 billion, subject to post-closing adjustments which management does not believe will be material. The Company accounted for the acquisition as a purchase with assets and liabilities of REMA reflected at their estimated fair values. On a preliminary basis, the Company's fair value adjustments related to the acquisition primarily included adjustments in property, plant and equipment, air emissions regulatory allowances, materials and supplies inventory, environmental reserves and related deferred taxes. The air emissions regulatory allowances of $153 million are being amortized on a units-of-production basis as utilized. The excess of the purchase price over the fair value of net assets acquired of $7 million was recorded as goodwill and is being amortized over 35 years. The Company expects to finalize these fair value adjustments no later than May 2001, based on valuation reports of property, plant and equipment and intangible assets, and does not anticipate additional material modifications to the preliminary adjustments. Funds for the acquisition of REMA were made available through commercial paper borrowings by a finance subsidiary, which borrowings were supported by bank credit facilities. The net purchase price of REMA was allocated and the fair value adjustments to the seller's book value are as follows (in millions):
PURCHASE FAIR PRICE VALUE ALLOCATION ADJUSTMENTS ---------- ----------- Current assets.............................................. $ 75 $ (37) Property, plant and equipment............................... 1,941 670 Goodwill.................................................... 7 (144) Other intangibles........................................... 153 (10) Other assets................................................ 4 (4) Current liabilities......................................... (45) (8) Other liabilities........................................... (38) (14) ------ ----- $2,097 $ 453 ====== =====
Adjustments to property, plant and equipment, other intangibles, which includes air emissions regulatory allowances, and environmental reserves included in other liabilities are based primarily on valuation reports prepared by independent appraisers and consultants. In August 2000, the Company entered into separate sale/leaseback transactions with each of three owner-lessors for the Company's 16.45%, 16.67% and 100% interests in the Conemaugh, Keystone and Shawville generating stations, respectively, acquired as part of the REMA acquisition. As lessee, the Company leases an interest in each facility from each owner-lessor under a facility lease agreement. As consideration for 14 the sale of the Company's interest in the facilities, the Company received $1.0 billion in cash. The Company used the $1.0 billion of sale proceeds to repay commercial paper referred to above. The Company's results of operations include the results of REMA only for the period beginning May 12, 2000. Prior to November 24, 1999, the acquired entities' operations were fully integrated with, and their results of operations were consolidated into, the regulated electric utility operations of a prior owner of the facilities. In addition, prior to November 24, 1999, the electric output of the facilities was sold based on rates set by regulatory authorities and is not indicative of REMA's future results. The following table presents selected actual financial information and unaudited pro forma information for 1999 and 2000, as if the acquisition had occurred on November 24, 1999 and January 1, 2000, as applicable. Pro forma information prior to November 24, 1999 would not be meaningful since historical financial results of the business and the revenue generating activities underlying that period as described above are substantially different from the wholesale generation activities that REMA has been engaged in after November 24, 1999. Pro forma amounts also give effect to the sale and leaseback of interests in three of the REMA generating plants, which were consummated in August 2000.
YEAR ENDED DECEMBER 31, ----------------------------------------- 1999 2000 ------------------- ------------------- UNAUDITED UNAUDITED ACTUAL PRO FORMA ACTUAL PRO FORMA ------- --------- ------- --------- (IN MILLIONS, EXCEPT PER SHARE AMOUNTS) Revenues............................................. $15,223 $15,253 $29,339 $29,506 Income from continuing operations before extraordinary items................................ 1,674 1,664 771 762 Net income attributable to common stockholders....... 1,482 1,472 447 438 Basic earnings per share from continuing operations before extraordinary items......................... 5.87 5.84 2.71 2.68 Diluted earnings per share from continuing operations before extraordinary items......................... 5.85 5.82 2.68 2.65 Basic earnings per share............................. 5.20 5.16 1.57 1.54 Diluted earnings per share........................... 5.18 5.15 1.56 1.53
These unaudited pro forma results, based on assumptions deemed appropriate by the Company's management, have been prepared for informational purposes only and are not necessarily indicative of the amounts that would have resulted if the acquisition of the REMA entities had occurred on November 24, 1999 and January 1, 2000, as applicable. Purchase-related adjustments to the results of operations include the effects on depreciation and amortization, interest expense and income taxes. (b) N.V. UNA. Effective October 7, 1999, the Company acquired N.V. UNA (UNA), a Dutch electric generation company, for a total net purchase price, payable in Dutch Guilders (NLG), of $1.9 billion based on an exchange rate on October 7, 1999 of 2.06 NLG per U.S. dollar. The aggregate purchase price paid in 1999 by the Company consisted of $833 million in cash. On March 1, 2000, under the terms of the acquisition agreement, the Company funded the remaining purchase obligation for $982 million. The business purchase obligation was recorded in the Company's Consolidated Balance Sheet as of December 31, 1999, based on the exchange rate on December 31, 1999, of 2.19 NLG per U.S. dollar. A portion ($596 million) of the business purchase obligation was classified as a non-current liability, as this portion of the obligation was financed with a three-year term loan facility obtained in the first quarter of 2000. The Company recorded the UNA acquisition under the purchase method of accounting, with assets and liabilities of UNA reflected at their estimated fair values. As outlined in the table below, the Company's fair value adjustments related to the acquisition of UNA primarily included increases in property, plant and equipment, long-term debt, severance liabilities, post-employment benefit liabilities and deferred foreign taxes. Additionally, a $19 million receivable was recorded in connection with the acquisition as the selling 15 shareholders agreed to reimburse UNA for some obligations incurred prior to the purchase of UNA. Adjustments to property, plant and equipment are based primarily on valuation reports prepared by independent appraisers and consultants. The excess of the purchase price over the fair value of net assets acquired of $897 million was recorded as goodwill and will be amortized on a straight-line basis over 30 years. The Company finalized these fair value adjustments during September 2000. The Company finalized a severance plan (UNA Plan) in connection with the UNA acquisition in September 2000 (commitment date) and in accordance with EITF 95-3 "Recognition of Liabilities in Connection with a Purchase Business Combination," recorded this liability of $19 million in the third quarter of 2000. Payments under the UNA Plan will be primarily made in mid-2001. In connection with the acquisition of UNA, the Company developed a comprehensive business process reengineering and employee severance plan intended to make UNA competitive in the deregulated Dutch electricity market that began January 1, 2001. The UNA Plan's initial conceptual formulation was initiated prior to the acquisition of UNA in October 1999. The finalization of the UNA Plan was approved and completed in September 2000. The Company identified 195 employees who will be involuntarily terminated in UNA's following functional areas: plant operations and maintenance, procurement, inventory, general and administrative, legal, finance and support. The Company has notified all employees identified under the severance component of the UNA Plan that they are subject to involuntary termination and that the majority of terminations will occur over a period not to exceed twelve months from the date of finalization of the UNA Plan. The termination benefits under the UNA Plan are governed by UNA's Social Plan, a collective bargaining agreement between UNA and its various representative labor unions signed in 1998. The Social Plan provides defined benefits for involuntarily severed employees, depending upon age, tenure and other factors, and was agreed to by the management of UNA as a result of the anticipated deregulation of the Dutch electricity market. The Social Plan is still in force and binding on the current management of the Company and UNA. The Company is currently executing the UNA Plan as of the date of these Consolidated Financial Statements. The net purchase price of UNA was allocated and the fair value adjustments to the seller's book value are as follows (in millions):
PURCHASE FAIR PRICE VALUE ALLOCATION ADJUSTMENTS ---------- ----------- Current assets.............................................. $ 229 $ 19 Property, plant and equipment............................... 1,899 719 Goodwill.................................................... 897 897 Current liabilities......................................... (336) -- Deferred taxes.............................................. (81) (81) Long-term debt.............................................. (422) (87) Other long-term liabilities................................. (244) (35) ------ ------ $1,942 $1,432 ====== ======
The following table presents selected actual financial information for 1998 and 1999, and unaudited pro forma information for 1998 and 1999, as if the acquisition of UNA had occurred on January 1, 1998 and 1999, respectively. The unaudited pro forma results are based on assumptions deemed appropriate by the Company's management, have been prepared for informational purposes only and are not necessarily indicative of the consolidated results that would have resulted if the acquisition of UNA had occurred on January 1, 1998 and 1999, as applicable. Purchase related adjustments to results of operations include amortization of goodwill, 16 interest expense and the effects on depreciation and amortization of the assessed fair value of some of UNA's net assets and liabilities.
YEAR ENDED DECEMBER 31, ----------------------------------------- 1998 1999 ------------------- ------------------- UNAUDITED UNAUDITED ACTUAL PRO FORMA ACTUAL PRO FORMA ------- --------- ------- --------- (IN MILLIONS, EXCEPT PER SHARE AMOUNTS) Revenues............................................. $11,230 $12,062 $15,223 $15,704 Income from continuing operations before extraordinary item................................. (278) (227) 1,674 1,648 Net (loss) income attributable to common stockholders....................................... (141) (90) 1,482 1,455 Basic earnings per share from continuing operations before extraordinary item.......................... (0.98) (0.80) 5.87 5.78 Diluted earnings per share from continuing operations before extraordinary item.......................... (0.98) (0.80) 5.85 5.76 Basic earnings per share............................. (0.50) (0.32) 5.20 5.11 Diluted earnings per share........................... (0.50) (0.32) 5.18 5.09
o (4) REGULATORY MATTERS (a) Texas Electric Choice Plan and Discontinuance of SFAS No. 71 for Electric Generation Operations. In June 1999, the Texas legislature adopted the Legislation, which substantially amended the regulatory structure governing electric utilities in Texas in order to allow retail electric competition. Retail pilot projects for up to 5% of each utility's load in all customer classes will begin in June 2001, and retail electric competition for all other customers will begin on January 1, 2002. In preparation for that competition, the Company expects to make significant changes in the electric utility operations it conducts through its electric utility division, Reliant Energy HL&P. In addition, the Legislation requires the Texas Utility Commission to issue a number of new rules and determinations in implementing the Legislation. The Legislation defines the process for competition and creates a transition period during which most utility rates are frozen at rates not in excess of their present levels. The Legislation provides for utilities to recover their generation related stranded costs and regulatory assets (as defined in the Legislation). Retail Choice. Under the Legislation, on January 1, 2002, retail customers of most investor owned electric utilities in Texas will be entitled to purchase their electricity from any of a number of "retail electric providers," which will have been certified by the Texas Utility Commission. Retail electric providers will not own or operate generation assets and their sales rates will not be subject to traditional cost-of-service rate regulation. Retail electric providers that are affiliates of electric utilities may compete substantially statewide for these sales, but rates they charge within the affiliated electric utility's traditional service territory are subject to some limitations at the outset of retail choice, as described below. The Texas Utility Commission will prescribe regulations governing quality, reliability and other aspects of service from retail electric providers. Transactions between the regulated utility and its current and future competitive affiliates are subject to regulatory scrutiny and must comply with a code of conduct established by the Texas Utility Commission. The code of conduct governs interactions among employees of regulated and current and future unregulated affiliates as well as the exchange of information between these affiliates. The Company intends to compete in the Texas retail market and, as a result, has certified two of its subsidiaries as retail electric providers. Unbundling. By January 1, 2002, electric utilities in Texas such as Reliant Energy HL&P will restructure their businesses in order to separate power generation, transmission and distribution, and retail activities into different units. Pursuant to the Legislation, the Company submitted a plan in January 2000 that was later amended to accomplish the required separation (the Business Separation Plan). For additional information regarding the Business Separation Plan, see Note 4(b). The transmission and distribution 17 business will continue to be subject to cost-of-service rate regulation and will be responsible for the delivery of electricity to retail customers. Generation. Power generators will sell electric energy to wholesale purchasers, including retail electric providers, at unregulated rates beginning January 1, 2002. To facilitate a competitive market, each power generation company affiliated with a transmission and distribution utility will be required to sell at auction 15% of the output of its installed generating capacity. The first auction will be held on or before September 1, 2001 for power delivered after January 1, 2002. This obligation continues until January 1, 2007 unless before that date the Texas Utility Commission determines at least 40% of the quantity of electric power consumed in 2000 by residential and small commercial load in the electric utility's service area is being served by retail electric providers other than the affiliated retail electric provider. See Note 4(b) for information regarding the capacity auctions and the effect of the Business Separation Plan on the Company. The Legislation also creates a program mandating air emissions reductions for non-permitted generating facilities. The Company anticipates that any stranded costs associated with this obligation incurred before May 1, 2003 will be recoverable through the stranded costs recovery mechanisms contained in the Legislation. Rates. Base rates charged by Reliant Energy HL&P on September 1, 1999 will be frozen until January 1, 2002. Pursuant to Texas Utility Commission regulations, effective January 1, 2002, retail rates charged to residential and small commercial customers by the utility's affiliated retail electric provider will be reduced by 6% from the average rates (on a bundled basis) in effect on January 1, 1999 (adjusted for fuel charges). That reduced rate will be known as the "price to beat" and will be charged by the affiliated retail electric provider to residential and small commercial customers in the utility's service area who have not elected service from another retail electric provider. The affiliated retail electric provider may not offer different rates to residential or small commercial customer classes in the utility's service area until the earlier of the date the Texas Utility Commission determines that 40% of power consumed by that class in the affiliated transmission and distribution utility's service area is being served by non-affiliated retail electric providers or January 1, 2005. In addition, the affiliated retail electric provider must make the price to beat available to eligible consumers until January 1, 2007. Stranded Costs. Reliant Energy HL&P will be entitled to recover its stranded costs (i.e., the excess of net book value of generation assets (as defined by the Legislation) over the market value of those assets) and its regulatory assets related to generation. The Legislation prescribes specific methods for determining the amount of stranded costs and the details for their recovery. However, during the base rate freeze period from 1999 through 2001, earnings above the utility's authorized return formula will be applied in a manner to accelerate depreciation of generation related plant assets for regulatory purposes. In addition, depreciation expense for transmission and distribution related assets may be redirected to generation assets for regulatory purposes during that period. The Texas Utility Commission has recently stated on record that it would consider requiring electric utilities to reverse the amount of redirected depreciation and accelerated depreciation previously taken if in its estimation the utility has overmitigated its stranded costs. The reversal could occur through a lower rate for the transmission and distribution utility and/or through credits contained in the transmission and distribution utility's rate. Any order requiring the reversal of these amounts would likely be included in the Texas Utility Commission proceeding establishing the initial rate of the transmission and distribution utility. The Company does not expect the final Reliant Energy HL&P transmission and distribution rate to be established until August 2001. For information regarding redirected depreciation, see "Accounting" in this Note 4(a). The Legislation provides for Reliant Energy HL&P, or a special purpose entity, to issue securitization bonds for the recovery of generation related regulatory assets and a portion of stranded costs. These bonds will be sold to third parties and will be amortized through non-bypassable charges to transmission and distribution customers. Any stranded costs not recovered through the securitization bonds will be recovered through a non-bypassable charge to transmission and distribution customers. Costs associated with nuclear decommissioning that have not been recovered as of January 1, 2002, will continue to be subject to cost-of-service rate regulation and will be included in a non-bypassable charge to transmission and distribution customers. For 18 further discussion of the effect of the Business Separation Plan on funding of the nuclear decommissioning trust fund, see Note 4(b). In May 2000, the Texas Utility Commission issued a financing order to the Company authorizing the issuance of transition bonds in an amount not to exceed $740 million plus actual up-front qualified costs. Payments on the transition bonds will be made out of funds derived from non-bypassable transition charges to Reliant Energy HL&P's transmission and distribution customers. The offering of the transition bonds will be registered under the Securities Act of 1933 and is expected to be consummated during 2001. Capacity Auction True-up. In accordance with the Legislation, beginning on January 1, 2002, and ending when the true-up proceeding is completed, any difference between market power prices received in the generation capacity auction and the Texas Utility Commission's earlier estimates of those market prices will be included in the 2004 stranded costs true-up, as further discussed below. This component of the true-up is intended to ensure that neither the customers nor the Company are disadvantaged economically as a result of the two-year transition period by providing this pricing structure. For information regarding the effect of the Business Separation Plan on the generation capacity auctions, see Note 4(b). Accounting. Historically, Reliant Energy HL&P has applied the accounting policies established in SFAS No. 71. In general, SFAS No. 71 permits a company with cost-based rates to defer some costs that would otherwise be expensed to the extent that it meets the following requirements: (a) its rates are regulated by a third-party; (b) its rates are cost-based; and (c) there exists a reasonable assumption that all costs will be recoverable from customers through rates. When a company determines that it no longer meets the requirements of SFAS No. 71, pursuant to SFAS No. 101 and SFAS No. 121, it is required to write off regulatory assets and liabilities unless some form of recovery continues through rates established and collected from remaining regulated operations. In addition, such company is required to determine any impairment to the carrying costs of deregulated plant and inventory assets in accordance with SFAS No. 121. In July 1997, the EITF reached a consensus on Issue No. 97-4, "Deregulation of the Pricing of Electricity -- Issues Related to the Application of FASB Statements No. 71, Accounting for the Effects of Certain Types of Regulation, and No. 101, Regulated Enterprises Accounting for the Discontinuation of Application of FASB Statement No. 71" (EITF No. 97-4). EITF No. 97-4 concluded that a company should no longer apply SFAS No. 71 to a segment which is subject to a deregulation plan at the time the deregulation legislation or enabling rate order contains sufficient detail for the utility to reasonably determine how the plan will affect the segment to be deregulated. In addition, EITF No. 97-4 requires that regulatory assets and liabilities be allocated to the applicable portion of the electric utility from which the source of the regulated cash flows will be derived. The Company believes that the Legislation provides sufficient detail regarding the deregulation of the Company's electric generation operations to require it to discontinue the use of SFAS No. 71 for those operations. Effective June 30, 1999, the Company applied SFAS No. 101 to Reliant Energy HL&P's electric generation operations. Reliant Energy HL&P's transmission and distribution operations continue to meet the criteria of SFAS No. 71. In 1999, the Company evaluated the effects that the Legislation would have on the recovery of its generation related regulatory assets and liabilities. The Company determined that a pre-tax accounting loss of $282 million existed because it believes only the economic value of its generation related regulatory assets (as defined by the Legislation) will be recovered. Therefore, the Company recorded a $183 million after-tax extraordinary loss in the fourth quarter of 1999. If events were to occur that made the recovery of some of the remaining generation related regulatory assets no longer probable, the Company would write off the remaining balance of such assets as a non-cash charge against earnings. Pursuant to EITF No. 97-4, the remaining recoverable regulatory assets will not be written off and will become associated with the transmission and distribution portion of the Company's electric utility business. For details regarding Reliant Energy HL&P's regulatory assets, see Note 2(f). At June 30, 1999, the Company performed an impairment test of its previously regulated electric generation assets pursuant to SFAS No. 121 on a plant specific basis. Under SFAS No. 121, an asset is 19 considered impaired, and should be written down to fair value, if the future undiscounted net cash flows expected to be generated by the use of the asset are insufficient to recover the carrying amount of the asset. For assets that are impaired pursuant to SFAS No. 121, the Company determined the fair value for each generating plant by estimating the net present value of future cash inflows and outflows over the estimated life of each plant. The difference between fair value and net book value was recorded as a reduction in the current book value. The Company determined that $797 million of electric generation assets were impaired as of June 30, 1999. Of these amounts, $745 million related to the South Texas Project and $52 million related to two gas-fired generation plants. The Legislation provides for recovery of this impairment through regulated cash flows during the transition period and through non-bypassable charges to transmission and distribution customers. As such, a regulatory asset has been recorded for an amount equal to the impairment loss and is included on the Company's Consolidated Balance Sheets as a regulatory asset. The Company recorded amortization expense related to the recoverable impaired plant costs and other assets created from discontinuing SFAS No. 71 of $221 million in the third and fourth quarters of 1999 and $329 million in 2000. The Company expects to fully amortize this regulatory asset as it is recovered from regulated cash flows in 2001. The impairment analysis requires estimates of possible future market prices, load growth, competition and many other factors over the lives of the plants. The resulting impairment loss is highly dependent on these underlying assumptions. In addition, after January 10, 2004, Reliant Energy HL&P must finalize and reconcile stranded costs (as defined by the Legislation) in a filing with the Texas Utility Commission. Any positive difference between the regulatory net book value and the fair market value of the generation assets (as defined by the Legislation) will be collected through future non-bypassable charges. Any over-mitigation of stranded costs may be refunded through future non-bypassable charges. This final reconciliation allows alternative methods of third party valuation of the fair market value of these assets, including outright sale, stock valuations and asset exchanges. Because generally accepted accounting principles require the Company to estimate fair market values on a plant-by-plant basis in advance of the final reconciliation, the financial impacts of the Legislation with respect to the final determination of stranded costs in 2004 are subject to material changes. Factors affecting such change may include estimation risk, uncertainty of future energy and commodity prices and the economic lives of the plants. If events occur that make the recovery of all or a portion of the regulatory assets associated with the generation plant impairment loss and other assets created from discontinuance of SFAS No. 71 pursuant to the Legislation no longer probable, the Company will write off the corresponding balance of these assets as a non-cash charge against earnings. One of the results of discontinuing the application of SFAS No. 71 for the generation operations is the elimination of the regulatory accounting effects of excess deferred income taxes and investment tax credits related to these operations. The Company believes it is probable that some parties will seek to return these amounts to ratepayers and accordingly, the Company has recorded an offsetting liability. In order to reduce potential exposure to stranded costs related to generation assets, Reliant Energy HL&P redirected $195 million and $99 million of depreciation in 1998 and for the six months ended June 30, 1999, respectively, from transmission and distribution related plant assets to generation assets for regulatory and financial reporting purposes. This redirection was in accordance with the Company's Transition Plan. See Note 4(c) for additional information regarding the Transition Plan. The Legislation provides that depreciation expense for transmission and distribution related assets may be redirected to generation assets during the base rate freeze period from 1999 through 2001. For regulatory purposes, the Company has continued to redirect transmission and distribution depreciation to generation assets. Beginning June 30, 1999, redirected depreciation expense cannot be recorded by the electric generation operations portion of Reliant Energy HL&P for financial reporting purposes as this portion of electric operations is no longer accounted for under SFAS No. 71. During the six months ended December 31, 1999 and during 2000, $99 million and $218 million in depreciation expense, respectively, has been redirected from transmission and distribution for regulatory purposes and has been established as an embedded regulatory asset included in transmission and distribution related plant and equipment balances. As of December 31, 1999 and 2000, the cumulative amount of redirected depreciation for regulatory purposes is $393 million and $611 million, respectively. 20 The Company has reviewed its long-term purchase power contracts and fuel contracts for potential loss in accordance with SFAS No. 5, "Accounting for Contingencies" and Accounting Research Bulletin No. 43, Chapter 4, "Inventory Pricing." Based on projections of future market prices for wholesale electricity, the analysis indicated no loss recognition is appropriate at this time. Other Accounting Policy Changes. As a result of discontinuing SFAS No. 71, the accounting policies discussed below related to Electric Operations' generation operations have been changed effective July 1, 1999. Allowance for funds used during construction will no longer be accrued on generation related construction projects. Instead, interest will be capitalized on these projects in accordance with SFAS No. 34, "Capitalization of Interest Cost." Previously, in accordance with SFAS No. 71, Reliant Energy HL&P deferred the premiums and expenses that arose when long-term debt was redeemed and amortized these costs over the life of the new debt. If no new debt was issued, these costs were amortized over the remaining original life of the retired debt. Effective July 1, 1999, costs resulting from the retirement of debt attributable to the generation operations of Reliant Energy HL&P will be recorded in accordance with SFAS No. 4, "Reporting Gains and Losses from Extinguishment of Debt," unless these costs will be recovered through regulated cash flows. In that case, these costs will be deferred and recorded as a regulatory asset by the entity through which the source of the regulated cash flows will be derived. (b) Business Separation Plan. General. As required by the Legislation, Reliant Energy submitted the Business Separation Plan in 2000 to the Texas Utility Commission. The Business Separation Plan was later amended to provide for the restructuring of the Company's businesses into two separate and publicly traded companies in order to separate its unregulated businesses from its regulated businesses. In December 2000, the plan was approved by the Texas Utility Commission. Reliant Resources holds Reliant Energy's unregulated businesses, including the Wholesale Energy segment, European Energy segment, communications business, eBusiness group, new ventures group and retail electric business. As further described below, Reliant Energy will undergo a restructuring of the Company's corporate organization to achieve a holding company structure. This holding company will hold primarily what are currently Reliant Energy's rate-regulated businesses. Reliant Resources expects to conduct the Offering in 2001. After the Offering, Reliant Energy will own approximately 80% of Reliant Resources common stock. Reliant Energy expects the Offering to be followed by a distribution to Reliant Energy's or its successor's shareholders of the remaining common stock of Reliant Resources within 12 months of the Offering (the Distribution Date). The Offering and the Distribution are subject to further corporate approvals, market and other conditions, and government actions, including receipt of a favorable Internal Revenue Service ruling that the Distribution would be tax-free to Reliant Energy or its successor and its shareholders for U.S. federal income tax purposes, as applicable. There can be no assurance that the Offering and the Distribution will be completed as described or within the time periods outlined above. Restructuring of Regulated Entities. Under the Business Separation Plan, Reliant Energy will restructure its regulated operations into a holding company structure in which a new corporate entity (Regulated Holding Company) will be formed as the parent with the Company's regulated businesses as subsidiaries. This Regulated Holding Company is expected to own (a) the Company's electric transmission and distribution operations, (b) its natural gas distribution businesses, (c) initially, its regulated electric generating assets in Texas, (d) its interstate pipelines, gas gathering and pipeline services operations, and (e) its interests in energy companies in Latin America until disposition of these investments (see Note 19). In these Notes, references to Reliant Energy in connection with events occurring or the performance of agreements after the restructuring generally refer to the Regulated Holding Company. In connection with the formation of the new holding company for regulated businesses, Reliant Energy expects to transfer the stock of all of its subsidiaries to the new holding company and will transfer its regulated electric generating assets in Texas to an indirect wholly owned partnership (Texas Genco) until the stranded costs associated with those assets are valued in 2004. At that time, Reliant Resources will have the right to 21 exercise an option to acquire those assets, as further discussed below. As a result of the stock and asset transfers described above, Reliant Energy will become solely a transmission and distribution company, with its other businesses becoming subsidiaries of the new holding company. Reliant Energy expects that the regulated holding company will be required to assume all of Reliant Energy's debt other than its first mortgage bonds, which would remain with Reliant Energy. The indebtedness of some wholly owned financing subsidiaries is expected to be refinanced by the regulated holding company by the end of 2002. Reliant Energy has made and will continue to make internal asset and stock transfers intended to allocate the assets and liabilities of Reliant Energy in accordance with regulatory requirements and as contemplated by the Business Separation Plan. Forms of each of the intercompany agreements described below have been prepared and will be entered into by Reliant Energy and Reliant Resources prior to the Offering. Aspects of the restructuring of Reliant Energy's regulated businesses are subject to the approval of Reliant Energy's shareholders and lenders and approvals from the SEC under the Public Utility Holding Company Act and from the United States Nuclear Regulatory Commission (NRC). There can be no assurance that the restructuring of the Company's regulated businesses will be completed as described above. Agreements Related to Texas Generating Assets. Pursuant to the Business Separation Plan, Reliant Energy expects to cause Texas Genco to either issue and sell in an initial public offering or to distribute to its shareholders no more than 20% of the common stock of Texas Genco by June 30, 2002. In connection with the separation of its unregulated businesses from its regulated businesses, Reliant Energy will grant Reliant Resources an option to purchase all of the shares of capital stock of Texas Genco that will be owned by Reliant Energy after the initial public offering or distribution. The Texas Genco option may be exercised between January 10, 2004 and January 24, 2004. The per share exercise price under the option will be the average daily closing price on the national exchange for publicly held shares of common stock of Texas Genco for the 30 consecutive trading days with the highest average closing price during the 120 trading days immediately preceding January 10, 2004, plus a control premium, up to a maximum of 10%, to the extent a control premium is included in the valuation determination made by the Texas Utility Commission relating to the market value of Texas Genco's common stock equity. The exercise price is also subject to adjustment based on the difference between the per share dividends paid during the period there is a public ownership interest in Texas Genco and Texas Genco's per share earnings during that period. If the disposition to the public of common stock of Texas Genco is by means of a primary or secondary public offering, the public offering may be of as little as 17% (rather than 19%) of Texas Genco's outstanding common stock, in which case Reliant Energy will have the right to subsequently reduce its interest to a level not less than 80%. Reliant Resources will agree that if it exercises the Texas Genco Option and purchases the shares of Texas Genco common stock, Reliant Resources will also purchase all notes and other receivables from Texas Genco then held by Reliant Energy, at their principal amount plus accrued interest. Similarly, if Texas Genco holds notes or receivables from the Company, Reliant Resources will assume those obligations in exchange for a payment to Reliant Resources by the Company of an amount equal to the principal plus accrued interest. Exercise of the Texas Genco option by Reliant Resources will be subject to various regulatory approvals, including Hart-Scott-Rodino antitrust clearance and Nuclear Regulatory Commission license transfer approval. The option will be exercisable only if Reliant Energy or its successor distributes all of the shares of Reliant Resources common stock it owns to its shareholders. The Texas Genco option agreement will require Reliant Energy to take commercially reasonable action as may be appropriate to cause Texas Genco to have a capital structure appropriate, in the judgment of Reliant Energy's Board of Directors, for the satisfactory marketing of Texas Genco common stock in an initial public offering or to establish a satisfactory trading market for Texas Genco common stock following a distribution of shares to Reliant Energy's shareholders. It also will contain covenants relating to the operation of the Texas Genco assets prior to the exercise or expiration of the option and require that Reliant Energy maintain ownership of all equity of Texas Genco until exercise or expiration of the Texas Genco option, subject to the initial public offering or distribution obligation. Reliant Resources will provide engineering and technical support services and environmental, safety and industrial health services to support the operations and maintenance of Texas Genco's facilities. Reliant 22 Resources will also provide systems, technical, programming and consulting support services and hardware maintenance (but excluding plant-specific hardware) necessary to provide dispatch planning, dispatch and settlement and communication with the independent system operator. The fees charged for these services will be designed to allow Reliant Resources to recover its fully allocated direct and indirect costs and reimbursement of out-of-pocket expenses. Expenses associated with capital investment in systems and software that benefit both the operation of Texas Genco's facilities and Reliant Resources' facilities in other regions will be allocated on an installed megawatt basis. The term of the technical services agreement will begin at the Distribution Date. The term of this agreement will end on the first to occur of (a) the closing date of the Reliant Resources' Texas Genco option, (b) Reliant Energy's sale of Texas Genco, or all or substantially all of the assets of Texas Genco, if Reliant Resources does not exercise the Texas Genco option, or (c) December 31, 2004, provided the Texas Genco option is not exercised. Texas Genco may extend the term of this agreement until December 31, 2005. Pursuant to the Legislation, Texas Genco will be required to sell at auction 15% of the output of its installed generating capacity beginning January 1, 2002. The first auction will be held on or before September 1, 2001 for power delivered after January 1, 2002. This obligation continues until January 1, 2007, unless before that date the Texas Utility Commission determines that at least 40% of the quantity of electric power consumed in 2000 by residential and small commercial customers in the Reliant Energy HL&P traditional service area is being served by retail electric providers other than subsidiaries of Reliant Resources. Texas Genco plans to auction all of its remaining output during the time period prior to Reliant Resources' exercise of the Texas Genco option. Pursuant to the Business Separation Plan, Reliant Resources is entitled to purchase, at prices established in these auctions, up to 50% of the remaining capacity, energy and ancillary services auctioned by Texas Genco. When Texas Genco is organized, it will become the beneficiary of the decommissioning trust that has been established to provide funding for decontamination and decommissioning of a nuclear electric generation station in which Reliant Energy owns a 30.8% interest (see Note 6). The master separation agreement will provide that Reliant Energy will collect through rates or other authorized charges to its electric utility customers amounts designated for funding the decommissioning trust, and will pay the amounts to Texas Genco. Texas Genco will in turn be required to deposit these amounts received from Reliant Energy into the decommissioning trust. Upon decommissioning of the facility, in the event funds from the trust are inadequate, Reliant Energy will be required to collect through rates or other authorized charges to customers as contemplated by the Texas Utilities Code all additional amounts required to fund Texas Genco's obligations relating to the decommissioning of the facility. Following the completion of the decommissioning, if surplus funds remain in the decommissioning trust, the excess will be refunded to Reliant Energy's ratepayers. Retail Agreement between Reliant Energy and Reliant Resources. Under a retail agreement, Reliant Resources will provide customer service call center operations, credit and collections and revenue reporting services for Reliant Energy's electric utility division and receiving and processing payments for the accounts of Reliant Energy's electric utility division and two of Reliant Energy's natural gas distribution divisions. Reliant Energy will provide the office space and equipment for Reliant Resources to perform these services. These services will terminate on January 1, 2002. The charges Reliant Energy will pay Reliant Resources for these services are generally intended to allow Reliant Resources to recover its fully allocated costs of providing the services, plus out-of-pocket costs and expenses. Service Agreements between Reliant Energy and Reliant Resources. Reliant Resources plans to enter into agreements with Reliant Energy under which Reliant Energy will provide Reliant Resources, on an interim basis, with various corporate support services (including accounting, finance, investor relations, planning, legal, communications, governmental and regulatory affairs and human resources), information technology services and other previously shared services such as corporate security, facilities management, accounts receivable, accounts payable and payroll, office support services and purchasing and logistics. These arrangements will continue after the Offering under a transition services agreement providing for their continuation until December 31, 2004, or, in the case of some corporate support services, until the 23 Distribution Date. The charges Reliant Resources will pay Reliant Energy for these services are generally intended to allow Reliant Energy to recover its fully allocated costs of providing the services, plus out-of-pocket costs and expenses. In each case, Reliant Resources will have the right to terminate categories of services at an earlier date. Pursuant to a lease agreement, Reliant Energy will lease Reliant Resources office space in its headquarters building in Houston, Texas for an interim period. Other Agreements. In connection with the separation of Reliant Resources' businesses from those of Reliant Energy, Reliant Resources will also enter into other agreements providing, among other things, for mutual indemnities and releases with respect to Reliant Resources' respective businesses and operations, matters relating to corporate governance, matters relating to responsibility for employee compensation and benefits, and allocation of tax liabilities. In addition, Reliant Resources and Reliant Energy will enter into various agreements relating to ongoing commercial arrangements, including among other things the leasing of optical fiber and related maintenance activities, rights to build fiber networks along existing rights of way, and the provision of local exchange telecommunications and data services in the greater Houston metropolitan area and long distance telecommunications services. Reliant Energy will agree that $1.9 billion of intercompany indebtedness owed by Reliant Resources and its subsidiaries prior to the closing of the Offering will be converted into equity as a capital contribution to Reliant Resources. (c) Transition Plan. In June 1998, the Texas Utility Commission issued an order in Docket No. 18465 approving the Company's Transition Plan filed by Reliant Energy HL&P in December 1997. The Transition Plan included base rate credits to residential customers of 4% in 1998 and an additional 2% in 1999. Commercial customers whose monthly billing is 1,000 kva or less were entitled to receive base rate credits of 2% in each of 1998 and 1999. The Company implemented the Transition Plan effective January 1, 1998. (d) Reliant Energy HL&P Filings. As of December 31, 2000, Reliant Energy HL&P had recorded as a regulatory asset under-recovered fuel cost of $558 million. In two separate filings in 2000, Reliant Energy HL&P filed and received approval to implement a fuel surcharge to collect the under recovery of fuel expenses, as well as to adjust the fuel factor to compensate for significant increases in the price of natural gas. On March 15, 2001, Reliant Energy HL&P filed to revise its fuel factor and address the Company's undercollected fuel costs of $389 million, which is the accumulated amount since September 2000 through February 2001 plus estimates for March and April, 2001. Reliant Energy HL&P is requesting to revise its fixed fuel factor to be implemented with the May 2001 billing cycle and has proposed to defer the collection of the $389 million until the 2004 stranded costs true-up proceeding, discussed in Note 4(a) above. o (5) DERIVATIVE FINANCIAL INSTRUMENTS (a) Price Risk Management and Trading Activities. The Company offers energy price risk management services primarily related to natural gas, electric power and other energy related commodities. The Company provides these services by utilizing a variety of derivative financial instruments, including (a) fixed and variable-priced physical forward contracts, (b) fixed and variable-priced swap agreements, (c) options traded in the over-the-counter financial markets and (d) exchange-traded energy futures and option contracts (Trading Derivatives). Fixed-price swap agreements require payments to, or receipts of payments from, counterparties based on the differential between a fixed and variable price for the commodity. Variable-price swap agreements require payments to, or receipts of payments from, counterparties based on the differential between industry pricing publications or exchange quotations. 24 The Company applies mark-to-market accounting for all of its energy trading, marketing and price risk management operations. Accordingly, these Trading Derivatives are recorded at fair value with realized and unrealized gains (losses) recorded as a component of revenues. The recognized, unrealized balances are included in price risk management assets/liabilities. The notional quantities, maximum terms and the estimated fair value of Trading Derivatives at December 31, 1999 and 2000 are presented below (volumes in billions of British thermal units equivalent (Bbtue) and dollars in millions):
VOLUME-FIXED VOLUME-FIXED MAXIMUM PRICE PAYOR PRICE RECEIVER TERM (YEARS) ------------ -------------- ------------ 1999 Natural gas.................................... 1,278,953 1,251,319 9 Electricity.................................... 242,868 239,452 10 Oil and other.................................. 285,251 286,521 3 2000 Natural gas.................................... 1,876,358 1,868,597 17 Electricity.................................... 526,556 523,942 6 Oil and other.................................. 52,820 42,380 2
FAIR VALUE AVERAGE FAIR VALUE(1) --------------------- --------------------- ASSETS LIABILITIES ASSETS LIABILITIES ------ ----------- ------ ----------- 1999 Natural gas.................................. $ 581 $ 564 $ 550 $ 534 Electricity.................................. 122 91 96 74 Oil and other................................ 193 206 183 187 ------ ------ ------ ------ $ 896 $ 861 $ 829 $ 795 ====== ====== ====== ====== 2000 Natural gas.................................. $4,059 $4,054 $2,058 $2,038 Electricity.................................. 1,115 1,087 601 561 Oil and other................................ 39 39 63 70 ------ ------ ------ ------ $5,213 $5,180 $2,722 $2,669 ====== ====== ====== ======
--------------- (1) Computed using the ending balance of each quarter. In addition to the fixed-price notional volumes above, the Company also has variable-priced agreements, as discussed above, totaling 2,147,173 Bbtue and 3,004,336 Bbtue as of December 31, 1999 and 2000, respectively. Notional amounts reflect the commodity volumes underlying the transactions but do not represent the amounts exchanged by the parties to the financial instruments. Accordingly, notional amounts do not accurately measure the Company's exposure to market or credit risks. All of the fair values shown in the table above at December 31, 1999 and 2000, have been recognized in income. The Company estimated the fair value as of December 31, 1999 and 2000, using quoted prices where available and other valuation techniques when market data was not available, for example in illiquid markets. For financial instruments for which quoted prices are not available, the Company utilizes alternative pricing methodologies, including, but not limited to, extrapolation of forward pricing curves using historically reported data from illiquid pricing points. These same pricing techniques are used to evaluate a contract prior to taking the position. The prices and fair values are subject to significant changes based on changing market conditions. The weighted-average term of the trading portfolio, based on volumes, is less than one year. The maximum and average terms disclosed herein are not indicative of likely future cash flows, as these positions may be changed by new transactions in the trading portfolio at any time in response to changing market 25 conditions, market liquidity and the Company's risk management portfolio needs and strategies. Terms regarding cash settlements of these contracts vary with respect to the actual timing of cash receipts and payments. In addition to the risk associated with price movements, credit risk is also inherent in the Company's risk management activities. Credit risk relates to the risk of loss resulting from non-performance of contractual obligations by a counterparty. The following table shows the composition of the total price risk management assets of the Company as of December 31, 1999 and 2000.
DECEMBER 31, 1999 DECEMBER 31, 2000 ------------------ ------------------- INVESTMENT INVESTMENT GRADE(1) TOTAL GRADE(1) TOTAL ---------- ----- ---------- ------ (IN MILLIONS) Energy marketers................................ $202 $230 $2,507 $2,709 Financial institutions.......................... 90 159 1,159 1,296 Gas and electric utilities...................... 220 221 511 586 Oil and gas producers........................... 31 31 500 599 Industrials..................................... 3 4 78 89 Others.......................................... 174 263 -- -- ---- ---- ------ ------ Total................................. $720 908 $4,755 5,279 ==== ====== Credit and other reserves....................... (12) (66) ---- ------ Energy price risk management assets(2).......... $896 $5,213 ==== ======
--------------- (1) "Investment Grade" is primarily determined using publicly available credit ratings along with the consideration of credit support (such as parent company guarantees) and collateral, which encompass cash and standby letters of credit. (2) As of December 31, 2000, the Company had credit risk exposure to three investment-grade counterparties that each represented greater than 5% of price risk management assets. This information excludes some offsetting contracts that either require or permit net settlement with non-trading transactions not included in price risk management assets. The Company's resulting net credit risk exposure to these three counterparties is below 5% of price risk management assets. (b) Non-Trading Activities. To reduce the risk from market fluctuations in the revenues derived from the sale of electric power and natural gas and related transportation, the Company enters into futures transactions, forward contracts, swaps and options (Energy Derivatives) in order to hedge some expected purchases of electric power and natural gas and sales of electric power and natural gas (a portion of which are firm commitments at the inception of the hedge). Energy Derivatives are also utilized to fix the price of compressor fuel or other future operational gas requirements and to protect natural gas distribution earnings against unseasonably warm weather during peak gas heating months, although usage to date for this purpose has not been material. The Company applies hedge accounting for its derivative financial instruments utilized in non-trading activities. Unrealized changes in the market value of Energy Derivatives utilized as hedges are not generally recognized in the Company's Statements of Consolidated Operations until the underlying hedged transaction occurs. Once it becomes probable that an anticipated transaction will not occur, the Company recognizes deferred gains and losses. In general, the financial impact of transactions involving these Energy Derivatives is included in the Company's Statements of Consolidated Operations under the captions (a) fuel expenses, in the case of natural gas transactions, (b) purchased power, in the case of electric power purchase transactions, and (c) revenues, in the case of electric power sales transactions. Cash flows resulting from these transactions in Energy Derivatives are included in the Company's Statements of Consolidated Cash Flows in the same category as the item being hedged. 26 In connection with the Company's acquisition of UNA in 1999, the Company entered into call option agreements with several banks to hedge the impact of foreign exchange movements on the Dutch guilder. These call options provided the right, but not the obligation, to purchase NLG 695 million from specific banks at specific strike prices. The total premium paid, classified as other expense on the Company's Statement of Consolidated Operations, for all of the options that were to expire on October 26, 1999, was $8 million. On October 12, 1999, the Company sold the remaining value in the call options for $0.6 million. The proceeds were reflected in the Company's results of operations as a reduction of other expense. As of December 31, 1999 and 2000, the Company had outstanding foreign currency swaps for 258 million and Euros 671 million, respectively (approximately $228 million and $632 million), terminating in September 2000 and January 2001, respectively. The Company also issued Euro-denominated debt, maturing in March and June 2001. The foreign currency swaps and Euro-denominated debt hedge the Company's net investment in UNA. In January 2001, the Company entered into foreign currency swaps for Euros 671 million (approximately $633 million) to replace the foreign currency swaps that expired in January 2001. These foreign currency swaps terminate in January 2002. In January and March 2001, the Company entered into foreign currency forward contracts for Euros 159 million (approximately $150 million) to adjust the hedge of its net investment in UNA. These forward contracts expire in January 2002. The Company records changes in the value of the hedging instruments and debt as foreign currency translation adjustments as a component of stockholders' equity and accumulated other comprehensive loss. The effectiveness of the hedging instruments can be measured by the net change in foreign currency translation adjustments attributed to the net investment in UNA. These amounts generally offset amounts recorded in stockholders' equity as adjustments resulting from translation of the hedged investment into U.S. dollars. As of December 31, 1999 and 2000, the net carrying value of the currency swaps was a $6 million receivable and $62 million obligation, respectively, and was recorded in other current assets and other current liabilities in the Company's Consolidated Balance Sheets. During 2000, European Energy entered into financial instruments to purchase approximately $120 million to hedge future fuel purchases payable in U.S. dollars. As of December 31, 2000, the fair value of these financial instruments was a $6 million liability. Unrealized changes in the market value of these financial instruments are not recognized in the Company's Statements of Consolidated Operations until the underlying hedged transaction occurs. For transactions involving either Energy Derivatives or foreign currency derivatives, hedge accounting is applied only if the derivative reduces the risk of the underlying hedged item and is designated as a hedge at its inception. Additionally, the derivatives must be expected to result in financial impacts that are inversely correlated to those of the item(s) to be hedged. This correlation, a measure of hedge effectiveness, is measured both at the inception of the hedge and on an ongoing basis, with an acceptable level of correlation of at least 80% for hedge designation. If and when correlation ceases to exist at an acceptable level, hedge accounting ceases and mark-to-market accounting is applied. At December 31, 1999, the Company was a fixed-price payor and a fixed-price receiver in Energy Derivatives covering 33,108 Bbtu and 5,481 Bbtu of natural gas, respectively. At December 31, 2000, the Company was a fixed-price payor and a fixed-price receiver in Energy Derivatives covering 198,001 Bbtu and 22,874 Bbtu of natural gas, respectively, and 486 Bbtu and zero Bbtu of oil, respectively. In addition to the fixed-price notional volumes above, the Company also has variable-priced agreements totaling 44,958 Bbtu and 174,900 Bbtu of natural gas at December 31, 1999 and 2000, respectively. The weighted average maturity of these instruments is less than two years. The notional amount is intended to be indicative of the Company's level of activity in these derivatives. However, the amounts at risk are significantly smaller because, in view of the price movement correlation required for hedge accounting, changes in the market value of these derivatives generally are offset by changes in the value associated with the underlying physical transactions or in other derivatives. When Energy Derivatives are closed out in advance of the underlying commitment or anticipated transaction, however, the market value changes may not offset due to the fact that price movement correlation ceases to exist when the 27 positions are closed, as further discussed above. Under these circumstances, gains (losses) are deferred and recognized as a component of income when the underlying hedged item is recognized in income. The average maturity discussed above and the fair value discussed in Note 15 are not necessarily indicative of likely future cash flows as these positions may be changed by new transactions in the trading portfolio at any time in response to changing market conditions, market liquidity and the Company's risk management portfolio needs and strategies. Terms regarding cash settlements of these contracts vary with respect to the actual timing of cash receipts and payments. (c) Trading and Non-trading -- General Policy. In addition to the risk associated with price movements, credit risk is also inherent in the Company's risk management activities. Credit risk relates to the risk of loss resulting from non-performance of contractual obligations by a counterparty. The Company has off-balance sheet risk to the extent that the counterparties to these transactions may fail to perform as required by the terms of each contract. In order to minimize this risk, the Company enters into these contracts primarily with counterparties having a minimum investment grade index rating, i.e. a Standard & Poor's or Moody's rating of BBB- or Baa3, respectively. For long-term arrangements, the Company periodically reviews the financial condition of these firms in addition to monitoring the effectiveness of these financial contracts in achieving the Company's objectives. If the counterparties to these arrangements fail to perform, the Company would seek to compel performance at law or otherwise obtain compensatory damages. The Company might be forced to acquire alternative hedging arrangements or be required to replace the underlying commitment at then-current market prices. In this event, the Company might incur additional losses to the extent of amounts, if any, already paid to the counterparties. For information regarding credit risk related to the California wholesale electricity market, see Note 14(h). The Company's policies prohibit the use of leveraged financial instruments. A leveraged financial instrument, for this purpose, is a transaction involving a derivative whose financial impact will be based on an amount other than the notional amount or volume of the instrument. The Company has established a Risk Oversight Committee, comprised of corporate and business segment officers that oversees all commodity price and credit risk activities, including the Company's trading, marketing, power origination and risk management activities. The committee's duties are to establish the Company's commodity risk policies, allocate risk capital within limits established by the Company's Board of Directors, approve trading of new products and commodities, monitor risk positions and ensure compliance with the Company's risk management policies and procedures and trading limits established by the Company's Board of Directors. o (8) INDEXED DEBT SECURITIES (ACES AND ZENS) AND AOL TIME WARNER SECURITIES (a) Original Investment in Time Warner Securities. On July 6, 1999, the Company converted its 11 million shares of Time Warner Inc. (TW) convertible preferred stock (TW Preferred) into 45.8 million shares of Time Warner common stock (TW Common). Prior to the conversion, the Company's investment in the TW Preferred was accounted for under the cost method at a value of $990 million in the Company's Consolidated Balance Sheets. The TW Preferred was redeemable after July 6, 2000, had an aggregate liquidation preference of $100 per share (plus accrued and unpaid dividends), was entitled to annual dividends of $3.75 per share until July 6, 1999 and was convertible by the Company. The Company recorded pre-tax dividend income with respect to the TW Preferred of $21 million in 1999 prior to the conversion and $41 million in 1998. Effective on the conversion date, the shares of TW Common were classified as trading securities under SFAS No. 115 and an unrealized gain was recorded in the amount of $2.4 billion ($1.5 billion after-tax) to reflect the cumulative appreciation in the fair value of the Company's investment in Time Warner securities. 28 (b) ACES. In July 1997, in order to monetize a portion of the cash value of its investment in TW Preferred, the Company issued 22.9 million of its unsecured 7% Automatic Common Exchange Securities (ACES) having an original principal amount of $1.052 billion and maturing July 1, 2000. The market value of ACES was indexed to the market value of TW Common. On the July 1, 2000 maturity date, the Company tendered 37.9 million shares of TW Common to fully settle its obligations in connection with its unsecured 7% ACES having a value of $2.9 billion. (c) ZENS. On September 21, 1999, the Company issued approximately 17.2 million of its 2.0% Zero-Premium Exchangeable Subordinated Notes due 2029 (ZENS) having an original principal amount of $1.0 billion. The original principal amount per ZENS will increase each quarter to the extent that the sum of the quarterly cash dividends and the interest paid during a quarter on the reference shares attributable to one ZENS is less than $.045, so that the annual yield to investors from the date the Company issued the ZENS to the date of computation of the contingent principal amount is not less than 2.309%. At maturity the holders of the ZENS will receive in cash the higher of the original principal amount of the ZENS (subject to adjustment as discussed above) or an amount based on the then-current market value of TW Common, or other securities distributed with respect to TW Common (one share of TW Common and such other securities, if any, are referred to as reference shares). Each ZENS has an original principal amount of $58.25 (the closing market price of the TW Common on September 15, 1999) and is exchangeable at any time at the option of the holder for cash equal to 95% (100% in some cases) of the market value of the reference shares attributable to one ZENS. The Company pays interest on each ZENS at an annual rate of 2% plus the amount of any quarterly cash dividends paid in respect of the quarterly interest period on the reference shares attributable to each ZENS. Subject to some conditions, the Company has the right to defer interest payments from time to time on the ZENS for up to 20 consecutive quarterly periods. As of December 31, 2000, no interest payments on the ZENS had been deferred. On January 11, 2001, TW and America Online, Inc. combined to form AOL Time Warner Inc. (AOL TW). As a result of the combination each share of TW Common was converted into 1.5 shares of AOL TW Common Stock (AOL TW Common) and the Company now holds 25.8 million shares of AOL TW Common. As a result of the combination, the reference shares attributable to one ZENS is 1.5 shares of AOL TW Common. The Company used $537 million of the net proceeds from the offering of the ZENS to purchase 9.2 million shares of TW Common, which are classified as trading securities under SFAS No. 115. Unrealized gains and losses resulting from changes in the market value of the TW Common are recorded in the Company's Statements of Consolidated Operations. Prior to January 1, 2001, an increase above $58.25 (subject to some adjustments) in the market value per share of TW Common resulted in an increase in the Company's liability for the ZENS. However, as the market value per share of TW Common declined below $58.25 (subject to some adjustments), the liability for the ZENS did not decline below the original principal amount. As of December 31, 1999 and 2000, the market value of TW Common was $72.31 and $52.24, respectively. Therefore, during 2000, the Company recorded a pre-tax net unrealized loss on its investment in TW Common and its obligation on its indexed debt securities of $103 million. Prior to the purchase of additional shares of TW Common on September 21, 1999, the Company owned approximately 8 million shares of TW Common that were in excess of the 38 million shares needed to economically hedge its ACES obligation. For the period from July 6, 1999 to the ZENS issuance date, losses (due to the decline in the market value of the TW Common during such period) on these 8 million shares were $122 million ($79 million after-tax). The 8 million shares of TW Common combined with the additional 9.2 million shares purchased are expected to be held to facilitate the Company's ability to meet its obligation under the ZENS. 29 The following table sets forth summarized financial information regarding the Company's investment in TW securities and the Company's ACES and ZENS obligations.
TW INVESTMENT ACES ZENS ------------- ------- ------ (IN MILLIONS) Balance at December 31, 1997......................... $ 990 $ 1,174 Loss on indexed debt securities...................... -- 1,176 ------- ------- Balance at December 31, 1998......................... 990 2,350 Issuance of indexed debt securities.................. -- -- $1,000 Purchase of TW Common................................ 537 -- -- Loss on indexed debt securities...................... -- 388 241 Gain on TW Common.................................... 2,452 -- -- ------- ------- ------ Balance at December 31, 1999......................... 3,979 2,738 1,241 ------- ------- ------ Loss (Gain) on indexed debt securities............... -- 139 (241) Loss on TW Common.................................... (205) -- -- Settlement of ACES................................... (2,877) (2,877) -- ------- ------- ------ Balance at December 31, 2000......................... $ 897 $ -- $1,000 ======= ======= ======
Upon adoption of SFAS No. 133 effective January 1, 2001, the ZENS obligation is bifurcated into a debt component and a derivative component (the holder's option to receive the appreciated value of AOL TW Common at maturity). The derivative component is valued at fair value and determines the initial carrying value assigned to the debt component ($121 million) as the difference between the original principal amount of the ZENS ($1.0 billion) and the fair value of the derivative component at issuance ($879 million). Effective January 1, 2001 the debt component is recorded at its accreted amount of $122 million and the derivative component is recorded at its current fair value of $788 million, as a current liability, resulting in a transition adjustment pre-tax gain of $90 million. The transition adjustment gain will be reported in the first quarter of 2001 as the effect of a change in accounting principle. Subsequently, the debt component will accrete through interest charges at 17.5% up to the minimum amount payable upon maturity of the ZENS in 2029, approximately $1.1 billion, and changes in the fair value of the derivative component will be recorded in the Company's Statements of Consolidated Operations. Changes in the fair value of the AOL TW Common held by the Company should substantially offset changes in the fair values of the derivative component of the ZENS. o (14) COMMITMENTS AND CONTINGENCIES (a) Capital and Environmental Commitments. The Company has various commitments for capital and environmental expenditures. The Wholesale Energy segment has entered into commitments associated with various non-rate regulated electric generating projects, including commitments for the purchase of combustion turbines aggregating $436 million. In addition, the Wholesale Energy segment has options to purchase additional generating equipment for a total estimated cost of $544 million for future generating projects. The Company anticipates investing up to $711 million in capital and other special project expenditures between 2001 and 2005 for environmental compliance. The Company anticipates expenditures to be as follows (in millions): 2001........................................................ $217 2002........................................................ 259 2003........................................................ 80 2004........................................................ 76 2005........................................................ 79 ---- Total............................................. $711 ====
30 (b) Fuel and Purchased Power. Reliant Energy HL&P is a party to several long-term coal, lignite and natural gas contracts, which have various quantity requirements and durations. Minimum payment obligations for coal and transportation agreements that extend through 2011 are approximately $280 million in 2001, $281 million in 2002 and $274 million in 2003. Purchase commitments related to lignite mining and lease agreements, natural gas purchases and storage contracts, and purchased power are not material to the operations of the Company. Currently, Reliant Energy HL&P is allowed recovery of these costs through base rates for electric service. As of December 31, 2000, some of these contracts are above market. The Company anticipates that stranded costs associated with these obligations will be recoverable through the stranded costs recovery mechanisms contained in the Legislation. For information regarding the Legislation, see Note 4(a). REMA is a party to several long-term fuel supply contracts which have various quantity requirements and durations. Minimum payment obligations under these agreements that extend through 2004 are as follows as of December 31, 2000 (in millions): 2001........................................................ $ 85 2002........................................................ 66 2003........................................................ 29 2004........................................................ 14 ---- Total............................................. $194 ====
The Company's other long-term fuel supply commitments which have various quantity requirements and durations are not considered material either individually or in the aggregate to the Company's results of operations or cash flows. (c) Lease Commitments. In August 2000, the Company entered into separate sale/leaseback transactions with each of three owner-lessors for the Company's respective 16.45%, 16.67% and 100% interests in the Conemaugh, Keystone and Shawville generating stations, respectively, acquired in the REMA acquisition. As lessee, the Company leases an interest in each facility from each owner-lessor under a facility lease agreement. The equity interests in all the subsidiaries of REMA are pledged as collateral for REMA's lease obligations. In addition, the subsidiaries have guaranteed the lease obligations. The lease documents contain some restrictive covenants that restrict REMA's ability to, among other things, make dividend distributions unless REMA satisfies various conditions. The covenant restricting dividends would be suspended if the direct or indirect parent of REMA, meeting specified criteria, guarantees the lease obligations. The Company will make lease payments through 2029. The lease terms expire in 2034. The following table sets forth information concerning the Company's obligations under non-cancelable long-term operating leases at December 31, 2000, which primarily relate to the REMA leases mentioned above. Other non-cancelable long-term operating leases principally consist of rental agreements for building space, data processing equipment and vehicles, including major work equipment.
REMA SALE-LEASE OBLIGATION OTHER TOTAL ---------- ----- ------ (IN MILLIONS) 2001....................................................... $ 259 $ 16 $ 275 2002....................................................... 137 10 147 2003....................................................... 77 8 85 2004....................................................... 84 6 90 2005....................................................... 75 6 81 2006 and beyond............................................ 1,188 36 1,224 ------ ---- ------ Total............................................ $1,820 $ 82 $1,902 ====== ==== ======
31 Total lease expense for all operating leases was $10 million, $13 million and $46 million during 1998, 1999 and 2000, respectively. (d) Cross Border Leases. During the period from 1994 through 1997, under cross border lease transactions, UNA leased several of its power plants and related equipment and turbines to non-Netherlands based investors (the head leases) and concurrently leased the facilities back under sublease arrangements with remaining terms as of December 31, 2000, of 1 to 24 years. UNA utilized proceeds from the head lease transactions to prepay its sublease obligations and to provide a source for payment of end of term purchase options and other financial undertakings. The initial sublease obligations totaled $2.4 billion of which $1.7 billion remained outstanding as of December 31, 2000. These transactions involve UNA providing to a foreign investor an ownership right in (but not necessarily title to) an asset, with a leaseback of that asset. The net proceeds to UNA of the transactions were recorded as a deferred gain and are currently being amortized to income over the lease terms. At December 31, 1999 and 2000, the unamortized deferred gain on these transactions totaled $87 million and $77 million, respectively. The power plants, related equipment and turbines remain on the financial statements of UNA and continue to be depreciated. UNA is required to maintain minimum insurance coverages, perform minimum annual maintenance and, in specified situations, post letters of credit. UNA's shareholder is subject to some restrictions with respect to the liquidation of UNA's shares. In the case of early termination of these contracts, UNA would be contingently liable for some payments to the sublessors, which at December 31, 2000, are estimated to be $274 million. Starting in March 2000, UNA was required by some of the lease agreements to obtain standby letters of credit in favor of the sublessors in the event of early termination. The amount of the required letters of credit was $274 million as of December 31, 2000. Commitments for these letters of credit have been obtained as of December 31, 2000. (e) Naming Rights to Houston Sports Complex. In October 2000, the Company acquired the naming rights for the new football stadium for the Houston Texans, the National Football League's newest franchise. In addition, the naming rights cover the entertainment and convention facilities included in the stadium complex. The agreement extends for 32 years. In addition to naming rights, the agreement provides the Company with significant sponsorship rights. The aggregate cost of the naming rights will be approximately $300 million. During the fourth quarter of 2000, the Company incurred an obligation to pay $12 million in order to secure the long-term commitment and for the initial advertising of which $10 million was expensed in the Company's Statement of Consolidated Operations in 2000. Starting in 2002, when the new stadium is operational, the Company will pay $10 million each year through 2032 for annual advertising under this agreement. (f) Transportation Agreement. A subsidiary of RERC Corp. had an agreement (ANR Agreement) with ANR Pipeline Company (ANR) that contemplated that this subsidiary would transfer to ANR an interest in some of RERC Corp.'s pipeline and related assets. As of December 31, 1999 and 2000, the Company had recorded $41 million in other long-term liabilities in the Company's Consolidated Balance Sheets to reflect the Company's obligation to ANR for the use of 130 Mmcf/day of capacity in some of the Company's transportation facilities. The level of transportation will decline to 100 Mmcf/day in the year 2003 with a refund of $5 million to ANR. The ANR Agreement will terminate in 2005 with a refund of $36 million. (g) Legal, Environmental and Other Regulatory Matters. LEGAL MATTERS. Reliant Energy HL&P Municipal Franchise Fee Lawsuits. In February 1996, the cities of Wharton, Galveston and Pasadena filed suit, for themselves and a proposed class of all similarly situated cities in Reliant Energy HL&P's service area, against Reliant Energy and Houston Industries Finance, Inc. (formerly a wholly 32 owned subsidiary of Reliant Energy) alleging underpayment of municipal franchise fees. Plaintiffs claim that they are entitled to 4% of all receipts of any kind for business conducted within these cities over the previous four decades. Because the franchise ordinances at issue affecting Reliant Energy HL&P expressly impose fees only on its own receipts and only from sales of electricity for consumption within a city, the Company regards all of plaintiffs' allegations as spurious and is vigorously contesting the case. The plaintiffs' pleadings asserted that their damages exceeded $250 million. The 269th Judicial District Court for Harris County granted partial summary judgment in favor of Reliant Energy dismissing all claims for franchise fees based on sales tax collections. Other motions for partial summary judgment were denied. A six-week jury trial of the original claimant cities (but not the class of cities) ended on April 4, 2000 (three cities case). Although the jury found for Reliant Energy on many issues, they found in favor of the original claimant cities on three issues, and assessed a total of $4 million in actual and $30 million in punitive damages. However, the jury also found in favor of Reliant Energy on the affirmative defense of laches, a defense similar to a statute of limitations defense, due to the original claimant cities having unreasonably delayed bringing their claims during the 43 years since the alleged wrongs began. The trial court in the three cities case granted most of Reliant Energy's motions to disregard the jury's findings. The trial court's rulings reduced the judgment to $1.7 million, including interest, plus an award of $13.7 million in legal fees. In addition, the trial court granted Reliant Energy's motion to decertify the class and vacated its prior orders certifying a class. Following this ruling, 45 cities filed individual suits against Reliant Energy in the District Court of Harris County. The extent to which issues in the three cities case may affect the claims of the other cities served by Reliant Energy HL&P cannot be assessed until judgments are final and no longer subject to appeal. However, the trial court's rulings disregarding most of the jury's findings are consistent with Texas Supreme Court opinions over the past decade. The Company estimates the range of possible outcomes for the plaintiffs to be between zero and $17 million inclusive of interest and attorneys' fees. The three cities case has been appealed. The Company believes that the $1.7 million damage award resulted from serious errors of law and that it will be set aside by the Texas appellate courts. In addition, the Company believes that because of an agreement between the parties limiting fees to a percentage of the damages, reversal of the award of $13.7 million in attorneys' fees in the three cities case is probable. California Wholesale Market. Reliant Energy and Reliant Energy Services, Inc. have been named as defendants in class action lawsuits and other lawsuits filed against a number of companies that own generation plants in California and other sellers of electricity in California markets. RERC Corp. has also been named as a defendant on one of the lawsuits. Pursuant to the terms of the master separation agreement between Reliant Energy and Reliant Resources (see Note 4(b)), Reliant Resources will agree to indemnify RERC Corp. for any damages arising under this lawsuit, and will agree to indemnify Reliant Energy for damages arising under any of these lawsuits, and may elect to defend these lawsuits at Reliant Resources' own expense. Three of these lawsuits were filed in the Superior Court of the State of California, San Diego County; two were filed in the Superior Court in San Francisco County. While the plaintiffs allege various violations by the defendants of state antitrust laws and state laws against unfair and unlawful business practices, each of the lawsuits is grounded on the central allegation that defendants conspired to drive up the wholesale price of electricity. In addition to injunctive relief, the plaintiffs in these lawsuits seek treble the amount of damages alleged, restitution of alleged overpayments, disgorgement of alleged unlawful profits for sales of electricity during all or portions of 2000, costs of suit and attorneys' fees. In one of the cases the plaintiffs allege aggregate damages of over $4 billion. Defendants have filed petitions to remove the cases to federal court. Furthermore, defendants have filed a motion with the Panel on Multidistrict Litigation seeking transfer and consolidation of all the cases. These lawsuits have only recently been filed. Therefore, the ultimate outcome of the lawsuits cannot be predicted with any degree of certainty at this time. However, the Company does not believe, based on its analysis to date of the claims asserted in these lawsuits and the underlying facts, that resolution of these lawsuits will have a material adverse effect on the Company's financial condition, results of operations or cash flows. 33 ENVIRONMENTAL MATTERS. Manufactured Gas Plant Sites. RERC Corp. and its subsidiaries (RERC) and its predecessors operated a manufactured gas plant (MGP) adjacent to the Mississippi River in Minnesota, formerly known as Minneapolis Gas Works (MGW) until 1960. RERC has substantially completed remediation of the main site other than ongoing water monitoring and treatment. The manufactured gas was stored in separate holders. RERC is negotiating clean-up of one such holder. There are six other former MGP sites in the Minnesota service territory. Remediation has been completed on one site. Of the remaining five sites, RERC believes that two were neither owned nor operated by RERC. RERC believes it has no liability with respect to the sites it neither owned nor operated. At December 31, 1999 and 2000, RERC had accrued $19 million and $17 million, respectively, for remediation of the Minnesota sites. At December 31, 2000, the estimated range of possible remediation costs was $8 million to $36 million. The cost estimates of the MGW site are based on studies of that site. The remediation costs for the other sites are based on industry average costs for remediation of sites of similar size. The actual remediation costs will be dependent upon the number of sites remediated, the participation of other potentially responsible parties, if any, and the remediation methods used. Other Minnesota Matters. At December 31, 1999 and 2000, RERC had recorded accruals of $1 million and $2 million, respectively (with a maximum estimated exposure of approximately $13 million and $17 million at December 31, 1999 and 2000, respectively), for other environmental matters in Minnesota for which remediation may be required. Issues relating to the identification and remediation of MGPs are common in the natural gas distribution industry. The Company has received notices from the United States Environmental Protection Agency and others regarding its status as a potentially responsible party (PRP) for other sites. Based on current information, the Company has not been able to quantify a range of environmental expenditures for potential remediation expenditures with respect to other MGP sites. Mercury Contamination. The Company's pipeline and distribution operations have in the past employed elemental mercury in measuring and regulating equipment. It is possible that small amounts of mercury may have been spilled in the course of normal maintenance and replacement operations and that these spills may have contaminated the immediate area with elemental mercury. This type of contamination has been found by the Company at some sites in the past, and the Company has conducted remediation at sites found to be contaminated. Although the Company is not aware of additional specific sites, it is possible that other contaminated sites may exist and that remediation costs may be incurred for these sites. Although the total amount of these costs cannot be known at this time, based on experience by the Company and that of others in the natural gas industry to date and on the current regulations regarding remediation of these sites, the Company believes that the costs of any remediation of these sites will not be material to the Company's financial position, results of operations or cash flows. REMA Ash Disposal Site Closures and Site Contaminations. Under the agreement to acquire REMA (see Note 3(a)), the Company became responsible for liabilities associated with ash disposal site closures and site contamination at the acquired facilities in Pennsylvania and New Jersey prior to a plant closing, except for the first $6 million of remediation costs at the Seward Generating Station. A prior owner retained liabilities associated with the disposal of hazardous substances to off-site locations prior to November 24, 1999. As of December 31, 2000, REMA has liabilities associated with six ash disposal site closures and six site investigations and environmental remediations. The Company has recorded its estimate of these environmental liabilities in the amount of $36 million as of December 31, 2000. The Company expects approximately $13 million will be paid over the next five years. UNA Asbestos Abatement and Soil Remediation. Prior to the Company's acquisition of UNA (see Note 3(b)), UNA had a $25 million obligation primarily related to asbestos abatement, as required by Dutch law, and soil remediation at six sites. During 2000, the Company initiated a review of potential environmental matters associated with UNA's properties. UNA began remediation in 2000 of the properties identified to have exposed asbestos and soil contamination, as required by Dutch law and the terms of some leasehold 34 agreements with municipalities in which the contaminated properties are located. All remediation efforts are to be fully completed by 2005. As of December 31, 2000, the estimated undiscounted liability for this asbestos abatement and soil remediation was $24 million. Other. From time to time the Company has received notices from regulatory authorities or others regarding its status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. In addition, the Company has been named as a defendant in litigation related to such sites and in recent years has been named, along with numerous others, as a defendant in several lawsuits filed by a large number of individuals who claim injury due to exposure to asbestos while working at sites along the Texas Gulf Coast. Most of these claimants have been workers who participated in construction of various industrial facilities, including power plants, and some of the claimants have worked at locations owned by the Company. The Company anticipates that additional claims like those received may be asserted in the future and intends to continue vigorously contesting claims which it does not consider to have merit. Although their ultimate outcome cannot be predicted at this time, the Company does not believe, based on its experience to date, that these matters, either individually or in the aggregate, will have a material adverse effect on the Company's financial position, results of operations or cash flows. OTHER MATTERS. The Company is involved in other legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. Some of these proceedings involve substantial amounts. The Company's management regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. The Company's management believes that the disposition of these matters will not have a material adverse effect on the Company's financial condition, results of operations or cash flows. (h) California Wholesale Market Uncertainty. During the summer and fall of 2000, prices for wholesale electricity in California increased dramatically as a result of a combination of factors, including higher natural gas prices and emission allowance costs, reduction in available hydroelectric generation resources, increased demand, decreases in net electric imports, structural market flaws including over-reliance on the electric spot market, and limitations on supply as a result of maintenance and other outages. Although wholesale prices increased, California's deregulation legislation kept retail rates frozen below 1996 levels. This caused two of California's public utilities, which are the Company's customers based on its deliveries to the Cal PX and the Cal ISO, to amass billions of dollars of uncollected wholesale power costs and to ultimately default in January and February 2001 on payments owed for wholesale power purchased through the Cal PX and from the Cal ISO. As of December 31, 2000, the Company was owed $101 million by the Cal PX and $181 million by the Cal ISO. In the fourth quarter of 2000, the Company recorded a pre-tax provision of $39 million against receivable balances related to energy sales in the California market. From January 1, 2001 through February 28, 2001, the Company has collected $105 million of these receivable balances. As of March 1, 2001, the Company was owed a total of $358 million by the Cal ISO, the Cal PX, the California Department of Water Resources (CDWR) and California Energy Resource Scheduling, for energy sales in the California wholesale market from the fourth quarter of 2000 through February 28, 2001. Management will continue to assess the collectibility of these receivables based on further developments affecting the California electricity market and the market participants described herein. Additional provisions to the allowance may be warranted in the future. In response to the filing of a number of complaints challenging the level of wholesale prices, the FERC initiated a staff investigation and issued an order on December 15, 2000 implementing a series of wholesale market reforms, including an interim price review procedure for prices above a $150/MWh "breakpoint" on sales to the Cal ISO and through the Cal PX. The order does not prohibit sales above the "breakpoint," but the seller is subject to weekly reporting and monitoring requirements. For each reported transaction, potential refund liability extends for a period of 60 days following the date any such transaction is reported to the FERC. On March 9, 2001, the FERC issued a further order establishing a proxy market 35 clearing price of $273/MWh for January 2001, and on March 16, 2001 the FERC issued a further order adjusting the proxy market clearing price to $430/MWh for February 2001. New market monitoring and mitigation measures to replace the $150/MWh breakpoint and reporting obligation are being developed by the FERC to take effect on May 1, 2001. In the FERC's March 9 and March 16 orders, the FERC outlined criteria for determining amounts subject to possible refund based on the proxy market clearing price for January and February 2001 and indicated that approximately $12 million of the $125 million charged by the Company in January 2001 in California to the Cal ISO and the Cal PX and approximately $7 million of the $47 million charged by the Company in February 2001 in California to the Cal ISO and the Cal PX were subject to possible refunds. In the March 9 and March 16 orders, the FERC set forth procedures for challenging possible refund obligations. Because the Company believes that there is cost or other justification for prices charged above the proxy market clearing prices established in the March 9 and March 16 orders, the Company intends to pursue such a challenge with respect to the Company's potential refund amounts identified in such orders. Any refunds the Company may ultimately be obligated to pay are to be credited against unpaid amounts owed to the Company for its sales in the Cal PX or to the Cal ISO. The December 15 order established that a refund condition would be in place for the period beginning October 2, 2000 through December 31, 2002. The December 15 order also eliminated the requirement that California's public utilities sell all of their generation into and purchase all of their power from the Cal PX and directed that the Cal PX wholesale tariffs be terminated effective April 2001. The Cal PX has since suspended its day-ahead and day-of markets and filed for bankruptcy protection on March 9, 2001. Motions for rehearing have been filed on a number of issues related to the December 15 order and such motions are still pending before the FERC. In addition to the FERC investigation discussed above, several state and other federal regulatory investigations and complaints have commenced in connection with the wholesale electricity prices in California and other neighboring Western states to determine the causes of the high prices and potentially to recommend remedial action. In California, the California Public Utilities Commission, the California Electricity Oversight Board, the California Bureau of State Audits and the California Office of the Attorney General all have separate ongoing investigations into the high prices and their causes. None of these investigations have been completed and no findings have been made in connection with any of them. Despite the market restructuring ordered under the December 15 order, the California public utilities have continued to accrue unrecovered wholesale costs. As a result, the credit ratings of two of these public utilities were severely downgraded to below investment grade in January 2001. As their credit lines became unavailable, the two utilities defaulted on payments due to the Cal PX and the Cal ISO, which operate financially as pass-through entities, coordinating payments from buyers and sellers of electricity. As a result, the Cal PX and Cal ISO were not able to pay final invoices to market participants totaling over $1 billion. The default of two of California's public utilities on amounts owed the Cal PX and the Cal ISO for purchased power has further exacerbated the current crisis in the California wholesale markets and resulted in substantial uncollected receivables owed to the Company by the Cal ISO and the Cal PX. The Cal PX's efforts to recover the available collateral of the utilities, in the form of block forward contracts, have been frustrated by the emergency acts of California's Governor, who seized control of the contracts upon the expiration of temporary restraining orders prohibiting such action. Although obligated to pay reasonable value for the contracts, the state of California has not yet made any payment for the contracts. Various actions have been filed challenging the Governor's ability to seize these contracts. Upon the default of the two utilities of amounts due to the Cal PX, the Cal PX issued "charge-backs" allocating the utilities' defaults to the other market participants. Proceedings were brought both in federal court and at the FERC seeking a suspension of the charge-backs and challenging the reasonableness of the Cal PX's actions. The Cal PX has since agreed to a preliminary injunction suspending any of its charge-back activities in order to allow the FERC to address the charge-back issues. Amounts owed to the Company were debited in invoices by the Cal PX for charge-backs in the amount of $29 million and, on February 14, 2001, the Company filed its own lawsuit against the Cal PX in the United States District Court for the Central District of California, seeking a recovery of those amounts and a stay of any further charge-backs by the Cal 36 PX. The filing of bankruptcy by the Cal PX will automatically stay for some period the various court and administrative cases against the Cal PX. The two defaulting utilities have both filed lawsuits challenging the refusal of state regulators to allow wholesale power costs to be passed through to retail customers under the "filed rate doctrine". The filed rate doctrine provides that wholesale power costs approved by the FERC are entitled to be recovered through rates. Additionally, to address the failing financial condition of the two defaulting utilities and the utilities' potential bankruptcy, the California Legislature passed emergency legislation, effective January 18, 2001 and February 2, 2001, appropriating funds to be used by the CDWR for the purchase of wholesale electricity on behalf of the utilities and authorizing the sale of bonds to fund future purchases under long-term power contracts with wholesale generators. The CDWR began the process of soliciting bids from generators for long-term contracts and continued the purchasing of short-term power contracts. No bonds have yet been issued by the CDWR to support long-term power purchases or to provide credit support for short-term purchases. As noted above two of California's public utilities have defaulted in their payment obligations to the Cal PX and the Cal ISO as a result of the refusal of state regulators to allow them to recover their wholesale power costs. This refusal by state regulators has also caused the utilities to default on numerous other financial obligations, which could result in either the voluntary or involuntary bankruptcy of the utilities. While a bankruptcy filing would result in further post-petition purchases of wholesale electricity being considered administrative expenses of the debtor, a substantial delay could be experienced in the payment of pre-petition receivables pending the confirmation of a reorganization plan. The California Legislature is currently considering legislation under which a state entity would be formed to purchase and operate a substantial share of the transmission lines in California in an effort to provide cash to the utilities and thereby avoid potential bankruptcy filings by the utilities. A number of the creditors for the two California public utilities have indicated, however, that unless California moves quickly with such a plan, an involuntary bankruptcy filing may be made by one or more of such creditors. Because California's power reserves remain at low levels, in part as a result of the lack of creditworthy buyers of power given the defaults of the California utilities, the Cal ISO has relied on emergency dispatch orders requiring generators to provide at the Cal ISO's direction all power not already under contract. The power supplied to the Cal ISO has been used to meet the needs of the customers of the utilities, even though two of those utilities do not have the credit required to receive such power and may be unable to pay for it. The Company has contested the obligation to provide power under these circumstances. The Cal ISO sought a temporary restraining order compelling the Company to continue to comply with the emergency dispatch orders despite the utilities' defaults. Although the payment issue is still disputed, on February 21, 2001, the Company and the CDWR entered into a contract expiring March 23, 2001 for the purchase of all of the Company's available capacity not already under contract and the litigation has been temporarily stayed. The CDWR is current in its payments under this contract, but the Company is still owed $108 million for power provided in compliance with the emergency dispatch orders for the six weeks prior to the agreement. Depending on the outcome of the court proceedings initiated by the Cal ISO seeking to enjoin us from ceasing power deliveries to the Cal ISO, the Company may be forced to continue selling power without the guarantee of payment. Additionally, the Company is seeking a prompt FERC determination that the Cal ISO is not complying with the credit provisions of its tariff and a related order of the FERC issued on February 14, 2001, requiring the Cal ISO not to make purchases in the real time market unless a creditworthy purchaser is responsible for such purchases. (i) Indemnification of Stranded Costs. The stranded costs in the Dutch electricity market are considered to be the liabilities, uneconomical contractual commitments, and other costs associated with obligations entered into by the coordinating body for the Dutch electricity generating sector, N.V. Samenwerkende elecktriciteits-produktiebedrijven (SEP), plus some district heating contracts with some municipalities in Holland. As of December 29, 2000, SEP changed its name to BV Nederlands Elektriciteit Administratiekantoor. 37 SEP was incorporated as the coordinating body for four of the large-scale Dutch electricity generation companies, including UNA, which currently has an equity interest in SEP of 25%. Among other things, SEP prior to 2001 owned and managed the dispatch for the national transmission grid, coordinated the fuel supply, managed the import and the export of electricity, and settled production costs for the electricity generation companies. Under the Cooperation Agreement (OvS Agreement), UNA and the other Dutch generators agreed to sell their generating output through SEP. Over the years, SEP incurred stranded costs as a result of a perceived need to cover anticipated shortages in energy production supply. SEP stranded costs consist primarily of investments in alternative energy sources and fuel and power purchase contracts currently estimated to be uneconomical. In December 2000, the Dutch parliament adopted legislation, The Electricity Production Sector Transitional Arrangements Act (Transition Act), allocating to the Dutch generation sector, including UNA, financial responsibility for various stranded costs contracts and other liabilities of SEP. The Transition Act also authorizes the government to purchase from SEP at least a majority of the shares in the Dutch national transmission grid company. The legislation became effective in all material respects on January 1, 2001. The Transition Act allocates financial responsibility to the individual Dutch generators based on their average share in the costs and revenues under the OvS Agreement during the past ten years. UNA's allocated share of these costs has been set at 22.5%. In particular, the Transition Act allocates to the four Dutch generation companies, including UNA, financial responsibility for SEP's obligations to purchase electricity and gas under an import gas supply contract and three electricity import contracts. The gas import contract expires in 2015 and provides for gas imports aggregating 2.283 billion cubic meters per year. The three electricity contracts have the following capacities and terms: (a) 300 MW through 2005, (b) 600 MW through 2005 and (c) 600 MW through 2002 and 750 MW through 2009. The generators have the option of assuming their pro rata interests in the contracts or, subject to the assignment terms of the contracts, selling their interests to third parties. The Transition Act provides that, subject to the approval of the European Commission, the Dutch government will make financial compensations to the Dutch generation sector for the out of market costs associated with two stranded cost items: an experimental coal facility and district heating contracts. The four Dutch generation companies and SEP are in discussions with the Dutch Ministry of Economic Affairs regarding the implementation of the Transition Act. The parties have reached an agreement in principle with the Dutch Ministry of Economic Affairs regarding the compensation to be paid to SEP for the national transmission grid company. The proposed compensation amount is NLG 2.55 billion (approximately $1.1 billion based on an exchange rate of 2.34 NLG per U.S. dollar as of December 31, 2000). Although the Transition Act clarifies many issues regarding the anticipated resolution of the stranded costs debate in the Netherlands, there remain considerable uncertainties regarding the exact manner in which the Transition Act will be implemented and the potential for third parties to challenge the Transition Act on legal and constitutional grounds. In connection with the acquisition of UNA, the selling shareholders of UNA agreed to indemnify UNA for some stranded costs in an amount not to exceed NLG 1.4 billion (approximately $599 million based on an exchange rate of 2.34 NLG per U.S. dollar as of December 31, 2000), which may be increased in some circumstances at the option of the Company up to NLG 1.9 billion (approximately $812 million). Of the total consideration paid by the Company for the shares of UNA, NLG 900 million (approximately $385 million) has been placed by the selling shareholders in an escrow account under the direction of the Dutch Ministry of Economic Affairs to secure the indemnity obligations. Although the Company's management believes that the indemnity provision will be sufficient to fully satisfy UNA's ultimate share of any stranded costs obligation, this judgment is based on numerous assumptions regarding the ultimate outcome and timing of the resolution of the stranded cost issue, the former shareholders' timely performance of their obligations under the indemnity arrangement, and the amount of stranded costs which at present is not determinable. 38 (j) Operations Agreement with City of San Antonio. As part of the 1996 settlement of certain litigation claims asserted by the City of San Antonio with respect to the South Texas Project, the Company entered into a 10-year joint operations agreement under which the Company and the City of San Antonio, acting through the City Public Service Board of San Antonio (CPS), share savings resulting from the joint dispatching of their respective generating assets in order to take advantage of each system's lower cost resources. In January 2000, the contract term was extended for three years and is expected to terminate in 2009. Under the terms of the joint operations agreement entered into between CPS and Electric Operations, the Company has guaranteed CPS minimum annual savings of $10 million up to a total cumulative savings of $150 million over the term of the agreement. It is anticipated that the cumulative obligation will be met in the first quarter of 2001. In 1998, 1999 and 2000, savings generated for CPS' account were $14 million, $14 million and $60 million, respectively. Through December 31, 2000, cumulative savings generated for CPS' account were $124 million. (k) Nuclear Insurance. The Company and the other owners of the South Texas Project maintain nuclear property and nuclear liability insurance coverage as required by law and periodically review available limits and coverage for additional protection. The owners of the South Texas Project currently maintain $2.75 billion in property damage insurance coverage, which is above the legally required minimum, but is less than the total amount of insurance currently available for such losses. Pursuant to the Price Anderson Act, the maximum liability to the public of owners of nuclear power plants was $9.3 billion as of December 31, 2000. Owners are required under the Price Anderson Act to insure their liability for nuclear incidents and protective evacuations. The Company and the other owners of the South Texas Project currently maintain the required nuclear liability insurance and participate in the industry retrospective rating plan. There can be no assurance that all potential losses or liabilities will be insurable, or that the amount of insurance will be sufficient to cover them. Any substantial losses not covered by insurance would have a material effect on the Company's financial condition, results of operations and cash flows. (l) Nuclear Decommissioning. The Company contributes $14.8 million per year to a trust established to fund its share of the decommissioning costs for the South Texas Project. For a discussion of the accounting treatment for the securities held in the Company's nuclear decommissioning trust, see Note 2(l). In July 1999, an outside consultant estimated the Company's portion of decommissioning costs to be approximately $363 million. While the current and projected funding levels currently exceed minimum NRC requirements, no assurance can be given that the amounts held in trust will be adequate to cover the actual decommissioning costs of the South Texas Project. Such costs may vary because of changes in the assumed date of decommissioning and changes in regulatory requirements, technology and costs of labor, materials and equipment. Pursuant to the Legislation, costs associated with nuclear decommissioning that have not been recovered as of January 1, 2002, will continue to be subject to cost-of-service rate regulation and will be included in a non-bypassable charge to transmission and distribution customers. For information regarding the effect of the Business Separation Plan on funding of the nuclear decommissioning trust fund, see Note 4(b). o (20) SUBSEQUENT EVENTS (a) Credit Facilities. Between December 2000 and March 2001, Reliant Resources entered into eleven bilateral credit facilities with financial institutions, which provide for an aggregate of $1.6 billion in committed credit. The facilities became effective subsequent to December 31, 2000 and expire on October 2, 2001. Concurrent with the effectiveness of these facilities, $500 million of the facilities of a financing subsidiary were canceled. Interest rates on the borrowings are based on LIBOR plus a margin, a base rate or a rate determined through a bidding 39 process. These facilities contain various business and financial covenants requiring Reliant Resources to, among other things, maintain a ratio of net debt to the sum of net debt, subordinated affiliate debt and shareholders' equity not to exceed 0.60 to 1.00. These covenants are not anticipated to materially restrict Reliant Resources from borrowing funds or obtaining letters of credit under these facilities. The credit facilities are subject to commitment and usage fees that are calculated based on the amount of the facility and/or the amounts outstanding under the facilities, respectively. (b) RERC Corp. Debt Issuance. In February 2001, RERC Corp. issued $550 million of unsecured notes that bear interest at 7.75% per year and mature in February 2011. Net proceeds to RERC Corp. were $545 million. RERC Corp. used the net proceeds from the sale of the notes to pay a $400 million dividend to Reliant Energy, and for general corporate purposes. Reliant Energy used the $400 million proceeds from the dividend for general corporate purposes, including the repayment of short-term borrowings. (c) Florida Tolling Arrangement. In the first quarter 2001, the Company entered into tolling arrangements with a third party to purchase the right to utilize and dispatch electric generating capacity of approximately 1,100 MW. This electricity is expected to be generated by two gas-fired, simple-cycle peaking plants, with fuel oil backup, to be constructed by the tolling partner in Florida, which are anticipated to be completed by the summer of 2002, at which time the Company will commence tolling payments. 40