1 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 ------------------------ FORM 10-K <TABLE> <S> <C> [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999. [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO . COMMISSION FILE NO. 333-33397 </TABLE> NRG ENERGY, INC. (Exact name of Registrant as specified in its charter) <TABLE> <S> <C> DELAWARE 41-1724239 (State or other jurisdiction of (I.R.S. Employer of incorporation or organization) Identification No.) 1221 NICOLLET MALL, SUITE 700 55403 MINNEAPOLIS, MINNESOTA (Zip Code) (Address of principal executive offices) </TABLE> (612) 373-5300 (Registrant's telephone number, including area code) Securities registered pursuant to Section 12(b) of the Act: None Securities registered pursuant to Section 12(g) of the Act: None Indicated by check mark whether the Registrant (1) has filed all reports to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes X No ____ Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulations S-K is not contained herein, and will not be contained, to the best of the Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. Yes X No ____ As of March 30, 2000, there were 1,000 shares of common stock, $1.00 par value, outstanding, all of which were owned by Northern States Power Company. No other voting or non-voting common equity is held by non-affiliates of the Registrant. The Registrant meets the conditions set forth in General Instruction I (1)(a) and (b) of Form 10-K and is therefore filing this Form with the reduced disclosure format. Documents Incorporated by Reference: None - -------------------------------------------------------------------------------- - --------------------------------------------------------------------------------
2 CONSOLIDATED STATEMENTS OF INCOME NRG ENERGY, INC. AND SUBSIDIARIES INDEX <TABLE> <CAPTION> PAGE NO. -------- <S> <C> <C> PART I Item 1 Business.................................................... 1 Item 2 Properties.................................................. 20 Item 3 Legal Proceedings........................................... 23 Item 4 Submission of Matters to a Vote of Security Holders -- Omitted per General Instruction I(2)(c)................ -- PART II Item 5 Market Price of & Dividends on the Registrant's Common Equity and Related Stockholder Matters.................... 24 Item 6 Selected Financial Data -- Omitted per General Instruction I(2)(a)................................................... -- Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operations................................. 25 Item 7A Quantitative and Qualitative Disclosures About Market Risk...................................................... 28 Item 8 Financial Statements and Supplementary Data................. 29 Item 9 Changes in & Disagreements with Accountants on Accounting and Financial Disclosure.................................. 60 PART III Item 10 Directors and Executive Officers of the Registrant -- Omitted per General Instruction I(2)(c)..... -- Item 11 Executive Compensation -- Omitted per General Instruction I(2)(c)................................................... -- Item 12 Security Ownership of Certain Beneficial Owners and Management -- Omitted per General Instruction I(2)(c)..... -- Item 13 Certain Relationships and Related Transactions -- Omitted per General Instruction I(2)(c)........................... -- PART IV Item 14 Exhibits, Financial Statements Schedules and Reports On Form 8-K....................................................... 61 SIGNATURES............................................................. 64 </TABLE>
3 PART I ITEM 1 -- BUSINESS GENERAL NRG Energy, Inc. (the Company) is a leading participant in the independent power generation industry. Established in 1989 and wholly owned by Northern States Power Company (NSP), the Company is principally engaged in the acquisition, development, operations and maintenance of and ownership of power generation facilities. The power generation facilities in which the Company had interests (including those under construction) as of December 31, 1999, have a total design capacity of 20,728 megawatts (MW), of which the Company has or will have total or shared operational responsibility for 14,782 MW, and net ownership of, or leasehold interests in 10,990 MW. The Company has experienced significant growth in the last year, expanding from 3,300 MW of net ownership interests in power generation facilities (including those under construction) as of December 31, 1998 to 10,990 MW of net ownership interests as of December 31, 1999. This growth resulted primarily from a number of domestic acquisitions, notably the acquisition from Niagara Mohawk Power Corporation (NIMO) of the Huntley and Dunkirk generating stations in upstate New York, the acquisition from Montaup Electric Company (MEC) of the Somerset generating station in Massachusetts, the acquisition from San Diego Gas and Electric Company of the Encina generating station and combustion turbines in California, the acquisition from Consolidated Edison Company of New York, Inc. (ConEd) of the Arthur Kill generating station and Astoria gas turbines in New York City and the acquisition of the Middletown, Montville, Norwalk and Devon generating stations in Connecticut from Connecticut Light & Power Company (CL&P). The Company's total operating revenues and equity in earnings of projects increased from $182.1 million and $81.7 million, respectively, in 1998 to $500.0 million and $67.5 million, respectively, in 1999. The Company expects this growth to continue. The Company intends to acquire a 1,708 MW facility in Louisiana from Cajun Electric Power Cooperative, Inc. as part of its bankruptcy reorganization. The Company expects to acquire the 665 MW Killingholme A generating station from National Power plc. The Killingholme A generating station is a combined-cycle, gas turbine power station located in England. The Company plans to acquire 1,875 MW of fossil-fueled electric generating capacity and other assets from Conectiv of Wilmington, Delaware. These assets will add an additional 4,248 MW of net ownership interests in power generation facilities to the Company's existing portfolio. In addition, the Company announced that it has executed a memorandum of understanding with GE Power Systems, a division of General Electric Company, to purchase 11 gas turbine generators and five steam turbine generators over the next five years. The Company intends to install the 16 turbines, having a combined capacity of 3,000 MW, at certain of its existing North American plant sites. The Company's headquarters and principal executive offices are located at 1221 Nicollet Mall, Suite 700, Minneapolis, Minnesota 55403. Its telephone number is (612) 373-5300. STRATEGY The Company intends to continue to grow through a combination of acquisitions and development of power generation facilities and related assets in the United States and abroad. The Company believes that its facility operations and engineering expertise, fuel and environmental strategies, labor and government relations expertise, legal and financial skills give us a competitive advantage in the independent power market. The Company also believes that its experience in meeting or exceeding applicable environmental regulatory standards and our environmental compliance record will give us an advantage as regulators continue to impose increasingly stringent environmental requirements on the operation of power generation facilities. In addition, the Company continues to have access to technical and administrative support from NSP on a contract basis to augment its own expertise. The Company believes the knowledge and expertise it has gained in the financial and legal restructuring of its existing facilities, as well as our engineering expertise and reputation with respect to environmental compliance and labor relations, can be effectively employed in the development of both domestic and international greenfield projects. 1
4 In the United States, the Company's near-term focus will be primarily on the acquisition of existing power generation facilities, particularly in situations in which its expertise can be applied to improve the operating and financial performance of the facilities. In connection with this focus, the Company studies the opportunities that may be created by the current restructuring of the domestic electric utility industry, particularly the divestiture by some utility companies of their generating assets. In connection with these utility company divestitures of generating assets, which may be held by a purchasing subsidiary in many instances, the sellers require that we remain directly liable for certain indemnity, operation, provision of replacement power and/or debt payment obligations. The Company intends to focus our domestic development activities primarily on the acquisition or development of facilities in excess of 100 MW and to pursue smaller projects when we have the opportunity to combine several smaller projects into a larger transaction. The Company is also working with several industrial companies to develop energy projects that would provide both electricity and steam for their production facilities. In addition, to the extent that the replacement of aging power generating capacity or growth in demand creates the need for new power generation facilities in the United States, the Company intends to pursue opportunities to participate in the development of such facilities. In the international market, the Company will continue to pursue greenfield development and acquisition opportunities in those countries in which it believes that the legal, political and economic environment is conducive to increased foreign investment. Once the Company has developed one project in a country it uses that as a base to develop other projects in that same country or region, leveraging our experience and knowledge to enhance our likelihood of success in the area. The Company intends to continue to capitalize on opportunities created by the privatization of existing government-owned generating capacity. In addition, due to the significant existing demand for new power generating capacity in the international market, the Company intends to engage in the development of international greenfield projects. The Company intends to focus our international development activities primarily on the acquisition or development of facilities with capacity in excess of 100 MW and to pursue smaller projects when we have the opportunity to combine several smaller projects into a larger transaction. The Company believes that the global market will continue to provide attractive investment opportunities as the countries that have initiated privatization of their power generation capacity and have solicited bids from private companies to purchase existing facilities or to develop new capacity continue their privatization programs and other countries begin similar privatization efforts. Where appropriate, the Company will include a local or host country partner. By doing so, the Company expects to gain a number of advantages, including technical expertise possessed by others, greater knowledge of and experience with the political, economic, cultural and social conditions and commercial practices of the region or country where the project is being developed, and the ability to leverage our human and financial resources. A local partner also may, among other things, assist in obtaining financing from local capital markets as well as building political and community support for the project. 2
5 The Company intends to pursue the acquisition and development of natural gas-fired power generation facilities where appropriate to complement its existing and anticipated future investments in coal and other solid fuel-fired facilities. The Company currently holds no interest in, and has no present intention of investing in, any nuclear generation facility. RECENT EVENTS -- PROPOSED MERGER On March 24, 1999, NSP, and New Century Energies, Inc., a Delaware corporation (NCE), entered into an Agreement and Plan of Merger (the Merger Agreement) providing for a strategic business combination of NCE and NSP to merge and form Xcel Energy. At the time of the merger, each share of NCE common stock, will be converted into the right to receive 1.55 shares of Xcel common stock. NSP shares need not be exchanged and will become Xcel Energy shares on a one-for-one basis. Cash will be paid in lieu of any fractional shares of Xcel common stock. The merger requires approval or regulatory review by certain state utilities regulators, the SEC, the FERC, the Nuclear Regulatory Commission and the Federal Communication Commission and expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act (H-S-R). During June 1999, shareholders of both NSP and NCE approved the merger. The waiting period under H-S-R expired in March 2000. The FERC approved the merger in January 2000. The states of Kansas, Colorado and Arizona have approved the merger. Merger approval is not required in Michigan, Oklahoma, South Dakota or Wisconsin. Merger applications with regulators are pending in Minnesota, New Mexico, North Dakota, Wyoming and Texas, and at the SEC. While the Company cannot guarantee the timing or receipt of the necessary regulatory approvals, the Company expects the merger to be completed by the middle of 2000. The merger is expected to be a tax-free, stock-for-stock exchange for shareholders of both companies (except for fractional shares) and to be accounted for as a pooling of interests. NSP and NCE have agreed to certain undertakings and limitations regarding the conduct of their businesses prior to the closing of the transaction. At the time of the merger, Xcel Energy will register as a holding company under the Public Utility Holding Company Act of 1935. SIGNIFICANT INVESTMENTS, ACQUISITIONS AND DIVESTITURES IN 1999 In February 1999, the Company purchased from Thermal Ventures, Inc. (TVI) the remaining 50.1% limited partnership interests held by TVI in San Francisco Thermal Limited Partnership and Pittsburgh Thermal Limited Partnership for $12.3 million. In April 1999, the Company acquired TVI's 50% member interest in North American Thermal Systems LLC (the entity holding the general partnership interest in the San Francisco and Pittsburgh partnerships) for $500,000. In 1994, the Company, through a wholly-owned subsidiary, purchased a 50% ownership interest in Sunnyside Cogeneration Associates, a Utah joint venture, which owns and operates a 58 MW waste coal plant in Utah. The waste coal plant is currently being operated by a partnership that is 50% owned by a Company affiliate. In March 1999, the Company and its partner executed an agreement to sell the Sunnyside project to an affiliate of Baltimore Gas & Electric for a purchase price of $2.0 million. There was no gain or loss on the sale which closed during the second quarter of 1999. In April 1999, the Company completed the acquisition of the Somerset power station for approximately $55 million from the Eastern Utilities Association (EUA). The Somerset station, located in Somerset, Massachusetts, includes two coal-fired generating facilities and two aeroderivative combustion turbine peaking units with a capacity rating of 160 MW, excludes 69 MW on deactivated reserve. In connection with this acquisition, the Company entered into a Wholesale Standard Offer Service Agreement pursuant to which the Company is obligated to provide approximately 30% of the energy and capacity requirements of certain EUA affiliates (which is estimated to be approximately 275 MW at peak requirement) until December 31, 2009. 3
6 In May 1999, the Company and Dynegy Power Corporation (Dynegy), through West Coast Power LLC, completed the acquisition of the Encina generating station and 17 combustion turbines for approximately $356 million from San Diego Gas & Electric Company. The facilities, which have a combined capacity rating of 1,218 MW, are located near Carlsbad and San Diego, California. The Company and Dynegy each own a 50% interest in these facilities. In June 1999, the Company completed its acquisition of the Huntley and Dunkirk generating stations from NIMO for approximately $355 million. The two coal-fired power generation facilities are located near Buffalo, New York, and have a combined capacity rating of 1,360 MW. In connection with this acquisition, the Company entered into several Transition Power Purchase Agreements and a related swap agreement with NIMO pursuant to which NIMO purchases certain energy and capacity from these facilities for a term of four years. In June 1999, the Company completed its acquisition of the Arthur Kill generating station and the Astoria gas turbine station from ConEd for approximately $505 million. These facilities, which are located in the New York City area, have a combined capacity rating of 1,456 MW. In connection with the acquisition of each facility, the Company entered into (i) Transition Energy Sales Agreements pursuant to which energy from each facility is sold to ConEd for a transition period ending on the date on which the independent system operator in New York State (NYISO) commences operation of a spot market (which commencement date was November 18, 1999) for energy and certain ancillary services, and (ii) Transition Capacity Sales Agreements pursuant to which capacity from each facility is sold to ConEd for a transition period ending on the later of (a) the earlier of (i) December 31, 2002 or (ii) the date such facility receives notice from the NYISO that none of the electric generating capacity of such facility is required for meeting the installed capacity requirements in New York City, or (b) the date the NYISO commences an auction for system capacity. Pursuant to the Transition Energy Sales Agreements, the Company agreed to sell to ConEd at a fixed price varying amounts of energy from the Arthur Kill generating facility and the Astoria gas turbine generating facility, in each case in amounts to be specified by ConEd, up to the full capability of each facility. Pursuant to the Transition Capacity Sales Agreements, the Company has agreed to sell to ConEd at a fixed price, during certain periods, up to 100% of the capacity of the Arthur Kill generating facility and up to 100% of the capacity of the Astoria gas turbines facility. The Company, together with its partner and the Creditor's committee, filed a plan with the United States Bankruptcy court for the Middle District of Louisiana to acquire 1,708 MW of fossil generating assets from Cajun Electric Power Cooperative of Baton Rouge, Louisiana (Cajun) for approximately $1.0 billion. During the third quarter, the U.S. Bankruptcy Judge confirmed the Creditor's Plan of Reorganization and the Company exercised an option to purchase its partner's 50-percent interest in the project. The Company expects to close the acquisition of the Cajun assets during the first quarter of 2000. In August, the Company agreed to sell all but a 20 percent ownership interest in Cogeneration Corporation of America (CogenAmerica) to Calpine Corporation (Calpine) in connection with Calpine's acquisition of the remaining shares of CogenAmerica. Prior to December 1999, the Company owned approximately 45 percent of CogenAmerica. Upon closing of the transaction, all outstanding shares of CogenAmerica common stock (other than those retained by the Company) were acquired by Calpine for a cash purchase price of $25.00 per share. The transaction closed during the fourth quarter of 1999 and the Company retained a 20-percent ownership interest in CogenAmerica. In October 1999, the Company completed its acquisition of the Oswego generating station from NIMO and Rochester Gas and Electric for approximately $85 million. The oil and gas-fired power generating facility which has a capacity rating of 1,700 MW, is located on a 93-acre site in Oswego, New York. This facility consists of two units each having a capacity rating of 850 MW. In connection with this acquisition, the Company entered into a Transition Power Purchase Agreement with NIMO similar to those entered into in connection with the acquisitions of the Dunkirk and Huntley facilities. Pursuant to this agreement, the Company has agreed to sell 100% of the capacity of one unit, an option for up to 40% of the capacity of the other unit, and an option to purchase a nominal amount of energy to NIMO for a term of four years. 4
7 In December 1999, the Company acquired four fossil fuel generating stations and six remote gas turbines from CL&P for approximately $460 million, plus adjustments for working capital. These facilities are located throughout Connecticut and have a combined capacity rating of 2,235 MW. The Company entered into a Standard Offer Service Wholesale Sales Agreement with CL&P pursuant to which the Company will supply CL&P with 35% of its standard offer service load during 2000, 40% during 2001 and 2002, and 45% during 2003. The Company estimates that 45% of CL&P's standard offer service load in 2003 will be approximately 2,070 MW at peak requirement. The Agreement terminates on December 31, 2003. In December 1999, the Company purchased a 50% interest in the Rocky Road Power Plant, a 250 MW natural gas fired simple-cycle peaking facility in East Dundee, IL from Dynegy Inc., for approximately $60 million. The power plant began commercial operations on June 30, 1999 and received approval in October 1999, for the installation of an additional 100 MW natural gas combustion turbine, increasing the facilities generating capacity to 350 MW. The expansion is expected to be in service before the start of the peak summer 2000 season. SIGNIFICANT EQUITY INVESTMENTS LOY YANG POWER The Company has a 25.4% interest in Loy Yang Power (Loy Yang) which owns and operates a 2,000 MW brown coal fired thermal power station (the Power Station) and the adjacent Loy Yang coal mine (the Mine) located in Victoria, Australia. The Power Station has four generating units, each with a 500 MW boiler and turbo generator, which commenced commercial operation between July 1984 and December 1988. In addition, Loy Yang manages the common infrastructure facilities which are located on the Loy Yang site, which services not only the Power Station, but also the adjacent Loy Yang B 1000 MW power station (Loy Yang B), a pulverized dried brown coal plant, and several other nearby power stations. Loy Yang is required by law to sell its entire output of electricity (subject to certain narrow exemptions, including output used in the Power Station and the Mine) through the competitive wholesale market for electricity operated and administered by the Victorian Power Exchange (the Pool). There are two components to the wholesale electricity market in Victoria. The first is the Pool. The second is the price hedging contracts, known as Contracts for Differences (or CFDs), that are entered into between electricity sellers and buyers in lieu of traditional power purchase agreements, which are not available in Victoria because of the Pool system. Under the Victorian regulatory system, all electricity generated in Victoria must be sold and purchased through the Pool. All licensed generators and suppliers, including Loy Yang, are signatories to a pooling and settlement agreement, which governs the constitution and operation of the Pool and the calculation of payments due to and from generators and suppliers. The Pool also provides centralized settlement of accounts and clearing. Prices for electricity are set by the Pool daily for each half hour of the following day based on the bids of the generators and a complex set of calculations matching supply and demand and taking account of system stability, security and other costs. Under a new national electricity market, the grid in Victoria has been interconnected with that of New South Wales and limited trading is already taking place between those states. Over the long term, there are plans for the interconnection of the eastern seaboard states to establish what will be known as a national power pool. In a pool system, it is not possible for a generator such as Loy Yang to enter into traditional power purchase agreements. In order to provide a hedge against Pool price volatility and to support their financings, most of the Victorian generators have entered into CFDs with the Victorian distribution companies, Victorian government entities and industrial users (customers). These CFDs are financial hedging instruments, which have the effect of fixing the price for a specified quantity of electricity for a particular seller and purchaser over a defined period. They establish a "strike price" for a certain volume of electricity purchased by the user during a specified period; differences between that "strike price" and the actual price set by the Pool give rise to "difference payments" between the parties at the end of the period. Even if Loy Yang is producing less than its contracted quantity it will still be required to make and will be entitled to receive difference payments for the amounts set forth in its CFDs. 5
8 Loy Yang's current CFDs with the Victorian distribution companies and other Victorian government entities in respect of regulated customer load (which are called vesting contracts) cover approximately 64% of Loy Yang's forecast revenue from generation, thus providing considerable stability in its income over that period. Loy Yang also enters into CFDs with its unregulated or contestable customers. These CFDs are known as hedging contracts and, together with the vesting contracts with the regulated customers, cover approximately 95% of Loy Yang's forecast load at December 31, 1999. Each of the vesting contracts expires at the end of the franchise period (December 31, 2000), by which time all retail customers will have become contestable customers by operation of law. Loy Yang's hedging contracts are generally for a term of one to two years, and the volume of load covered by these contracts is expected to increase as retail customers progressively become contestable. Loy Yang's goal is to cover 85% of its forecast load with hedging contracts. Loy Yang and the State Electricity Commission of Victoria (SECV) have been issued a joint mining license for the Mine. Under the terms of the privatization, Loy Yang is required to mine coal to supply not only its own Power Station but also the neighboring Loy Yang B, a nearby plant, and an additional future power station that could be developed on a nearby site. This requirement extends to 2027, but may be extended for an additional 30 years at the SECV's option. Loy Yang receives a fixed capacity charge and a variable energy charge for these services, coupled with a system of initiatives and penalties. Loy Yang has over 70 years of economically viable coal supply at current usage rates within its mine license area, even assuming that it is required to continue supplying coal to the other parties beyond 2026. On the basis of historical Australian power pool prices, absent project debt restructuring, the Loy Yang project company will experience difficulty in servicing its long-term debt obligations. This, in turn, could trigger a senior debt default under the loan documents on or about June 2001 continuing until June 2003 as a result of the Debt Service Cover Ratio falling below prescribed threshold levels. This would trigger a senior debt "lock-up" under the project's loan documents, which lock-up would prevent the Loy Yang A project company from making equity distributions to its owners. As the Company did not expect the Loy Yang A project company would make any equity distributions in the immediate future, a senior debt lock-up will not have a materially adverse effect on the Company's results of operations. Effective December 9, 1999, the Australian government reduced the corporate income tax rate from 36% to 34% for the tax year 2000/2001 and from 34% to 30% for the tax years thereafter. The deferred tax assets and liabilities were restated to the appropriate tax rate, which resulted in a negative impact on net income of $3.4 million for 1999. In February 2000, CMS Energy (CMS) announced its intentions to divest its 49.6 percent ownership in Loy Yang Power, its only asset in eastern Australia. CMS Energy indicated it was selling the asset because it was no longer of strategic value to their portfolio and had not met financial expectations. The Company believes the fundamentals behind the power station are still sound and it will attract interest from other bidders. The Company has not decided if it will bid for the CMS stake in Loy Yang Power. The remaining partners in Loy Yang Power have pre-emptive rights over any sale of equity and any debt restructuring. GLADSTONE POWER STATION The Gladstone Power Station (Gladstone) is a 1,680 MW coal-fired power generation facility located in Gladstone, Australia. The Company acquired a 37.5% ownership interest in Gladstone when the facility was privatized in March 1994. The other participants in this acquisition are subsidiaries or affiliates of Comalco Limited, Marubeni Corporation, Sumitomo Corporation and Sumitomo Light Metal Industries, Mitsubishi Corporation and Mitsubishi Materials Corporation, and Yoshida Kogyo (the Participants). NRG Gladstone Operating Services Pty. Ltd., a wholly owned subsidiary of the Company (NRG Gladstone), operates Gladstone under an operations and maintenance agreement expiring in 2011. Gladstone sells electricity to the Queensland Power Trading Corporation (QPTC) and also to Boyne Smelters Limited (BSL) located at Boyne Island, Queensland (the Smelter). Pursuant to an Interconnection and Power Pooling Agreement (the IPPA), the Participants have the right to interconnect Gladstone to the QPTC system and QPTC is obligated to accept all electricity generated by the facility (subject to merit order 6
9 dispatch), for an initial term of 35 years. QPTC also has agreed under the IPPA to permit the Smelter to interconnect to the QPTC system and to provide sufficient generating capacity on its system in order to provide an uninterrupted supply of power to the Smelter in most circumstances. The Participants are obligated to maintain a 35% reserve margin for the Smelter design load, but the QPTC is obligated to provide capacity support to the Participants to make up any shortfall between the available capacity from Gladstone and the Smelter demand at any given time. The QPTC also entered into a 35 year Capacity Purchase Agreement (CPA) with each of the Participants for its percentage of the capacity of Gladstone, excluding that sold directly to the Smelter. Under the CPAs, the Participants are paid both a capacity and an energy charge by the QPTC. The capacity charge is designed to cover the projected fixed costs allocable to the QPTC, including debt service and an equity return, and is adjusted to reflect variations in interest rates. A capacity bonus is also available if the equivalent availability factor exceeds 88% on a rolling average basis, and damages are payable by the Participants if it is less than 82% on that same basis. As of December 31, 1999, the two-year average equivalent availability factor was 87.7%. The QPTC also pays an energy charge, which is intended to cover fuel costs. The owners of the Smelter (BSL) have also entered into a Block A Power Purchase Agreement (PPA) and Block B PPA with each Participant, providing for the sale and purchase of such Participant's percentage share of capacity allocated to the existing Smelter. The term of each of these PPAs is 35 years. BSL is obligated to pay to each Participant a demand charge that is intended to cover the fixed costs of supplying capacity to the existing Smelter and the Smelter expansion, including debt service and return on equity. BSL also is obligated to pay an energy charge based on the fuel cost associated with the production of energy from the facility. The Smelter expansion resulted in an increase in Gladstone capacity utilization from approximately 41% in 1994 to 60% in 1999. The Company anticipates that the capacity utilization will increase to 64% in 2000. Effective December 9, 1999, the Australian government reduced the corporate income tax rate from 36% to 34% for the tax year 2000/2001 and from 34% to 30% for the tax years thereafter. The Gladstone Power Station has restated its tax assets and liabilities to the appropriate tax rate. The reduced corporate income tax rate resulted in an increase in net income of $3.9 million for 1999. NRG Gladstone is responsible for operation and maintenance of Gladstone pursuant to a 17 year operation and maintenance agreement that commenced in 1994. NRG Gladstone is entitled to a base fee of AUS$ 1.25 million per year indexed in accordance with the Australian Consumer Price Index (ACPI) (approximately U.S. $0.896 million, based on exchange rates and ACPI in effect at December 31, 1999), and an annual bonus based on the capacity bonuses to which the Participants are entitled under the CPAs. NRG Gladstone is obligated to pay liquidated damages for shortfalls in availability in an amount calculated by reference to the liquidated damages payable by the Participants under the CPAs and the PPAs. NRG Gladstone's obligations under the operation and maintenance agreement are unconditionally guaranteed by the Company, subject to an aggregate liability cap of AUS$ 25.0 million indexed in accordance with ACPI (approximately U.S. $16.4 million, based on exchange rates and ACPI in effect at December 31, 1999). COLLINSVILLE POWER STATION The Collinsville Power Station (Collinsville) is a 192 MW coal-fired power generation facility located in Collinsville, Australia. In March 1996, the Company acquired a 50% ownership interest in Collinsville when it was privatized by the Queensland State government. The Company's partner in this acquisition is Transfield Holdings Pty Ltd (Transfield), an Australian infrastructure contractor, with which the Company formed an unincorporated joint venture to refurbish this plant. The joint venture contracted with an affiliate of Transfield to complete the refurbishment of the facility under a turn-key contract. The operation and maintenance of the facility was undertaken by Collinsville Operations Pty Ltd. (COPL), a 50% owned subsidiary of the Company. COPL has entered into a maintenance contract with Transfield to perform required maintenance on the facility and a technical services agreement with the Company for staffing and assistance with certain operational functions. 7
10 Collinsville Power Station commenced operations on August 11, 1998. The Company and Transfield have entered into an 18 year Power Purchase Agreement (PPA) with QPTC. Under this agreement QPTC will pay both a capacity and an energy charge to the participants. The capacity charge is designed to cover the projected fixed costs allocable to QPTC, including debt service and equity return. The energy charge is based on the fuel costs associated with the production of energy from the facility. Effective December 9, 1999, the Australian government reduced the corporate income tax rate from 36% to 34% for the tax year 2000/2001 and from 34% to 30% for the tax years thereafter. The Collinsville Power Station has restated its tax assets and liabilities to the appropriate tax rates as of December 31, 1999. The reduced corporate income tax rate resulted in an increase of $38,376 in net income for 1999. MIBRAG The Company owns an indirect 33 1/3% interest in the equity of Mitteldeutsche Braunkohlengesellschaft mbH (MIBRAG) which owns coal mining, power generation and associated operations, all of which are located south of Leipzig, Germany. MIBRAG is a corporation formed by the German government following the reunification of East and West Germany, to hold two open-cast brown coal (lignite) mining operations, a lease on an additional mine, three lignite-fired industrial cogeneration facilities and briquette manufacturing and coal dust plants, all located in the former East Germany. In connection with the acquisition, the Company and its partners agreed to invest (from cash flow from MIBRAG operations) in excess of DM 1 billion (US $514.9 million based on the exchange rate as of December 31, 1999) by December 31, 2004 to modernize the existing mines and power generation facilities and to develop new open-pit mines. The German government is obligated to provide certain guarantees of bank loans to MIBRAG relating to capital improvements to the Schleenhain mine. MIBRAG also agreed to operate the three power generation facilities until 2005, to operate the briquette plants in accordance with market demand until 2005, and to operate the lignite mines until continued operation of the mines is no longer economically justifiable. In addition, MIBRAG has made certain employee retention commitments until 2000. MIBRAG's cogeneration operations consist of the 110 MW Mumsdorf facility, the 86 MW Deuben facility and the 37 MW Wahlitz facility. These facilities provide power and thermal energy for MIBRAG's coal mining operations and its briquette manufacturing plants. All power not consumed by MIBRAG's internal operations is sold under an eight-year PPA with Westsachsische Energie Aktiengesellschaft (WESAG), a recently privatized German electric utility. The Company and PowerGen plc (Powergen) jointly, through Saale Energie Services GmbH (Saale), provide consulting services for a fee for the operation of the MIBRAG steam and power generation facilities, the associated electrical and thermal transmission and distribution system and the briquette manufacturing plants, under a power consultancy agreement with MIBRAG for the life of the facilities. After some retrofitting was completed by MIBRAG, the Company believes that all three of these cogeneration facilities now satisfy the current European Union environmental regulations. MIBRAG leases these cogeneration facilities under a 13-year lease pursuant to which MIBRAG has operating control of, and a 1% interest, in the facilities. MIBRAG's lignite mine operations include Profen, Zwenkau and Schleenhain with total estimated reserves of 776 million metric tons. Morrison Knudsen, an international mining company, provides consulting services to the mines under a consultancy agreement with MIBRAG for the life of the mines. In addition to providing approximately 3 million tons of lignite per year for MIBRAG's three cogeneration facilities and one briquette facility, output from these mines supplies lignite to the Schkopau power station and other facilities. The total output of the refurbished Schleenhain mine is dedicated to the new 1,730 MW Lippendorf power station. MIBRAG is currently supplying coal for the existing Lippendorf facility, which is expected to close at the end of March 2000. The first unit of the new Lippendorf facility has commenced operations and the second new unit is expected to commence operations in May of 2000. SCHKOPAU POWER STATION In 1993, the Company and PowerGen plc of the United Kingdom each acquired a 50% interest in a German limited liability company, Saale Energie GmbH (Saale). Saale then acquired a 41.9% interest in a 8
11 960 MW coal-fired power plant that was under construction in the city of Schkopau, Germany. PreussenElecktra Kraftwerke Ag (PE), a German energy company, owns the remaining 58.1% interest in Schkopau and operates the plant. The partnership of Saale and PE that owns the plant is called Kraftwerk Schkopau GbR (KS). The first 425 MW unit of the Schkopau plant began operation in January 1996, the 110 MW turbine went into commercial operation in February 1996, and the second 425 MW unit came on line in July 1996. PE operates and maintains the Schkopau facility under an operation and maintenance contract with Kraftwerk Schkopau Betriebsgesellschaft mbH, a German limited liability company (KSB), in which Saale and PE hold interests of 44.4% and 55.6% respectively, and which is responsible for the operation and maintenance of the facility pursuant to certain agreements with each of Saale and PE. PE is paid a management fee made up of several variable components that are adjusted according to changes in, among other things, labor costs, producer prices for light fuel oil and prices for electricity. Pursuant to the KSB partnership agreement between Saale and PE and the Saale shareholders agreement between the Company and PowerGen, the Company has the right to participate in the oversight of facility operations and in the approval and oversight of facility budgets and policies. The plant is fueled by brown coal which is provided under a long-term contract by MIBRAG's Profen lignite mine. Pursuant to the KS partnership agreement between Saale and PE, each partner has been allocated a share of capacity and energy generated by the facility. Saale sells its allocated 400 MW portion of the plant's capacity under a 25-year contract with VEAG, a major German utility which controls the high-voltage transmission of electricity in the former East Germany. VEAG pays a price that is made up of three components, the first of which is designed to recover installation and capital costs, the second to recover operating and other variable costs, and the third to cover fuel supply and transportation costs. The Company receives 50% of the net profits from these VEAG payments through its ownership interest in Saale. COBEE In December 1996, the Company acquired an interest in Compania Boliviana de Energia Electrica S.A.-Bolivian Power Company Limited (COBEE), the second largest generator of electricity in Bolivia. The acquisition was consummated through a Netherlands corporation, Tosli Investments B.V. (Tosli), which is equally owned by subsidiaries of the Company and Vattenfall AB of Sweden (Vattenfall). In December 1996, Tosli completed a successful tender offer for the shares of COBEE, which were listed on the New York Stock Exchange, acquiring 96.6% of COBEE's outstanding common shares for a total purchase price of $175 million. COBEE shares were delisted in January 1997. In November 1999, Tosli, successfully completed a second tender offer for shares of COBEE. As a result, Tosli currently holds 98.19% of COBEE's outstanding common shares. In addition, COBEE has met the requirements to deregister from the Securities and Exchange Commission and effective November 9, 1999 deregistered. The COBEE board of directors consists of three designees of the Company, three designees of Vattenfall and three directors appointed jointly by the Company and Vattenfall. COBEE has entered into an electricity supply contract with Electricidad de La Paz S.A., a Bolivian distribution company, (Electropaz) which provides that COBEE shall supply Electropaz with all of the electricity that COBEE can supply, up to the maximum amount of electricity required by Electropaz to supply the requirements of its distribution concession. This electricity supply contract expires in December 2008. COBEE has entered into a substantially similar contract with Empresa de Luz Fuerza Electricade Oruro, another Bolivian distribution company, S.A. (ELF). All payments by Electropaz and ELF are in local currency, tied to the value of the U.S. dollar. COBEE operates its electric generation business under a 40-year concession granted by the Government of Bolivia in 1990, as most recently amended in March 1995. Under this concession, COBEE is entitled to earn a return of 9% after all operating expenses, depreciation, taxes and interest expense, calculated on its U.S. dollar rate base, consisting of net fixed assets at historical cost in U.S. dollars and working capital and materials up to certain limits. The Bolivian Electricity Code also provides for the adjustment of rates to compensate COBEE for any shortfall or to recapture any excess in COBEE's actual rate of return during the 9
12 previous year. COBEE periodically applies to the Superintendent of Electricity for rate increases sufficient to provide its 9% rate of return based on COBEE's current operating results and its projection of future revenues and expenses. COGENERATION CORPORATION OF AMERICA On January 18, 1996, the U.S. Bankruptcy Court for the District of New Jersey awarded the Company the right to acquire a 41.86% equity interest in O'Brien Environmental Energy, Inc. (O'Brien), which emerged from bankruptcy on April 30, 1996 and was renamed "NRG Generating (U.S.) Inc." (NRGG). On July 20, 1998, NRGG's name was changed to Cogeneration Corporation of America. Prior to December 1999, the Company held 45.21% of the common stock of CogenAmerica. The remaining 54.79% of the common stock was held publicly. CogenAmerica has interests in six domestic operating projects with an aggregate capacity of approximately 575 MW. CogenAmerica's principal operating projects include: (a) the 54 MW Newark Boxboard Project (which is owned 100% by a wholly-owned project subsidiary of CogenAmerica), a gas-fired cogeneration facility that sells electricity to Jersey Central Power & Light (JCP&L) and steam to Newark Group Industries, Inc.; (b) the 122 MW E.I. du Pont Parlin Project (which is owned 100% by a wholly-owned project subsidiary of CogenAmerica), a gas-fired cogeneration facility that sells electricity to JCP&L and steam to E.I. du Pont de Nemours and Company; (c) an 83% interest in a 22 MW standby/peak sharing facility which provides electricity and standby capabilities for the Philadelphia Municipal Authority; (d) a 50% interest in the 150 MW Grays Ferry project, a gas-fired cogeneration project located in Philadelphia, Pennsylvania, which sells electricity to Philadelphia Electricity Company (PECO). PECO attempted to terminate the PPA with respect to the Grays Ferry project. The Grays Ferry partnership in turn commenced litigation claiming there is no basis for termination of such agreement. On April 23, 1999, Grays Ferry and PECO reached a final settlement on the resolution of the litigation concerning the parties' PPA. Under the terms of the settlement, PECO transferred its one-third ownership interest in the 150 MW project to Grays Ferry. As a result CogenAmerica's interest in Grays Ferry increased to 50%, effective April 23, 1999.; (e) the 117 MW Morris project, a gas-fired cogeneration project located in Morris, Illinois, which sells electricity and steam to Equistar Chemicals; (f) the 110 MW MCPC project, a gas-fired cogeneration project located in Pryor, Oklahoma, which sells electricity to Oklahoma Gas and Electric and steam to a number of industrial users. On October 9, 1998, CogenAmerica acquired the Company's 50% interest in MCPC, a 110 MW cogeneration project located in Pryor, Oklahoma. CogenAmerica also acquired the remaining 50% interest in this project from Decker Energy International Inc., and associated entities. The project sells electricity to Oklahoma Gas and Electric and steam to a number of industrial users. The purchase price was approximately $23.9 million. On December 30, 1997 CogenAmerica acquired from the Company 100% of the membership interests in NRG (Morris) Cogen, LLC which was building a 117 MW cogeneration plant on the site of the Equistar Chemicals, LP (Equistar) manufacturing facility in Morris, Illinois. In connection with the sale, the Company committed to finance the acquisition price pursuant to a loan agreement between the Company and CogenAmerica and the Company guaranteed the obligation of CogenAmerica to invest equity into the project company. CogenAmerica's Morris facility experienced two unscheduled outages in January 1999, which resulted in service and business interruptions to Equistar. The Company, as a provider of construction management services and operation and maintenance services to the Morris facility has participated with CogenAmerica and Equistar in an investigation into this matter. This investigation, which includes an examination of the respective rights and obligations of the parties with respect to one another and with respect to potentially responsible third parties, including insurers, is continuing. Although it is not possible at the present time to assess the Company's potential exposure related to the two outages, the Company does not believe that any claims which may be brought against it will have a material financial impact on the Company. In August 1999, CogenAmerica entered into an Agreement and Plan of Merger (Merger Agreement) with Calpine and Calpine East Acquisition Corp. (Calpine Acquisition) pursuant to which Calpine 10
13 Acquisition and CogenAmerica merged. At closing of the merger, all outstanding shares of CogenAmerica common stock (other then shares held by Calpine Acquisition) were converted into the right to receive $25.00 per share in cash. Concurrently with the Merger Agreement, the Company entered into a Contribution and Stockholders Agreement with Calpine and Calpine Acquisition. Immediately prior to the closing of the merger, the Company contributed approximately 20% of its CogenAmerica shares to Calpine Acquisition in exchange for 20% of the shares of stock of the surviving corporation. The transaction closed during the fourth quarter of 1999, the Company recognized a pretax gain on the sale of approximately $11 million. WEST COAST POWER In May 1999, Dynegy Power Corporation (Dynegy) and the Company formed West Coast Power LLC (West Coast Power), a Delaware limited liability company, 50% owned by affiliates of each sponsor. West Coast Power serves as the holding company for a portfolio of operating companies which own generating assets in Southern California. These assets are currently comprised of the El Segundo Generating Station, the Long Beach Generating Station, the Encina Generating Station and 17 Combustion Turbines in the San Diego area (the Encina Combustion Turbines). El Segundo Generating Station: The El Segundo Generating Station is a 1,020 MW plant consisting of four units: two units at 175 MW each and two units at 335 MW each. El Segundo was purchased from the Southern California Edison Company through a competitive bid process for $87.7 million on April 3, 1998. El Segundo sells electricity through the California power exchange. Long Beach Generating Station: The Long Beach Generating Station is a 530 MW plant with seven 60 MW gas turbine generators and two 70 MW steam turbine units. The Long Beach plant was purchased from Southern California Edison Company on March 31, 1998 through a competitive bid process for $29.8 million. Long Beach sells peak electricity and ancilliary services through the California power exchange and through bilateral contracts. Encina Generating Station: The Encina Generating Station is located in Carlsbad, California and consists of five steam-electric generating units and one combustion turbine with net generating capacity of 965 MW. Encina was purchased from San Diego Gas & Electric on May 21, 1999, at a purchase price of $290.5 million. Encina Combustion Turbines: The Encina Combustion Turbine assets consist of 17 combustion turbine generator sets (the CT's) with an aggregate capacity of 253 MW, located on seven different sites in San Diego County. On May 21, 1999, the Company and Dynegy, purchased the CT's from San Diego Gas & Electric through a competitive bid process. The CT's acquisition had a purchase price of $69.1 million. The CT's have the ability to provide spinning reserve, black start capability, quick start capability, voltage support and quick load capability for the ancilliary services market. SIGNIFICANT WHOLLY-OWNED OPERATIONS MINNEAPOLIS ENERGY CENTER Minneapolis Energy Center (Energy Center) provides steam and chilled water to customers in downtown Minneapolis, Minnesota. Energy Center currently provides 92 customers with 1.6 billion pounds of steam per year and 39 customers with 40.8 million ton-hours of chilled water per year. The Company acquired Energy Center in August 1993 for approximately $110 million. Energy Center's assets include two combined steam and chilled water plants, three chilled water plants, two steam plants, six miles of steam and two miles of chilled water distribution lines. The Energy Center plants have a combined steam capacity of 1,408 mmBtus per hour (413 MWt) and cooling capacity of 40,750 tons per hour. Energy Center provides steam and chilled water to its customers pursuant to energy supply agreements, which expire at varying dates from December 1999 to March 2019. Historically, Energy Center has renewed its energy supply agreements as they near expiration. With minor exceptions, these agreements are standard form contracts providing for a uniform rate structure consisting of three components: a demand charge designed to recover MEC's fixed capital costs, a consumption charge designed to provide a per unit margin, and an operating charge designed to pass through to customers all fuel, labor, maintenance, electricity and 11
14 other operating costs. The demand and consumption charges are adjusted in accordance with the Consumer Price Index every five years. During the fourth quarter of 1999, the Energy Center acquired Dayton's (Target Corporation) steam and chilled water facility located in Minneapolis, Minnesota. The acquisition added 85 mmBtus of steam capacity and 3,600 tons of chilled water. The facilities were acquired for approximately $3.0 million. NORTH AMERICAN THERMAL SYSTEM In February 1999, the Company purchased from TVI the remaining 50.1% limited partnership interest in San Francisco Thermal Limited Partnership and Pittsburgh Thermal Limited Partnership for $12.3 million. In April 1999, the Company acquired TVI's 50% member interest in North American Thermal Systems LLC (NATS) for $500,000. The Company owns 100% of the North American Thermal Systems limited partnership which holds the operating assets of the San Francisco, California and Pittsburgh, Pennsylvania district heating and cooling operations. The San Francisco thermal system has approximately 185 customers and a capacity of 490 mmBtu/hr of steam. The Pittsburgh thermal system has approximately 29 steam customers and 27 chilled water customers. It has a capacity of 240 MMBtu/hr of steam and 10,180 tons of chilled water. ROCK-TENN The Rock-Tenn process steam operation, which is owned and operated by the Company, consists of a five-mile closed-loop steam/condensate line that delivers steam to the Rock-Tenn Company (RTC) (formerly Waldorf Corporation), a paper manufacturer in St. Paul, Minnesota. Rock-Tenn has a peak steam capacity of 430 mmBtus per hour (126 MWt). As a result of the settlement of a 1987 dispute between RTC and NORENCO Corporation (a predecessor of the Company), RTC prepaid revenues for future steam service. As of December 31, 1999, deferred revenues remaining were approximately $2.0 million. The Company delivers steam to RTC under a steam sales agreement, pursuant to which RTC is obligated to purchase its total energy needs for its St. Paul, Minnesota facility through June 30, 2007. The agreement does not obligate RTC to purchase a minimum quantity of energy. Instead, RTC failure to purchase a certain quantity of energy during a given contract year triggers the Company's right to terminate the agreement, unless RTC elects to compensate the Company for the deficit energy usage amount. NEO CORPORATION NEO Corporation (NEO) is a wholly-owned project subsidiary of the Company that was formed to develop small power generation facilities, ranging in size from 1 to 50 MW, in the United States. NEO is currently focusing on the development and acquisition of landfill gas projects, the acquisition of small hydroelectric projects, the development of distributed generation projects and the acquisition of other green power assets. Through the investment vehicle, Northbrook Energy, L.L.C. (Northbrook), NEO has a 50% interest in eighteen small operating hydroelectric projects, ranging in size from 1 MW to 33 MW and having a total capacity of 71 MW. As of December 31, 1999, NEO's total investment in these projects was $13.5 million. NEO has a 50% interest in the generators associated with 25 operating landfill gas projects, as of December 31, 1999, ranging in size from 1 MW to 12 MW. NEO owns 100% of the gas collection systems associated with those 25 generating projects. As of December 31, 1999, NEO's investment in these projects totaled $70.7 million and loans to fund development, construction and start-up amounted to $26.9 million. In addition, NEO has three generating projects under construction. NEO expects its total funding requirements to be approximately $120 million and total capacity of the portfolio is expected to reach 107 MW in 2000. In 1999, NEO acquired 50% of the MESI syncoal project which processes waste coal into coal briquettes. The MESI syncoal project is located at the KenWest terminal in Catletsburg, Kentucky. The processed and solid waste coal produces Section 29 tax credits. 12
15 On September 24, 1997, certain affiliates of NEO entered into a Construction, Acquisition and Term Loan Agreement with Lyon Credit Corporation (Lyon) for $92 million to fund the construction of the landfill gas collection systems and generation facilities for certain NEO landfill gas projects in development. The construction loan for each project will convert to a term loan containing a maximum maturity date of ten years. The Company has agreed to provide Lyon with a guarantee during the construction loan period. In addition, the Company has agreed to guarantee the monetization and use of the Section 29 tax credits generated from the landfill gas projects financed by Lyon through the year 2007. An important factor in the after tax return of the landfill gas projects is the eligibility of these projects for Section 29 tax credits. The Section 29 tax credit is available only to projects that produce "qualified fuels". Landfill gas is a qualified fuel for purposes of the Section 29 credit. To qualify for the credit, the facility for producing gas must have been placed in service no later than June 30, 1998. Congress has not renewed the Section 29 credit for new landfill gas projects. RESOURCE RECOVERY FACILITIES The Company's Newport resource recovery facility, located in Newport, Minnesota, can process over 1,500 tons of Municipal Solid Waste, (MSW) per day, 90% of which is used as fuel in power generation facilities in Red Wing and Mankato, Minnesota and other recyclables. The Newport facility, which was originally constructed and operated by NSP, was transferred to the Company in 1993. The Company owns 100% of and operates and maintains the Newport facility. Pursuant to service agreements with Ramsey and Washington Counties, (Counties), which expire in 2007, the Company processes a minimum of 280,800 tons of MSW per year at the Newport facility and receives service fees based on the amount of waste processed, pass-through costs and certain other factors. The Company is also entitled to an operation and maintenance fee, which is designed to recover fixed costs and to provide the Company a guaranteed amount for operating and maintaining the Newport facility for the processing of 750 tons per day of MSW, whether or not the Counties deliver such waste for processing. Since 1989, the Company has operated the Elk River resource recovery facility located in Elk River, Minnesota, which can process over 1,500 tons of MSW per day, 90% of which is used as fuel in power generation facilities in Elk River and Mankato, Minnesota and other recyclables. NSP owns 85% of the Elk River facility, and United Power Association owns the remaining 15%. The Company also provides ash storage and disposal for the Elk River facility at NSP's Becker ash disposal facility, an approved ash deposit site adjacent to NSP's Sherburne County generating facility near Becker, Minnesota. The Company operates the Becker facility on behalf of NSP. Pursuant to an ash management services agreement between NSP and the counties, NSP receives an ash disposal fee based on the amount of ash disposal, pass-through costs and certain other factors. Refuse Derived Fuel (RDF) projects, such as the Company's Newport facility and NSP's Elk River facility, historically were assured adequate supply of waste through state and local flow control legislation, which directed that waste be disposed of in certain facilities. In May 1994, the United States Supreme Court held that such waste was a commodity in interstate commerce and, accordingly, that flow control legislation that prohibited shipment of waste out of state was unconstitutional. Since this ruling, the RDF facilities have faced increased competition from landfills in surrounding states in obtaining MSW. CROCKETT COGENERATION Pacific Crockett Energy, Inc., an indirect, wholly-owned subsidiary of the Company, is the general partner of the Crockett Cogeneration Project (Crockett). Crockett, a 240 MW gas fired plant began operations in May 1996. Pacific Generation Company, another wholly-owned subsidiary of the Company, owns a 56.67 percent limited partnership interest in Crockett through ENI Crockett LP (ENI Crockett). ENI Crockett is a limited partnership in which Pacific Generation Company is the general partner and Dynegy is a limited partner. The project sells 240 MW of capacity and energy to Pacific Gas & Electric Company under a modified Standard Offer No. 4 PPA extending to 2026. The PPA provides for a fixed capacity payment and a 13
16 variable energy payment based on the market price of gas. In addition, Crockett provides up to 450,000 lbs/hr of steam to the adjacent C&H Sugar refinery under a steam sales agreement that does not expire until 2026. Natural gas is supplied to the project by Amoco Canada Marketing Corp. under a fifteen year contract, with performance guaranteed by Amoco Canada Petroleum Company Ltd. ESOCO operates the project under a renewable 15 year contract that provides for reimbursement of all costs within an approved budget, plus a fee and provision for a performance bonus. Other limited partners include Energy Investors Fund LP and Energy Investors Fund II, LP and a subsidiary of Tomen Power Corp. Crockett was originally financed with a $260 million construction and term loan facility provided by a commercial bank syndicate led by ABN-AMRO. On December 15, 1999, Crockett was refinanced with a $255 million term loan facility provided by a commercial bank syndicate led by ABN-AMRO, maturing in December 31, 2014. NRG NORTHEAST GENERATING LLC The Company has acquired through its affiliates, in five separate transactions, certain generating assets from NIMO, ConEd, MEC, (a wholly owned subsidiary of Eastern Utilities Association (EUA)), and CL&P for a total cost of $1.5 billion. The Company has aggregated these assets into a regional generating company, NRG Northeast Generating LLC (NRG Northeast); (collectively, the NRG Northeast assets). The Company's Northeast assets represent competitive, low cost units with favorable market dynamics and locations close to major load centers in the New York Power Pool and New England Power Pool. Huntley and Dunkirk: In June 1999, the Company completed the acquisition of the Huntley and Dunkirk generating stations from NIMO for $355 million. The two coal-fired power generation facilities are located near Buffalo, New York and have a combined capacity rating of 1,360 MW. Oswego: On October 22, 1999, the Company completed the acquisition of the 1,700 MW oil and gas fired Oswego generating station for approximately $85 million from NIMO and Rochester Gas and Electric Corporation. Astoria Gas Turbines and Arthur Kill: In June 1999, the Company completed its acquisition of the Astoria gas turbine facility and the Arthur Kill Generating Station from ConEd for $505 million. These facilities, which are located in the New York City area and have a combined capacity rating of 1,456 MW. Somerset: In April 1999, the Company completed its acquisition of the Somerset power station for approximately $55 million from MEC. The Somerset station includes two coal fired base-load generating facilities supplying a total of 181 MW and two aeroderivative combustion turbine peaking units supplying a total of 48 MW, includes 69 MW on deactivated reserve. It is located on the west bank of the Taunton River in Somerset, Massachusetts and is interconnected with the NEPOOL market. Connecticut stations: In December 1999, the Company closed on the acquisition of four fossil fuel electric generating stations and six remote gas turbines totaling 2,235 MW from CL&P for $460 million, plus adjustments for working capital. The assets acquired from CL&P (CL&P Assets) are comprised of the Middletown, Montville, Devon and Norwalk Harbor gas- and oil-fired steam generating stations totaling 2,108 MW and 127 MW of remote gas turbines at Branford, Torrington and Cos Cob, Connecticut. Middletown station, an 856 MW gas and oil powered plant, is located in Middletown, Connecticut. The 498 MW Montville Station in Uncasville, Connecticut is composed of one gas- or oil-fired unit, one oil-fired unit and two diesel generators. Norwalk Station, with 353 MW of capacity from two oil-fired units and one gas turbine, is located on Manresa Island at the mouth of Norwalk Harbor. Devon Station, consisting of 401 MW of generation capacity derived from two gas- or oil-fired units and five gas turbines, is located at Milford, Connecticut. 14
17 SIGNIFICANT PENDING ACQUISITIONS AND PROJECTS UNDER DEVELOPMENT Because of the many complexities inherent in the acquisition, development and financing of projects, there can be no assurance that any of the Company's pending acquisitions and projects under development, including those described below, will be consummated. ENFIELD In December 1996, the Company reached an agreement with Indeck Energy Services (Europe) (Indeck) to sell a 50% interest in the Enfield Energy Center, a 396 MW gas-fired project in the North London borough of Enfield. In December 1998, the Company sold one-half of its 50% interest in the Enfield project to an affiliate of El Paso International. The power station was scheduled to commence commercial operations in November 1999, but due to operational problems, the power station completion date has been pushed back until mid-2000. Discussions are underway with EPC contractor to negotiate a settlement that will compensate the Company for the delay in completion of the power station. ESTONIA In December 1996, representatives of the Estonian Government, the state-owned Eesti Energia ("EE"), and the Company signed a development and cooperation agreement (DCA). The DCA defines the terms under which the parties are to establish a plan to develop and refurbish the Balti and Eesti Power Plants. Pursuant to the DCA, a business plan for the joint project was submitted in June 1997. In September 1997, the Estonian Government rejected the Company's business plan. However, early in 1998 the Estonian Government and EE agreed to work on a new business plan with the Company, which was submitted in May 1998. The Company has stated its willingness to invest up to $67.25 million of equity into the project and to assist the joint project in obtaining non-recourse debt to fund the required capital improvements to the Balti and Eesti Power Plants. A commission has been established to negotiate all terms and agreements between the Company, EE and the Estonian Government relating to the purchase of the Balti and Eesti Power Plants. The negotiation process is expected to be completed by the end of the third quarter of 2000. The Company has a policy of expensing all costs until there is a signed contract and Board of Directors approval. All such costs with respect to Estonia have been expensed. CAJUN The Company, together with its partner and the creditors' committee filed a plan with the United States Bankruptcy Court for the Middle District of Louisiana to acquire 1,708 MW of fossil generating assets from Cajun Electric Power Cooperative of Baton Rouge, Louisiana (Cajun) for approximately $1.0 billion. The consortium has the support of the Chapter 11 trustee and Cajun's secured creditors. During the third quarter of 1999, the U.S. Bankruptcy Judge confirmed the creditors plan of reorganization and the Company exercised an option to purchase its partner's 50 percent interest in the project. The Company expects to close the acquisition of the Cajun assets during the first quarter of 2000. KILLINGHOLME In November 1999, the Company agreed to purchase the 665 MW Killingholme A station from National Power plc. Killingholme A was commissioned in 1994 and is a combined-cycle, gas-turbine power station located in North Lincolnshire, England. The purchase price for the station will be approximately 410 million pounds sterling (approximately $662 million U.S. at end of year exchange rates), subject to commercial adjustments. The purchase price includes 20 million pounds sterling (approximately $32 million U.S. at end of year exchange rates) that is contingent upon the successful completion of negotiations regarding the Company's purchase of National Power's Blyth generating facilities. The Blyth assets consist of two coal-fired stations totaling 1,140 MW of generation capacity located in England. The acquisition of Killingholme is expected to close at the end of the first quarter of 2000. 15
18 CONECTIV ASSETS In January 2000, the Company agreed to purchase 1,875 MW of fossil-fueled electric generating capacity and other assets from Conectiv of Wilmington, Delaware for $800 million. The fossil-fueled generating facilities consist of Conectiv's wholly owned BL England, Deepwater, Indian River and Vienna steam stations plus Conectiv's interest in the Conemaugh and Keystone steam stations. Other assets in the purchase are the 241-acre Dorchester site located in Dorchester County, Maryland, certain Merrill Creek Reservoir entitlements in Harmony Township, New Jersey and certain excess emission allowances. The Company will sell 500 MW of energy to Delmarva (a subsidiary of Conectiv) under a five year power purchase agreement. The remaining energy and capacity will be sold in PJM and neighboring markets. The acquisition is expected to close at the end of the third quarter of 2000. The BL England Steam Station is a 447 MW coal and oil-fired generating facility in Beesley's Point, New Jersey. The Deepwater steam station is a 239 MW gas, oil and coal facility near Pensville, New Jersey. The Indian River Steam Station is a 784 MW coal fired facility near Millboro, Delaware. The Vienna Steam Station is a 170 MW oil-fired generating station located in the town of Vienna, Maryland. Of the 1,711 MW coal-fired Conemaugh Steam Station, located near Pittsburgh, Pennsylvania, the Company will acquire a 7.55 percent ownership or 129 MW of generation. The Company will also acquire a 6.17 percent ownership or 106 MW in the 1,711 MW coal-fired Keystone Steam Station also located near Pittsburgh, Pennsylvania. TURBINE PURCHASE AGREEMENT In January 2000, the Company executed a memorandum of understanding with GE Power Systems, a division of General Electric Company, to purchase 11 gas turbine generators and five steam turbine generators. The purchase will take place over the next five years and are valued at approximately $500 million with an option to purchase additional units. The 16 turbines have an equivalent generation output of 3,000 MW and will be installed at the Company's existing North American plant sites. PROJECT AGREEMENTS In the past, virtually all of the Company's operating power generation facilities have sold electricity under long-term power purchase agreements. A facility's revenue from a power purchase agreement usually consists of two components: energy payments and capacity payments. Several of the recent projects in which the Company has acquired or is acquiring do not have long-term power purchase agreements. For example, this is true for Enfield, because the United Kingdom has adopted a regulatory scheme under which all generators must sell their output to a grid where the price is established by a neutral regulator based on the market prices during each defined period. Similarly, the San Joaquin Valley Energy Partners Facilities accepted a buy-out of their long-term contracts, so if they recommence operations, it is anticipated that they will be "merchant" plants (i.e., plants operating without long-term power purchase agreements in place, selling their output into the market). The generation facilities which the Company has recently acquired in California, Connecticut, New York and Massachusetts are merchant plants, although a portion of the output of certain of these plants in the first several years of the Company's ownership of them is contracted for, either under transition power purchase contracts with their former owners or under bilateral contracts with other wholesale customers. In the case of the Kladno project, where there is a long-term agreement, the energy price is tied to the market price of electricity rather than to the costs incurred by the project, so the contract does not provide the traditional level of certainty and protection. In the case of the Loy Yang A project, Australian power pool prices have been significantly lower than anticipated at the time of the Company's purchase of its interest in the Loy Yang A project, resulting in earnings much lower than initially forecast. While these merchant projects introduce new risks and uncertainties, and require careful advance analysis of the local power markets, the Company believes that merchant projects are becoming increasingly accepted in the independent power market. The Company tries to obtain short, intermediate and long-term contracts for the sale of energy and capacity whenever feasible. 16
19 REGULATION The Company is subject to a broad range of federal, state and local energy and environmental laws and regulations applicable to the development, ownership and operation of its United States and international projects. These laws and regulations generally require that a number of permits and approvals be obtained before construction or operation of a power plant commences and that, after completion, the facility operate in compliance with local requirements. The Company strives to comply with the terms of all such laws, regulations, permits and licenses and believes that all of its operating plants are in material compliance with all such applicable requirements. No assurance can be given, however, that in the future all necessary permits and approvals will be obtained and all applicable statutes and regulations complied with. In addition, regulatory compliance for the construction of new facilities is a costly and time-consuming process, and intricate and rapidly changing environmental regulations may require major expenditures for permitting and create the risk of expensive delays or material impairment of project value if projects cannot function as planned due to changing regulatory requirements or local opposition. Furthermore, there can be no assurance that existing regulations will not be revised or that new regulations will not be adopted or become applicable to the Company which would have an adverse impact on its operations. ENVIRONMENTAL REGULATIONS Environmental controls at the federal, state, regional and local levels have a substantial impact on the Company's operations due to the cost of installation and operation of equipment required for compliance. Air On October 12, 1999, the Company received a letter from the Office of the Attorney General of the State of New York speculating that based on a preliminary analysis, it believes that significant modifications were made to the Huntley and Dunkirk facilities during NIMO's ownership of these facilities without obtaining Prevention of Significant Deterioration (PSD) and/or New Source Review (NSR) permits. The letter requested documents related to historic maintenance, repair, and replacement work at the facilities, as well as other data related to operations and emissions from these facilities. On January 12, 2000, the Company received a formal request from the New York Department of Environmental Conservation (NYDEC) seeking essentially the same documents covered by the Attorney General's letter. The Company understands that the NYDEC request supercedes the Attorney General's request. Although, the Company does not have reason to believe that NIMO failed to comply with the preconstruction permit requirements at the Huntley and Dunkirk facilities, the Company has recently initiated steps to investigate the allegations. If it is determined that these facilities did not comply with the PSD or NSR permit programs, the Company could be required among other things, to install pollution control technology to further control the emissions of nitrogen oxide (NOX) and sulfur dioxide (SO2) from the Huntley and Dunkirk facilities. By virtue of conditions imposed under the asset sale agreement between the Company and NIMO (the Company's rights and obligations under the asset sale agreement were substantially assigned to Huntley Power LLC and Dunkirk Power LLC), NIMO remains responsible for "any fines, penalties and assessments imposed by a governmental entity with respect to violation or alleged violation of Environmental Law which occurred prior to the Closing Date." Even so, the Company could become subject to fines and/or penalties associated with the period of time it has operated the facilities. On October 14, 1999, Governor Pataki of New York directed the Commissioner of the NYDEC to require further reductions of SO2 emissions and NOX emissions from New York power plants, beyond that which is required under current federal and state law. Under Governor Pataki's directive NOX emissions during the "non-ozone" season would be reduced to levels consistent with those currently mandated for the "ozone" season under the Ozone Transport Commission's Memorandum of Understanding. This additional reduction requirement would be phased in between January 1, 2003 and January 2, 2007. In addition, Governor Pataki announced that he is ordering a reduction of S02 emissions by 50% beyond the requirements of the Federal Acid Rain Program. These reductions would also be phased in between January 1, 2003 and January 1, 2007. Compliance with these emission reduction requirements, if they become effective, could have a material impact on the operation of the Company's facilities located in the State of New York. 17
20 On November 3, 1999, in the southern and mid-western regions of the United States, the United States Department of Justice (DOJ) filed suit against seven electric utilities for alleged violations of the Federal Clean Air Act (the Clean Air Act) NSR and PSD permit requirements at seventeen utility generating stations located in the southern and mid-western regions of the United States. In addition, the United States Environmental Protection Agency (U.S. EPA) issued administrative notices of violation alleging similar violations at eight other power plants owned by certain of the electric utilities named as defendants in the DOJ lawsuit, and also issued an administrative order to the Tennessee Valley Authority for similar violations at seven of its power plants. The DOJ lawsuit alleges that the defendants, over a period of twenty years, undertook modifications at their generating stations that resulted in increased air emissions without complying with regulatory requirements governing such modifications. Subsequent to the DOJ lawsuit, New York, Connecticut and New Jersey have brought their own lawsuits against American Electric Power, an Ohio based utility holding company, and have sought to intervene in the DOJ lawsuit. To date, no lawsuits or administrative actions have been brought against the Company or the former owners of the facilities alleging violations of the NSR or PSD requirements. However, there is a likelihood that future lawsuits alleging similar violations may be filed against additional electric utility generating stations. The Company can provide no assurance that lawsuits or administrative actions alleging violations of PSD and NSR requirements will not be filed in the future. The State of Connecticut has in the past considered legislation that would require older electrical generating stations to comply with more stringent pollution standards for NOX and SO2 emissions. During the 1999 legislative session, the Connecticut House of Representatives voted in favor of such legislation. The House bill was referred to the Energy Technology Committee where no action was taken. Similar legislation has been introduced as part of the 2000 legislative session. Site Contamination/Remediation With the acquisition of the NRG Northeast assets, the Company assumed certain liabilities for existing environmental conditions at the sites with the exception of off-site liabilities associated with the disposal of hazardous materials and certain other environmental liabilities. The Company has not assumed responsibility for any contamination resulting from the September 7, 1998 explosion and subsequent fire involving a transformer containing PCBs at the Arthur Kill Station. The transformer explosion, fire and subsequent oil spill resulted in the release of PCB's to the environment. ConEd maintains responsibility for the remediation of the PCB and other contamination associated with this event. Environmental site assessments have been prepared for all of the recently acquired NRG Northeast assets. The remediation activities at the Arthur Kill, Astoria Gas Turbine and Somerset facilities are still in the study phase. As such, the remediation costs estimates are based on approaches that have not been approved yet by the regulatory agencies involved. Data from additional investigations performed at the Astoria Gas Turbines and the approach being taken at the Somerset Station may result in less costly remediation efforts than originally estimated. For the Connecticut facilities, the Company is planning to conduct additional studies to better quantify remedial need. Such studies include the preparation of risk assessments to justify remedial actions proposed by the Company to the Connecticut Department of Environmental Protection and U.S. EPA. Costs The Company has recorded approximately $5.8 million for expected environmental costs related to site remediation issues at the Arthur Kill, Astoria facilities and Somerset facilities. These amounts are based on the environmental assessments for these sites. The Company has budgeted approximately $44 million for capital expenditures between 2000 and 2004 for environmental compliance, which includes the above remedial investigations, the installation of NOX control technology at the Somerset facility, intake screens at the Dunkirk facility, the resolution of consent orders for remediation at the Arthur Kill and Astoria facilities and the resolution of a consent order for water intake at the Arthur Kill facility. 18
21 EMPLOYEES At December 31, 1999, the Company had 1,323 employees, approximately 400 of whom are employed directly by the Company and approximately 923 of whom are employed by its wholly-owned subsidiaries. FORWARD-LOOKING STATEMENTS Forward looking statements above include but are not limited to the future performance of various facilities and expected operating results for future periods. In addition to any assumptions and other factors referred to specifically in connection with the forward-looking statements contained in this Form 10-K, factors that could cause the Company's actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following: - Economic conditions including inflation rates and monetary or currency exchange rate fluctuations; - Trade, monetary, fiscal, taxation, and environmental policies of governments, agencies and similar organizations in geographic areas where the Company has a financial interest; - Customer business conditions including demand for their products or services and supply of labor and materials used in creating their products and services; - Financial or regulatory accounting principles or policies imposed by the Financial Accounting Standards Board, the Securities and Exchange Commission, the Federal Energy Regulatory Commission and similar entities with regulatory oversight; - Availability or cost of capital such as changes in: interest rates; market perceptions of the power generation industry, the Company or any of its subsidiaries; or security ratings; - Factors affecting power generation operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, maintenance or repairs; unanticipated changes to fossil fuel, or gas supply costs or availability due to higher demand, shortages, transportation problems or other developments; environmental incidents; or electric transmission or gas pipeline system constraints; - Employee workforce factors including loss or retirement of key executives, collective bargaining agreements with union employees, or work stoppages; - Volatility of energy prices in a deregulated market environment; - Increased competition in the power generation industry; - Cost and other effects of legal and administrative proceedings, settlements, investigations and claims; - Technological developments that result in competitive disadvantages and create the potential for impairment of existing assets; - Factors associated with various investments including conditions of final legal closing, partnership actions, competition, operating risks, dependence on certain suppliers and customers, domestic and foreign environmental and energy regulations; - Limitations on the Company's ability to control the development or operation of projects in which the Company has less than 100% interest; - The lack of operating history at development projects, the lack of Company operating history at the projects not yet owned and the limited operating history at the remaining projects provide only a limited basis for management to project the results of future operations; - Risks associated with timely completion of projects located at ECKG and Enfield, including obtaining competitive contracts, obtaining regulatory and permitting approvals, local opposition, construction delays and other factors beyond the Company's control; 19
22 - The failure to timely satisfy the closing conditions contained in the definitive agreements for the acquisitions of projects subject to definitive agreements but not yet closed, many of which are beyond the Company's control; - Factors challenging the successful integration of projects not previously owned or operated by the Company, including the ability to obtain operating synergies; - Factors associated with operating in foreign countries including: delays in permitting and licensing, construction delays and interruption of business, political instability, risk of war, expropriation, nationalization, renegotiation, or nullification of existing contracts, changes in law, and the ability to convert foreign currency into United States dollars; - Other business or investment considerations that may be disclosed from time to time in the Company's Securities and Exchange Commission filings or in other publicly disseminated written documents, including the Company's Registration Statement No. 333-93055, as amended, and all supplements therein. The Company undertakes no obligation or publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors pursuant to the Act should not be construed as exhaustive. ITEM 2 -- PROPERTIES Listed below are descriptions of the Company's interests in facilities, operations or projects under construction as of December 31, 1999. INDEPENDENT POWER PRODUCTION AND COGENERATION FACILITIES (1) <TABLE> <CAPTION> LATER OF DATE NRG'S OF ACQUISITION TOTAL PERCENTAGE OR COMMERCIAL CAPACITY OWNERSHIP NAME AND LOCATION OF FACILITY OPERATION (MW)(2) INTEREST POWER PURCHASER - ----------------------------- -------------- -------- ---------- --------------- <S> <C> <C> <C> <C> INTERNATIONAL PROJECTS: Loy Yang Power (3), Australia......... 1997 2,000 25.37 Victorian Pool Gladstone Power Station, Australia.... 1994 1,680 37.50 QTPTC; Boyne Smelter Collinsville, Australia............... 1998 192 50.00 QTPTC Energy Developments Limited, Australia........................... 1997 274 29.14 Various Kladno Czech Republic, existing project............................. 1994 28 44.26 STE/Industrials Kladno Czech Republic, expansion project............................. 2000 345 44.50 STE/Industrials Schkopau Power Station, Germany....... 1996 960 20.95 VEAG MIBRAG mbH(3), (Mumsdorf) Germany..... 1994 110 33.33 WESAG/MIBRAG MIBRAG mbH(3), (Deuben) Germany....... 1994 86 33.33 WESAG/MIBRAG MIBRAG mbH(3), (Wahlitz) Germany...... 1994 37 33.33 WESAG/MIBRAG Enfield (London), UK.................. 2000 396 25.00 U.K. Electricity grid COBEE, Bolivia........................ 1996 219 49.10 Electropaz/ELF Bulo Bulo, Bolivia.................... 2000 80 30.00 Bolivian Grid Latin Power (Mamonal), Colombia....... 1994 90 6.45 Proelectrica/Electribol Latin Power (Termovalle), Colombia.... 1998 199 4.88 EPSA/Proelectrica Latin Power (Termotasajero), Columbia............................ 1998 150 10.03 Columbian Grid Latin Power (ELCOSA), Honduras........ 1994 80 7.65 ENEE Electrica Latin Power (Dr. Bird), Jamaica....... 1995 74 8.86 Jamaica Public Service Company, Ltd. Latin Power (Orzumil), Guatemala...... 1999 24 12.25 INDE Latin Power (Aguaytia), Peru.......... 1998 155 3.28 Central Peruvian Electricity Grid Kingston Cogeneration, Canada......... 1997 110 25.00 OntarioHydro Energy Investors Fund, 1 and 3 (Int'l)............................. 1997 1,039 0.25 Various </TABLE> 20
23 <TABLE> <CAPTION> LATER OF DATE NRG'S OF ACQUISITION TOTAL PERCENTAGE OR COMMERCIAL CAPACITY OWNERSHIP NAME AND LOCATION OF FACILITY OPERATION (MW)(2) INTEREST POWER PURCHASER - ----------------------------- -------------- -------- ---------- --------------- <S> <C> <C> <C> <C> DOMESTIC PROJECTS: El Segundo Power, California.......... 1998 1,020 50.00 Cal PX Long Beach Generating, California..... 1998 530 50.00 Cal PX Encina, California.................... 1999 965 50.00 Cal PX/bilateral contracts San Diego Combustion Turbines, Cal.... 1999 253 50.00 Cal PX/bilateral contracts Crockett Cogeneration, California..... 1997 240 57.67 PG&E Mt. Poso Cogeneration, California..... 1997 50 39.10 PG&E Power Smith Cogeneration, Okla........ 1997 110 8.75 OGE Energy Rocky Road Power, Illinois............ 1999 250 50.00 Electric Clearinghouse Cadillac Renewable Energy, Michigan... 1997 39 50.00 Consumers Energy Curtis-Palmer Hydro, New York......... 1997 58 8.50 NIMO/International Paper Dunkirk, New York..................... 1999 600 100.00 NIMO/NYISO Huntley, New York..................... 1999 760 100.00 NIMO/NYISO Oswego, New York...................... 1999 1,700 100.00 NIMO/NYISO Arthur Kill, New York................. 1999 842 100.00 Con Ed/NYISO Astoria Gas Turbines, New York........ 1999 614 100.00 Con Ed/NYISO Somerset (4), Massachusetts........... 1999 229 100.00 EUA/NEPOOL/ISO-NE Middletown, Connecticut............... 1999 856 100.00 NEPOOL/NYPP/ISO-NE Montville, Connecticut................ 1999 498 100.00 NEPOOL/NYPP/ISO-NE Norwalk, Connecticut.................. 1999 353 100.00 NEPOOL/NYPP/ISO-NE Devon, Connecticut.................... 1999 401 100.00 NEPOOL/NYPP/ISO-NE Connecticut Jet Power, Connecticut.... 1999 127 100.00 NEPOOL/NYPP/ISO-NE Penobscot Energy Recovery, Maine...... 1997 25 28.71 Bangor Hydro Maine Energy Recovery, Maine.......... 1997 22 16.25 Central Maine Power NEO Corporation....................... 1994 175 51.72 Various Energy Investors Fund, 1 and 3 (US)... 1997 1,030 1.12 Various COGENERATION CORPORATION OF AMERICA: CogenAmerica Pryor, Oklahoma.......... 1997 110 20.00 OGE Energy/PSO CogenAmerica Morris, Illinois......... 1998 117 20.00 Equistar/ComEd Grays Ferry CogenAmerica, Penn........ 1998 150 10.00 PECO Energy Philadelphia Water Dept, Penn......... 1996 22 16.60 Philadelphia Municipal Authority Newark CogenAmerica, New Jersey....... 1996 54 20.00 Jersey Central Power & Light Company Parlin Cogen America, New Jersey...... 1996 122 20.00 Jersey Central Power & Light Company IDLED FACILITIES San Joaquin Valley (Madera), California.......................... 1992 23 45.00 NA(5) San Joaquin Valley (Chowchilla), California.......................... 1992 10 45.00 NA(5) San Joaquin Valley (El Nido), California.......................... 1992 10 45.00 NA(5) Jackson Valley Energy Partners, California.......................... 1991 16 50.00 NA(6) Turners Falls, Mass................... 1997 20 8.90 NA(6) </TABLE> - --------------- (1) Includes assets under construction. (2) Capacity rating methods vary. (3) Loy Yang and MIBRAG also own coal mines and sell coal both to its respective power plant and to third parties. (4) Includes 69 MW on deactivated reserve. (5) Operations suspended following buy-out of power purchase contracts and pending negotiation of new power purchase agreements or sale of such facilities. (6) Operations are suspended. 21
24 THERMAL ENERGY PRODUCTION AND TRANSMISSION FACILITIES AND RESOURCE RECOVERY FACILITIES <TABLE> <CAPTION> NRG'S PERCENTAGE THERMAL ENERGY DATE OF OWNERSHIP PURCHASER/MSW NAME AND LOCATION OF FACILITY ACQUISITION CAPACITY(1) INTEREST SUPPLIER ----------------------------- ----------- ----------- ---------- -------------- <S> <C> <C> <C> <C> THERMAL ENERGY PRODUCTION AND TRANSMISSION FACILITIES San Francisco Thermal LLC, California...................... 1995 Steam; 490 mmBtu/hr 100.00 Approximately 185 customers (Purchased remaining 51%)....... 1999 (144 MWt) San Diego Power & Cooling, California...................... 1997 Chilled Water: 100.00 Approximately 19 8,000 tons/hr. customers Camas Power Boiler, Washington...................... 1997 200mmBtu/hr 100.00 Fort James Corp. (59 MWt) Grand Forks Air Force Base, North Dakota.................... 1992 105 mmBtu/hr. 100.00 Grand Forks Air Force (31 MWt) Base Minneapolis Energy Center (MEC), Minnesota....................... 1993 Stem: 1,408 mmBtu/hr. 100.00 Approximately 92 steam (413 MWt) Chilled customers and 39 chilled water: 40,750 tons/hr. water customers Hennepin Co. Energy Center, Minn............................ NA 290 mmBtu/hr 0.00 MEC Customers (85 MWt) Rock-Tenn, Minnesota............ 1992 Steam: 430 mmBtu/hr. 100.00 Rock-Tenn Company (126 MWt) Washco, Minnesota............... 1992 160 mmBtu/hr 100.00 Andersen Corporation (47 MWt) Minnesota Correctional Facility Pittsburgh Thermal LLC, Pennsylvania.................... 1995 Steam; 240 mmBtu/hr 100.00 Approximately 29 steam customers and 27 chilled water customers (Purchased remaining 51%)....... 1999 (70 MWt) Chilled Water-10,180 tons Energy Center Kladno, Czech Republic(2)..................... 1994 512 mmBtu/hr 44.26 City of Kladno (150 MWt) RESOURCE RECOVERY FACILITIES Newport, Minnesota.............. 1993 MSW: 1,500 tons/day 100.00 Ramsey and Washington Counties Elk River, Minnesota............ NA(3) MSW: 1,500 tons/day 0.00 Anoka, Hennepin, and Sherburne Counties; Tri-County Solid Waste Management Commission Penobscot Energy Recovery, Maine........................... 1997 MSW: 800 tons/day 28.71 Bangor Hydroelectric Company Maine Energy Recovery, Maine.... 1997 MSW: 680 tons/day 16.25 Central Maine Power </TABLE> - --------------- (1) Thermal production and transmission capacity is based on 1,000 Btus per pound of steam production or transmission capacity. The unit mmBtu is equal to one million Btus. (2) Kladno also is included in the Independent Power Production and Cogeneration Facilities table on the preceding page. (3) The Company operates the Elk River resource recovery facility on behalf of NSP. 22
25 OTHER PROPERTIES In addition to the above, the Company leases its offices at 1221 Nicollet Mall, Suite 700, Minneapolis, Minnesota 55403, under a five-year lease that expires in June 2002. Additional office space is leased in San Diego, California under a five and one-half year lease expiring in June 2004 and San Francisco, California under a five year lease expiring in April 2005. Thermal division leases and operates the Hennepin County Energy Center. ITEM 3 -- LEGAL PROCEEDINGS On or about July 12, 1999, Fortistar Capital Inc., a Delaware Corporation (Fortistar), filed a complaint in District Court (Fourth Judicial District, Hennepin County) in Minnesota against the Company, asserting claims for injunctive relief and for damages as a result of the Company's alleged breach of a confidentiality letter agreement with Fortistar relating to the Oswego facility (Letter Agreement). The Company disputes Fortistar's allegations and has asserted numerous counterclaims. A temporary injunction hearing was held on September 27, 1999. The acquisition of the Oswego facility was closed on October 22, 1999, following notification to the Court of Oswego Power's intention to close on that date. On January 14, 2000, the court denied Fortistar's request for a temporary injunction. The Company intends to continue to vigorously defend the suit and believes Fortistar's complaint to be without merit. No trial date has been set. There are no other material legal proceedings pending, other than ordinary routine litigation incidental to the Company's business, to which the Company is a party. There are no material legal proceedings to which an officer or director is a party or has a material interest adverse to the Company or its subsidiaries. There are no material administrative or judicial proceedings arising under environmental quality or civil rights statutes pending or known to be contemplated by governmental agencies to which the Company is or would be a party, other than those discussed in PART I Item I -- Business, Environmental Regulations. 23
26 PART II ITEM 5 -- MARKET PRICE OF AND DIVIDENDS ON THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS This is not applicable as the Company is a wholly-owned subsidiary of Northern States Power Company. 24
27 ITEM 7 -- MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Management's Discussion and Analysis of Financial Condition and Results of Operations is omitted per conditions as set forth in General Instructions I (1) (a) and (b) of Form 10-K for wholly owned subsidiaries. It is replaced with management's narrative analysis of the results of operations set forth in General Instructions I (2) (a) of Form 10-K for wholly-owned subsidiaries (reduced disclosure format). This analysis will primarily compare the Company's revenue and expense items for the year ended December 31, 1999 with the year ended December 31, 1998. RESULTS OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 1999 COMPARED TO THE YEAR ENDED DECEMBER 31, 1998 Net income for the year ended December 31, 1999, was $57.2 million, an increase of $15.5 million or 37.2%, compared to net income of $41.7 million in the same period in 1998. This increase was due to the factors described below. REVENUES For the year ended December 31, 1999, the Company had total revenues of $500.0 million, compared to $182.1 million for the year ended December 31, 1998, an increase of $317.9 million or 174.5%. The Company's operating revenues from wholly owned operations for the twelve months ended December 31, 1999 were $432.5 million, an increase of $332.1 million, or 330.7%, over the same period in 1998. Approximately $303.6 million of the increase in revenues was due to the acquisition of the NRG Northeast assets during 1999. Approximately $29.1 million of the increase is due to increased revenues due to the consolidation of Pittsburgh and San Francisco Thermal and the consolidation of Crockett Cogeneration during 1999. These increases in revenues were partially offset by a drop in the processing rates received by the Company's resource recovery operations. For the twelve months ended December 31, 1999, revenues from wholly owned operations consisted primarily of revenue from electrical generation (78.3%), heating, cooling and thermal activities (17.6%) and technical services (4.1%). Equity in earnings of unconsolidated affiliates was $67.5 million for the year ended December 31, 1999, compared to $81.7 million for the year ended December 31, 1998, a decrease of $14.2 million or 17.4%. The decrease was due to a $12.8 million reduction in earnings for the Company's interest in the West Coast power generation facilities resulting from unfavorable weather conditions during the summer of 1999 compared to the summer of 1998, which was more favorable than normal. In addition, the results of operations of the West Coast facilities were adversely impacted by project level debt that was issued during the year. Equity earnings were also reduced by lower earnings at Mt. Poso, by the consolidation of the Company's Thermal operations and Crockett Cogeneration subsidiaries during 1999 and by an unfavorable currency translation adjustment relating to the Kladno project. These reductions were partially offset by a favorable legal settlement at CogenAmerica and increased earnings from MIBRAG. OPERATING COSTS AND EXPENSES Cost of wholly owned operations was $269.9 million for the year ended December 31, 1999. This is an increase of $217.5 million or 414.9% over the same period in 1998. Approximately $194.9 million of this increase was due to the acquisition of the NRG Northeast assets during 1999. The remaining increase was due to the consolidation of the Company's Thermal operations and the addition of new projects during 1999 by the Company's NEO subsidiary. Cost of operations, as a percentage of revenues from wholly owned operations for the year, was 62.4% which is 10.2% higher than the same period in 1998. Depreciation and amortization costs were $37.0 million for the year ended December 31, 1999, compared to $16.3 million for the year ended December 31, 1998. The increase in depreciation and amortization was due primarily to the addition of the NRG Northeast assets and the addition of new projects by the Company's 25
28 NEO subsidiary during 1999. In addition, depreciation and amortization also increased due to the consolidation of the Company's Thermal operations and Crockett Cogeneration in 1999. General, administrative and development costs were $83.6 million for the year ended December 31, 1999, compared to $56.4 million for the year ended December 31, 1998. Approximately $8.0 million of the increase was due to the acquisition of the NRG Northeast assets during 1999. The remaining increase was due primarily to increased business development activities and increased legal, technical, and accounting expenses resulting from expanded operations. As a percent of total revenues, administrative and general expenses declined to 16.7% from 31.0% during the same period one-year earlier. OTHER INCOME (EXPENSE) Minority interest in projects was $2.5 million for the twelve-month period compared to $2.3 million for the same period in 1998. Minority interest relates to certain Pacific Generation projects that were acquired in November 1997 and certain Thermal operations which have a minority interest. In December 1999, the Company sold a portion of its interest in CogenAmerica, an affiliate of the Company for a pretax gain of approximately $11.0 million ($4.1 million after-tax) to Calpine. The Company retained a 20% interest in CogenAmerica. Other income was $6.4 million for the twelve months ended December 31, 1999 compared with $8.4 million for the twelve months ended December 31, 1998. The $2.0 million decline was due primarily to a reclassification of management fees to equity in earnings of unconsolidated affiliates and lower interest income from loans to affiliates. Interest expense was $93.4 million for the twelve months ended December 31, 1999 compared with $50.3 million for the twelve months ended December 31, 1998. The increase in interest expense was due primarily to the acquisition of the NRG Northeast assets and the incremental interest expense resulting from the $682 million of project level debt issued by NRG Northeast Generating LLC and to the issuance of $300 million and $240 million of senior notes in June 1999 and November 1999, respectively. Additionally, a higher average outstanding balance of the Company's revolving line of credit and the consolidation of Crockett Cogeneration and the Company's Thermal operations contributed to higher interest expense. INCOME TAX The Company has recognized an income tax benefit due to the recognition of certain tax credits. The net income tax benefit for the year ended December 31, 1999, increased by $0.4 million to $26.1 million as compared to $25.7 million in the same period one year earlier. The increase in tax benefits for the twelve month period was due to increased interest expense on domestic debt, project write downs and an increase in Section 29 credits related to the Company's NEO subsidiary operations and foreign tax benefits associated with the Loy Yang project, which was substantially offset by higher overall earnings. YEAR 2000 The Company incurred costs to modify or replace existing information technology systems (including computer software) and non-information technology systems, for uninterrupted operation in Y2K and beyond. A committee including senior management led the Company's initiatives to identify Y2K-related issues and to remediate business processes as necessary. The Company also partnered with its parent, NSP, for a consistent overall company process in addressing the Y2K issue. The Company completed its Y2K readiness project on schedule and was Y2K ready (including completion of final testing) at year-end 1999. The Company has spent approximately $11.8 million for Y2K efforts from 1998-1999. This includes $6.0 million in 1999. These costs have been expensed as incurred. To date, the Company is not aware of any material Y2K-related problems experienced by our information technology or non-information technology systems. Also, the Company has not been informed by any of its 26
29 material customers, suppliers or its other key business partners that any such parties experienced any material Y2K-related problems. The Company cannot guarantee, however, that either the Company or its key business partners will not experience any Y2K-related problems in the future. If such problems do occur, the Company cannot provide any assurance that they will not have any material adverse effect on its results of operations, liquidity or business prospects. 27
30 ITEM 7A -- QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The Company uses derivative financial instruments to mitigate the impact of changes in foreign currency exchange rates on its international project cash flows, electricity and fuel prices on margins and interest rates on the cost of borrowing. The fair value of the Company's interest rate hedging contracts is sensitive to changes in interest rates. As of December 31, 1999, a 10 percent increase in interest rates from then prevailing market rates would increase the market value of the Company's interest rate hedging contracts by approximately $27.8 million. Conversely, a 10 percent decrease in interest rates from the prevailing market rates would decrease the market value by approximately $25.8 million. See Note 12 to the Financial Statements under Item 8 for further discussion of this matter. During the third quarter of 1999, NRG Northeast, entered into $600 million of "treasury locks," at various interest rates, which expired in February 2000. These treasury locks were an interest rate hedge for an NRG Northeast bond offering which was completed on February 22, 2000. During the first quarter of 2000, the Company entered into $375 million of "treasury locks" at various interest rates, which expire in July 2000. These treasury locks are an interest rate hedge for the NRG South Central Generating LLC offering scheduled for the first quarter of 2000. The Company has an investment in the Kladno project in the Czech Republic. Statement of Financial Accounting Standard (SFAS) No. 52, Foreign Currency Translation, requires foreign currency gains and losses to flow through the income statement if settlement of an obligation is in a currency other than the local currency of the entity. A portion of the Kladno project debt is in a non-local currency (U.S. dollars and German deutsche marks). As of December 31, 1999, if the value of the Czech koruna decreases by 10 percent in relation to the U.S. dollar and the German deutsche mark, the Company would record a $5.0 million loss (after tax) on the currency transaction adjustment. If the value of the Czech koruna increased by 10 percent, the Company would record a $5.0 million gain (after tax) on the currency transaction adjustment. These currency fluctuations are inherent to the debt structure of the project and not indicative of the long-term earnings potential of the investment. Kladno is the only project the Company has at this time with this type of debt structure. The Company's power marketing subsidiary is exposed to the risk of changes in market prices of fuel oil, natural gas and electricity. To manage exposure to volatility in the fuel oil, natural gas and electricity markets, the Company uses a variety of energy contracts, including options, swaps and forward contracts. As of December 31, 1999, a 10 percent increase in fuel oil, natural gas and electricity forward prices would result in a gain on these contracts of approximately $11.9 million. Conversely, a 10 percent decrease in fuel oil, natural gas and electricity forward prices would result in a loss on these contacts of approximately $11.9 million. These hypothetical gains and losses on energy forward contracts would be offset by the gains and losses on the underlying commodities being hedged. 28
31 ITEM 8 -- FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA <TABLE> <CAPTION> PAGE NO. -------- <S> <C> Report of Independent Accountants........................... 30 Consolidated Statement of Income............................ 31 Consolidated Statement of Cash Flows........................ 32 Consolidated Balance Sheet.................................. 33 Consolidated Statement of Stockholders' Equity.............. 34 Notes to Consolidated Financial Statements.................. 35 </TABLE> 29
32 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Stockholder of NRG Energy, Inc.: In our opinion, the accompanying consolidated balance sheet and the related consolidated statement of income, of stockholder's equity and of cash flows present fairly, in all material respects, the financial position of NRG Energy, Inc. (a wholly-owned subsidiary of Northern States Power Company) and its subsidiaries at December 31, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. /s/ PRICEWATERHOUSECOOPERS LLP March 17, 2000 30
33 NRG ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF INCOME <TABLE> <CAPTION> YEAR ENDED DECEMBER 31, -------------------------------- 1999 1998 1997 ---- ---- ---- (THOUSANDS OF DOLLARS) <S> <C> <C> <C> OPERATING REVENUES Revenues from wholly-owned operations..................... $432,518 $100,424 $ 92,052 Equity in earnings of unconsolidated affiliates........... 67,500 81,706 26,200 -------- -------- -------- Total operating revenues............................... 500,018 182,130 118,252 -------- -------- -------- OPERATING COSTS AND EXPENSES Cost of wholly-owned operations........................... 269,900 52,413 46,717 Depreciation and amortization............................. 37,026 16,320 10,310 General, administrative and development................... 83,572 56,385 43,116 -------- -------- -------- Total operating costs and expenses 390,498 125,118 100,143 -------- -------- -------- OPERATING INCOME............................................ 109,520 57,012 18,109 -------- -------- -------- OTHER INCOME (EXPENSE) Minority interest in earnings of consolidated subsidiary............................................. (2,456) (2,251) (131) Gain on sale of interest in projects...................... 10,994 29,950 8,702 Write-off of project investments.......................... -- (26,740) (8,964) Other income, net......................................... 6,432 8,420 11,764 Interest expense.......................................... (93,376) (50,313) (30,989) -------- -------- -------- Total other expense.................................... (78,406) (40,934) (19,618) -------- -------- -------- INCOME (LOSS) BEFORE INCOME TAXES........................... 31,114 16,078 (1,509) INCOME TAX BENEFIT.......................................... (26,081) (25,654) (23,491) -------- -------- -------- NET INCOME.................................................. $ 57,195 $ 41,732 $ 21,982 ======== ======== ======== </TABLE> See notes to consolidated financial statements. 31
34 NRG ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF CASH FLOWS <TABLE> <CAPTION> YEAR ENDED DECEMBER 31, ----------------------------------- 1999 1998 1997 ---- ---- ---- (THOUSANDS OF DOLLARS) <S> <C> <C> <C> CASH FLOWS FROM OPERATING ACTIVITIES Net income............................................... $ 57,195 $ 41,732 $ 21,982 Adjustments to reconcile net income to net cash provided by operating activities Undistributed equity in earnings of unconsolidated affiliates.......................................... (27,181) (23,391) 6,481 Depreciation and amortization......................... 37,026 16,320 10,310 Deferred income taxes and investment tax credits...... (3,401) 7,618 3,107 Minority interest..................................... 857 (5,019) -- Investment write-downs................................ -- 26,740 8,964 Gain on sale of investments........................... (10,994) (29,950) (8,702) Cash provided (used) by changes in certain working capital items, net of effects from acquisitions and dispositions Accounts receivable................................. (99,608) 297 (2,859) Accounts receivable-affiliates...................... 9,964 21,657 (19,963) Accrued income taxes................................ 25,834 (24,861) 1,762 Inventory........................................... (17,287) (28) (307) Other current assets................................ (13,433) 469 305 Accrued property and sales taxes.................... 1,740 (553) 1,645 Accounts payable.................................... 40,616 (8,082) 7,791 Accrued salaries, benefits, and related costs....... 1,955 4,735 3,826 Accrued interest.................................... 5,192 1,050 1,215 Other current liabilities........................... (3,533) (2,219) 6,084 Cash used by changes in other assets and liabilities...................................... (16,322) (4,517) (7,155) ----------- --------- --------- NET CASH (USED) PROVIDED BY OPERATING ACTIVITIES........... (11,380) 21,998 34,486 ----------- --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES Investments in projects............................... (163,340) (132,379) (318,149) Acquisition, net of liabilities assumed............... (1,519,365) -- (148,830) Consolidation of equity subsidiaries.................. 20,181 -- -- Cash from sale of project investment.................. 43,500 18,053 19,158 Decrease (increase) in notes receivable............... 58,331 16,858 (37,431) Capital expenditures.................................. (94,853) (31,719) (26,936) (Increase) decrease in restricted cash................ (13,067) (2,433) 16,100 Other, net............................................ -- -- 10,114 ----------- --------- --------- NET CASH USED BY INVESTING ACTIVITIES...................... (1,668,613) (131,620) (485,974) ----------- --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES Net borrowings under line of credit agreement......... 216,000 2,000 122,000 Capital contributions from parent..................... 250,000 100,000 80,900 Proceeds from issuance of long-term debt.............. 575,633 23,169 254,061 Proceeds from issuance of note........................ 682,096 -- -- Principal payments on long-term debt.................. (18,634) (21,152) (5,925) ----------- --------- --------- NET CASH PROVIDED BY FINANCING ACTIVITIES.................. 1,705,095 104,017 451,036 ----------- --------- --------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS....... 25,102 (5,605) (452) CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR............. 6,381 11,986 12,438 =========== ========= ========= CASH AND CASH EQUIVALENTS AT END OF YEAR................... $ 31,483 $ 6,381 $ 11,986 =========== ========= ========= SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION Interest paid (net of amount capitalized)............. $ 82,891 $ 49,089 $ 30,890 Income taxes paid (benefits received), net............ (54,384) (6,797) (24,577) </TABLE> See notes to consolidated financial statements. 32
35 NRG ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET <TABLE> <CAPTION> DECEMBER 31, ----------------------- 1999 1998 ---- ---- (THOUSANDS OF DOLLARS) <S> <C> <C> ASSETS CURRENT ASSETS Cash and cash equivalents................................. $ 31,483 $ 6,381 Restricted cash........................................... 17,441 4,021 Accounts receivable-trade, less allowance for doubtful accounts of $186 and $100............................... 126,376 15,223 Accounts receivable-affiliates............................ -- 7,324 Taxes Receivable.......................................... -- 21,169 Current portion of notes receivable -- affiliates......... 287 4,460 Current portion of notes receivable....................... -- 26,200 Inventory................................................. 119,181 2,647 Prepayments and other current assets...................... 29,202 4,533 ---------- ---------- Total current assets.................................... 323,970 91,958 ---------- ---------- PROPERTY, PLANT AND EQUIPMENT, AT ORIGINAL COST In service................................................ 2,022,724 291,558 Under construction........................................ 53,448 5,352 ---------- ---------- Total property, plant and equipment..................... 2,076,172 296,910 Less accumulated depreciation............................. (156,849) (92,181) ---------- ---------- Net property, plant and equipment....................... 1,919,323 204,729 ---------- ---------- OTHER ASSETS Investments in projects................................... 988,671 800,924 Capitalized project costs................................. 2,592 13,685 Notes receivable, less current portion -- affiliates...... 65,494 101,887 Notes receivable, less current portion.................... 5,787 3,744 Intangible assets, net of accumulated amortization of $4,308 and $2,984....................................... 55,586 22,507 Debt issuance costs, net of accumulated amortization of $6,640 and $1,675....................................... 20,081 7,276 Other assets, net of accumulated amortization of $8,909 and $7,350.............................................. 50,180 46,716 ---------- ---------- Total other assets...................................... 1,188,391 996,739 ---------- ---------- TOTAL ASSETS................................................ $3,431,684 $1,293,426 ---------- ---------- LIABILITIES AND STOCKHOLDER'S EQUITY CURRENT LIABILITIES Current portion of project level long-term debt........... $ 30,462 $ 8,258 Revolving line of credit.................................. 340,000 -- Consolidated project level, non-recourse debt............. 35,766 -- Accounts payable-trade.................................... 61,211 7,371 Accounts payable-affiliate................................ 6,404 -- Accrued income taxes...................................... 4,730 -- Accrued property and sales taxes.......................... 4,998 3,251 Accrued salaries, benefits and related costs.............. 9,648 7,551 Accrued interest.......................................... 13,479 7,648 Other current liabilities................................. 17,657 8,289 ---------- ---------- Total current liabilities............................... 524,355 42,368 OTHER LIABILITIES: Minority interest......................................... 14,373 13,516 Consolidated project-level, long-term, non-recourse debt.................................................... 1,026,398 113,437 Corporate level long-term debt, less current portion...... 915,000 504,781 Deferred Income Taxes..................................... 16,940 19,841 Deferred Investment Tax Credits........................... 1,088 1,343 Postretirement and other benefit obligations.............. 24,613 11,060 Other long-term obligations and deferred income........... 15,263 7,748 ---------- ---------- Total liabilities....................................... 2,538,030 714,094 ---------- ---------- STOCKHOLDER'S EQUITY Common stock; $1 par value; 1,000 shares authorized; 1,000 shares issued and outstanding........................... 1 1 Additional paid-in capital................................ 781,913 531,913 Retained earnings......................................... 187,210 130,015 Accumulated other comprehensive income.................... (75,470) (82,597) ---------- ---------- Total Stockholder's Equity.............................. 893,654 579,332 ---------- ---------- TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY.................. $3,431,684 $1,293,426 ========== ========== </TABLE> See notes to consolidated financial statements. 33
36 NRG ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF STOCKHOLDER'S EQUITY <TABLE> <CAPTION> ACCUMULATED ADDITIONAL OTHER TOTAL COMMON PAID-IN RETAINED COMPREHENSIVE STOCKHOLDER'S STOCK CAPITAL EARNINGS INCOME EQUITY ------ ---------- -------- ------------- ------------- (THOUSANDS OF DOLLARS) <S> <C> <C> <C> <C> <C> BALANCES AT DECEMBER 31, 1996.......... $1 $351,013 $ 66,301 $ 4,599 $421,914 == ======== ======== ======== ======== Net Income............................. 21,982 21,982 Currency translation adjustments....... (74,098) (74,098) -------- Comprehensive income for 1997.......... (52,116) Capital contributions from parent...... 80,900 80,900 -- -------- -------- -------- -------- BALANCES AT DECEMBER 31, 1997.......... $1 $431,913 $ 88,283 $(69,499) $450,698 == ======== ======== ======== ======== Net Income............................. 41,732 41,732 Currency translation adjustments....... (13,098) (13,098) -------- Comprehensive income for 1998.......... 28,634 Capital contributions from parent...... 100,000 100,000 -- -------- -------- -------- -------- BALANCES AT DECEMBER 31, 1998.......... $1 $531,913 $130,015 $(82,597) $579,332 == ======== ======== ======== ======== Net Income............................. 57,195 57,195 Currency translation adjustments....... 7,127 7,127 -------- Comprehensive income for 1999.......... 64,322 Capital contributions from parent...... 250,000 250,000 -- -------- -------- -------- -------- BALANCES AT DECEMBER 31, 1999.......... $1 $781,913 $187,210 $(75,470) $893,654 == ======== ======== ======== ======== </TABLE> Other comprehensive income is shown net of tax expenses (benefits) which were $0 during both 1999 and 1998 and $5.9 million in 1997. See notes to consolidated financial statements. 34
37 NOTE 1 -- ORGANIZATION NRG Energy, Inc. (the Company), a Delaware Corporation, was incorporated on May 29, 1992, as a wholly owned subsidiary of Northern States Power Company (NSP). Beginning in 1989, the Company was doing business through its predecessor companies, NRG Energy, Inc. and NRG Group, Inc., Minnesota corporations, which were merged into the Company subsequent to its incorporation. The Company and its subsidiaries and affiliates develop, build, acquire, own and operate non-regulated energy-related businesses. NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES PRINCIPLES OF CONSOLIDATION AND BASIS OF PRESENTATION The consolidated financial statements include the accounts of the Company and its subsidiaries (referred to collectively herein as the Company). All significant intercompany transactions and balances have been eliminated in consolidation. Accounting policies for all of the Company's operations are in accordance with accounting principles generally accepted in the United States. As discussed in Note 5, the Company has investments in partnerships, joint ventures and projects for which the equity method of accounting is applied. Earnings from equity in international investments are recorded net of foreign income taxes. CASH EQUIVALENTS Cash equivalents include highly liquid investments (primarily commercial paper) with a remaining maturity of three months or less at the time of purchase. RESTRICTED CASH Restricted cash consists primarily of cash collateral for letters of credit issued in relation to project development activities and funds held in trust accounts to satisfy the requirements of certain debt agreements. INVENTORY Inventory is valued at the lower of average cost or market and consists principally of fuel oil, coal, spare parts and raw materials used to generate steam. PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment are capitalized at original cost. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance are charged to expense as incurred. Depreciation is computed using the straight-line method over the following estimated useful lives: <TABLE> <S> <C> Facilities and improvements................................. 10-45 years Machinery and equipment..................................... 7-30 years Office furnishings and equipment............................ 3-5 years </TABLE> CAPITALIZED INTEREST Interest incurred on funds borrowed to finance projects expected to require more than three months to complete is capitalized. Capitalization of interest is discontinued when the project is completed and considered operational. Capitalized interest is amortized using the straight line method over the useful life of the related project. Capitalized interest was $287,000 and $172,000 in 1999 and 1998, respectively. DEVELOPMENT COSTS AND CAPITALIZED PROJECT COSTS These costs include professional services, dedicated employee salaries, permits, and other costs which are incurred incidental to a particular project. Such costs are expensed as incurred until a sales agreement or letter of intent is signed, and the project has been approved by the Company's Board of Directors. Additional costs incurred after this point are capitalized. When project operations begin, previously capitalized project costs are 35
38 reclassified to investment in projects and amortized on a straight-line basis over the lesser of the life of the project's related assets or revenue contract period. DEBT ISSUANCE COSTS Costs to issue long-term debt have been capitalized and are being amortized over the terms of the related debt. INTANGIBLES Intangibles consist principally of the excess of the cost of investment in subsidiaries over the underlying fair value of the net assets acquired and are being amortized using the straight-line method over 20 to 30 years. The Company periodically evaluates the recovery of goodwill and other intangibles based on an analysis of estimated undiscounted future cash flows. OTHER LONG TERM ASSETS Other long-term assets consist primarily of service agreements and operating contracts. These assets are being amortized over the remaining terms of the individual contracts, which range from seven to twenty-eight years. INCOME TAXES The Company is included in the consolidated tax returns of NSP. The Company calculates its income tax provision on a separate return basis under a tax sharing agreement with NSP as discussed in Note 9. Current federal and state income taxes are payable to or receivable from NSP. The Company records income taxes using the liability method. Income taxes are deferred on all temporary differences between pretax financial and taxable income and between the book and tax bases of assets and liabilities. Deferred taxes are recorded using the tax rates scheduled by law to be in effect when the temporary differences reverse. The Company's policy for income taxes related to international operations is discussed in Note 9. REVENUE RECOGNITION Under fixed-price contracts, revenues are recognized as products or services are delivered. Revenues and related costs under cost reimbursable contract provisions are recorded as costs are incurred. Anticipated future losses on contracts are charged against income when identified. FOREIGN CURRENCY TRANSLATION The local currencies are generally the functional currency of the Company's foreign operations. Foreign currency denominated assets and liabilities are translated at end-of-period rates of exchange. The resulting currency adjustments are accumulated and reported as a separate component of stockholder's equity. Income, expense, and cash flows are translated at weighted-average rates of exchange for the period. DERIVATIVE FINANCIAL INSTRUMENTS To preserve the U.S. dollar value of projected foreign currency cash flows, the Company hedges, or protects, those cash flows if appropriate foreign hedging instruments are available. The gains and losses on those agreements offset the effect of exchange rate fluctuations on the Company's known and anticipated cash flows. The Company defers gains on agreements that hedge firm commitments of cash flows, and accounts for them as part of the relevant foreign currency transaction when the transaction occurs. The Company defers expected losses on these agreements, unless it appears that the deferral would result in recognizing a loss later. While the Company is not currently hedging investments involving foreign currency, the Company will hedge such investments when it believes that preserving the U.S. dollar value of the investment is appropriate. 36
39 The Company is not hedging currency translation adjustments related to future operating results. The Company does not speculate in foreign currencies. From time to time the Company also uses interest rate hedging instruments to protect it from an increase in the cost of borrowing. Gains and losses on interest rate hedging instruments are reported as part of the asset for Investments In Projects when the hedging instrument relates to a project that has financial statements that are not consolidated into the Company's financial statements. Otherwise, they are reported as part of debt. USE OF ESTIMATES The preparation of financial statements in conformity with Generally Accepted Accounting Principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. In recording transactions and balances resulting from business operations, the Company uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, tax provisions, uncollectible accounts and actuarially determined benefit costs, among others. As better information becomes available (or actual amounts are determinable), the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates. NEW ACCOUNTING PRONOUNCEMENTS In June 1998, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standard (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities,". This statement requires that all derivatives be recognized at fair value in the balance sheet and that changes in fair value be recognized either currently in earnings or deferred as a component of Other Comprehensive Income, depending on the intended use of the derivative, its resulting designation and its effectiveness. The Company plans to adopt this standard in the first quarter of 2001, as required. The Company has not determined the potential impact of implementing this statement. RECLASSIFICATIONS Certain prior-year amounts have been reclassified for comparative purposes. These reclassifications had no effect on net income or stockholder's equity as previously reported. NOTE 3 -- ASSET ACQUISITIONS AND DIVESTITURES In February 1999, the Company purchased from Thermal Ventures, Inc. (TVI) the remaining 50.1% limited partnership interests held by TVI in San Francisco Thermal Limited Partnership and Pittsburgh Thermal Limited Partnership for $12.3 million. In April 1999, NRG acquired TVI's 50% member interest in North American Thermal Systems LLC (the entity holding the general partnership interest in the San Francisco and Pittsburgh partnerships) for $500,000. In 1994, the Company, through a wholly-owned subsidiary, purchased a 50% ownership interest in Sunnyside Cogeneration Associates, a Utah joint venture, which owns and operates a 58 MW waste coal plant in Utah. The waste coal plant is currently being operated by a partnership that is 50% owned by a Company affiliate. In March 1999, the Company and its partner executed an agreement to sell the Sunnyside project to an affiliate of Baltimore Gas & Electric for a purchase price of $2.0 million. There was no gain or loss on the sale which closed during the second quarter of 1999. In April 1999, the Company completed the acquisition of the Somerset power station for approximately $55 million from the Eastern Utilities Association (EUA). The Somerset station, located in Somerset, Massachusetts, includes two coal-fired generating facilities and two aeroderivative combustion turbine peaking units with a capacity rating of 229 MW, of which 69 MW is on deactivated reserve. In connection with this acquisition, the Company entered into a Wholesale Standard Offer Service Agreement pursuant to which the 37
40 Company is obligated to provide approximately 30% of the energy and capacity requirements of certain EUA affiliates (which is estimated to be approximately 275 MW at peak requirement) until December 31, 2009. In May 1999, the Company and Dynegy Power Corporation (Dynegy), through West Coast Power LLC, completed the acquisition of the Encina generating station and 17 combustion turbines for approximately $356 million from San Diego Gas & Electric Company. The facilities, which have a combined capacity rating of 1,218 MW, are located near Carlsbad and San Diego, California. The Company and Dynegy each own a 50% interest in these facilities. In June 1999, the Company completed its acquisition of the Huntley and Dunkirk generating stations from Niagara Mohawk Power Corporation (NIMO) for approximately $355 million. The two coal-fired power generation facilities are located near Buffalo, New York, and have a combined summer capacity rating of 1,360 MW. In connection with this acquisition, the Company entered into several Transition Power Purchase Agreements and a related swap agreement with NIMO pursuant to which NIMO purchases certain energy and capacity from these facilities for a term of four years. In June 1999, the Company completed its acquisition of the Arthur Kill generating station and the Astoria gas turbine site from Consolidated Edison Company of New York, Inc. (ConEd) for approximately $505 million. These facilities, which are located in the New York City Area, have a combined capacity rating of 1,456 MW. In connection with the acquisition of each facility, the Company entered into (i) Transition Energy Sales Agreements pursuant to which energy from each facility is sold to ConEd for a transition period ending on the date on which the independent system operator in New York State (NYISO) commences operation (which commencement date was November 18, 1999) of a spot market for energy and certain ancillary services, and (ii) Transition Capacity Sales Agreements pursuant to which capacity from each facility is sold to ConEd for a transition period ending on the later of (a) the earlier of (i) December 31, 2002 or (ii) the date such facility receives notice from the NYISO that none of the electric generating capacity of such facility is required for meeting the installed capacity requirements in New York City, or (b) the date the NYISO commences an auction for system capacity. Pursuant to the Transition Energy Sales Agreements, the Company agreed to sell to ConEd at a fixed price varying amounts of energy from the Arthur Kill generating facility and the Astoria gas turbine generating facility, in each case in amounts to be specified by ConEd, up to the full capability of each facility. Pursuant to the Transition Capacity Sales Agreements, the Company agreed to sell to ConEd at a fixed price, during certain periods, up to 100% of the capacity of the Arthur Kill generating facility and up to 100% of the capacity of the Astoria gas turbines facility. In August, the Company agreed to sell all but a 20 percent ownership interest in Cogeneration Corporation of America (CogenAmerica) to Calpine Corporation in connection with Calpine's acquisition of the remaining shares of CogenAmerica. Prior to December 1999, the Company owned approximately 45% of CogenAmerica. Upon closing of the transaction, all outstanding shares of CogenAmerica common stock (other than those retained by the Company) were acquired by Calpine for a cash purchase price of $25.00 per share. The transaction closed during the fourth quarter of 1999 and the Company retained a 20% ownership interest in CogenAmerica. In October 1999, the Company completed its acquisition of the Oswego generating station from NIMO and Rochester Gas and Electric for approximately $85 million. The oil and gas-fired power generating facility which has a capacity rating of 1,700 MW, is located on a 93-acre site in Oswego, New York. This facility consists of two units each having a capacity rating of 850 MW. In connection with this acquisition, the Company entered into a Transition Power Purchase Agreement with NIMO similar to those entered into in connection with the acquisitions of the Dunkirk and Huntley facilities. Pursuant to this agreement, the Company has agreed to sell 100% of the capacity of one unit, an option for up to 40% of the capacity of the other unit. The Company has agreed to sell NIMO an option to purchase a nominal amount of energy for a term of four years. In December 1999, the Company acquired four fossil fuel generating stations and six remote gas turbines from CL&P for approximately $460 million, plus adjustments for working capital. These facilities are located throughout Connecticut and have a combined nominal capacity rating of 2,235 MW. The Company entered into a Standard Offer Service Wholesale Sales Agreement with CL&P pursuant to which the Company will 38
41 supply CL&P with 35% of its standard offer service load during 2000, 40% during 2001 and 2002, and 45% during 2003. The Company estimates that 45% of CL&P's standard offer service load in 2003 will be approximately 2,070 MW at peak requirement. The Agreement terminates on December 31, 2003. In December 1999, the Company purchased a 50% interest in the Rocky Road Power Plant, a 250 MW natural gas fired simple-cycle peaking facility in East Dundee, IL from Dynegy Inc., for approximately $60 million. The power plant began commercial operations on June 30, 1999 and received approval for the installation of an additional 100 MW natural gas combustion turbine in October 1999, increasing the facilities generating capacity to a nominal 350 MW. The expansion is expected to be in service before the start of the peak summer 2000 season. Pro forma information has not been presented for the assets acquired in 1999 due to the fact that the assets acquired do not constitute businesses under Rule 11-01(d) of Regulation S-X. Accordingly, historical financial information does not exist for the assets acquired. NOTE 4 -- PROPERTY, PLANT AND EQUIPMENT The major classes of property, plant and equipment at December 31 were as follows: <TABLE> <CAPTION> 1999 1998 ---- ---- (THOUSANDS OF DOLLARS) <S> <C> <C> Facilities and equipment, including construction work in progress of $53,448 and $5,352................... $2,000,541 $280,876 Land and improvements................................. 64,330 10,397 Office furnishings and equipment...................... 11,301 5,637 ---------- -------- Total property, plant and equipment.............. 2,076,172 296,910 Accumulated depreciation.............................. (156,849) (92,181) ---------- -------- Net property, plant and equipment..................... $1,919,323 $204,729 ========== ======== </TABLE> NOTE 5 -- INVESTMENTS ACCOUNTED FOR BY THE EQUITY METHOD The Company has investments in various international and domestic energy projects. The equity method of accounting is applied to such investments in affiliates, which include joint ventures and partnerships, because the ownership structure prevents the Company from exercising a controlling influence over operating and financial policies of the projects. Under this method, equity in pretax income or losses of domestic partnerships and, generally, in the net income or losses of international projects are reflected as equity in earnings of unconsolidated affiliates. 39
42 A summary of the Company's significant equity-method investments which were in operation at December 31, 1999 is as follows: <TABLE> <CAPTION> ECONOMIC PURCHASED OR NAME GEOGRAPHIC AREA INTEREST PLACED IN SERVICE ---- --------------- -------- ----------------- <S> <C> <C> <C> Loy Yang A................................... Australia 25.37% May 1997 Energy Developments Limited.................. Australia 29.14% February 1997 ECK Generating............................... Czech Republic 44.50% December 1994 MIBRAG mbH................................... Germany 33.33% January 1994 Gladstone Power Station...................... Australia 37.50% March 1994 Schkopau Power Station....................... Germany 20.95% January and July 1996 Scudder Latin American Projects.............. Latin America 6.63% June 1993 Long Beach Generating........................ USA 50.00% April 1998 El Segundo Power............................. USA 50.00% April 1998 Bolivian Power Company (Cobee)............... Bolivia 49.10% December 1996 Cogeneration Corp. of America................ USA 20.00% April 1996 Encina....................................... USA 50.00% May 1999 San Diego Combustion Turbines................ USA 50.00% May 1999 </TABLE> Summarized financial information for investments in unconsolidated affiliates accounted for under the equity method as of and for the year ended December 31, is as follows: <TABLE> <CAPTION> 1999 1998 1997 ---- ---- ---- (THOUSANDS OF DOLLARS) <S> <C> <C> <C> Operating revenues....................................... $1,732,521 $1,491,197 $1,612,897 Costs and expenses....................................... 1,531,958 1,346,569 1,522,727 ---------- ---------- ---------- Net income.......................................... $ 200,563 $ 144,628 $ 90,170 ---------- ---------- ---------- Current assets........................................... $ 742,674 $ 710,159 $ 713,390 Noncurrent assets........................................ 7,322,219 7,938,841 7,733,886 ---------- ---------- ---------- Total assets........................................ $8,064,893 $8,649,000 $8,447,276 ---------- ---------- ---------- Current liabilities...................................... $ 708,114 $ 527,196 $ 472,980 Noncurrent liabilities................................... 5,168,893 5,854,284 6,042,102 Equity................................................... 2,187,886 2,267,520 1,932,194 ---------- ---------- ---------- Total liabilities and equity........................ $8,064,893 $8,649,000 $8,447,276 NRG's share of equity.................................... $ 988,671 $ 800,924 $ 694,655 NRG's share of income.................................... $ 67,500 $ 81,706 $ 26,200 </TABLE> In accordance with FASB No. 121 "Accounting for Impairment of Long-lived Assets to be Disposed of," the Company reviews long lived assets, investments and certain intangibles for impairment whenever events or circumstances indicate the carrying amounts of an asset may not be recoverable. During 1998, the Company wrote down accumulated project development expenditures of $26.7 million. The Company's West Java, Indonesia, project totaling $22.0 million was written off due to the uncertainties surrounding infrastructure projects in Indonesia. Also during 1998, the Company wrote off its $1.9 million investment in the Sunnyside project and its $2.8 million investment in Alto Cachopoal. The charge represents the difference between the carrying amount of the investment and the fair value of the asset, determined using a cash flow model. In December 1997, the Company reviewed the carrying amount of the Sunnyside project that failed to restructure its debt and recorded a charge of $8.9 million. The charge represents the difference between the carrying amount of the investment and the fair value of the asset, determined using a discounted cash flow model. 40
43 NOTE 6 -- RELATED PARTY TRANSACTIONS SALE TO AFFILIATE During October 1998, the Company sold its interest in the Mid-Continent Power Corporation (MCPC) facility to CogenAmerica for a $2.1 million gain after elimination of affiliate interest. The MCPC facility is a 110 MW, gas-fired generation station located near Pryor, Oklahoma. The Company owns 20 percent of the outstanding stock of CogenAmerica. OPERATING AGREEMENTS The Company has two agreements with NSP for the purchase of thermal energy. Under the terms of the agreements, NSP charges the Company for certain costs (fuel, labor, plant maintenance, and auxiliary power) incurred by NSP to produce the thermal energy. The Company paid NSP $4.4 million in 1999 and $5.1 million in 1998 under these agreements. The Company has a renewable 10-year agreement with NSP, expiring on December 31, 2001, whereby NSP agrees to purchase refuse-derived fuel for use in certain of its boilers and the Company agrees to pay NSP a burn incentive. Under this agreement, the Company received $1.4 million and $1.4 million from NSP, and paid $2.7 million and $3.1 million to NSP in 1999 and 1998, respectively. ADMINISTRATIVE SERVICES AND OTHER COSTS The Company and NSP have entered into an agreement to provide for the reimbursement of actual administrative services provided to each other, an allocation of NSP administrative costs and a working capital fee. Services provided by NSP to the Company are principally cash management, legal, accounting, employee relations, benefits administration and engineering support. In addition, the Company employees participate in certain employee benefit plans of NSP as discussed in Note 10. During 1999 and 1998, the Company paid NSP $6.4 million and $5.2 million, respectively, as reimbursement under this agreement. In 1996, the Company and NSP entered into an agreement for the Company to provide operations and maintenance services for NSP's Elk River resource recovery facility and Becker ash landfill. During 1999 and 1998, NSP paid the Company $1.9 million and $1.7 million, respectively, as compensation under this agreement. 41
44 NOTE 7 -- NOTES RECEIVABLE Notes receivable consists primarily of fixed and variable rate notes secured by equity interests in partnerships and joint ventures. The notes receivable at December 31, are as follows: <TABLE> <CAPTION> 1999 1998 ---- ---- (THOUSANDS OF DOLLARS) <S> <C> <C> COGENERATION CORPORATION OF AMERICA: Note due 2001, 9.5%....................................... $ -- $ 2,539 Grays Ferry note due 2005, LIBOR plus 4.0% (9.31%@12/98).......................................... -- 1,900 Morris note due 2004, prime + 3.5% (11.25%@12/98)......... -- 12,027 MCPC note due 2004, prime +3.5% (11.25%@12/98)............ -- 23,947 El Paso note, due January 1999, non interest bearing........ -- 26,200 Thermal Ventures, Inc. note due 1999, 11%................... -- 1,500 TOSLI, various notes due 2000, LIBOR plus 4.0% (10.0%@12/99)............................................. 207 132 Various secured notes due 2000 and later, non-interest and interest bearing.......................................... 224 723 NEO notes to various affiliates due primarily 2012, prime +2% to 12.5%.............................................. 26,850 27,445 Southern MN Praireland Solid Waste, note due 2003, 7%....... 44 1,441 Pacific Generation, various notes, prime +2% to 12%......... 3,368 4,203 NRGenerating International BV notes to various affiliates, non-interest bearing...................................... 40,410 34,234 O'Brien Cogen II note, due 2008, non interest bearing....... 465 -- ------- -------- Total................................................ $71,568 $136,291 ======= ======== </TABLE> 42
45 NOTE 8 -- LONG-TERM DEBT Long-term debt consists of the following at December 31: <TABLE> <CAPTION> 1999 1998 ---- ---- (THOUSANDS OF DOLLARS) <S> <C> <C> NEO Landfill Gas, Inc. term loan, due October 30, 2007, 9.35%..................................................... $ -- $ 9,847 NEO Landfill Gas Inc. construction loan due October 30, 2007 LIBOR + 1% (6.31 @ 12/98)................................. -- 6,550 NEO Landfill Gas, Inc. City of L.A. term loan, due December 2019 non-interest bearing................................. -- 1,395 COBEE, due April 21, 2000, 0%............................... 5,761 -- O'Brien Cogen II due August 31, 2000, 9.5%.................. 2,893 -- NRG San Diego, Inc. promissory note, due June 25, 2003, 8.0%...................................................... 1,729 2,141 Pittsburgh Thermal LP -- Credit Line, due 2004, LIBOR + 4.25%..................................................... 1,100 -- San Francisco Thermal LP -- Credit Line, due 2004, LIBOR + 4.25%..................................................... 900 -- Pittsburgh Thermal LP, due 2002-2004, 10.61%-10.73%......... 6,800 -- San Francisco Thermal LP, October 5, 2004, 10.61%........... 5,905 -- NRG Energy senior notes, due February 1, 2006, 7.625%....... 125,000 125,000 Note payable to NSP, due December 1, 1995-2006, 5.40%-6.75%............................................... 6,495 7,174 NRG Energy senior notes, due June 15, 2007, 7.50%........... 250,000 250,000 Camas Power Boiler LP, unsecured term loan, due June 30, 2007, 7.65%............................................... 17,087 17,576 Camas Power Boiler LP, revenue bonds, due August 1, 2007, 4.65%..................................................... 9,130 11,010 Various NEO debt due 2005-2008, 9.35%....................... 28,615 -- NRG Energy senior notes, due June 1, 2009, 7.50%............ 300,000 -- NRG Energy Center, Inc. senior secured notes due June 15, 2013, 7.31%............................................... 68,881 71,783 NRG Energy senior notes, due Nov. 1, 2013, 8.00%............ 240,000 -- Crockett Corp. LLP, due Dec. 31, 2014, 8.13%................ 255,000 -- NRG Northeast Generating debt............................... 646,564 -- ---------- -------- 1,971,860 502,476 Less current maturities..................................... (30,462) (8,258) ---------- -------- Total................................................ $1,941,398 $494,218 ========== ======== </TABLE> The NRG Energy Center, Inc. notes are secured principally by long-term assets of the Minneapolis Energy Center (MEC). In accordance with the terms of the note agreement, MEC is required to maintain compliance with certain financial covenants primarily related to incurring debt, disposing of MEC assets, and affiliate transactions. MEC was in compliance with these covenants at December 31, 1999. The note payable to NSP relates to long-term debt assumed by the Company in connection with the transfer of ownership of a Refuse Derived Fuel processing plant by NSP to the Company in 1993. The NRG Energy $125 million, $250 million, $300 million and $240 million senior notes are unsecured and are used to support equity requirements for projects acquired and in development. The interest is paid semi-annually and the ten-year senior notes mature in February 2006, June 2007, and 2009. The fourteen year notes mature in November 2013. The $240 million of NRG Energy Senior notes due November 1, 2013 are remarketable or redeemable Security (ROARS). November 1, 2003 is the first remarketing date for these notes. Interest is payable semi-annually beginning May 1, 2000 through November 1, 2003, and then at intervals and interest rates as discussed in the indenture. On the remarketing date, the notes will either be mandatorily tendered to and purchased by Credit Suisse Financial Products or mandatorily redeemed by the Company at prices discussed in the indenture. The notes are unsecured debt that rank senior to all of the Company's existing and future subordinated indebtedness. 43
46 The NRG San Diego, Inc. promissory note is secured principally by long-term assets of the San Diego Power & Cooling Company. The various NEO notes are term loans. The loans are secured principally by long-term assets of NEO Landfill Gas collection system. NEO Landfill Gas is required to maintain compliance with certain covenants primarily related to incurring debt, disposing of the NEO Landfill Gas assets, and affiliate transactions. The Camas Power Boiler LP notes are secured principally by long-term assets. In accordance with the terms of the note agreements, Camas Power Boiler LP is required to maintain compliance with certain financial covenants primarily related to incurring debt, disposing of assets, and affiliate transactions. Camas Power Boiler was in compliance with these covenants at December 31, 1999. The Crockett Corporation term loan is secured by primarily the long-term assets of the Crockett Cogeneration project. The O'Brien Cogen II promissory note is payable on the earlier of the first anniversary of the effective date (August 31, 1999) or upon the sale of the assets at the O'Brien Cogen II facility. Full payment of the note is guaranteed by the Company. Annual maturities of long-term debt for the years ending after December 31, 1999 are as follows: <TABLE> <CAPTION> (THOUSANDS OF DOLLARS) ---------------------- <S> <C> 2000...................................................... $ 30,462 2001...................................................... 23,637 2002...................................................... 26,104 2003...................................................... 27,610 2004...................................................... 31,594 Thereafter................................................ 1,832,453 ---------- Total................................................ $1,971,860 ========== </TABLE> The Company has $550 million in revolving credit facilities under a commitment fee arrangement. These facilities provide short-term financing in the form of bank loans and letters of credit. At December 31, 1999, the Company has $340 million outstanding under its revolving credit agreements. The Company had $116 million and $33.6 million in outstanding letters of credit as of December 31, 1999 and 1998, respectively. In December 1999, the Company filed a shelf registration with the SEC to issue up to $500 million of unsecured debt securities. The Company expects to issue debt under this shelf during 2000 for general corporate purposes, which may include financing, development and construction of new facilities, additions to working capital and financing capital expenditures and pending or potential acquisitions. On February 22, 2000, NRG Northeast Generating issued $750 million of senior secured bonds to refinance short-term project borrowings and for certain other purposes. The bond offering included three tranches: $320 million with an interest rate of 8.065 percent due in 2004, $130 million with an interest rate of 8.842 percent due in 2015 and $300 million with an interest rate of 9.292 percent due in 2024. The Company used $647 million of the proceeds to repay short-term borrowings outstanding at December 31, 1999; accordingly, $646.6 million of short term debt has been re-classified as long-term debt, based on this refinancing. In March 2000, the Company issued $250 million of 8.70 percent 20-year remarketable or redeemable securities through an unconsolidated grantor trust. The funds were subsequently converted to 160 million pound sterling and will be used to finance the Company's investment in the Killingholme Power Station in England. In March 2000, NRG South Central Generating LLC, a subsidiary of the Company, issued $800 million of senior secured bonds in a two-part offering. The first tranche was for $500 million with a coupon of 8.962 percent and a maturity of 2016. The second tranche was for $300 million with a coupon of 9.479 percent and a maturity of 2024. The proceeds will be used to finance the Company's investment in the Cajun generating facilities. 44
47 GUARANTEES The Company may be directly liable for the obligations of certain of its project affiliates and other subsidiaries pursuant to guarantees relating to certain of their indebtedness, equity and operating obligations. One example is the Company's guarantee of the obligations of its project subsidiary that operates the Gladstone facility for up to AU$25 million, indexed to the Australian consumer price index, under the project subsidiary's operating and maintenance agreement with the owners of the facility. In addition, in connection with the purchase and sale of fuel, emission credits and power generation products to and from third parties with respect to the operation of some of the Company's generation facilities in the United States, the Company may be required to guarantee a portion of the obligations of certain of its subsidiaries. As of December 31, 1999, the Company's obligations pursuant to its guarantees of the performance, equity and indebtedness obligations of its subsidiaries totaled approximately $416.4 million. NOTE 9 -- INCOME TAXES The Company and its parent, NSP, have entered into a federal and state income tax sharing agreement relative to the filing of consolidated federal and state income tax returns. The agreement provides, among other things, that (1) if the Company, along with its subsidiaries, is in a taxable income position, the Company will be currently charged with an amount equivalent to its federal and state income tax computed as if the group had actually filed separate federal and state returns, and (2) if the Company, along with its subsidiaries, is in a tax loss position, the Company will be currently reimbursed to the extent its combined losses are utilized in a consolidated return, and (3) if the Company, along with its subsidiaries, generates tax credits, the Company will be currently reimbursed to the extent its tax credits are utilized in a consolidated return. The provision for income taxes consists of the following: <TABLE> <CAPTION> 1999 1998 1997 ---- ---- ---- (THOUSANDS OF DOLLARS) <S> <C> <C> <C> Current Federal................................................ $ 3,620 $(10,773) $ (8,516) State.................................................. 1,041 (3,940) (1,274) Foreign................................................ 4,040 2,358 236 -------- -------- -------- 8,701 (12,355) (9,554) Deferred Foreign................................................ (7,668) (7,736) (2,703) Federal................................................ (2,792) 8,828 (958) State.................................................. (3,901) 1,541 (439) -------- -------- -------- (14,361) 2,633 (4,100) Tax credits recognized................................... (20,421) (15,932) (9,837) -------- -------- -------- Total income tax (benefit).......................... $(26,081) $(25,654) $(23,491) ======== ======== ======== Effective tax rate....................................... (84)% (160)% (1,557)% </TABLE> 45
48 The components of the net deferred income tax liability at December 31 were: <TABLE> <CAPTION> 1999 1998 ---- ---- (THOUSANDS OF DOLLARS) <S> <C> <C> Deferred tax liabilities Differences between book and tax basis of property........ $37,713 $29,712 Investments in projects................................... 17,308 14,911 Goodwill.................................................. 1,117 978 Other..................................................... 5,544 6,212 ------- ------- Total deferred tax liabilities............................ 61,682 51,813 Deferred tax assets Deferred revenue.......................................... 841 1,402 Deferred compensation, accrued vacation and other reserves............................................... 10,996 6,514 Development costs......................................... 6,768 9,241 Deferred investment tax credits........................... 450 661 Steam capacity rights..................................... 844 910 Foreign tax benefit....................................... 20,919 12,425 Other..................................................... 3,924 819 ------- ------- Total deferred tax assets................................. 44,742 31,972 ------- ------- Net deferred tax liability................................ $16,940 $19,841 ======= ======= </TABLE> The effective income tax rate for the years 1999, 1998 and 1997 differs from the statutory federal income tax rate of 35% primarily due to state tax, foreign tax, and tax credits as shown above, income and expenses from foreign operations not subject to U.S. taxes (as discussed below). The Company intends to reinvest the earnings of foreign operations except to the extent the earnings are subject to current U.S. income taxes. Accordingly, U.S. income taxes and foreign withholding taxes have not been provided on a cumulative amount of unremitted earnings of foreign subsidiaries of approximately $195 million and $158 million at December 31, 1999 and 1998. The additional U.S. income tax and foreign withholding tax on the unremitted foreign earnings, if repatriated, would be offset in whole or in part by foreign tax credits. Thus, it is not practicable to estimate the amount of tax that might be payable. NOTE 10 -- BENEFIT PLANS AND OTHER POSTRETIREMENT BENEFITS PENSION BENEFITS The Company participates in NSP's noncontributory, defined benefit pension plan that covers substantially all employees, other then those employed as a result of the NE Generating asset acquisitions. Benefits are based on a combination of years of service, the employee's highest average pay for 48 consecutive months, and Social Security benefits. Plan assets principally consist of the common stock of public companies, corporate bonds and U.S. government securities. The Company's net annual periodic pension cost includes the following components: COMPONENTS OF NET PERIODIC BENEFIT COST <TABLE> <CAPTION> 1999 1998 1997 ---- ---- ---- (THOUSANDS OF DOLLARS) <S> <C> <C> <C> Service cost benefits earned................................ $ 1,602 $ 1,303 $ 1,127 Interest cost on benefit obligation......................... 1,739 1,417 1,187 Expected return on plan assets.............................. (2,866) (2,226) (1,029) Amortization of prior service cost.......................... 393 172 5 Recognized actuarial (gain) loss............................ (2,053) (1,878) (3) ------- ------- ------- Net periodic (benefit) cost............................... $(1,185) $(1,212) $ 1,287 ======= ======= ======= </TABLE> 46
49 The Company discontinued funding its pension costs in 1998 due to the effects of funding limitations from employee benefit and tax laws on NSP's plan. Plan assets consist principally of common stock of public companies, corporate bonds and U.S. government securities. The funded status of the pension plan in which the Company employees participate is as follows at December 31: RECONCILIATION OF FUNDED STATUS <TABLE> <CAPTION> 1999 1998 -------------------------- ------------------------- NSP PLAN NRG PORTION NSP PLAN NRG PORTION -------- ----------- -------- ----------- (THOUSANDS OF DOLLARS) <S> <C> <C> <C> <C> Benefit obligation at Jan. 1................. $ 1,143,464 $ 20,112 $1,048,251 $17,410 Service cost................................. 36,421 1,602 31,643 1,303 Interest cost................................ 86,429 1,739 78,839 1,417 Plan amendments.............................. 184,255 2,214 102,315 3,045 Actuarial gain............................... (105,634) (178) (41,635) (2,278) Benefit payments............................. (97,086) (1,200) (75,949) (785) ----------- -------- ---------- ------- Benefit obligation at Dec. 31.............. $ 1,247,849 $ 24,289 $1,143,464 $20,112 =========== ======== ========== ======= Fair value of plan assets at Jan. 1.......... $ 2,221,819 39,079 $1,978,538 $18,795 Actual return on plan assets................. 293,904 9,199 319,230 21,069 Benefit payments............................. (97,086) (1,200) (75,949) (785) ----------- -------- ---------- ------- Fair value of plan assets at Dec. 31....... $ 2,418,637 $ 47,078 $2,221,819 $39,079 =========== ======== ========== ======= Funded status at Dec. 31 -- excess of assets over obligation............................ $ 1,170,788 $ 22,789 $1,078,355 $18,967 Unrecognized transition (asset) obligation... (311) -- (387) -- Unrecognized prior service cost.............. 277,350 4,775 114,305 2,954 Unrecognized net gain........................ (1,381,889) (26,944) (1,167,340) (22,486) ----------- -------- ---------- ------- Accrued (prepaid) benefit obligation at Dec. 31......................................... $ 65,938 $ 620 $ 24,933 $ (565) =========== ======== ========== ======= </TABLE> AMOUNT RECOGNIZED IN THE BALANCE SHEET <TABLE> <CAPTION> 1999 1998 ----------------------- ----------------------- NSP PLAN NRG PORTION NSP PLAN NRG PORTION -------- ----------- -------- ----------- (THOUSANDS OF DOLLARS) <S> <C> <C> <C> <C> Prepaid benefit cost............................. $65,938 $ 868 $24,933 $ -- Accrued benefit liability........................ -- (248) -- (565) ------- ----- ------- ----- Net amount recognized -- asset (liability)............................... $65,938 $ 620 $24,933 $(565) ======= ===== ======= ===== </TABLE> The weighted average discount rate used in determining the actuarial present value of the projected benefit obligation was 7.5% for December 31, 1999 and 6.5% for December 31, 1998. The rate of increase in future compensation levels used in determining the actuarial present value of the projected obligation was 4.5% in 1999 and 4.5% in 1998. The assumed long-term rate of return on assets used for cost determinations was 8.5% for 1999 and 1998 and 9.0% for 1997. Effective Jan. 1, 1998, NSP changed its method of accounting for subsidiary pension costs under SFAS No. 87. The new method, which now allocates plan assets based on subsidiary benefit obligations, was adopted to better match earnings on total plan assets with the corresponding subsidiary benefit obligations. The effect of this change decreased periodic pension costs by $2.9 million in 1998 from 1997 levels, including $1.3 million related to periods prior to the change. The effects of this change have not been reported separately on the income statement and prior periods have not been restated due to immateriality. 47
50 NRG EQUITY PLAN Employees are eligible to participate in the Company's Equity Plan (the Plan). The Plan grants phantom equity units to employees based upon performance and job grade. The Company's equity units are valued based upon the Company's growth and financial performance. The primary financial measures used in determining the equity units' value are revenue growth, return on investment and cash flow from operations. The units are awarded to employees annually at the respective year's calculated share price (grant price). The Plan provides employees with a cash pay out for the unit's appreciation in value over the vesting period. The Plan has a seven year vesting schedule with actual payments beginning after the end of the third year and continuing at 20% each year for the subsequent five years. During 1999 and 1998, the Company recorded approximately $13 million and $2.6 million, respectively for the Plan. The Plan includes a change of control provision, which allow all shares to vest if the ownership of the Company were to change. POSTRETIREMENT HEALTH CARE The Company participates in NSP's contributory health and welfare benefit plan that provides health care and death benefits to substantially all employees after their retirement. The plan, was terminated for nonbargaining employees retiring after 1998 and for bargaining employees retiring after 1999. is intended to provide for sharing of costs of retiree health care between the Company and retirees. For covered retirees, the plan enables the Company to share the cost of retiree health costs. Nonbargaining retirees pay 40 percent of total health care costs. Cost-sharing for bargaining employees is governed by the terms of the collective bargaining agreement. Postretirement health care benefits for the Company are determined and recorded under the provisions of SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." SFAS No. 106 requires the actuarially determined obligation for postretirement health care and death benefits to be fully accrued by the date employees attain full eligibility for such benefits, which is generally when they reach retirement age. The Company's net annual periodic benefit cost under SFAS No. 106 includes the following components: COMPONENTS OF NET PERIODIC BENEFIT COST <TABLE> <CAPTION> 1999 1998 1997 ---- ---- ---- (THOUSANDS OF DOLLARS) <S> <C> <C> <C> Service cost benefits earned................................ $ 9 $165 $223 Interest cost on benefit obligation......................... 24 145 246 Amortization of transition asset............................ -- 17 70 Amortization of prior service cost.......................... (104) (40) -- Recognized actuarial (gain) loss............................ (34) 2 -- ----- ---- ---- Net periodic (benefit) cost............................ $(105) $289 $539 ===== ==== ==== </TABLE> Plan assets as of December 31, 1999 consisted of investments in equity mutual funds and cash equivalents. The Company's funding policy is to contribute to NSP benefits actually paid under the plan. 48
51 The following table sets forth the funded status of the health care plan in which the Company employees participate at December 31: RECONCILIATION OF FUNDED STATUS <TABLE> <CAPTION> 1999 1998 ------------------------ ------------------------ NSP PLAN NRG PORTION NSP PLAN NRG PORTION -------- ----------- -------- ----------- (THOUSANDS OF DOLLARS) <S> <C> <C> <C> <C> Benefit obligation at Jan. 1................... $ 219,762 $ 1,517 $ 279,230 $ 3,893 Service cost................................... 196 9 3,247 165 Interest cost.................................. 9,184 24 15,896 145 Plan amendments................................ (80,840) (770) (51,456) (1,872) Actuarial gain loss............................ 8,269 (359) (9,732) (814) Benefit payments............................... (16,637) -- (17,423) -- --------- ------- --------- ------- Benefit obligation at Dec. 31............. $ 139,934 $ 421 $ 219,762 $ 1,517 ========= ======= ========= ======= Fair Value of plan assets at Jan. 1............ $ 34,514 $ -- $ 19,783 $ -- Actual return on plan assets................... 3,982 -- 2,471 -- Employer contributions......................... 13,339 -- 29,683 -- Benefit payments............................... (16,637) -- (17,423) -- --------- ------- --------- ------- Fair value of plan assets at Dec. 31...... $ 35,198 $ -- $ 34,514 $ -- ========= ======= ========= ======= Funded status at Dec. 31 -- unfunded obligation................................... $(104,736) $ (421) $ 185,248 $ 1,517 Unrecognized transition obligation............. 22,073 -- (104,482) -- Unrecognized prior service cost................ (2,926) (1,452) 2,399 786 Unrecognized net gain (loss)................... 10,580 (562) (3,790) 237 --------- ------- --------- ------- Accrued (liability) benefit recorded at Dec. 31........................................... $ (75,009) $(2,435) $ 79,375 $ 2,540 ========= ======= ========= ======= </TABLE> The assumed health care cost trend rates used in measuring the accumulated projected benefit obligation (APBO) at both December 31, 1999 and 1998, were 8.1% for those under age 65, and 6.1 % for those over age 65. The assumed cost trends are expected to decrease each year until they reach 5.0% for both age groups in the year 2004, after which they are assumed to remain constant. A one percent increase in the assumed health care cost trend rate would increase the APBO by approximately $36 thousand as of December 31, 1999. Service and interest cost components of the net periodic postretirement cost would increase by approximately $2 thousand with a similar one percent increase in the assumed health care cost trend rate. The assumed discount rate used in determining the APBO was 6.5% for both December 31, 1999 and 1998, compounded annually. The assumed long-term rate of return on assets used for cost determinations under SFAS No. 106 was 8% for 1999, 1998 and 1997 PENSION BENEFITS -- 1999 ACQUISITIONS During 1999, the Company acquired several generating assets and assumed benefit obligations for a number of employees associated with those acquisitions. The plans assumed included noncontributory defined benefit pension formulas, matched 401(k) savings plans, and contributory post-retirement welfare plans. Approximately, 56 percent of the Company's benefit employees are represented by eight local labor unions under collective bargaining agreements, which expire between 2000 and 2003. 49
52 The Company sponsors one noncontributory, defined benefit pension plan that covers most of the employees associated with the 1999 acquisitions. Generally, the benefits are based on a combination of years of service, the final average pay and Social Security benefits. COMPONENTS OF NET PERIODIC BENEFIT COST <TABLE> <CAPTION> 1999 ---- (THOUSANDS OF DOLLARS) <S> <C> Service cost benefits earned................................ $ 968 Interest cost on benefit obligation......................... 1,115 Expected return on plan assets.............................. (1,193) ------- Net periodic (benefit) cost............................ $ 890 ======= </TABLE> RECONCILIATION OF FUNDED STATUS <TABLE> <CAPTION> 1999 ---- (THOUSANDS OF DOLLARS) <S> <C> Benefit obligation at beginning of period................... $ 24,954 Additional Acquisitions during the Year..................... 27,330 Service cost................................................ 968 Interest cost............................................... 1,115 Plan amendments............................................. -- Actuarial gain.............................................. (1,098) Benefit payments............................................ (403) -------- Benefit obligation at Dec. 31.......................... $ 52,866 ======== Fair value of plan assets at beginning of period............ $ 24,905 Additional assets transferred............................... 10,070 Actual return on plan assets................................ 3,091 Benefit payments............................................ (403) -------- Fair value of plan assets at Dec. 31................... $ 37,663 ======== Funded status at Dec. 31 -- excess of assets over obligation................................................ $(15,203) Unrecognized transition (asset) obligation.................. -- Unrecognized prior service cost............................. -- Unrecognized net gain....................................... (2,996) -------- (Accrued) Prepaid benefit obligation at Dec. 31............. $(18,199) ======== </TABLE> AMOUNT RECOGNIZED IN THE BALANCE SHEET <TABLE> <CAPTION> 1999 ---------------------- (THOUSANDS OF DOLLARS) <S> <C> Prepaid benefit cost....................................... -- Accrued benefit liability.................................. $(18,199) -------- Net amount recognized -- (liability)..................... $(18,199) ======== </TABLE> The weighted average discount rate used in determining the actuarial present value of the projected benefit obligation was 7.5% for December 31, 1999. The rate of increase in future compensation levels used in determining the actuarial present value of the projected obligation was 4.5% for nonunion employees and 3.50% for union employees. The assumed long-term rate of return on assets used for cost determinations was 8.5% for 1999. 50
53 POSTRETIREMENT HEALTH CARE The Company has also assumed post retirement health care benefits for some of the Company's employees associated with the 1999 acquisitions. The plan enables the Company and the retirees to share the costs of retiree health care. The cost sharing varies by acquisition group and collective bargaining agreements. There are no existing Company retirees under these plans as of December 31, 1999. Complete valuation data is not available for some of these groups. The estimated net periodic postretirement benefit cost for 1999 is $0.85 million. The estimated accumulated post-retirement benefit obligation is $12 million at December 31,1999. 401(K) PLANS The Company also assumed several contributory, defined contribution employee savings plans as a result of its 1999 acquisition activity. These plans comply with Section 401(k) of the Internal Revenue Code and cover substantially all of the Company's employees who are not covered by NSP's 401(k) Plan. The Company matches specified amounts of employee contributions to the plan. Employer contributions made to the Company's plans were approximately $0.31 million in 1999. NOTE 11 -- SALES TO SIGNIFICANT CUSTOMERS During 1999, the Company's electric power generation operations located in the northeastern part of the United States, NRG Northeastern Generating LLC, accounted for approximately 60% of the Company's total revenues from wholly owned operations. Sales to three customers accounted for 10.5%, 21.0% and 19.7% of total revenues from wholly owned operations in 1999. During 1999, the Company entered into transition agreements with these customers providing for the sale of energy and other ancilliary services generated from certain electric generating facilities recently acquired from these customers and others. These agreements generally range from four to ten years in duration. The Company and the Ramsey/Washington Resource Recovery Project have a service agreement for waste disposal, which expires in 2006. Approximately 26.5% in 1998 of the Company's operating revenues were recognized under this contract. In addition, sales to one thermal customer amounted to 10.3% of operating revenues in 1998. NOTE 12 -- FINANCIAL INSTRUMENTS The estimated December 31 fair values of the Company's recorded financial instruments are as follows: <TABLE> <CAPTION> 1999 1998 ----------------------- ------------------- CARRYING FAIR CARRYING FAIR AMOUNT VALUE AMOUNT VALUE -------- ----- -------- ----- (THOUSANDS OF DOLLARS) <S> <C> <C> <C> <C> Cash and cash equivalents.......................... $ 31,483 $ 31,483 $ 6,381 $ 6,381 Restricted cash.................................... 17,441 17,441 4,021 4,021 Notes receivable, including current portion........ 71,568 71,568 136,291 136,291 Long-term debt, including current portion.......... 1,971,860 1,931,969 502,476 519,418 </TABLE> For cash, cash equivalents and restricted cash, the carrying amount approximates fair value because of the short-term maturity of those instruments. The fair value of notes receivable is based on expected future cash flows discounted at market interest rates. The fair value of long-term debt is estimated based on the quoted market prices for the same or similar issues. DERIVATIVE FINANCIAL INSTRUMENTS As of December 31, 1999, the Company had no contracts to hedge or protect foreign currency denominated future cash flows. One contract that was executed during 1999 had no material effect on earnings. 51
54 During the third quarter of 1999, NRG Northeast, a wholly owned subsidiary of the Company entered into $600 million of "treasury locks," at various interest rates, which expired in February 2000. These treasury locks were an interest rate hedge for an NRG Northeast bond offering that was completed on February 22, 2000. The proceeds of this bond offering were used to pay down borrowings under a NRG Northeast's existing short-term credit facility. As of December 31, 1999, the Company had three interest rate swap agreements with notional amounts totaling approximately $393 million. The contracts are used to manage the Company's exposure to changes in interest rates. If the swaps had been discontinued on December 31, 1999, the Company would have owed the counterparties approximately $3 million. Management believes that the Company's exposure to credit risk due to nonperformance by the counterparties to its hedging contracts is insignificant, based on the investment grade rating of the counterparties. - In September 1999, the Company entered into a $200 million swap agreement effectively converting the 7.5 percent fixed rate on its senior notes to a variable rate based on the London Interbank Offered Rate. The swap expires on June 1, 2009. - A second swap effectively converts a $16 million issue of variable rate debt into a fixed rate debt. The swap expires on September 30, 2002. - A third swap converts $177 million of variable rate debt into fixed rate debt. The swap expires on December 17, 2014. The Company's Power Marketing subsidiary uses energy forward contracts along with physical supply, to hedge market risk in the energy market. At December 31, 1999, the notional amount of energy forward contracts was approximately $207 million. If the contracts had been terminated at December 31, 1999, the Company would have received approximately $12.0 million based on price fluctuations to date. Management believes the risk of counterparty nonperformance with regard to any of the Company's hedging transactions is not significant. NOTE 13 -- COMMITMENTS AND CONTINGENCIES OPERATING LEASE COMMITMENTS The Company leases certain of its facilities and equipment under operating leases, some of which include escalation clauses, expiring on various dates through 2010. Rental expense under these operating leases was $5.4 million in 1999 and $1.7 million in 1998. Future minimum lease commitments under these leases for the years ending after December 31, 1999 are as follows: <TABLE> <CAPTION> (THOUSANDS OF DOLLARS) ------------- <S> <C> 2000........................................................ $ 5,518 2001........................................................ 5,223 2002........................................................ 4,614 2003........................................................ 4,161 2004........................................................ 4,094 Thereafter.................................................. 35,293 ------- Total..................................................... $58,903 ======= </TABLE> The Company expects to invest approximately $2.7 billion in 2000 and approximately $4.7 billion for the five-year period 2000 - 2004 for nonregulated projects and property, which include acquisitions and projects investments. The Company's capital requirements for 2000 reflect expected acquisitions of existing generation facilities, including Cajun, Killingholme A and the Conectiv fossil assets. 52
55 CAPITAL COMMITMENTS -- INTERNATIONAL In November 1999, the Company agreed to purchase the 665 MW Killingholme A station from National Power plc. Killingholme A was commissioned in 1994 and is a combined-cycle, gas-turbine power station located in England. The purchase price for the station will be approximately 410 million pounds sterling (approximately $662 million U.S. at end of year exchange rates), subject to commercial adjustments. The purchase price includes 20 million pounds sterling (approximately $32 million U.S. at end of year exchange rates) that is contingent upon the successful completion of negotiations regarding NRG's purchase of National Power's Blyth generating facilities. The Blyth assets consist of two coal-fired stations totaling 1,140 MW of generation capacity located in England. CAPITAL COMMITMENTS -- DOMESTIC The Company, together with its partner and the creditors's committee filed a plan with the United States Bankruptcy Court for the Middle District of Louisiana to acquire 1,708 MW of fossil generating assets from Cajun Electric Power Cooperative of Baton Rouge, Louisiana (Cajun) for approximately $1.0 billion The consortium has the support of the Chapter 11 trustee and Cajun's secured creditors. During the third quarter of 1999, the U.S. Bankruptcy Judge confirmed the creditors plan of reorganization and the Company exercised an option to purchase its partner's 50 percent interest in the project. The Company expects to close the acquisition of the Cajun assets during the first quarter of 2000. In January 2000, the Company agreed to purchase 1,875 MW of fossil-fueled electric generating capacity and other assets from Conectiv of Wilmington, Delaware for $800 million. The fossil-fueled generating facilities consist of Conectiv's wholly owned BL England, Deepwater, Indian River and Vienna steam stations plus Conectiv's interest in the Conemaugh and Keystone steam stations. Other assets in the purchase are the 241-acre Dorchester site located in Dorchester County, Maryland, certain Merrill Creek Reservoir entitlements in Harmony Township, New Jersey and certain excess emission allowances. In January 2000, the Company executed a memorandum of understanding with GE Power Systems, a division of General Electric Company, to purchase 11 gas turbine generators and five steam turbine generators. The purchase will take place over the next five years and is valued at approximately $500 million with an option to purchase additional units. The 16 turbines have an equivalent generation output of 3,000 MW and will be installed at the Company's existing North American plant sites. The Company has contractually agreed to the monetization of certain tax credits generated from landfill gas sales through the year 2007. Future capital commitments related to projects are as follows: <TABLE> <CAPTION> (MILLIONS OF DOLLARS) ------------ <S> <C> 2000........................................................ $2,700 2001........................................................ 500 2002........................................................ 500 2003........................................................ 500 2004........................................................ 500 ------ Total..................................................... $4,700 ====== </TABLE> SOURCE OF CAPITAL The Company anticipates funding its ongoing capital commitments through the issuance of debt, additional equity from NSP, and operating cash flows. In addition, the Company may issue a limited amount of equity financing to third parties for funding a portion of the capital requirements. CONTINGENT REVENUES During 1999, the first year of deregulation in the state of New York power industry, the Company has claims related to certain revenues earned during the period April 27, 1999 to December 31, 1999. The Company is actively pursuing resolution and/or collection of these amounts, which totaled approximately $8.9 million as of December 31, 1999. These amounts have not been recorded in the financial statements and will 53
56 not be recognized as income until disputes are resolved and collection is assured. The contingent revenues relate to interpretation of certain transition power sales agreements and to sales to the NYPP and NEPOOL, conflicting meter readings, pricing of firm sales and other power pool reporting issues. CONTRACTUAL COMMITMENTS Arthur Kill Power and Astoria Power have entered into agreements with ConEd that obligate them to maintain the electric generating capability and availability of their respective facilities at specified levels for the terms of these agreements, and whereby during certain periods, ConEd will purchase specified amounts of capacity, as long as the capacity is counted in the installed capacity requirement for New York City. The capacity must satisfy all criteria, standards and requirements applicable to providers of installed capacity established by the New York State Reliability Counsel ("NYSRC"), the Northwest Power Coordinating Council ("NPCC"), the North American Electric Reliability Council ("NERC"), the New York Power Pool (NYPP) or the NYISO. Should the capacity of the facility drop below the minimum level required, the subsidiary owning the facility will pay to ConEd a deficiency charge. The sellers may use electric capacity other than that generated by their own plants to satisfy ConEd's demands. The respective subsidiary will bill ConEd for the electricity capacity sold and ConEd will bill that subsidiary for any capacity deficiency payments on a monthly basis. Any amount unpaid after it is due will accrue interest. Any dispute on the amount payable will first be settled by good faith negotiation among the parties. For the next four years, the Company estimates that a significant portion of the total revenues from the Dunkirk and Huntley facilities will be derived from four-year transition contracts for capacity and energy. All forward capacity is sold to NIMO during the transition period, with the remainder of energy sold to the NYISO. Each of the following agreements was executed on June 11, 1999 and extends for a term of four years. To hedge its transition to market rates, NIMO has required NRG Power Marketing to enter into an International Swap Dealers Association (ISDA) Master Agreement (together with the Schedule, the Confirmation and the Guarantee Agreement, the "Swap Agreement"). Under the Swap Agreement, NIMO will pay to NRG Power Marketing a fixed monthly price for the Dunkirk (units 1, 2, 3 and 4) and Huntley (units 67 and 68 only) facilities' capacity and ancillary services and NRG Power Marketing will pay to NIMO the market rates for the related capacity and ancillary services. The swap is only a financial contract and it incorporates the terms of the ISDA Master Agreement. NIMO will have the right from time to time to exercise a call option for an additional swap pursuant to which, within a certain limit consistent with outages and availability requirements, NIMO will nominate certain amounts of energy from the Dunkirk and Huntley facilities and will pay to NRG Power Marketing an amount for such energy determined in accordance with the heat rate curve representing the nominated unit. NRG Power Marketing will pay to NIMO the market rates for such energy at the time that the energy was nominated. However, NRG Power Marketing may refuse the call option for either of the facilities if a facility is unexpectedly forced off-line or derated sufficiently to be unable to fulfill the portion of the specified quantity of power in the option. Any such refusal of the call option will be limited to the Decline Quantity Cap, which is calculated based upon the capacity of the relevant facility for the prior six months. NIMO will be entitled to make up for any refused call option in the future by delivering reasonable notice to NRG Power Marketing. In addition to the Swap Agreement, Huntley Power has entered into an agreement with NIMO that gives NIMO the option to purchase from the Huntley facility certain quantities of electricity generated by Huntley units 65 and 66, during the summer and winter months, up to a specified maximum limit for the term of this agreement. If Huntley Power is selling the electrical output generated by units 65 and 66 to a third party, Huntley Power may refuse to deliver such output to NIMO. Furthermore, if unit 65 or 66 is generating for NIMO, Huntley Power has the right to "recall" the unit(s) in order to facilitate a sale to a third party. If Huntley Power fails to meet NIMO's quantity request for electricity output, it will compensate NIMO. NIMO will pay Huntley Power according to the amount of electricity output delivered to NIMO, on a monthly basis. Control and title pass at the point of delivery of the energy and each party agrees to indemnify 54
57 the other against any claims arising out of any act or incident occurring during the period when control and title of the electricity is vested in the indemnifying party. Huntley Power has also entered into an agreement with NIMO that gives NIMO the option to purchase from Huntley Power certain quantities of electricity generated by Huntley units 67 or 68 (during peak and off-peak summer hours), within a specified range of MW per hour, not to exceed 189 MW for any one hour during the peak hours, for the term of the agreement. If Huntley Power fails to meet NIMO's quantity request for electricity, Huntley Power will compensate NIMO for quantities not provided. NIMO will pay Huntley Power according to the amount of power delivered to NIMO, on a monthly basis. Control and title passes at the point of delivery of the energy and each party shall indemnify the other party from any claims arising out of any act or incident occurring during the period when control and title of the electricity is vested in the indemnifying party. Oswego Power has entered into a four-year transition power sales contract with NIMO in order to hedge its transition to market rates. Under the agreement, NIMO will pay to Oswego Power a fixed monthly price plus start up fees for the right, but not the obligation, to claim, at a specified delivery point or points, the installed capacity of unit 5 of the Oswego facility, and for the right to exercise, at a specified price, an option for an additional 350 MW of installed capacity. The total amount of energy which Oswego Power must supply under the call option is limited to a nominal amount of energy per year. Oswego Power may refuse such option if the facility is unexpectedly unavailable or derated sufficiently to be unable to fulfill the option, as long as Oswego Power uses "good utility practice" to maintain the power stations. Oswego Power may also choose to supply the energy required from another source as long as adjustment is made for any difference in value between the agreed upon delivery point and the actual point of delivery. In the event that Oswego Power is unable to provide from its own sources installed capacity of unit 5 in the amount claimed by NIMO, Oswego Power must procure the capacity from the market and provide it to NIMO at no additional cost or else suffer a penalty. NRG Power Marketing has entered into a Wholesale Standard Offer Service Agreement, dated October 13, 1998 and amended as of January 15, 1999 (the "WSO Agreement"), with Blackstone Valley Electric Company, Eastern Edison Company, and Newport Electric Corporation (collectively the "EUA Companies"), which obligates NRG Power Marketing to provide each of the EUA Companies with firm all-requirements electric service, including capacity, energy, reserves, losses and related services necessary to serve a specified share of the EUA Companies' aggregate load attributable to retail customers taking standard offer service. NRG Power Marketing assumes all expenses, liabilities and losses, regulatory or economical, related to such service. NRG Power Marketing may supply the power to the EUA Companies at any point on the New England Power Pool transmission facilities system or on the EUA Companies' system. The price for each unit of electricity is a combination of a fixed price plus a fuel adjustment factor. The EUA Companies will calculate the estimated power supplied each month and pay to NRG Power Marketing the price for such electricity before the end of the next month. Any amounts unpaid by the due date will accrue interest. The EUA Companies may make retroactive adjustments to the bills for up to one year after the date of the original billing. NRG Power Marketing must meet certain creditworthiness criteria for the term of the agreement, or must provide a guaranty from an entity which meets the creditworthiness criteria. The term extends from April 26, 1999, the closing date of the asset purchase agreement until December 31, 2009. The agreement may also be terminated in the case of an event of default or if the facility's electric service requirement is less than 1 MW/hr for two consecutive months. In 1999, the Company entered into a Standard Offer Service Wholesale Sales Agreement with CL&P. The Company will supply CL&P with 35 percent of its standard offer service load during 2000, 40 percent during 2001 and 2002, and 45 percent during 2003. The four year contract is valued at $1.7 billion. The Company will serve the load with a combination of existing generation and power purchases. ENVIRONMENTAL REGULATIONS Environmental controls at the federal, state, regional and local levels have a substantial impact on the Company's operations due to the cost of installation and operation of equipment required for compliance. 55
58 AIR On October 12, 1999, the Company received a letter from the Office of the Attorney General of the State of New York speculating that based on a preliminary analysis, it believes that significant modifications were made to the Huntley and Dunkirk facilities during NIMO's ownership of these facilities without obtaining Prevention of Significant Deterioration (PSD) and/or New Source Review (NSR) permits. The letter requested documents related to historic maintenance, repair, and replacement work at the facilities, as well as other data related to operations and emissions from these facilities. On January 12, 2000, the Company received a formal request from the New York Department of Environmental Conservation (NYDEC) seeking essentially the same documents covered by the Attorney General's letter. The Company understands that the NYDEC request supercedes the Attorney General's request. Although, the Company does not have knowledge that NIMO failed to comply with the preconstruction permit requirements at the Huntley and Dunkirk facilities, the Company has only recently initiated steps to investigate more fully allegations to the contrary. If it is determined that these facilities did not comply with the PSD or NSR permit programs, the Company could be required among other things, to install pollution control technology to further control the emissions of nitrogen oxide (NO(X)) and sulfur dioxide (SO(2)) from the Huntley and Dunkirk facilities. By virtue of conditions imposed under the asset sale agreement between the Company and NIMO (the Company's rights and obligations under the asset sale agreement were substantially assigned to Huntley Power LLC and Dunkirk Power LLC), NIMO remains responsible for "any fines, penalties and assessments imposed by a governmental entity with respect to violation or alleged violation of Environmental Law which occurred prior to the Closing Date." Even so, the Company could become subject to fines and/or penalties associated with the period of time it has operated the facilities. On October 14, 1999, Governor Pataki of New York directed the Commissioner of the NYDEC to require further reductions of SO(2) emissions and NO(X) emissions from New York power plants, beyond that which is required under current federal and state law. Under Governor Pataki's directive NO(X) emissions during the "non-ozone" season would be reduced to levels consistent with those currently mandated for the "ozone" season under the Ozone Transport Commission's Memorandum of Understanding. This additional reduction requirement would be phased in between January 1, 2003 and January 2, 2007. In addition, Governor Pataki announced that he is ordering a reduction of S02 emissions by 50% beyond the requirements of the Federal Acid Rain Program. These reductions would also be phased in between January 1, 2003 and January 1, 2007. Compliance with these emission reduction requirements, if they become effective, could have a material impact on the operation of the Company's facilities located in the State of New York. On November 3, 1999, in the southern and mid-western regions of the United States, the United States Department of Justice (DOJ) filed suit against seven electric utilities for alleged violations of the Federal Clean Air Act (the Clean Air Act) NSR and PSD permit requirements at seventeen utility generating stations located in the southern and mid-western regions of the United States. In addition, the United States Environmental Protection Agency (U.S. EPA) issued administrative notices of violation alleging similar violations at eight other power plants owned by certain of the electric utilities named as defendants in the DOJ lawsuit, and also issued an administrative order to the Tennessee Valley Authority for similar violations at seven of its power plants. The DOJ lawsuit alleges that the defendants, over a period of twenty years, undertook modifications at their generating stations that resulted in increased air emissions without complying with stringent regulatory requirements governing such modifications. Subsequent to the DOJ lawsuit, New York, Connecticut and New Jersey have brought their own lawsuits against American Electric Power, an Ohio based utility holding company, and have sought to intervene in the DOJ lawsuit. To date, no lawsuits or administrative actions have been brought against the Company or the former owners of the facilities alleging violations of the NSR or PSD requirements. However, there is a likelihood that future lawsuits alleging similar violations may be filed against additional electric utility generating stations. The Company can provide no assurance that lawsuits or administrative actions alleging violations of PSD and NSR requirements will not be filed in the future. The State of Connecticut has in the past considered legislation that would require older electrical generating stations to comply with more stringent pollution standards for NO(X) and SO(2) emissions. During the 1999 legislative session, the Connecticut House of Representatives voted in favor of such legislation. The 56
59 House bill was referred to the Energy Technology Committee where no action was taken. Similar legislation has been introduced as part of the 2000 legislative session. SITE CONTAMINATION/REMEDIATION With the acquisition of the NRG Northeast assets, the Company assumed certain liabilities for existing environmental conditions at the sites with the exception of off-site liabilities associated with the disposal of hazardous materials and certain other environmental liabilities. The Company has not assumed responsibility for any contamination resulting from the September 7, 1998 explosion and subsequent fire involving a transformer containing PCBs at the Arthur Kill Station. The transformer explosion, fire and subsequent oil spill resulted in the release of PCB's to the environment. Consolidated Edison Company of New York, Inc. maintains responsibility for the remediation of the PCB and other contamination associated with this event. Environmental site assessments have been prepared for all of the recently acquired NRG Northeast assets. The remediation activities at the Arthur Kill, Astoria Gas Turbine and Somerset facilities are still in the study phase. As such, the remediation cost estimates are based on approaches that have not been approved yet by the regulatory agencies involved. Data from additional investigations performed at the Astoria Gas Turbines and the approach being taken at the Somerset Station may result in less costly remediation efforts than originally estimated. For the Connecticut facilities, the Company is planning to conduct additional studies to better quantify remedial need. Such studies include the preparation of risk assessments to justify remedial actions proposed by the Company to the Connecticut Department of Environmental Protection and U.S. EPA. COSTS The Company has recorded approximately $5.8 million for expected environmental costs related to site remediation issues at the Arthur Kill, Astoria facilities and Somerset facilities. These amounts are based on the environmental assessments for these sites. The Company has budgeted approximately $44 million for capital expenditures between 2000 and 2004 for environmental compliance, which includes the above remedial investigations, the installation of NO(X) control technology at the Somerset facility, intake screens at the Dunkirk facility, the resolution of consent orders for remediation at the Arthur Kill and Astoria facilities and the resolution of a consent order for water intake at the Arthur Kill facility. CLAIMS AND LITIGATION On or about July 12, 1999, Fortistar Capital Inc., a Delaware Corporation (Fortistar), filed a complaint in District Court (Fourth Judicial District, Hennepin County) in Minnesota against the Company, asserting claims for injunctive relief and for damages as a result of the Company's alleged breach of a confidentiality letter agreement with Fortistar relating to the Oswego facility (Letter Agreement). The Company disputes Fortistar's allegations and has asserted numerous counterclaims. A temporary injunction hearing was held on September 27, 1999. The acquisition of the Oswego facility was closed on October 22, 1999, following notification to the Court of Oswego Power's intention to close on that date. On January 14, 2000, the court denied Fortistar's request for a temporary injunction. The Company intends to continue to vigorously defend the suit and believes Fortistar's complaint to be without merit. No trial date has been set. The Company is involved in various other litigation matters. The Company is actively defending these matters and does not feel the outcome of such matters would materially impact the Company's results of operations. 57
60 NOTE 14 -- SEGMENT REPORTING The Company conducts its business within three segments: Independent Power Generation, Alternative Energy (Resource Recovery and Landfill Gas) and Thermal projects. These segments are distinct components of the Company with separate operating results and management structures in place. The "Other" category includes operations that do not meet the threshold for separate disclosure and corporate charges that have not been allocated to the operating segments. <TABLE> <CAPTION> INDEPENDENT POWER ALTERNATIVE GENERATION ENERGY THERMAL OTHER TOTAL ----------- ----------- ------- ----- ----- (THOUSANDS OF DOLLARS) <S> <C> <C> <C> <C> <C> 1999 OPERATING REVENUES Revenues from wholly-owned operations(a).... $322,943 $ 26,934 $76,277 $ 5,401 $431,555 Intersegment revenues....................... -- 963 -- -- 963 Equity in earnings of unconsolidated affiliates(b)............................. 69,686 (2,205) 19 -- 67,500 -------- -------- ------- -------- -------- Total operating revenues............. 392,629 25,692 76,296 5,401 500,018 -------- -------- ------- -------- -------- OPERATING COSTS AND EXPENSES Cost of wholly-owned operations............. 207,081 24,977 42,401 (4,559) 269,900 Depreciation and amortization............... 17,153 6,126 6,280 7,467 37,026 General, administrative, and development.... 33,783 7,876 8,869 33,044 83,572 -------- -------- ------- -------- -------- Total operating costs and expenses... 258,017 38,979 57,550 35,952 390,498 -------- -------- ------- -------- -------- OPERATING INCOME.............................. 134,612 (13,287) 18,746 (30,551) 109,520 -------- -------- ------- -------- -------- OTHER INCOME (EXPENSE) Minority interest in earnings of consolidated Subsidiary................... (2,322) -- (134) -- (2,456) Write-off of investment..................... -- -- -- -- -- Gain on sale of interest in projects........ -- -- -- 10,994 10,994 Other income, net........................... 2,328 (4,281) 10 8,375 6,432 Interest expense............................ (25,918) 169 (8,152) (59,475) (93,376) -------- -------- ------- -------- -------- Total other income (expense)......... (25,912) (4,112) (8,276) (40,106) (78,406) -------- -------- ------- -------- -------- INCOME (LOSS) BEFORE INCOME TAXES............. 108,700 (17,399) 10,470 (70,657) 31,114 INCOME TAX (BENEFIT).......................... 8,812 (27,642) 3,963 (11,214) (26,081) -------- -------- ------- -------- -------- NET INCOME.................................... $ 99,888 $ 10,243 $ 6,507 $(59,443) $ 57,195 </TABLE> 58
61 <TABLE> <CAPTION> INDEPENDENT POWER ALTERNATIVE GENERATION ENERGY THERMAL OTHER TOTAL ----------- ----------- ------- ----- ----- (THOUSANDS OF DOLLARS) <S> <C> <C> <C> <C> <C> 1998 OPERATING REVENUES Revenues from wholly-owned operations(a).... $ 8,185 $ 30,143 $52,699 $ 7,660 $ 98,687 Intersegment revenues....................... -- 1,737 -- -- 1,737 Equity in earnings of unconsolidated affiliates(b)............................. 81,948 (1,314) 1,215 (143) 81,706 -------- -------- ------- -------- -------- Total operating revenues............. 90,133 30,566 53,914 7,517 182,130 -------- -------- ------- -------- -------- OPERATING COSTS AND EXPENSES Cost of wholly-owned operations............. 7,097 20,980 24,665 (329) 52,413 Depreciation and amortization............... 980 5,590 9,258 492 16,320 General, administrative, and development.... (7,099) 7,776 3,298 52,410 56,385 -------- -------- ------- -------- -------- Total operating costs and expenses... 978 34,346 37,221 52,573 125,118 -------- -------- ------- -------- -------- OPERATING INCOME.............................. 89,155 (3,780) 16,693 (45,056) 57,012 -------- -------- ------- -------- -------- OTHER INCOME (EXPENSE) Minority interest in earnings of consolidated Subsidiary.................................. (2,251) -- -- -- (2,251) Write-off of investment..................... (26,740) -- -- -- (26,740) Gain on sale of interest in projects........ 29,950 -- -- -- 29,950 Other income, net........................... 2,482 2,683 118 3,137 8,420 Interest expense............................ (586) (1,921) (7,359) (40,447) (50,313) -------- -------- ------- -------- -------- Total other income (expense)......... 2,855 762 (7,241) (37,310) (40,934) -------- -------- ------- -------- -------- INCOME (LOSS) BEFORE INCOME TAXES............. 92,010 (3,018) 9,452 (82,366) 16,078 INCOME TAX (BENEFIT).......................... 18,605 (16,445) 2,852 (30,666) (25,654) -------- -------- ------- -------- -------- NET INCOME.................................... $ 73,405 $ 13,427 $ 6,600 $(51,700) $ 41,732 1997 OPERATING REVENUES Revenues from wholly-owned operations(a).... $ 5,339 $ 27,257 $48,604 $ 9,926 $ 91,126 Intersegment revenues....................... -- 926 -- -- 926 Equity in earnings of unconsolidated affiliates(b)............................. 26,206 (192) 186 -- 26,200 -------- -------- ------- -------- -------- Total operating revenues............. 31,545 27,991 48,790 9,926 118,252 -------- -------- ------- -------- -------- OPERATING COSTS AND EXPENSES Cost of wholly-owned operations............. 1,693 17,730 24,902 2,392 46,717 Depreciation and amortization............... 483 2,842 6,623 362 10,310 General, administrative, and development.... 8,186 6,111 2,403 26,416 43,116 -------- -------- ------- -------- -------- Total operating costs and expenses... 10,362 26,683 33,928 29,170 100,143 -------- -------- ------- -------- -------- OPERATING INCOME.............................. 21,183 1,308 14,862 (19,244) 18,109 -------- -------- ------- -------- -------- OTHER INCOME (EXPENSE) Minority interest in earnings of consolidated Subsidiary................... (131) (131) Write-off of investment..................... (8,964) (8,964) Gain on sale of interest in projects........ 1,559 7,143 8,702 Other income, net........................... 5,888 2,618 (14) 3,272 11,764 Interest expense............................ (653) (529) (5,958) (23,849) (30,989) -------- -------- ------- -------- -------- Total other income (expense)......... (2,301) 2,089 (5,972) (13,434) (19,618) -------- -------- ------- -------- -------- INCOME (LOSS) BEFORE INCOME TAXES............. 18,882 3,397 8,890 (32,678) (1,509) INCOME TAX (BENEFIT).......................... (6,502) (4,888) 3,165 (15,266) (23,491) -------- -------- ------- -------- -------- NET INCOME.................................... $ 25,384 $ 8,285 $ 5,725 $(17,412) $ 21,982 </TABLE> - --------------- (a) Revenues from wholly-owned operations are from external customers located in the United States. (b) The Company has significant equity investments for non-regulated projects outside of the United States. Equity earnings of unconsolidated affiliates, primarily independent power projects, includes $33.5 million in 1999, $29.3 million in 1998 and $27.1 million in 1997 from non-regulated projects located outside of the United States. The Company's equity investments in projects outside of the United States were $602.4 million in 1999, $591 million in 1998 and $517 million in 1997. 59
62 ITEM 9 -- CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES None. 60
63 PART IV ITEM 14 -- EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a)(1) Consolidated Financial Statements Included in Part II. (a)(2) Supplemental Financial Statement Schedules Exhibit 99.1 contains the financial statements of Mitteldeutsche Braunkohlengesell Schaft mbH ("MIBRAG"). Exhibit 99.2 contains the financial statements of Saale Energie GmbH ("Saale"). Exhibit 99.3 contains the financial statements of Sunshine State Power BVI and Sunshine State Power BVII (the "Sunshines"). Exhibit 99.4 contains the financial statements of NRG West Coast Power LLC ("West Coast Power"). All other financial statement schedules have been omitted because either they are not required or the information required to be set forth therein is included in the Consolidated Financial Statements or in the Notes thereto. (a)(3) Exhibits <TABLE> <C> <S> 3.1 Certificate of Incorporation. (Incorporated herein by reference to Exhibit 3.1 to the Registrants' Registration Statement on Form S-1, as amended, File No. 333-33397.) ("Form S-1") 3.2 By-Laws. (Incorporated herein by reference to Exhibits 3.2 to the Form S-1.) 4.1 Indenture, dated as of June 1, 1997, between the Company and Norwest Bank Minnesota, National Association. (Incorporated herein by reference to Exhibit 4.1 to the Form S-1). 4.2 Form of Exchange Notes. (Incorporated herein by reference to Exhibit 4.2 to the Form S-1). 4.3 Loan Agreement, dated June 4, 1999 between NRG Northeast Generating LLC, Chase Manhattan Bank and Citibank, N.A. 4.4 Indenture between the Company and Norwest Bank Minnesota, National Association, as Trustee dated as of May 25, 1999 (incorporated herein by reference to Exhibit 4.1 to the Company's current report on Form 8-K dated May 25, 1999 and filed on May 27, 1999). 4.5 Indenture between the Company and NRG Northeast Generating LLC and The Chase Manhattan Bank, as Trustee dated as of February 22, 2000. 4.6 NRG Energy Pass-Through Trust 2000-1, $250,000,000 8.70% Remarketable or Redeemable Securities ("ROARS") due March 15, 2005. 4.7 Trust Agreement between NRG Energy Inc. and The Bank of New York, as Trustee, dated March 20, 2000. 4.8 Indenture between NRG Energy Inc. and the Bank of New York , as Trustee dated March 20, 2000, 160,000,000 pounds sterling Reset Senior Notes due March 15, 2020. 10.1 Employment Contract, dated as of June 28, 1995, between the Company and David H. Peterson.(Incorporated herein by reference to Exhibit 10.1 to the Form S-1.) 10.2 Indenture, dated as of January 31, 1996, between the Company and Norwest Bank Minnesota, National Association, As Trustee. (Incorporated herein by reference to Exhibit 10.2 to the Form S-1). 10.3 Revolving Credit Agreement, dated as of March 17, 1997, ("ABN Credit Agreement") among the Company, the banks party thereto and ABN AMRO Bank, N.V. as Agent. (Incorporated herein by reference to Exhibit 10.3 to the Form S-1). 10.4 Note Agreement, dated August 20, 1993, among the Company Energy Center, Inc. and each of the purchasers named therein. (Incorporated herein by reference to Exhibit 10.4 to the Form S-1). </TABLE> 61
64 <TABLE> <C> <S> 10.5 Master Shelf and Revolving Credit Agreement, dated August 20, 1993 among the Company Energy Center, Inc., The Prudential insurance Registrants of America and each Prudential Affiliate which becomes party thereto. (Incorporated herein by reference to Exhibit 10.5 to the Form S-1). 10.6 Energy Agreement, dated February 12, 1988 between the Company (formerly known as Norenco Corporation) and Waldorf Corporation (the "Energy Agreement"). (Incorporated herein by reference to Exhibit 10.6 to the Form S-1). 10.7 First Amendment to the Energy Agreement, dated August 27, 1993. (Incorporated herein by reference to Exhibit 10.7 to the Form S-1). 10.8 Second Amendment to the Energy Agreement, dated August 27, 1993. (Incorporated herein by reference to Exhibit 10.8 to the Form S-1). 10.9 Third Amendment to the Energy Agreement, dated August 27, 1993. (Incorporated herein by reference to Exhibit 10.9 to the Form S-1). 10.10 Construction, Acquisition, and Term Loan Agreement, dated September 2, 1997 by and among NEO Landfill Gas, Inc , as Borrower, the lenders named on the signature pages, Credit Lyonnais New York Branch, as Construction/Acquisition Agent and Lyon Credit Corporation as Term Agent. (Incorporated herein by reference to Exhibit 10.10 to the Form S-1). 10.11 Guaranty, dated September 12, 1997 by the Company in favor of Credit Lyonnais New York Branch as agent for the Construction/Acquisition Lenders. (Incorporated herein by reference to Exhibit 10.11 to the Form S-1). 10.12 Construction, Acquisition, and Term Loan Agreement, dated September 2, 1997 by and among Minnesota Methane LLC, as Borrower, the lenders named on the signature pages, Credit Lyonnais New York Branch, as Construction/Acquisition Agent and Lyon Credit Corporation as Term Agent. (Incorporated herein by reference to Exhibit 10.12 to the Form S-1). 10.13 Guaranty, dated September 12, 1997 by the Company in favor of Credit Lyonnais New York Branch as agent for the Construction/Acquisition Lenders. (Incorporated herein by reference to Exhibit 10.14 to the Form S-1). 10.14 Non Operating Interest Acquisition Agreement dated as of September 12, 1997, by and among the Company and NEO Corporation. (Incorporated herein by reference to Exhibit 10.14 to the Form S-1). 10.15 First Amendment to ABN Credit Agreement, dated as of March 17, 1998. (Incorporated by reference to Exhibit 10.15 of Form 10-K for the year ended December 31, 1997). 10.16 364-Day Revolving Credit Agreement dated as of March 17, 1998, among the Company Energy, Inc., the Banks party thereto and ABN AMRO Bank N.V. as Agent. (Incorporated by reference to Exhibit 10.16 of Form-10K for the year ended December 31, 1997). 10.17 Employment Agreements between the Company and certain officers dated as of April 15, 1998. (Incorporated herein by reference to Exhibit 10.17 on Form 10-Q for the quarter ended March 31, 1998). 10.18 Wholesale Standard Offer Service Agreement between Blackstone Valley Electric Company, Eastern Edison Company, Newport Electric Corporation and NRG Power Marketing, Inc., dated October 13, 1998. 10.19 Asset Sales Agreement by and between Niagara Mohawk Power Corporation and NRG Energy, Inc., dated December 23, 1998. 10.20 First Amendment to Wholesale Standard Offer Service Agreement between Blackstone Valley Electric Company, Eastern Edison Company, Newport Electric Corporation and NRG Power Marketing, Inc., dated January 15, 1999. 10.21 Generating Plant and Gas Turbine Asset Purchase and Sale Agreement for the Arthur Kill generating plants and Astoria gas turbines by and between Consolidated Edison Company of New York, Inc., and NRG Energy, Inc., dated January 27, 1999. 10.22 Transition Energy Sales Agreement between Arthur Kill Power LLC and Consolidated Edison Company of New York, Inc., dated June 1, 1999. 10.23 Transition Power Purchase Agreement between Astoria Gas Turbine Power LLC and Consolidated Edison Company of New York, Inc., dated June 1,1999. </TABLE> 62
65 <TABLE> <C> <S> 10.24 Transition Power Purchase Agreement between Niagara Mohawk Power Corporation and Huntley Power LLC, dated June 11, 1999. 10.25 Transition Power Purchase Agreement between Niagara Mohawk Power Corporation and Dunkirk Power LLC, dated June 11, 1999. 10.26 Power Purchase Agreement between Niagara Mohawk Power Corporation and Dunkirk Power LLC, dated June 11, 1999. 10.27 Power Purchase Agreement between Niagara Mohawk Power Corporation and Huntley Power LLC, dated June 11, 1999. 10.28 Amendment to the Asset Sales Agreement by and between Niagara Mohawk Power Corporation and NRG Energy, Inc., dated June 11, 1999. 10.29 Transition Capacity Agreement between Astoria Gas Turbine Power LLC and Consolidated Edison Company of New York, Inc., dated June 25, 1999. 10.30 Transition Capacity Agreement between Arthur Kill Power LLC and Consolidated Edison Company of New York, Inc., dated June 25, 1999. 10.31 First Amendment to the Employment Agreement of David H. Peterson, dated June 27, 1999. 10.32 Second Amendment to the Employment Agreement of David H. Peterson, dated August 26, 1999. 10.33 Third Amendment to the Employment Agreement of David H. Peterson, dated October 20, 1999. 10.34 [Swap] Master Agreement between Niagara Mohawk Power Corporation and NRG Power Marketing, Inc., dated June 11, 1999. 10.35 Standard Offer Service Wholesale Sales Agreement between the Connecticut Light And Power Company and NRG Power Marketing, Inc., dated October 29, 1999. 10.36 364-day Revolving Credit Agreement among the Company and The Financial Institutions party thereto, and ABN-AMRO Bank, N.V., as Agent, dated as of March 10, 2000. 23.1 Consent of PricewaterhouseCoopers LLP. 24 Power of Attorney (included on signature page). 27 Financial Data Schedule. 99.1 Financial Statements of "MIBRAG". 99.2 Financial Statements of "Saale" (upon amendment). 99.3 Financial Statements of "Sunshines". 99.4 Financial Statements of "West Coast Power". (b) Reports on Form 8-K On November 8, 1999, the Company filed a Form 8-K reporting under Item 5 -- Other Events. The Company announced that on November 3, 1999 a Prospectus Supplement, dated November 2, 1999 and accompanying Prospectus, dated April 7, 1999, relating to the offering of $240,000,000 principle amount of 8.0% Remarketable or Redeemable Securities (ROARS) was filed. On November 16, 1999, the Company filed a Form 8-K reporting under Item 5 -- Other Events. The Company announced that on November 8, 1999 it had completed its $240,000,000 principle amount 8.0% Remarketable or Redeemable Securities (ROARS) offering. On December 28, 1999, the Company filed a Form 8-K reporting under Item 5 -- Other Events. The Company announced that on December 15, 1999, it acquired certain generating stations totaling 2,235 MW of generating capacity located in Connecticut from Connecticut Light & Power Company of Hartford, Connecticut. On March 30, 2000, the Company filed a Form 8-K reporting under Item 5 -- Other Events. The Company announced that as of March 29, 2000, The Board of Directors of Northern States Power Company approved the potential sale in a public offering by its wholly owned subsidiary, NRG Energy, Inc. of up to 18% interest in the common stock of NRG Energy. </TABLE> 63
66 SIGNATURES Pursuant to the requirements of Section 13 or 15 (d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 30, 2000. NRG ENERGY, INC. By: /s/ LEONARD A. BLUHM ------------------------------------ Leonard A. Bluhm Executive Vice President and Chief Financial Officer POWER OF ATTORNEY Each person whose signature appears below constitutes and appoints David H. Peterson and Leonard A. Bluhm, each or any of them, such person's true and lawful attorney-in-fact and agent with full power of substitution and resubstitution for such person and in such person's name, place and stead, in any and all capacities, to sign any and all amendments to this report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing necessary or desirable to be done in and about the premises, as fully to all intents and purposes as such person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them or his or their substitute or substitutes, may lawfully do or cause to be done by virtue hereof. In accordance with the Exchange Act, this report has been signed by the following persons on behalf of the registrant in the capacities indicated on March 30, 2000: <TABLE> <CAPTION> SIGNATURE TITLE --------- ----- <C> <S> /s/ DAVID H. PETERSON Chairman of the Board, President and Chief Executive - --------------------------------------------- Officer (Principal Executive Officer) David H. Peterson /s/ LEONARD A. BLUHM Executive Vice President and Chief Financial Officer - --------------------------------------------- (Principal Financial Officer) Leonard A. Bluhm /s/ DAVID E. RIPKA Controller (Principal Accounting Officer) - --------------------------------------------- David E. Ripka /s/ GARY R. JOHNSON Director - --------------------------------------------- Gary R. Johnson /s/ CYNTHIA L. LESHER Director - --------------------------------------------- Cynthia L. Lesher /s/ EDWARD J. MCINTYRE Director - --------------------------------------------- Edward J. McIntyre </TABLE> SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT. An annual report will be sent to security holders and will be supplementally filed with the Commission. Such annual report to security holders shall not be deemed "filed" with the Commission or otherwise subject to the liabilities of Section 18 of the Securities Exchange Act of 1934. No proxy material will be sent to security holders. 64