1 - - -------------------------------------------------------------------------------- - - -------------------------------------------------------------------------------- UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 ------------------------ FORM 10-K NRG ENERGY, INC. (Exact name of Registrant as specified in its charter)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000. [ ] 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. 000-25569 (612) 373-5300 (Registrant's telephone number, including area code) SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT: Common stock -- $.01 par value (Listed on the New York Stock Exchange) Corporate Units -- (Listed on the New York Stock Exchange) SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: None Indicate 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 Regulation 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. [x] THE AGGREGATE MARKET VALUE OF THE REGISTRANT'S COMMON STOCK HELD BY NON-AFFILIATES OF THE REGISTRANT WAS $1,523,732,734 AT MARCH 15, 2001. INDICATE THE NUMBER OF SHARES OUTSTANDING OF EACH OF THE REGISTRANT'S CLASSES OF COMMON STOCK AS OF THE LATEST PRACTICABLE DATE.
DELAWARE 41-1724239 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 901 MARQUETTE AVENUE 55402 MINNEAPOLIS, MINNESOTA (Zip Code) (Address of principal executive offices) Documents Incorporated by Reference: With respect to Part III (Items 10, 11, 12 and 13), Notice and Proxy Statement for the 2001 Annual Meeting of Shareholders will be filed not later than 120 days after December 31, 2000. - - -------------------------------------------------------------------------------- - - --------------------------------------------------------------------------------
CLASS OUTSTANDING AT MARCH 15, 2001 - - -------------------------------------- -------------------------------------- Class A - Common Stock, $0.01 par value 147,604,500 shares Common Stock, $0.01 par value 50,858,903 shares 2 NRG ENERGY, INC. AND SUBSIDIARIES INDEX
PAGE NO. -------- PART I Item 1 Business.................................................... 1 Item 2 Properties.................................................. 23 Item 3 Legal Proceedings........................................... 26 Item 4 Submission of Matters to a Vote of Security Holders......... 27 PART II Item 5 Market for the Registrant's Common Equity and Related Stockholder Matters....................................... 27 Item 6 Selected Financial Data..................................... 28 Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operations................................. 28 Item 7A Quantitative and Qualitative Disclosures About Market Risk...................................................... 36 Item 8 Financial Statements and Supplementary Data................. 38 Item 9 Changes in & Disagreements with Accountants on Accounting and Financial Disclosure.................................. 74 PART III Item 10 Directors and Executive Officers of the Registrant.......... 74 Item 11 Executive Compensation...................................... 74 Item 12 Security Ownership of Certain Beneficial Owners and Management................................................ 74 Item 13 Certain Relationships and Related Transactions.............. 74 PART IV Item 14 Exhibits, Financial Statements Schedules and Reports On Form 8-K....................................................... 75 SIGNATURES............................................................. 80 3 PART I ITEM 1 -- BUSINESS GENERAL NRG Energy, Inc. (NRG Energy or the Company) is a leading global energy company, primarily engaged in the acquisition, development, ownership, and operation of power generation facilities and the sale of energy, capacity and related products. NRG Energy was incorporated as a Delaware corporation on May 29, 1992. As of December 31, 2000, NRG Energy had interests in power generation facilities (including those under construction) having a total design capacity of 25,059 megawatts (MW), of which NRG Energy has or will have total or shared operational responsibility for 13,784 MW, and net ownership of, or leasehold interests in, 15,007 MW. On June 5, 2000, NRG Energy completed its initial public offering. Prior to its initial public offering, NRG Energy was a wholly-owned subsidiary of Northern States Power (NSP). In August 2000, NSP merged with New Century Energies, Inc. (NCE), a Colorado-based public utility holding company. The surviving corporation in the merger was renamed Xcel Energy Inc. (Xcel), and the shares of NRG Energy's class A common stock previously owned by NSP are now owned by a wholly-owned subsidiary of Xcel. As of December 31, 2000, Xcel owned an 82% interest in NRG Energy's outstanding common and class A common stock, representing 98% of the total voting power of NRG Energy's common stock and class A common stock. Xcel is one of the ten largest electricity and natural gas companies in the United States. Xcel has six public utility subsidiaries that collectively serve approximately 3.1 million electricity customers and 1.5 million gas customers in twelve states and has numerous non-utility subsidiaries, including NRG Energy, which are engaged in energy related businesses. In March 2001, NRG Energy completed a public offering of 18.4 million shares of its common stock. Following this offering, Xcel owns approximately 74% interest in NRG Energy's common stock and Class A common stock, representing 96.7% of the total voting power of NRG Energy's common stock and Class A common stock. NRG Energy has experienced significant growth in the last year, expanding from 10,990 MW of net ownership interests in power generation facilities (including those under construction) as of December 31, 1999, to 15,007 MW of net ownership interests as of December 31, 2000. This growth resulted primarily from a number of domestic and international acquisitions, notably the acquisition of Big Cajun I and II from Cajun Electric Power Cooperative, Inc. (Cajun Electric), the Killingholme A generating facility from National Power plc and the acquisition of Flinders Power in South Australia. In addition to NRG Energy's power generation projects, NRG Energy also has interests in district heating and cooling systems and steam transmission operations. As of December 31, 2000, NRG Energy's thermal and chilled water businesses had a steam and chilled water capacity equivalent to approximately 1,506 MW, of which its net ownership interest was 1,379 MW. NRG Energy believes that through its subsidiary NEO Corporation (NEO), it is one of the largest landfill gas generation companies in the United States, extracting methane from landfills to generate electricity. NEO owns 33 landfill gas collection systems and has 46 MW of net ownership interests in related electric generation facilities. NEO also has 58 MW of net ownership interests in 19 small hydroelectric facilities and 6 MW of net ownership interest in three small distributed generation facilities. NRG Energy intends to continue its growth through a combination of targeted acquisitions in selected core markets, the expansion or repowering of existing facilities and the development of new greenfield projects. NRG Energy has signed agreements to acquire an additional 5,704 MW of net ownership interest in existing generation projects and has acquired or has expansion plans for 5,515 MW of net ownership interest in expansion, repowering and greenfield generation projects. To prepare for these expansion, repowering and greenfield development opportunities, NRG Energy has agreed to purchase 22 turbine generators from General Electric Company and two turbine generators from Seimens Westinghouse over a five-year period commencing in 2002. These new turbines, which NRG Energy expects to install at domestic facilities, will 1 4 have a combined nominal generating capacity of approximately 4,640 MW. In addition, NRG Energy has on order three General Electric turbines with a combined nominal capacity of approximately 740 MW scheduled for delivery in January 2002, which are expected to be installed in facilities outside the United States. NRG Energy has also acquired the right to purchase an additional 24 General Electric turbines and an additional three Siemens Westinghouse turbines through its acquisition of assets from LS Power, LLC. These turbines have a combined generating capacity of approximately 4,306 MW. All but 1,993 MW of the turbines NRG Energy has on order have been allocated to NRG Energy's current, identified expansion, repowering or greenfield development projects. NRG Energy has also expanded its power marketing activities, which allow NRG Energy to optimize the value of its power generation assets and enable it to better meet its customers' energy requirements and improve its power marketing and risk management expertise. NRG Energy believes that it has secured and will continue to secure favorable pricing for its fuel purchases and power sales. NRG Energy's headquarters and principal executive offices are located at 901 Marquette Avenue, Suite 2300, Minneapolis, Minnesota 55402. NRG Energy's telephone number is (612) 373-5300. MARKET OPPORTUNITY The power industry is one of the largest industries in the world, accounting for approximately $220 billion in annual revenues and approximately 810,000 MW of installed generating capacity in the United States alone. The generation segment of the industry historically has been characterized by regulated electric utilities producing and selling electricity to a captive customer base. However, the power generation market has been evolving from a regulated market based on cost of service pricing to a competitive market. In response to increasing customer demand for access to low-cost electricity and enhanced services, new regulatory initiatives have been and are continuing to be adopted to increase competition in the power industry. NRG Energy believes that the power generation industry in the United States will experience MW growth of approximately 2% per year through 2008. NRG Energy believes that increasing demand and the need to replace old and inefficient generation facilities will create a significant need for additional power generating capacity throughout the United States and the world. In NRG Energy's view, these factors combined with recent restructuring legislation provide an attractive domestic environment for a competitive power producer like NRG Energy with a history of successfully developing, acquiring and operating power generation facilities. Outside of the United States, many governments in developed economies are privatizing their utilities and developing regulatory structures that are expected to encourage competition in the electricity sector, having realized that their energy assets can be sold to raise capital without hindering system reliability. In developing countries, the demand for electricity is expected to grow rapidly. In order to satisfy this anticipated increase in demand, many countries have adopted active government programs designed to encourage private investment in power generation facilities. NRG Energy believes that these market trends will continue to create opportunities to acquire and develop power generation facilities globally. STRATEGY NRG Energy's vision is to be a well-positioned, top three generator of power in selected core markets. Central to this vision is the pursuit of a well-balanced generation business that is diversified in terms of geographic location, fuel type and dispatch level. Currently, approximately 79% of NRG Energy's net MW of generation in operation and under construction is located in the United States in four core markets: our Northeast, South Central and West Coast regions and the recently added North Central region. The North Central Region was added to manage a newly acquired portfolio of operating projects and projects in construction and advanced development. Upon completion of NRG Energy's pending project acquisitions from Conectiv, NRG Energy intends to add a Mid-Atlantic region as a fifth core market. With NRG Energy's diversified asset base, NRG Energy seeks to have generating capacity available to back up any given facility during its outages, whether planned or unplanned, while having ample resources to take advantage of peak power market price opportunities. 2 5 NRG Energy's strategy is to capitalize on its acquisition, development, construction and operating skills to build a balanced, global portfolio of power generation assets. NRG Energy intends to implement this strategy by continuing an aggressive acquisition program and accelerating its development of existing site expansion projects and greenfield projects. NRG Energy believes that its operational skills and experience give it a strong competitive position in the unregulated generation marketplace. NORTH AMERICAN POWER GENERATION The North American power generation market is evolving from a regulated, utility dominated market based upon cost-of-service pricing to an independent power generation market based on competitive market pricing. While most domestic generation capacity is still utility owned and subject to cost-of-service regulation, NRG Energy expects the evolution to continue as regulated utility power generation assets are divested to non-regulated generators. In addition, NRG Energy expects that a significant share of the new generation capacity that is built to serve increasing demand and to replace less efficient facilities will be developed and owned by competitive power producers. Most of NRG Energy's North American projects are grouped under regional holding companies corresponding to their domestic core markets. In order to better manage NRG Energy's North American projects and to develop new projects in these regions more effectively, NRG Energy has established regional offices in Pittsburgh, Pennsylvania (Northeast region), Baton Rouge, Louisiana (South Central region) and San Diego, California (West Coast region). NRG Energy's recently added North Central region is managed from its Minneapolis headquarters. Upon completion of NRG Energy's pending project acquisitions from Conectiv, NRG Energy intends to add a Mid-Atlantic region, which will be managed from its Wilmington, Delaware office. NRG Energy operates its generation facilities within each region as a separate operating unit within its power generation business. This regional portfolio structure allows NRG Energy to coordinate the operations of its assets to take advantage of regional opportunities, reduce risks related to outages, whether planned or unplanned, and pursue expansion plans on regional basis. NORTHEAST REGION As of December 31, 2000, NRG Energy owned approximately 7,104 MW of net generating capacity (including projects under construction) in the Northeast United States, primarily in New York, New Jersey, Connecticut and Massachusetts. These generation facilities are well diversified in terms of dispatch level (base-load, intermediate and peaking), fuel type (coal, natural gas and oil) and customers. In addition, NRG Energy believes certain of its facilities and facility sites in the Northeast provide opportunities for repowering or expanding existing generating capacity. NRG Energy's Northeast facilities are generally competitively positioned within their respective market dispatch levels with favorable market dynamics and locations close to the major load centers in the New York Power Pool (NYPP) and NEPOOL. SOUTH CENTRAL REGION As of December 31, 2000, NRG Energy owned approximately 2,413 MW of net generating capacity (including projects under construction) in the South Central United States, primarily in Louisiana. NRG Energy's South Central generating assets consist primarily of its net ownership of 1,708 MW of power generation facilities in New Roads, Louisiana (which are referred to as the Cajun facilities) that were acquired in March 2000. NRG Energy believes that the Cajun facilities and related infrastructure provide significant opportunities for expanding its generating capacity in the region. WEST COAST REGION As of December 31, 2000, NRG Energy owned approximately 1,570 MW of net generating capacity (including projects under construction) on the West Coast of the United States. NRG Energy's West Coast generation assets consist primarily of a 50% interest in West Coast Power LLC (West Coast Power) and a 58% interest in the Crockett Cogeneration facility. In May 1999, Dynegy Power Corporation (Dynegy) and 3 6 NRG Energy formed West Coast Power to serve as the holding company for a portfolio of operating companies that own generation assets in Southern California. This portfolio currently comprises the El Segundo Generating Station, the Long Beach Generating Station, the Encina Generating Station and 17 combustion turbines in the San Diego area. Dynegy provides power marketing and fuel procurement services to West Coast Power, and NRG Energy provides operations and management services. NRG Energy believes certain of its facilities and facility sites on the West Coast provide opportunities for repowering or expanding generating capacity, and NRG Energy has submitted permit applications to expand its El Segundo facility. NORTH CENTRAL REGION As of December 31, 2000, NRG Energy owned approximately 175 MW of net generating capacity in the north central United States, primarily Illinois. In January 2001, NRG Energy completed its project acquisition from LS Power, LLC of approximately 5,633 MW of operating projects and projects in construction and advanced development, 1,697 MW of which are currently in operation, or under construction. MID-ATLANTIC REGION NRG Energy plans to add a Mid-Atlantic region upon the completion of its acquisition of approximately 1,875 MW of net ownership interests in generation facilities from subsidiaries of Conectiv. The Mid-Atlantic region will contain facilities located primarily in Pennsylvania, Maryland, Delaware and New Jersey. COMPETITIVE POWER GENERATION -- INTERNATIONAL Historically, the majority of power generating capacity outside of the United States has been owned and controlled by governments. During the past decade, however, many foreign governments have moved to privatize power generation plant ownership through sales to third parties and by encouraging new capacity development and refurbishment of existing assets by independent power developers. Governments have taken a variety of approaches to encourage the development of competitive power markets, from awarding long-term contracts for energy and capacity to purchasers of power generation to creating competitive wholesale markets for selling and trading energy, capacity and related products. NRG Energy believes that there will be significant opportunities to invest in attractive projects in international markets. Based upon NRG Energy's assessment of market opportunities and its portfolio risk management criteria, NRG Energy intends to leverage its reputation, experience and expertise in order to acquire foreign assets in selected countries. As market opportunities develop, NRG Energy expects that its international strategy will be consistent with its domestic core market strategy in terms of geographic, fuel and dispatch diversification. NRG Energy believes operating and asset diversity will allow it to reduce business and market risks, while positioning it to take advantage of market opportunities, including peak power market price opportunities and periods of constrained availability of generating capacity, fuels and transmission. To manage NRG Energy's international asset portfolio risks, NRG Energy utilizes a portfolio risk management discipline based upon country risk, as identified by an independent, internationally recognized organization. This portfolio tool, which has been endorsed by NRG Energy's board of directors, requires that it manage its entire portfolio of generation capacity to maintain a high quality, weighted average, equivalent country risk. Using this tool, NRG Energy is able to monitor the exposure it is taking in emerging markets to maintain an appropriate balance in its asset portfolio. NRG Energy's international power generation projects are managed as three distinct markets, Asia Pacific, Europe and Other Americas. NRG Energy is presently focusing its international development in Europe, Australia and Latin America. In the future, NRG Energy will consider international projects outside of these markets if it believes that an opportunity exists to create a new core market or that the expected returns from a particular project warrant an investment. ASIA PACIFIC NRG Energy is one of the largest competitive power producers in Australia with a net ownership interest of 2,083 MW. As of December 31, 2000, in power generation facilities (including projects under construction). NRG Energy intends to maintain its position in this market through additional acquisitions and 4 7 development of new projects. NRG Energy will also look for opportunities in selected countries in the Asia Pacific region to become established within the region. EUROPE NRG Energy has been a significant participant in the competitive power generation markets in Germany and the Czech Republic since its entry into those markets. NRG Energy's growth in Europe was augmented in early 2000 with the acquisition of the Killingholme facility and will expand further with the expected mid-2001 commencement of commercial operations at the Enfield facility, both of which are located in the United Kingdom. NRG Energy intends to continue its growth efforts in these countries and to develop projects in selected countries. As of December 31, 2000, NRG Energy has a net ownership interest of 1,223 MW in power generation facilities (including projects under construction) in Europe. OTHER AMERICAS NRG Energy has pursued acquisition and development opportunities in Latin America since the mid-1990s. Initially, NRG Energy participated as one of four original sponsors of the Latin Power fund, a private equity investment fund managed by Scudder. More recently, NRG Energy acquired a 49% interest in the second largest generator of electricity in Bolivia, Compania Boliviana de Energia Electrica S.A. -- Bolivian Power Company Limited (COBEE). NRG Energy plans to target new opportunities in selected countries, primarily Brazil and Argentina, where NRG Energy believes more attractive acquisition and greenfield opportunities exist. As of December 31, 2000, NRG Energy has a net ownership interest of 225 MW in power generation facilities (including projects under construction) in Latin America. ALTERNATIVE ENERGY NRG Energy provides alternative energy through NEO, one of the largest landfill gas generation companies in the United States, and resource recovery, which processes municipal solid waste as fuel used to generate power. NEO CORPORATION NEO is a wholly-owned subsidiary of NRG Energy's 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 and the acquisition of small hydroelectric projects. NEO owns 33 landfill gas collection systems and has 46 MW of net ownership interests in related electric generation facilities. NEO also has 58 MW of net ownership interests in 19 small hydroelectric facilities and 6 MW of net ownership interests in three small distributed generation facilities. NEO derives a substantial portion of its income as a result of the generation of Section 29 tax credits, which, for 2000, totaled $33.8 million. The existing tax law authorizing these credits is scheduled to expire in 2007. RESOURCE RECOVERY FACILITIES NRG Energy's Newport, Minnesota, resource recovery facility can process over 1,500 tons of municipal solid waste per day, 90% of which is used as fuel in power generation facilities in Red Wing and Mankato, Minnesota. Pursuant to service agreements with Ramsey and Washington Counties, Minnesota, which expire in 2007, NRG Energy processes a minimum of 280,800 tons of municipal solid waste per year at the Newport facility and receives service fees based on the amount of waste processed, pass-through costs and certain other factors. NRG Energy is also entitled to an operation and maintenance fee, which is designed to recover fixed costs and to provide NRG Energy with a guaranteed amount for operating and maintaining the Newport facility for the processing of 750 tons per day of municipal solid waste, whether or not such waste is delivered for processing. Since 1989, NRG Energy has operated the Elk River resource recovery facility located in Elk River, Minnesota, which can process over 1,500 tons of municipal solid waste per day, 90% of which is recovered and used in power generation facilities in Elk River and Mankato, Minnesota. Xcel owns 85% of the Elk River facility and United Power Association owns the remaining 15%. NRG Energy also manages and operates an 5 8 ash storage and disposal facility for the Elk River facility at Xcel's Becker ash disposal facility, an approved ash deposit site near Becker, Minnesota. NRG Energy operates the Becker facility on behalf of Xcel. THERMAL NRG Energy has interests in district heating and cooling systems and steam transmission operations. NRG Energy's thermal and chilled water businesses have a steam and chilled water capacity equivalent to approximately of 1,506 MW, of which its net ownership interest is 1,379 MW. NRG Energy owns and operates, through its holding company NRG Thermal Corporation, five district heating and cooling systems in Minneapolis, San Francisco, Pittsburgh, Harrisburg and San Diego. These systems provide steam heating to approximately 600 customers and chilled water to 81 customers. In addition, NRG Energy's thermal division operates five projects that serve industrial/government customers with high-pressure steam and hot water. POWER MARKETING NRG Energy's energy marketing subsidiary, NRG Power Marketing, Inc. (NRG Power Marketing), began operations in 1998 to maximize the utilization of and return from its domestic generation assets and to mitigate the risks associated with those assets. This subsidiary purchases and markets energy and energy related commodities, including electricity, natural gas, oil, coal and emission allowances. By using internal resources to acquire fuel for and to market electricity generated by its domestic facilities, NRG Energy believes that it can secure the best pricing available in the markets in which it sells power and enhance its ability to compete. NRG Power Marketing provides a full range of energy management services for NRG Energy's generation facilities in its Northeast, South Central and North Central regions. These services are provided under power sales and agency agreements pursuant to which NRG Power Marketing manages the sales and marketing of energy, capacity and ancillary services from these facilities and also manages the purchase and sale of fuel and emission allowances needed to operate these facilities. NRG Power Marketing conducts its activities in accordance with risk management guidelines approved by the NRG Power Marketing board of directors, which has primary responsibility for oversight of NRG Power Marketing activities. NRG Energy's risk management guidelines require that its treasury department perform a credit review and approve all counter parties and credit limits prior to NRG Power Marketing entering into a transaction with such counter parties. NRG Energy does not engage in speculative trading, thus transactions are primarily for physical delivery of the particular commodity for the specified period. These physical delivery transactions may take the form of fixed price, floating price or indexed sales or purchases, and options on physical transactions, such as puts, calls, basis transactions and swaps, are also permitted. Contracts for the transmission and transportation of these commodities are also authorized, as necessary, in order to meet physical delivery requirements and obligations. All forward sales and purchases of electricity and fuel are reported to the board of directors of NRG Power Marketing and to our Financial Risk Management Committee. In accordance with the risk management guidelines, no more than 50% of the uncommitted energy or capacity of any facility will be sold forward without the approval of the board of directors of NRG Power Marketing. Violation by any employee of any of the risk management guidelines is grounds for immediate termination of employment. NRG Power Marketing handles fuel procurement and trading of emissions allowances in order to support NRG Energy's overall needs. Generally, NRG Energy seeks to hedge prices for 50% to 70% of its expected fuel requirements during the succeeding 12 to 24 month period. This provides NRG Energy with certainty as to a portion of its fuel costs while allowing it to maintain flexibility to address lower than expected dispatch rates and to take advantage of the dual fuel capabilities at many of its facilities. 6 9 HOW NRG ENERGY SELLS ITS GENERATING CAPACITY AND ENERGY NRG Energy's operating revenues are derived primarily from the sale of electrical energy, capacity and other energy products from its power generation facilities. Revenues from these facilities are received pursuant to: - long-term contracts of more than one year including: - power purchase agreements with utilities and other third parties (generally 2-25 years); - standard offer agreements to provide load serving entities with a percentage of their requirements (generally 4-9 years); and - "transition" power purchase agreements with the former owners of acquired facilities (generally 3-5 years). - short-term contracts or other commitments of one year or less and spot sales including: - spot market and other sales into various wholesale power markets; and - bilateral contracts with third parties. NRG Energy's objective is to mitigate variability in its earnings by having approximately 50% of its capacity contracted for under contracts greater than one year, generally seeking to enter into contracts with lengths of 1-5 years, selling half of its remaining capacity (25%) in the forward market for 30-365 days, and selling the other half of its remaining capacity (25%) in the spot market to capture opportunities in the market when prices are higher. By following this strategy, NRG Energy seeks to achieve positive, stable returns while retaining the flexibility to capture premium returns when available. During 2000, NRG Energy derived approximately 34.4% of its 2000 revenues from majority owned operations from two customers: New York Independent System Operator (22.2%) and Connecticut Light and Power Company (12.2%). During 1999, NRG Energy derived approximately 51.2% of total revenues from wholly owned operations from three customers: Niagara Mohawk Power Corporation (21%), Consolidated Edison Company of New York, Inc. (19.7%) and Eastern Utilities Associates (10.5%). GEOGRAPHICAL INFORMATION For financial information on NRG Energy's operations on a geographical basis, see Item 8 -- Note 18 to the financial statements. PLANT OPERATIONS NRG Energy's success depends on its ability to achieve operational efficiencies and high availability at its generation facilities. In the new unregulated energy industry, minimizing operating costs without compromising safety or environmental standards while maximizing plant flexibility and maintaining high reliability is critical to maximizing profit margins. NRG Energy's operations and maintenance practices are designed to achieve these goals. NRG Energy's overall corporate strategy of establishing a top three presence in certain core markets is in part driven by its operational strategy. While NRG Energy's approach to plant management emphasizes the operational autonomy of its individual plant managers and staff to identify and resolve operations and maintenance issues at their respective facilities, NRG Energy has also implemented a regional shared practices system in order to facilitate the exchange of information and best practices among the plants in its various regions. NRG Energy has organized its operations geographically such that inventories, maintenance, backup and other operational functions are pooled within a region. This approach enables NRG Energy to realize cost savings and enhances its ability to meet its facility availability goals. Plant supervisors and staff within core markets and across the company typically participate in weekly conference calls in order to discuss operational issues and share best practices. 7 10 SIGNIFICANT ASSET AND BUSINESS ACQUISITIONS In March 2000, NRG Energy acquired the assets of the Killingholme A generation facility from National Power plc for L390 million (approximately $615 million at the date of acquisition), subject to post-closing adjustments. Killingholme is a combined cycle gas-fired baseload facility located in North Lincolnshire, England. The facility comprises three units with a total generating capacity of 680 MW. NRG Energy owns and operates the facility, which sells its power into the wholesale electricity market of England and Wales. In March 2000, NRG Energy acquired the Cajun facilities, 1,708 MW of coal and gas-fired generation assets in Louisiana, for approximately $1,055.9 million (the Cajun facilities). These assets were formerly owned by Cajun Electric. NRG Energy acquired these assets as a result of a competitive bidding process following the Chapter 11 bankruptcy of Cajun Electric. In September 2000, NRG Energy completed the acquisition of Flinders Power in South Australia. NRG Energy paid approximately AUD $314.4 million (U.S. $180 million at the date of acquisition) for a 100-year lease of the Flinders Power assets. Flinders Power includes two power stations totaling 760 MW. In addition, NRG Energy received a 20-year lease, renewable for additional 10-year terms, of the Leigh Creek coal mine and a dedicated rail line. The 100-year lease also includes managing the long-term fuel supply and power purchase agreement of the 180 MW Osborne Cogeneration Station. In January 2001, NRG Energy completed the acquisition of a 5,633 MW portfolio of operating projects and projects in construction and advanced development that are located primarily in the north central and south central United States, from LS Power for $708 million. Approximately 1,697 MW are currently in operation or under construction, and NRG Energy expects that an additional $1,850 million will be required to complete projects currently under construction or about to commence construction. Each facility employs natural gas-fired, combined-cycle technology. Through December 31, 2005, NRG Energy also has the opportunity to acquire ownership interests in an additional 3,000 MW of generation projects developed and offered for sale by LS Power and its partners. SIGNIFICANT EQUITY INVESTMENTS The following are significant equity investments included in NRG Energy's Independent Power Generation Segment. LOY YANG POWER NRG Energy has a 25.4% interest in Loy Yang Power, which owns and operates the 2,000 MW Loy Yang A brown coal fired thermal power station and the adjacent Loy Yang coal mine located in Victoria, Australia. This interest was purchased for AUD $340 million (approximately US $264.3 million at the time of the acquisition) in 1997. The power station has four 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 that are located on the Loy Yang site, which service not only the Loy Yang A facility, but also the adjacent Loy Yang B 1,000 MW power station, a pulverized dried brown coal plant, and several other nearby power stations. The wholesale electricity market in Australia is regulated under the National Electricity Law, which provides for a legally enforceable National Electricity Code, which defines the market rules. The code also makes provision for the establishment of the National Electricity Market Management Company to manage the power system, maintain system security and administer the spot market. Under the rules of the National Electricity Market, the Loy Yang facility is required to sell all of its output of electricity through the competitive wholesale market for electricity operated and administered by the National Electricity Market. Loy Yang Power is subject to a number of senior debt lending covenants. From 1997 through 1999, energy prices received by Loy Yang were lower than NRG Energy expected when the assets were purchased. As a result, during 2000, the company projected that during 2001 it would breach the loan covenants permitting equity distributions to the project owners. Based upon current forecasts incorporating improve- 8 11 ments in the electricity market, indications are that possible future senior debt covenant breaches forecast in earlier financial reports will not occur. In the event that the forecast improvements are not achieved, a breach of these covenants could occur. While Loy Yang Power would still expect to fully service all of its senior debt payment obligations, senior lenders might exercise their rights to enforce their securities at that time. NRG Energy could be required to write-off all or a significant portion of its current $250 million investment in this project as a result of such enforcement, a determination by the project company that a write-down of its assets is required or NRG Energy's determination that it would not be able to recover its investment in this project. Junior debt interest payments to the value of AUD $33.9 (approximately US $18.9 million ) were accumulated during 2000 and, of this, a payment of $7.8 million (approximately US $4.4 million) was made. Deferred/Accrued Junior debt interest payments as of December 31, 2000, totaled AUD $36.9 million (approximately US $20.6 million). Based on current cash forecasts it is possible that further interest payments on the Junior Debt Facility may also be deferred, all deferred interest will be paid at a later time as permitted under the workings of the project financing arrangements. In the National Electricity Market power 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, generators have entered into "contracts for differences" with distribution companies, electricity retailers and industrial customers. These contracts for differences 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. In February 2000, CMS Energy announced its intention to divest its 49.6% ownership in the Loy Yang project but has established no deadline for completion of the sale. CMS Energy indicated that it intended to sell its interest because the project was no longer of strategic value to its portfolio and had not met its financial expectations. Under certain circumstances CMS will require the approval of Loy Yang Power's lenders and other parties to enable the sale to proceed. The impact (if any) of the proposed sale on NRG's existing investment in Loy Yang Power is not known at the date of this report. MIBRAG NRG Energy indirectly purchased a 33 1/3% interest in the equity of Mitteldeutsche Braunkohlengesellschaft mbH (MIBRAG) in 1994 for $10.6 million. MIBRAG owns coal mining, power generation and associated operations, all of which are located south of Leipzig, Germany. MIBRAG was 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. 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 power purchase agreement with Westsachsische Energie Aktiengesellschaft, a recently privatized German electric utility. MIBRAG's lignite mine operations include Profen, Zwenkau and Schleenhain with total estimated reserves of 776 million metric tons, which are expected to last for more than 40 years. A dispute has arisen as to coal transportation compensation payments to be made to MIBRAG pursuant to the acquisition agreement by Bundesanstalt fur vereinigungsbedingte Sonderaufgaben (BvS), a German governmental entity that facilitated the privatization of MIBRAG. The size of the annual coal transportation compensation payments fluctuates based on the volume of coal transported to the Schkopau facility. The payment due for 2000 was approximately 59 million deutsche marks (approximately U.S. $28 million) and has been received by MIBRAG. However, BvS disputes its obligation to make any future compensation payments. MIBRAG and BvS are engaged in active discussions to resolve this disagreement. Although MIBRAG believes that a satisfactory resolution can be negotiated, if that did not occur and BvS ceased to make any further annual transportation compensation payments to MIBRAG, but MIBRAG were nevertheless required to continue to transport coal to the Schkopau facility without the benefit of these 9 12 transportation compensation payments at the prices agreed in 1993 when the compensation and acquisition agreements were negotiated, it would have a material adverse effect on MIBRAG. COBEE In December 1996, NRG Energy acquired for $81.8 million a 49.1% interest in COBEE, the second largest generator of electricity in Bolivia. COBEE has entered into contracts, which expire in 2008, with two Bolivian distribution companies pursuant to which COBEE supplies electricity. All payments under these contracts are made in United States dollars. COBEE operates its electric generation business under a 40-year concession granted by the Bolivian government in 1990. Under this concession, COBEE is entitled to earn a return of 9.0% on assets within its rate base. 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 previous year. COBEE periodically applies to the Superintendent of Electricity for rate increases sufficient to provide its 9.0% rate of return based on COBEE's current operating results and its projection of future revenues and expenses. Under COBEE's concession, COBEE's assets are required to be removed from the rate base in 2008. GLADSTONE POWER STATION The Gladstone facility is a 1,680 MW coal-fired power generation facility located in Gladstone, Australia. NRG Energy acquired a 37.5% ownership interest in the Gladstone facility for $64.9 million when the facility was privatized in March 1994. NRG Energy is responsible for the operation and maintenance of the Gladstone facility pursuant to a 17-year operation and maintenance agreement that commenced in 1994, which includes an annual bonus based on availability targets. The Gladstone facility sells electricity to the Queensland Power Trading Corporation and also to Boyne Smelters Limited. Pursuant to an interconnection and power pooling agreement, Queensland Power is obligated to accept all electricity generated by the facility, subject to merit order dispatch, for an initial term of 35 years. Queensland Power also entered into a 35-year capacity purchase agreement with each of the project's owners for such owner's percentage of the capacity of the Gladstone facility, excluding that sold directly to Boyne Smelters. Under the capacity purchase agreements, Queensland Power pays the facility owners both a capacity and an energy charge. The capacity charge is designed to cover the projected fixed costs allocable to Queensland Power, including debt service and an equity return, and is adjusted to reflect variations in interest rates. The owners of Boyne Smelters have also entered into a power purchase agreement with each of the project's owners, providing for the sale and purchase of such owner's percentage share of capacity allocated to Boyne Smelters. The term of each of these power purchase agreements is 35 years. The owners of Boyne Smelters is obligated to pay to each of the project's owners a demand charge that is intended to cover the fixed costs of supplying capacity to Boyne Smelters, including debt service and return on equity. The owners of Boyne Smelters are also obligated to pay an energy charge based on the fuel cost associated with the production of energy from the Gladstone facility. SCHKOPAU POWER STATION In 1993, NRG Energy acquired for $18.2 million an indirect 50% interest in a German limited liability company, Saale Energie GmbH, which then acquired a 41.9% interest in a 960 MW coal-fired power plant that was under construction in the East German city of Schkopau. The first 425 MW unit of the Schkopau plant began operation in January 1996, the 110 MW turbine in February 1996, and the second 425 MW unit in July 1996. The coal is provided under a long-term contract by MIBRAG's Profen lignite mine. 10 13 Saale Energie sells its allocated 400 MW portion of the plant's capacity under a 25-year contract with VEAG, a major German utility that 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. NRG Energy receives 50% of the net profits from these VEAG payments through its ownership interest in Saale Energie. COLLINSVILLE POWER STATION The Collinsville Power Station is a 192 MW coal-fired power generation facility located in Collinsville, Australia. In March 1996, NRG Energy acquired a 50% ownership interest in the idled Collinsville facility for $11.9 million when the Queensland State government privatized it. The Collinsville facility was recommissioned and commenced operations on August 11, 1998. Transfield Holdings Pty Ltd, the project's other 50% owner, and NRG Energy have entered into an 18-year power purchase agreement with Queensland Power under which Queensland Power will pay both a capacity and an energy charge to the project's owners. The capacity charge is designed to cover the projected fixed costs allocable to Queensland Power, including debt service and an equity return. The energy charge is based on the fuel costs associated with the production of energy from the facility. ENERGY CENTER KLADNO The Energy Center Kladno project, located in Kladno, the Czech Republic consists of two distinct phases. In 1994, NRG Energy acquired an interest in the existing coal-fired electricity and thermal energy facility that can supply 28 MW of electrical energy and 150 MW equivalent of steam and heated water. This facility historically supplied electrical energy to a nearby industrial complex. The second phase was the expansion of the existing facility, which was completed in January 2000, by the addition of 345 MW of new capacity, 271 MW of which is coal-fired and 74 MW of which is gas-fired. The original project is owned by Energy Center Kladno, a Czech limited liability company in which NRG Energy owns a 44.26% interest. The expansion is held separately through ECK Generating, a Czech limited liability company in which NRG Energy owns a 44.50% interest. ENERGY DEVELOPMENTS LTD Energy Developments Limited, a publicly traded company listed on the Australian Stock Exchange, owns and operates approximately 274 MW of generation primarily in Australia. Between February 1997 and April 1998, NRG Energy acquired a total of 14,609,670 common shares and 16,800,000 convertible, non- voting preference shares of Energy Developments. NRG Energy paid a total of approximately AUD$69.1 million (US$44.5 million at the time of acquisition), or AUD$2.20 (US$1.42) per share, for the shares, which represent approximately a 29.1% ownership interest in Energy Developments. NRG Energy has agreed to restrictions on its ability to purchase more shares or to dispose of any existing shares of Energy Developments. The preference shares do not become convertible into common shares unless a takeover bid is made for Energy Developments. In such event, if Energy Developments fails to comply with an obligation to appoint directors nominated by the owner of the preference shares, the preference shares can be converted at the option of the owner to common shares on a share-for-share basis. WEST COAST POWER In May 1999, Dynegy and NRG Energy formed West Coast Power, 50% owned by affiliates of each sponsor. West Coast Power serves as the holding company for a portfolio of operating companies that 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). 11 14 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 $88.3 million during April 1998. Long Beach Generating Station: The Long Beach Generating Station is a 560 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 during March 1998 through a competitive bid process for $29.9 million. 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 during May 1999, at a purchase price of $283.2 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. During May 1999, Dynegy and NRG Energy 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 ancillary services market. In December 2000, NRG Energy and its partner submitted permit applications in respect of a planned repowering of the jointly-owned El Segundo station. The planned repowering will add approximately 621 MW of generating capacity to the facility at a cost of approximately $368 million. Prior to the repowering, approximately 350 MW at the El Segundo Station will be decommissioned. The repowering project has a targeted operation date of June 2003. For additional information regarding California's liquidity crisis see Item 7 -- Management's Discussion and Analysis of Financial Condition and Results of Operations -- California Liquidity Crisis. SIGNIFICANT MAJORITY- AND WHOLLY-OWNED OPERATIONS The following are significant majority- and wholly-owned operations included in NRG Energy's Independent Power Generation segment. CROCKETT COGENERATION Pacific Crockett Energy, Inc., an indirect, wholly-owned subsidiary of NRG Energy's, 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 Purchase Power Agreement (PPA) extending to 2026. The PPA provides for a fixed capacity payment and a 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 expires in 2026. Natural gas is supplied to the project by BP Canada Energy Marketing. 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. 12 15 NRG NORTHEAST GENERATING LLC NRG Energy has acquired, through subsidiaries, in five separate transactions, certain generating assets from Niagara Mohawk Power Corporation (NIMO), Consolidated Edison Company of New York (ConEd), Montaup Electric Company (MEC), a wholly owned subsidiary of Eastern Utilities Association (EUA), and Connecticut Light & Power Company (CL&P) for a total cost of approximately $1.5 billion. NRG Energy has aggregated these assets into a regional generating company, NRG Northeast Generating LLC (NRG Northeast); (collectively, the NRG Northeast assets). The NRG Northeast assets represent competitive, low cost units with favorable market dynamics and locations close to major load centers in the NYPP and NEPOOL. Huntley and Dunkirk: In June 1999, NRG Energy 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. In connection with this acquisition, NRG Energy entered into a 4-year agreement with NIMO that requires NRG Energy to provide to NIMO pursuant to a predetermined schedule fixed quantities of energy and capacity at a fixed price. Oswego: In October 1999, NRG Energy 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, NRG Energy completed the 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, have a combined capacity rating of 1,456 MW. Somerset: In April 1999, NRG Energy completed the 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, NRG Energy completed 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. NRG Energy also entered into a 4-year standard offer agreement that requires NRG Energy to provide to CL&P a portion of its load requirements through the year 2003 at a substantially fixed price. 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. NRG SOUTH CENTRAL GENERATING LLC In March 2000, the Cajun facilities were acquired in a competitive bidding process following a Chapter 11 bankruptcy filing by their former owner, Cajun Electric. NRG Energy paid approximately $1,055.9 million for these facilities. The Cajun facilities consist of 100% of two gas-fired intermediate/peaking power generation units with a total capacity of 220 MW, which NRG Energy collectively refers to as Big Cajun I, and two coal-fired, base-load power generation units with a total capacity of 1,150 MW, and a 58% interest in a third coal-fired, base load unit with a total capacity of 575 MW, which NRG Energy refers to collectively as Big Cajun II. 13 16 NRG Energy believes the bankruptcy of Cajun Electric resulted from Cajun Electric's inability to service approximately $2,200 million in secured debt provided in part by the Rural Utilities Service of the United States Department of Agriculture, most of which was incurred as a result of the purchase by Cajun Electric of a 30% interest in the River Bend Nuclear Station Unit 1, a nuclear power generation facility located in Saint Francisville, Louisiana. Cajun Electric's 30% interest in the River Bend nuclear facility was transferred to Entergy Gulf States in December 1997. NRG Energy has no ownership interest in the River Bend nuclear facility or responsibility for any indebtedness of Cajun Electric to the Rural Utilities Service or otherwise. NRG Energy sells most of the energy and capacity of the Cajun facilities to 11 of Cajun Electric's former power cooperative members. Seven of these cooperatives have entered into 25-year power purchase agreements with NRG Energy, and four have entered into two to four year power purchase agreements. In addition, NRG Energy sells power under contract to two municipal power authorities and one investor-owned utility that were former customers of Cajun Electric. KILLINGHOLME In March 2000, NRG Energy acquired the 680 MW gas-fired Killingholme combined cycle, baseload facility in North Lincolnshire, England from National Power plc. The purchase price was (pounds)390 million (approximately U.S. $615.0 million at the time of acquisition), subject to post closing adjustments. NRG Energy financed the acquisition with a 19-year non-recourse credit facility that provides for (pounds)235 million (approximately U.S. $374 million at the time of acquisition) for the costs of the acquisition and (pounds)90 million (approximately U.S. $143 million at the time of acquisition) for letters of credit and working capital needs. NRG Energy sells power from the facility into the wholesale electricity market of England and Wales. The facility has a ten and one half year contract to purchase up to 70% of its natural gas requirements from a subsidiary of Centrica plc. From January 1, 2000 through the date of the acquisition, NRG Energy entered into a tolling agreement with National Power pursuant to which NRG Energy received revenues based on the prevailing market prices for electricity in exchange for payments to National Power based on the incremental operating costs of the facility. NRG Energy anticipates that prices for power in the wholesale electricity market of England and Wales will decrease over the short term due to new trading rules that are expected to come into effect and increase competition in this market. This expected market trend was taken into account when NRG Energy bid to acquire this facility. NRG Energy has entered into short-term agreements to sell a portion of the output of the Killingholme facility, and, in the future, NRG Energy intends to enter into similar short-term and long-term agreements that will provide a degree of stability to its revenues from the facility. FLINDERS POWER In September 2000, NRG Energy completed the acquisition of Flinders Power, South Australia's final generation company to be privatized. NRG Energy paid approximately AUD $314.4 million (approximately U.S. $180 million at the date of acquisition) for a 100-year lease of certain Flinders Power assets, including two power stations totaling 760 MW. In addition, NRG Energy received a 20-year lease, renewable for additional 10-year terms, for the Leigh Creek coal mine and a dedicated rail line. The 100-year lease agreement also includes managing the long-term fuel supply and power purchase agreement of the 180 MW Osborne Cogeneration Station. LS POWER PROJECTS In January 2001, NRG Energy completed the acquisition of a 5,633 MW portfolio of operating projects and projects in construction and advanced development from LS Power, LLC for approximately $708 million, subject to purchase price adjustments. Approximately 1,697 MW are currently in operation or under construction, and NRG Energy expects that an additional $1,850 million will be required to complete construction of the projects currently under construction or about to commence construction. Each facility employs natural gas-fired combined cycle technology. Through 2005, NRG has the opportunity to acquire 14 17 ownership interests in an additional 3,000 MW of generation projects developed and offered for sale by LS Power and its partners. SIGNIFICANT PENDING ACQUISITIONS AND PROJECTS UNDER DEVELOPMENT Due to the many complexities inherent in the acquisition, development and financing of projects, there can be no assurance that any of NRG Energy's pending acquisitions and projects under development, including those described below, will be consummated. TURKEY In 1999, NRG Energy and its partners were selected as the winning bidder for the 600 MW Seyitomer Power Station and related lignite mine in Kuthya, Turkey. Seyitomer is NRG Energy's second successful bid in Turkey. In 1998, also with partners, NRG Energy won a bid to acquire the 450 MW coal-fired Kangal plant and lignite mine in central Turkey. A law has been introduced in the Turkish parliament that would require these projects, among others, to close by June 30, 2001 or be cancelled. NRG Energy is working to meet this deadline. ESTONIA In June 2000, the Estonian cabinet approved the terms under which NRG Energy may proceed to purchase a 49% interest in Narva Power, which owns approximately 3,000 MW of oil shale-fired generation plants and a 51% interest in state-owned oil shale mines. In August 2000, NRG Energy signed a Heads of Terms Agreement with Eesti Energia, the Estonian state-owned electric utility, providing for the purchase, for approximately $65.5 million, of a 49% stake in Narva Power, the owner-operator of the oil shale fired Eesti and Balti power plants located near Narva, Estonia. A government-owned entity, Eesti-Energia, will retain 51% ownership of Narva Power. Narva Power's two stations, Balti and Eestia, currently supply more than 90% of Estonia's electricity, and have a combined capacity of approximately 2,700 MW. NRG Energy is working to close the acquisition in the second quarter of 2001. CONECTIV ASSETS In January 2000, NRG Energy executed purchase agreements with Conectiv to acquire 1,875 MW of coal, gas and oil fired electric generating capacity and other assets located in New Jersey, Delaware, Maryland and Pennsylvania. NRG Energy will pay approximately $800 million for the assets. 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 (7.55%)and Keystone (6.17%) steam stations in Pennsylvania. 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. NRG Energy will sell 500 MW of capacity and associated energy to Delmarva (a subsidiary of Conectiv) under a five-year power purchase agreement commencing upon the closing of the acquisition. The remaining energy and capacity will be sold in PJM and neighboring markets. Closing of the acquisition has been delayed pending receipt of required regulatory approvals. NRG Energy expects to close the acquisition in the second quarter of 2001. 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, NRG Energy will acquire a 7.55% ownership or 129 MW of generation. NRG Energy will also acquire a 6.17% ownership or 106 MW in the 1,711 MW coal-fired Keystone Steam Station also located near Pittsburgh, Pennsylvania. 15 18 PARTNERSHIP WITH AVISTA-STEAG LLC In November 2000, NRG Energy agreed to form a partnership with Avista-STEAG LLC to build, operate and manage a 633 MW natural gas-fired power plant in Fort Bend County, Texas. NRG Energy expects to own 50% of the project. NRG Energy's investment in the project is expected to total approximately $163 million. Construction is scheduled to begin in early 2001, with commercial operation expected in February 2003. BRIDGEPORT AND NEW HAVEN HARBOR In December 2000, NRG Energy signed asset purchase agreements to acquire the 585 MW coal fired Bridgeport Harbor Station and the 466 MW oil and gas fired New Haven Harbor Station in Connecticut from Wisconsin Energy Corporation for $325 million, subject to purchase price adjustments. The acquisition is subject to regulatory and other conditions and is expected to close during the second quarter of 2001. REID GARDNER AND CLARK GENERATING STATIONS In November 2000, Dynegy Inc. and NRG Energy executed asset purchase agreements to acquire the 740 MW gas fired Clark Generating Station and 445 MW of the 605 MW coal-fired Reid Gardner Generating Station, both of which are near Las Vegas, Nevada. The purchase price is approximately $634 million, subject to purchase price adjustments. The acquisition is subject to regulatory and other conditions. Although NRG Energy is working to close the acquisition during the second quarter of 2001, legislation has been recently introduced in the Nevada legislature that, if passed as introduced, would prohibit the sale of the Reid Gardner and Clark stations. In addition, the Public Utilities Commission of Nevada has commenced a proceeding that could reverse its original requirement that these plants be sold. Finally, NRG Energy and Dynegy are negotiating to acquire an additional 145 MW of the Reid Gardner Station. NORTH VALMY In October 2000, NRG Energy signed an asset purchase agreement to acquire from Sierra Pacific Resources its 50% interest in the 522 MW coal fired North Valmy Generating Station located in Valmy, Nevada, and a 100% interest in 25 MW of peaking units near the North Valmy Station. Idaho Power, the other 50% owner of the North Valmy Station, has a 180-day right of first refusal on purchasing this 50% interest. The right of first refusal expires in May 2001. In addition, the California legislature recently enacted legislation prohibiting any public utility subject to regulation by the California Public Utilities Commsion from selling any generating asset until 2006. This law applies to Sierra Pacific Resources because approximately 10% of its rate payers are located in California. NRG Energy is working to have legislation introduced to exempt the North Valmy Station and the peaking units from application of this law. MERIDEN In December 2000, NRG Energy signed a purchase agreement to acquire a 540 MW natural gas fired generation facility being developed in Meriden, Connecticut, for a purchase price of approximately $25 million. NRG Energy expects to close the acquisition during the second quarter of 2001. NRG Energy estimates the costs to complete construction of the plant to be approximately $384 million, which has a planned commercial operation date of June 2003. AUDRAIN In February 2001, NRG Energy signed a purchase agreement to acquire an approximately 640 MW natural gas fired power plant currently under construction in Audrain County, Missouri, from Duke Energy North America LLC. NRG Energy expects the acquisition to close during the second quarter of 2001, with commercial operation of the plant commencing in June 2001. 16 19 REGULATION NRG Energy 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. NRG Energy 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 NRG Energy which would have an adverse impact on its operations. In particular, the competitive power markets in the United States, United Kingdom, Australia and other countries are dependent on the existing regulatory structure, and while NRG Energy strives to take advantage of the opportunities created by regulatory changes, it is impossible to predict the impact of regulatory changes on its operations. Further, NRG Energy believes that the level of environmental awareness and enforcement is growing in most countries, including most of the countries in which NRG Energy intends to develop and operate new projects. Based on current trends, NRG Energy believes that the nature and level of environmental regulation to which it is subject will become more stringent. NRG Energy's policy is therefore to operate its projects in accordance with applicable local law or relevant environmental guidelines adopted by the World Bank, whichever reflects the more stringent level of control. COMPETITION The independent power industry is characterized by numerous strong and capable competitors, some of which may have more extensive operating experience, more extensive experience in the acquisition and development of power generation facilities, larger staffs or greater financial resources than NRG Energy does. Many of NRG Energy's competitors also are seeking attractive power generation opportunities, both in the Untied States and abroad. This competition may adversely affect NRG Energy's ability to make investments or acquisitions. In recent years, the independent power industry has been characterized by increased competition for asset purchases and development opportunities. In addition, regulatory changes have also been proposed to increase access to transmission grids by utility and non-utility purchasers and sellers of electricity. Industry deregulation may encourage the disaggregation of vertically integrated utilities into separate generation, transmission and distribution businesses. As a result, significant additional competitors could become active in the generation segment of the industry. The United States electric utility industry is currently experiencing increasing competitive pressures, primarily in wholesale markets, as a result of consumer demands, technological advances, greater availability of natural gas-fired generation that is more efficient than NRG Energy's generation facilities and other factors. The Federal Energy Regulatory Commission (FERC) has implemented and continues to propose regulatory changes to increase access to the nationwide transmission grid by utility and non-utility purchasers and sellers of electricity. In addition, a number of states are considering or implementing methods to introduce and promote retail competition. Recently, some utilities have brought litigation aimed at forcing the renegotiation or termination of power purchase agreements requiring payments to owners of QF projects based upon past estimates of avoided cost that are now substantially in excess of market prices. In the future, utilities, with the approval of state public utility commissions, could seek to abrogate their existing power purchase agreements. Proposals have been introduced in Congress to repeal PURPA and PUHCA, and FERC has publicly indicated support for the PUHCA repeal effort. If the repeal of PURPA or PUHCA occurs, either separately or as part of legislation designed to encourage the broader introduction of wholesale and retail competition, the 17 20 significant competitive advantages that independent power producers currently enjoy over certain regulated utility companies would be eliminated or sharply curtailed, and the ability of regulated utility companies to compete more directly with independent power companies would be increased. To the extent competitive pressures increase and the pricing and sale of electricity assumes more characteristics of a commodity business, the economics of domestic independent power generation projects may come under increasing pressure. Deregulation may not only continue to fuel the current trend toward consolidation among domestic utilities, but may also encourage the disaggregation of vertically-integrated utilities into separate generation, transmission and distribution businesses. In addition, the independent system operators who oversee most of the wholesale power markets have in the past imposed, and may in the future continue to impose, price limitations and other mechanisms to address some of the volatility in these markets. For example, the independent system operator for the New York power Pool and the California independent system operator have recently imposed price limitations. These types of price limitations and other mechanisms in New York, California, the New England Power Pool and elsewhere may adversely impact the profitability of NRG Energy's generation facilities that sell energy into the wholesale power markets. Finally, the regulatory and legislative changes that have recently been enacted in a number of states in an effort to promote competition are novel and untested in many respects. These new approaches to the sale of electric power have very short operating histories, and it is not yet clear how they will operate in times of market stress or pressure. Given the extreme volatility and lack of meaningful long-term price history in many of these markets and the imposition of price limitations by independent system operators. ENVIRONMENTAL MATTERS The construction and operation of power projects are subject to extensive environmental protection and land use regulation in the United States. These laws and regulations often require a lengthy and complex process of obtaining licenses, permits and approvals from federal, state and local agencies. If such laws and regulations are changed and NRG Energy's facilities are not grandfathered, extensive modifications to project technologies and facilities could be required. Most of the foreign countries in which NRG Energy owns or may acquire or develop independent power projects have laws or regulations relating to the ownership or operation of electric power generation facilities. These laws and regulations are typically significant for independent power producers because they are still changing and evolving in many countries. NRG Energy retains appropriate advisors in foreign countries and seeks to design its international development and acquisition strategy to comply with and take advantage of opportunities presented by each country's energy laws and regulations. There can be no assurance that changes in such laws or regulations could not adversely affect NRG Energy's international operations. NRG Energy and its subsidiaries continue to strive to achieve compliance with all environmental regulations currently applicable to their operations. However, it is not possible at this time to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations, interpretations or enforcement policies or, generally, what effect future laws or regulations may have upon NRG Energy's operations. For more information on Environmental Matters see Note 17 to the Financial Statements under Item 8. EMPLOYEES At December 31, 2000, NRG Energy had 2,934 employees, approximately 424 of whom are employed directly by NRG Energy and approximately 2,510 of whom are employed by its wholly owned subsidiaries and affiliates. Approximately 1,496 employees are covered by bargaining agreements. NRG Energy has experienced no significant labor stoppages or labor disputes at its facilities. 18 21 FORWARD-LOOKING STATEMENTS Certain statements included in this annual report are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities and Exchange Act of 1934. While NRG Energy believes that the expectations expressed in such forward-looking statements are reasonable, NRG Energy can give no assurances that these expectations will prove to have been correct. 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 our 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 NRG Energy 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 NRG Energy'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 NRG Energy's 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 under construction, including obtaining competitive contracts, obtaining regulatory and permitting approvals, local opposition, construction delays and other factors beyond NRG Energy's control; - 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 NRG Energy's control; 19 22 - Factors challenging the successful integration of projects not previously owned or operated by NRG Energy, 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; - Changes in government regulation or the implementation of government regulations, including pending changes within or outside of California as a result of the California energy crisis, which could result in NRG Energy's failure to obtain regulatory approvals required to close project acquisitions, and which could adversely affect the continued deregulation of the electric industry; - Other business or investment considerations that may be disclosed from time to time in NRG Energy's Securities and Exchange Commission filings or in other publicly disseminated written documents, including NRG Energy's Registration Statement No. 333-52508, as amended, and all supplements therein. NRG Energy 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 that could cause our actual results to differ materially from those contemplated in any forward-looking statements included in this Form 10-K should not be construed as exhaustive. EXECUTIVE OFFICERS OF THE REGISTRANT MANAGEMENT The name, age and title of each of the executive officers and directors of NRG as of March 27, 2001 are as set forth below: David H. Peterson has been Chairman of the Board of NRG Energy since January 1994, Chief Executive Officer since November 1993, President since 1989 and a Director since 1989. Mr. Peterson was also Chief 20
NAME AGE TITLE ---- --- ----- David H. Peterson 59 Chairman of the Board, President, Chief Executive Officer and Director James J. Bender 44 Vice President and General Counsel and Corporate Secretary Brian B. Bird 38 Vice President and Treasurer Leonard A. Bluhm 55 Executive Vice President and Chief Financial Officer W. Mark Hart 50 Senior Vice President, NRG Energy, Inc. and President NRG Europe and Latin America Roy R. Hewitt 55 Vice President, Administrative Services Keith G. Hilless 62 Senior Vice President, Asia Pacific Craig A. Mataczynski 40 Senior Vice President, North America John A. Noer 54 Senior Vice President, NRG Energy Inc. and President, NRG Worldwide Operations William T. Pieper 35 Controller Ronald J. Will 60 Senior Vice President, Europe Wayne H. Brunetti 58 Director, President and CEO Xcel Energy Inc. Luella G. Goldberg 64 Director, Former Acting President and Chair of the Board of Trustees Wellesley College Pierson M. Grieve 73 Director, Retired Chairman and CEO Ecolab, Inc. William A. Hodder 69 Director, Retired Chairman and CEO Donaldson Company Inc. James J. Howard 65 Director, Chairman of the Board Xcel Energy, Inc. Gary R. Johnson 54 Director, Vice President and General Counsel Xcel Energy Inc. Richard C. Kelly 54 Director, President-Enterprises Xcel Energy Inc. Edward J. McIntyre 50 Director, Vice President and CFO Xcel Energy Inc. 23 Operating Officer of NRG Energy from June 1992 to November 1993. Prior to joining NRG Energy, Mr. Peterson was Vice President, Non-Regulated Generation for Northern States Power, and he has served in various other management positions with Northern States Power during the last 20 years. James J. Bender has been Vice President, General Counsel and Secretary of NRG since June 1997. He served as the General Counsel of the Polymers Division of Allied Signal Inc. from May 1996 until June 1997. From June 1994 to May 1996, Mr. Bender was employed at NRG Energy, acting as Senior Counsel until December 1994 and as Assistant General Counsel and Corporate Secretary from December 1994 to May 1996. Brian B. Bird has been Vice President and Treasurer of NRG Energy since June 1999 and Treasurer since June 1997, prior to which he was Director of Corporate Finance and Treasury for Deluxe Corporation in Shoreview, Minnesota from September 1994 to May 1997. Mr. Bird was Manager of Finance for the Minnesota Vikings professional football team from March 1993 to September 1994. Mr. Bird held several financial management positions with Northwest Airlines in Minneapolis, Minnesota from 1988 to March 1993. Leonard A. Bluhm has been Executive Vice President and Chief Financial Officer of NRG Energy since January 1997. Immediately prior to that, he served as the first President and Chief Executive Officer of Cogeneration Corporation of America. Mr. Bluhm was Vice President, Finance of NRG Energy from January 1993 through April 1996. Mr. Bluhm was Chief Financial Officer of Cypress Energy Partners, a wholly-owned project subsidiary of NRG Energy, from April 1992 to January 1993, prior to which he was Director, International Operations and Manager, Acquisitions and Special Projects of NRG Energy from 1991. Mr. Bluhm previously served for 20 years in various financial positions with Northern States Power. W. Mark Hart is Senior Vice President, Europe and Latin America of NRG Energy. Prior to joining NRG, Hart was vice president of Canadian Operations at Newmont Mining Company and vice president of Business Processes and Operations for Europe, South America and Asia. Before that he managed mining operations, engineering and machinery with Cyprus Amax Minerals Company where he served as senior vice president of U.S. Operations and president and chief executive officer of Australia. He has also worked for American Electric Power Fuel Supply, Standard Oil Company's minerals division and Consolidated Coal Company. Roy R. Hewitt has been Vice President, Administrative Services at NRG Energy since February 1999. He has over 30 years experience in the power industry including 24 years with Northern States Power and seven years with NRG Energy. Mr. Hewitt joined NRG Energy in 1994 as a member of the senior management team with NRG's Gladstone Power Station project in Queensland, Australia. In 1996, he returned to NRG Energy's corporate headquarters as Executive Director, Human Resources. In 1997, Mr. Hewitt returned to Australia as Managing Director of the Gladstone Project and later served as Executive Director, Operations and Engineering for NRG Energy's Asia-Pacific region headquartered in Brisbane, Australia. Keith G. Hilless has been Senior Vice President, Asia Pacific of NRG Energy and Managing Director of NRG Asia Pacific since July 1998, prior to which he was a senior executive since August 1997. Prior to joining NRG Energy, Mr. Hilless was Chief Executive Officer of the Queensland Transmission and Supply Corporation where he had served since January 1995. From 1993 to January 1995, Mr. Hilless served as the Queensland Electricity Commissioner. Craig A. Mataczynski has been Senior Vice President, North America of NRG Energy and President and Chief Executive Officer of NRG North America, since July 1998. From December 1994 until July 1998, Mr. Mataczynski served as Vice President, U.S. Business Development of NRG. From May 1993 to January 1995, Mr. Mataczynski served as President of NEO Corporation, NRG Energy's wholly-owned subsidiary that develops small electric generation projects within the United States. Prior to joining NRG Energy, Mr. Mataczynski worked for Northern States Power from 1982 to 1994 in various positions, including Director, Strategy and Business Development and Director, Power Supply Finance. John A. Noer has been Senior Vice President of NRG Energy and President of NRG Worldwide Operations since January 1, 2000. Immediately prior to that he served as President-NSP Combustion and 21 24 Hydro Generation for Northern States Power Company and as a director of NRG since June 1997. He was President and CEO of Northern States Power Wisconsin, a wholly-owned subsidiary of Northern States Power, since January 1993. Prior to joining Northern States Power Wisconsin, Mr. Noer was President of Cypress Energy Partners, a project subsidiary of NRG Energy, from March 1992 to January 1993. Prior to joining Cypress Energy Partners, Mr. Noer held various management positions with Northern States Power since joining the company in September 1968. William T. Pieper has been Controller of NRG Energy since May 2000. He has also held the positions of Assistant Controller and Manager of International Accounting since joining NRG Energy in March 1995. Prior to joining NRG Energy, Mr. Pieper practiced as a Certified Public Accountant for six years with the firm of KPMG. Ronald J. Will has been Senior Vice President, Europe of NRG Energy and President and Chief Executive Officer of NRG Europe since July 1998. From March 1994 until July 1998, Mr. Will served as Vice President, Operations and Engineering of NRG Energy, prior to which he served as Vice President, Operations from June 1992. Prior to joining NRG, he served as President and Chief Executive Officer of NRG Thermal from February 1991 to June 1993. Prior to February 1991, Mr. Will served in a variety of positions with Norenco, a wholly-owned thermal services subsidiary of NRG, including Vice President and General Manager from August 1989 to February 1991. Wayne H. Brunetti is president and CEO of Xcel Energy Inc. Prior to assuming his current position in August, 2000, Brunetti was vice chairman, president and chief executive officer of NCE. He was vice chairman, president and chief operating officer of Public Service Company of Colorado before it merged with Southwestern Public Service Company to form NCE. He joined Public Service Company of Colorado as president and chief operating officer in 1994. Luella G. Goldberg is a member of the boards of directors of TCF Financial, ReliaStar Financial and Hormel Foods Corporations. From 1985 to 1993, Goldberg served as chair of the Wellesley College Board of Trustees. She served as acting president of the college from July 1993 to October 1993 and is now a Trustee Emerita. Pierson M. (Sandy) Grieve is a member of the boards of directors of The St. Paul Companies, Inc., Media One Group, Inc., Reliant Energy Minnegasco, Guide Corporation, Mesaba Aviation and Bank of Naples. Grieve served as chairman and CEO of Ecolab, Inc. from 1983 to 1995 after moving from his position as president and CEO of Questor Corp. William A. Hodder is a member of the boards of directors of Musicland Stores Corp., ReliaStar Financial Corp., SUPERVALU, Inc., Wells Fargo & Co, and the University of Minnesota, Carlson School of Management (Board of Overseers). Hodder served as chairman and CEO of Donaldson Company, Inc. from 1994 to 1996 and chairman, president and CEO from 1985 to 1994. Hodder joined Donaldson as president in 1973. James J. Howard is chairman, of Xcel Energy. He served as chairman, President and CEO of Northern States Power from 1994 until August 2000. He joined NSP as president and CEO in 1987. Before joining NSP, Howard was president and chief operating officer of Ameritech. Howard is also chairman of the Federal Reserve Bank of Minneapolis, a director of Ecolab Inc., Honeywell International Inc. and Walgreen Co. Gary R. Johnson has been a Director of NRG Energy since 1993 and has been Vice President and General Counsel of Xcel since August 2000. He served as Vice President and General Counsel of Northern States Power from November 1991 to August 2000. Prior to November 1991, Mr. Johnson was Vice President-Law of Northern States Power from January 1989, acting Vice President from September 1988 and Director of Law from February 1987, and he has served in various management positions with Northern States Power during the last 20 years. Richard C. Kelly has been a Director of NRG Energy since August 2000. He is President -- Enterprises of Xcel, and was formerly executive vice president, financial and support services, and chief financial officer for 22 25 NCE. Before that, Kelly was senior vice president of finance, treasurer and chief financial officer for Public Service Company of Colorado, which he joined in 1968. Edward J. McIntyre has been a Director of NRG Energy since 1993. He has been Vice President and Chief Financial Officer of Xcel Energy since August 2000, and prior to that was Vice President and Chief Financial Officer of Northern States Power from January 1993. Mr. McIntyre served as President and Chief Executive Officer of Northern States Power-Wisconsin, a wholly-owned subsidiary of Northern States Power, from July 1990 to December 1992, as Vice President Gas Utility from November 1985 to June 1990, and he has served in various other management positions since joining Northern States Power in 1973. ITEM 2 -- PROPERTIES Listed below are descriptions of NRG Energy's interests in facilities, operations and/or projects under construction as of December 31, 2000. INDEPENDENT POWER PRODUCTION AND COGENERATION FACILITIES 23
NRG'S NET PERCENTAGE CAPACITY OWNERSHIP NAME AND LOCATION OF FACILITY PURCHASER/POWER MARKET (MW)(2) INTEREST FUEL TYPE - - ----------------------------- ---------------------- -------- ---------- --------- NORTHEAST REGION: Oswego, New York............... Niagara Mohawk/NYISO 1,700 100% Oil/Gas Huntley, New York.............. Niagara Mohawk/NYISO 760 100% Coal Dunkirk, New York.............. Niagara Mohawk/NYISO 600 100% Coal Arthur Kill, New York.......... Con Ed/NYISO 842 100% Gas Astoria Gas Turbines, New York......................... Con Ed/NYISO 614 100% Gas Somerset, Massachusetts........ NEPOOL/ISO-NE 229 100% Coal/Oil Middletown, Connecticut........ NEPOOL/NYPP/ISO-NE 856 100% Oil/Gas Montville, Connecticut......... NEPOOL/NYPP/ISO-NE 498 100% Gas/Oil Norwalk, Connecticut........... NEPOOL/NYPP/ISO-NE 353 100% Oil Connecticut Remote Jets, Connecticut.................. NEPOOL/NYPP/IOS-NE 127 100% Oil Devon, Connecticut............. NEPOOL/NYPP/IOS-NE 401 100% Gas/Oil Other -- 10 projects........... Various 124 Various Various SOUTH CENTRAL REGION: Big Cajun I, Louisiana Unit 1....................... Cooperatives/SERC/Municipals 110 100% Gas Unit 2....................... Cooperatives/SERC/Municipals 110 100% Gas Big Cajun I expansion, Louisiana.................... Cooperatives/SERC/Municipals 238 100% Gas Big Cajun II, Louisiana Unit 1....................... Cooperatives/SERC/Municipals 575 100% Coal Unit 2....................... Cooperatives/SERC/Municipals 575 100% Coal Unit 3....................... Cooperatives/SERC/Municipals 338 58% Coal Sterlington, Louisiana......... SERC/Various 130 100% Gas Sterlington expansion, Louisiana.................... SERC/Various 72 100% Gas Sabine River Works, Texas...... Dupont/ERCOT 210 50% Gas Other -- 3 projects............ Various 55 Various Various WEST COAST REGION: El Segundo Power, California... Cal PX 510 50% Gas Encina, California............. Cal PX/Must-run 483 50% Gas/Oil Long Beach Generating, California................... Cal PX 265 50% Gas San Diego Combustion Turbines, California................... Cal PX/Must-run 127 50% Gas/Oil Crockett Cogeneration, California................... PG&E 138 57.67% Gas Mt. Poso Cogeneration, California................... PG&E 20 39.50% Coal Other -- 4 projects............ Various 27 Various Various NORTH CENTRAL REGION: Rocky Road Power, Illinois..... ECAR/MAIN 175 50% Gas 26 24
NRG'S NET PERCENTAGE CAPACITY OWNERSHIP NAME AND LOCATION OF FACILITY PURCHASER/POWER MARKET (MW)(2) INTEREST FUEL TYPE - - ----------------------------- ---------------------- -------- ---------- --------- MID-ATLANTIC REGION: Dover, Delaware................ Conectiv/PJM 18 100% Gas Dover expansion, Delaware...... Conectiv/PJM 88 100% Gas INTERNATIONAL PROJECTS: Australia: Flinders, South Australia...... National Electricity Market 760 100% Coal Gladstone Power Station, Queensland................... QPTC; Boyne Smelter 630 37.50% Coal Loy Yang Power A, Victoria..... Victorian Pool 507 25.37% Coal Collinsville, Collinsville Australia.................... QPTC 96 50% Coal Energy Investors Funds, Various...................... Various 2 0.25% Coal Energy Developments Limited, Various...................... Various 88 26.59% LFG/Methane Europe: Killingholm, UK................ UK Electricity Grid 680 100% Gas Enfield, UK.................... UK Electricity Grid 99 25% Gas Schkopau Power Station, Germany...................... VEAG 200 20.95% Coal MIBRAG mbH, Germany............ WESAG/MIBRAG 78 33.33% Coal Energy Center Kladno, (ECK)/ ECKG......................... STE/Industrials 166 44% Coal Latin America: COBEE, Bolivia................. Electropaz/ELF 108 49.45% Hydro/Gas Bulo Bulo, Bolivia............. Bolivian Grid 26 30% Gas Itiquira Energetica S.A., Brazil....................... 38 25.05% Hydro Latin Power, Various........... Various 53 Various Gas/Coal/Oil/Geo OTHER NORTH AMERICA NEO Corporation................ Various 97 Various Various Energy Investors funds (1&3)... Various 11 Various Various 27 THERMAL ENERGY PRODUCTION AND TRANSMISSION FACILITIES AND RESOURCE RECOVERY FACILITIES - - --------------- (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) NRG Energy operates the Elk River resource recovery facility on behalf of Xcel. 25
NRG'S PERCENTAGE THERMAL ENERGY DATE OF OWNERSHIP PURCHASER/MSW NAME AND LOCATION OF FACILITY ACQUISITION NET EQUITY CAPACITY(1) INTEREST SUPPLIER ----------------------------- ----------- ---------------------- ---------- -------------- 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: 8,000 100.00 Approximately 19 tons/hr. customers Camas Power Boiler, Washington.................... 1997 200mmBtu/hr (59 MWt) 100.00 Fort James Corp. NRG Minneapolis Energy Center (MEC), Minnesota.............. 1993 Steam: 1,408 mmBtu/hr. 100.00 Approximately 92 steam (413 MWt) customers and 39 chilled water customers Chilled water: 40,750 tons/hr. Hennepin Co. Energy Center, Minn.......................... NA 140 mmBtu/hr (81 MWt) -- MEC Customers Rock-Tenn, Minnesota............ 1992 Steam: 430 mmBtu/hr. 100.00 Rock-Tenn Company (12 MWt) Washco, Minnesota............... 1992 160 mmBtu/hr. (47 MWt) 100.00 Andersen Corporation 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 227 mmBtu/hr. (150 44.26 City of Kladno MWt) NRG Energy Center Harrisburg.... 2000 Steam -- 490 mmBtu/hr. 100.00 City of Harrisburg and Chilled Water 1,800 Commonwealth of tons Pennsylvania NRG Energy Center Dover......... 2000 190 mmBtu/hr. 100.00 Local manufacturing corporation and Dover municipal electric utility RESOURCE RECOVERY FACILITIES Newport, Minnesota.............. 1993 MSW: 1,500 tons/day 100.00 Ramsey and Washington Counties Elk River, Minnesota............ NA(3) MSW: 0 tons/day -- Anoka, Hennepin, and Sherburne Counties; Tri-County Solid Waste Management Commission Penobscot Energy Recovery, Maine......................... 1997 MSW: 209 tons/day 26.12 Bangor Hydroelectric Company Maine Energy Recovery, Maine.... 1997 MSW: 111 tons/day 16.25 Central Maine Power 28 OTHER PROPERTIES In addition to the above, NRG Energy leases its corporate offices at 901 Marquette, Suite 2300, Minneapolis, Minnesota 55402 and various other office spaces. ITEM 3 -- LEGAL PROCEEDINGS FORTISTAR CAPITAL V. NRG ENERGY In July 1999, Fortistar Capital Inc., a Delaware corporation, filed a complaint in District Court (Fourth Judicial District, Hennepin County) in Minnesota against NRG Energy asserting claims for injunctive relief and for damages as a result of NRG Energy's alleged breach of a confidentiality letter agreement with Fortistar relating to the Oswego facility. NRG Energy disputed Fortistar's allegations and has asserted numerous counterclaims. NRG Energy has counterclaimed against Fortistar for breach of contract, fraud and negligent misrepresentations and omissions, unfair competition and breach of the covenant of good faith and fair dealing. NRG Energy seeks, among other things, dismissal of Fortistar's complaint with prejudice and rescission of the letter agreement. 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 LLC's and Niagara Mohawk Power Corporation's intention to close on that date. On January 14, 2000, the court denied Fortistar's request for a temporary injunction. In April and December 2000, NRG Energy filed summary judgment motions to dispose of the litigation. A hearing on these motions was held in January 2001. A ruling on these motions has not yet been issued. NRG Energy intends to continue to vigorously defend the suit and believes Fortistar's complaint to be without merit. No trial date has been set. NEW YORK DEPARTMENT OF ENVIRONMENTAL CONSERVATION NOTICE OF VIOLATION On May 25, 2000 the New York Department of Environmental Conservation issued a Notice of Violation to NRG Energy and the prior owner of the Huntley and Dunkirk facilities relating to physical changes made at those facilities prior to our assumption of ownership. The Notice of Violation alleges that these changes represent major modifications undertaken without obtaining the required permits. Although NRG Energy has a right to indemnification by the previous owner for fines, penalties, assessments, and related losses resulting from the previous owner's failure to comply with environmental laws and regulations, if these facilities did not comply with the applicable permit requirements, NRG Energy could be required, among other things, to install specified pollution control technology to further reduce air emissions from the Dunkirk and Huntley facilities and NRG Energy could become subject to fines and penalties associated with the current and prior operation of the facilities. NRG Energy is currently in settlement discussions with the Department of Environmental Conservation and the State Attorney General's office. CALIFORNIA LITIGATION NRG Energy and other power generators and power traders have been named as defendants in certain private plaintiff class actions filed in the Superior Court of the State of California for the County of San Diego in San Diego, California on November 27, 2000 (Pamela R. Gorden v. Reliant Enegy, Inc., et al.) and November 29, 2000 (Ruth Hendricks v. Dynegy Power Marketing Inc., et al.), and in the Superior Court of the State of California, City and County of San Francisco (Pier 23 Restaurant v. PG&E Energy Trading, et al., filed January 16, 2001 in the Superior Court of the State of California for the County of San Diego, brought by three California water districts, as consumers of electricity (Sweetwater Authority v. Dynegy Inc., et al.), and in a suit filed on January 18, 2001 in Superior Court of the State of California, County of San Francisco, brought by the San Francisco City Attorney on behalf of the People of the State of California (The People of the State of California v. Dynegy Power Marketing, Inc., et al.). Although the complaints contain a number of allegations, the basic claim is that, by underbidding forward contracts and exporting electricity to surrounding markets, the defendants, acting in collusion, were able to drive up wholesale prices on the Real Time and Replacement Reserve markets, through the Western Systems Coordinating Council and otherwise. 26 29 The complaints allege that the conduct violated California antitrust and unfair competition laws. NRG Energy does not believe that it has engaged in any illegal activities, and intends to vigorously defend these lawsuits. While these cases are in too preliminary a stage to speculate on their outcome, if they were ultimately resolved adversely to the defendants it could have a material adverse effect on NRG Energy's results of operations and financial condition. There are no other material legal proceedings pending to which NRG Energy 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 NRG Energy or its subsidiaries. There are no other material administrative or judicial proceedings arising under environmental quality or civil rights statutes pending or known to be contemplated by governmental agencies to which NRG Energy is or would be a party. ITEM 4 -- SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matters were considered during the fourth quarter of 2000. PART II ITEM 5 -- MARKET PRICE FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS QUARTERLY STOCK DATA NRG Energy's common stock is traded principally on the New York Stock Exchange (the Exchange). The common stock was first traded on the Exchange on June 5, 2000, concurrent with the underwritten initial public offering of shares of NRG Energy's common stock at an initial price to the public of $15.00 per share. The following table reflects the range of high and low selling prices of NRG Energy's common stock by quarter from June 5, 2000 through December 31, 2000. This information is based on selling prices as reported by the New York Stock Exchange. HOLDERS At March 15, 2001, there were approximately 98 holders of record of common stock and 1 holder of Class A common stock. DIVIDENDS NRG Energy has not paid and does not currently intend to distribute any earnings as dividends. 27
2000 1999 ---------------- ------------ HIGH LOW HIGH LOW ---- --- ---- --- First Quarter.......................................... N.A N.A. N.A. N.A. Second Quarter......................................... $18.15 $16.25 N.A.. N.A. Third Quarter.......................................... $36.50 $18.15 N.A.. N.A. Fourth Quarter......................................... $36.50 $22.50 N.A.. N.A. N.A. -- Not available -- stock not publicly traded 30 ITEM 6 -- SELECTED FINANCIAL DATA The following table presents selected financial data of NRG Energy, Inc. This historical data should be read in conjunction with the Consolidated Financial Statements and the related notes thereto in Item 8 and "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Item 7. - - ------------------------- * Earnings Per Share amounts for the years 1999 and earlier have been restated to reflect the issuance of Class A common stock. ITEM 7 -- MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, -------------------------------------------------------------- 2000 1999 1998 1997 1996 (In thousands, except per share data.) ---------- ---------- -------- ---------- -------- Total operating revenues.............. $2,157,986 $ 500,018 $182,130 $ 118,252 $104,464 Total operating costs and expenses.... 1,584,913 390,498 125,118 100,143 84,188 Net Income............................ 182,935 57,195 41,732 21,982 19,978 Weighted Average Number of Common Shares Outstanding -- Basic......... 165,861 147,605 147,605 147,605 147,605 Weighted Average Number of Common Shares Outstanding -- Diluted....... 166,989 147,605 147,605 147,605 147,605 Earnings per Weighted Average Common Share -- Basic...................... $ 1.10 $ .39 $ .28 $ .15 $ .14 Earnings per Weighted Average Common Share -- Diluted.................... 1.10 .39 .28 .15 .14 Total Assets.......................... 5,978,992 3,431,684 1,293426 1,168,102 680,809 Long-term debt, including current maturities.......................... 3,797,318 1,971,860 626,476 620,855 212,141 28
FOR THE YEAR ENDED DECEMBER 31, ------------------------ 2000 1999 1998 ---- ---- ---- OPERATING REVENUES AND EQUITY EARNINGS Revenues from majority-owned operations..................... 94% 87% 55% Equity in earnings of unconsolidated affiliates............. 6% 13% 45% --- --- --- TOTAL OPERATING REVENUES AND EQUITY EARNINGS................ 100% 100% 100% --- --- --- OPERATING COSTS AND EXPENSES Cost of majority-owned operations........................... 59% 54% 29% Depreciation and amortization............................... 6% 7% 9% General, administrative, and development.................... 8% 17% 31% --- --- --- TOTAL OPERATING COSTS AND EXPENSES.......................... 73% 78% 69% --- --- --- OPERATING INCOME............................................ 27% 22% 31% --- --- --- OTHER INCOME (EXPENSE) Minority interest in earnings of consolidated Subsidiaries.............................................. (1%) -- (1%) Other income, net........................................... -- 3% 6% Interest expense............................................ (13%) (19%) (27%) --- --- --- TOTAL OTHER EXPENSE......................................... (14%) (16%) (22%) --- --- --- INCOME BEFORE INCOME TAXES.................................. 13% 6% 9% INCOME TAX EXPENSE (BENEFIT)................................ 4% (5%) (14%) --- --- --- NET INCOME.................................................. 9% 11% 23% === === === 31 FOR THE YEAR ENDED DECEMBER 31, 2000 COMPARED TO THE YEAR ENDED DECEMBER 31, 1999 For the year ended December 31, 2000, net income was $182.9 million compared to $57.2 million for 1999, an increase of $125.7 million or 219.8%. This increase was due to the factors described below. REVENUES AND EQUITY IN EARNINGS OF UNCONSOLIDATED AFFILIATES For the year ended December 31, 2000, NRG Energy had total revenues and equity earnings of $2,157.9 million, compared to $500.0 million for the year ended December 31, 1999, an increase of $1,657.9 million or 331.6%. NRG Energy's operating revenues from majority-owned operations were $2,018.6 million compared to $432.5 million, an increase of $1,586.1 million or 366.7%. The increase in revenues from majority-owned operations is primarily due to increased sales resulting from recently completed acquisitions of electric generating facilities, primarily during the later portion of 1999 and the first and third quarters of 2000. During the later portion of 1999, NRG Energy acquired certain electric generating facilities in the northeastern region of the United States. In addition, NRG Energy acquired certain electric generating facilities located in Louisiana and the United Kingdom at the end of the first quarter of 2000. During the third quarter of 2000, NRG Energy acquired Flinders Power and certain thermal operations. In addition, NRG Energy's increased ownership in Crockett Cogeneration has contributed significantly to its revenue growth during 2000, as compared to 1999. For the year ended December 31, 2000, NRG Energy had equity in earnings of unconsolidated affiliates of $139.4 million, compared to $67.5 million for the year ended December 31, 1999, an increase of $71.9 million or 106.5%. The increase in equity earnings of unconsolidated affiliates is due primarily to NRG Energy's investment in West Coast Power LLC, which benefited from favorable market conditions in California. In addition, NRG Energy's investment in Rocky Road LLC, in the fourth quarter of 1999, also contributed favorably to the increase in equity earnings, compared to the prior year. These increases were partially offset by reductions in the earnings attributable to NRG Energy's international equity investments and its investment in NEO Corporation. NEO Corporation derives a significant portion of its net income from Section 29 tax credits. NRG Energy does not expect its investment in West Coast Power LLC to generate similar earnings in the year 2001. OPERATING COSTS AND EXPENSES For the year ended December 31, 2000, cost of majority-owned operations, was $1,289.5 million, compared to $269.9 million, an increase of $1,019.6 million or 377.8%. For the year ended December 31, 2000 and 1999, cost of majority-owned operations represented 59.8% and 54.0% of total operating revenues and equity earnings, respectively. For the year ended December 31, 2000, the increase of $1,019.6 million is primarily due to NRG Energy's recent acquisitions of electric generating facilities during the later portion of 1999 and primarily the first and third quarters of 2000. During the later portion of 1999, NRG Energy acquired certain electric generating facilities in the northeastern region of the United States. In addition, NRG Energy acquired certain electric generating facilities located in Louisiana and the United at the end of the first quarter of 2000. During the third quarter of 2000, NRG Energy acquired Flinders Power and certain thermal operations. In addition, NRG Energy's ownership in Crockett Cogeneration has contributed significantly to the growth the cost of majority-owned operations during 2000, as compared to 1999. DEPRECIATION AND AMORTIZATION For the year ended December 31, 2000, depreciation and amortization was $122.9 million, compared to $37.0 million for the year ended December 31, 1999, an increase of $85.9 million or 232.1%. This increase is primarily due to the addition of property, plant and equipment related to NRG Energy's recently completed acquisitions of electric generating facilities during the later portion of 1999 and primarily the first and third quarters of 2000. In addition the consolidation of NRG Energy's investment in Crockett Cogeneration at the end of 1999 also contributed to the increase in depreciation and amortization during 2000. Through these acquisitions NRG Energy's net property, plant and equipment balance has grown to $4,041.7 million at the end of 2000 from $1,975.4 million at the end of 1999, an increase of $2,066.3 million or 104.6%. 29 32 GENERAL, ADMINISTRATIVE AND DEVELOPMENT For the year ended December 31, 2000, general, administrative and development costs were $172.5 million, compared to $83.6 million, an increase of $88.9 million or 106.4%. This increase is primarily due to increased business development activities, associated legal, technical and accounting expenses, employees and equipment resulting from expanded operations and pending acquisitions. NRG Energy's asset base has grown to $5,978.9 million at the end of 2000, compared to $3,431.7 million at the end of 1999, an increase of $2,547.2 million or 74.2%. NRG Energy expects this trend to continue as it continues to be successful in expanding its operations through closure of its pending acquisitions and business development activities. OTHER INCOME (EXPENSE) For the year ended December 31, 2000, total other expense was $297.4 million, compared to $78.4 million for the year ended December 31, 1999, an increase of $219.0 million or 279.3%. The increase in total other expense of $219.0 million, as compared to 1999, consisted primarily of an increase in Interest expense and Minority interest in earnings of consolidated subsidiary. These increases were partially offset by decreases in other income, net and gain on sale of interest in projects, in comparison to 1999. For the year ended December 31, 2000, interest expense (which includes both corporate and project level interest expense) was $293.9 million, as compared to $93.4 million in 1999, an increase of $200.5 million or 214.8%. This increase is due to increased corporate and project level debt issued during 2000 as compared to 1999. During 2000, NRG Energy issued substantial amounts of long term debt at both the corporate level (recourse debt) and project level (non-recourse debt) to either directly finance the acquisition of electric generating facilities or refinance short term bridge loans incurred to finance such acquisitions. NRG Energy's outstanding long-term debt balances have grown to $3,797.3 million at the end of 2000 from $1,971.9 million at the end of 1999. The growth of such outstanding debt balances has contributed directly to the growth in interest expense during 2000 as compared to 1999. For the year ended December 31, 2000, minority interest in earnings of consolidated subsidiaries was $11.3 million, compared to $2.5 million, an increase of $8.8 million or 361.5% as compared to 1999. The increase is due to the consolidation of NRG Energy's 58% interest in Crockett Cogeneration at the end of 1999 and the recognition of the minority interest in the project. For the year ended December 31, 2000, NRG Energy did not recognize any gains on the sale of any project interests. During 1999 NRG Energy recognized a gain of $11.0 million related to the reduction in its ownership of Cogeneration Corporation of America (CogenAmerica). For the year ended December 31, 2000, other income, net, was $7.9 million, as compared to $6.4 million, for the year ended December 31, 1999, an increase of $1.5 million, or 22.2%. Other income, net consists primarily of interest income on loans to affiliates, and miscellaneous other items, including the income statement impact of certain foreign currency translation adjustments and the impact of project write-downs and gains and losses on the dispositions of investments. The increase of $1.5 million is primarily due to an increase in interest income in 2000. INCOME TAX For the year ended December 31, 2000, income tax expense was $92.7 million, compared to an income tax benefit of $26.1 million, an increase of $118.8 million or 455.6%, compared to 1999. The increase in tax expense in 2000 compared to 1999 is due primarily to higher domestic taxable income. This increase was partially offset by additional IRC Section 29 energy credits. For the year ended December 31, 2000, NRG Energy's overall effective income tax rate was approximately 34%. NRG Energy's effective income tax rate before recognition of tax credits is 46%. This rate is higher than a combined federal and Minnesota statutory rate because a significant portion of NRG Energy's income is generated in New York City, an area with high state and local tax rates. In addition, NRG Energy has recorded a valuation allowance on certain state and foreign tax losses, also increasing the effective tax rate. 30 33 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 37.1%, compared to net income of $41.7 million in the same period in 1998. This increase was due to the factors described below. REVENUES AND EQUITY IN EARNINGS OF UNCONSOLIDATED AFFILIATES For the year ended December 31, 1999, NRG Energy 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%. NRG Energy'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 NRG Energy'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 NRG Energy'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 NRG Energy'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 NRG Energy's Thermal operations and the addition of new projects during 1999 by NRG Energy'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 percentage points 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 NRG Energy's NEO subsidiary during 1999. In addition, depreciation and amortization also increased due to the consolidation of NRG Energy'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. 31 34 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, NRG Energy sold a portion of its interest in CogenAmerica, an affiliate of NRG Energy, for a pretax gain of approximately $11.0 million ($4.1 million after-tax) to Calpine. NRG Energy retained a 20% interest in CogenAmerica. 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 $686.5 million of project level debt issued by NRG Northeast Generating LLC and to the issuance by NRG Energy of $300 million and $240 million of senior notes in June 1999 and November 1999, respectively. Additionally, a higher average outstanding balance of NRG Energy's revolving line of credit and the consolidation of Crockett Cogeneration and NRG Energy's Thermal operations contributed to higher interest expense. INCOME TAX NRG Energy 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 NRG Energy's NEO subsidiary operations and foreign tax benefits associated with the Loy Yang project, which was substantially offset by higher overall earnings. LIQUIDITY AND CAPITAL RESOURCES To date, NRG Energy and its subsidiaries have obtained cash from operations, issuance of debt and equity securities, borrowings under credit facilities, capital contributions from Xcel, reimbursement by Xcel of tax benefits pursuant to a tax sharing agreement and proceeds from non-recourse project financings. NRG Energy has used these funds to finance operations, service debt obligations, fund the acquisition, development and construction of generation facilities, finance capital expenditures and meet other cash and liquidity needs. CASH FLOWS Net cash provided by operating activities increased during 2000 compared with 1999, primarily due to increased earnings during the year, increased depreciation and amortization and deferred income tax and investment tax credits, non-cash reductions in earnings and improved working capital. Cash provided by operating activities in 1999 decreased compared to 1998, primarily due to a decrease in working capital due to a timing of cash flows.
2000 1999 1998 ---- ---- ---- Net cash provided by (used in) operating activities (in thousands)................................................ $361,984 ($11,380) $21,998 Net cash used in investing activities increased in 2000, compared with 1999, primarily due to acquisitions of electric generating facilities and increased capital expenditures and project investments. Net cash used in investing activities also increased in 1999 compared to 1998, primarily due to the acquisition of electric generating facilities.
2000 1999 1998 ---- ---- ---- Net cash used in investing activities (in thousands).... ($2,204,454) ($1,668,613) ($131,620) 32
2000 1999 1998 ---- ---- ---- Net cash provided by financing activities (in thousands)... $1,905,870 $1,705,095 $104,017 35 Net cash provided by financing activities during 2000 increased, compared to 1999, primarily due to the issuance of debt and equity securities to finance asset acquisitions. Net cash provided by financing activities during 1999 increased, compared to 1998, primarily due to the issuance of debt and capital contributions from NRG Energy's parent to finance asset acquisitions. PROSPECTIVE CAPITAL REQUIREMENTS As of December 31, 2000, NRG Energy estimates its capital expenditure program to be approximately $6,500 million for the period 2001 - 2005. NRG Energy expects to spend approximately $3,138 million in 2001, $1,341 million in 2002 and $1,517 million in 2003. These estimated expenditures are primarily for NRG Energy's project acquisition and development program. For 2001, NRG Energy's capital requirements reflect the expected acquisition of existing generating facilities, including the Conectiv assets, North Valmy, LS Power, Reid Gardner and Clark assets and the Bridgeport and New Haven Harbor facilities as well as certain other projects under construction. NRG Energy's capital expenditure program is subject to continuing review and modification. Actual expenditures may differ significantly depending upon such factors as the success, timing of and the level of involvement in projects under consideration. CAPITAL SOURCES NRG Energy expects to meet its future financing requirements through a combination of internally generated cash, corporate and project level long term and short term debt, equity securities and equity like securities. NRG Energy has generally financed the acquisition and development of its projects under financing arrangements to be repaid solely from each of its project's cash flows, which are typically secured by the plant's physical assets and equity interests in the project company. Financing needs are subject to continuing review and can change depending on market and business conditions and changes, if any, in the capital requirements of NRG Energy and its subsidiaries. During the second quarter of 2000, NRG Energy completed its initial public offering of 32.4 million shares priced at $15 per share. Upon completion of the offering, Xcel owned approximately 147.6 million Class A common shares or 82% of NRG Energy's outstanding common shares. The net proceeds of approximately $453.7 million were used primarily to repay short-term debt and for general corporate purposes. During March of 2001, NRG Energy raised net proceeds of approximately $473.9 million through a second common stock offering of 18.4 million shares of common stock. In addition, approximately $278.4 million of net proceeds was raised through the issuance of 11.5 million equity units. Each equity unit initially comprises a $25 principal amount of NRG Energy's senior debentures and an obligation to acquire shares of NRG Energy's common stock no later then May 18, 2004. A portion of the combined net proceeds were used to repay a $600 million bridge credit agreement entered into in January 2001 to acquire certain generating facilities and projects from LS Power; the remaining net proceeds will be used for general corporate purposes. NRG REVOLVING CREDIT FACILITY NRG Energy is in the process of structuring and marketing an up to $2.5 billion revolving funding program, which will be used to finance a significant portion of its U.S. acquisitions and development projects over the next five years. This revolving credit facility will allow NRG Energy to procure temporary funding for both the non-recourse debt portion as well as equity contributions for new projects through an expedient and simplified review and approval process. NRG Energy is permitted under the revolver to repay borrowed funds, thus making them available to be borrowed again. NRG Energy plans to do that by refinancing projects in the long-term capital or bank markets when construction projects reach commercial operation or when market conditions are favorable. Any unutilized borrowing capacity may be deployed for future projects. 33 36 REGISTRATION STATEMENT In December 2000, NRG Energy filed a universal shelf registration statement with the SEC. Based on this registration, NRG Energy can issue up to $1,650 million of debt securities, preferred stock, common stock, depositary shares, warrants and convertible securities. This registration statement includes $150 million of securities that are being carried forward from a previous shelf registration. During March 2001, NRG Energy issued 18.4 million shares of common stock and 11.5 million corporate units under this shelf registration. SHORT TERM BORROWING ARRANGEMENT For information on NRG Energy's short term borrowing arrangements, see Item 8 -- Note 9 to the Financial Statements. ACCOUNTING CHANGES In June 1998, the Financial Accounting Standards Board (the FASB) issued Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133), subsequently amended by SFAS No. 137 and SFAS No. 138. SFAS No. 133 requires NRG Energy to record all derivatives on the balance sheet at fair value. Changes in derivative fair values will either be recognized in earnings as offsets to the changes in fair value of related hedged assets, liabilities and firm commitments or, for forecasted transactions, deferred and recorded as a component of other accumulated comprehensive income until the hedged transactions occur and are recognized in earnings. The ineffective portion of a hedging derivative's change in fair value will be immediately recognized in earnings. SFAS No. 133 will apply to NRG Energy's energy and energy related commodities financial instruments, long-term power sales contracts and long-term gas purchase contracts used to mitigate variability in earnings due to fluctuations in spot market prices, hedge fuel requirements at generation facilities and protect investment in fuel inventories. SFAS No. 133 will also apply to various interest rate swaps used to mitigate the risks associated with movements in interest rates. NRG Energy has adopted SFAS No. 133 effective January 1, 2001. The effect of adopting SFAS No. 133 was as follows: - A one-time after-tax unrealized loss of $22.6 million recorded to other accumulated comprehensive income related to the initial adoption of SFAS No. 133 during the quarter ended March 31, 2001, and - Increased volatility in future earnings is possible due to the impact of market fluctuations on derivative instruments used by NRG Energy. In September 2000, the FASB issued Statement No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities- A Replacement of FASB Statement No. 125 (SFAS No. 140). SFAS No. 140 revises the standards for accounting for securitizations and other transfers of financial assets and collateral and requires certain disclosures, but it carries over most of SFAS No. 125's provisions without reconsideration. SFAS No. 140 is effective for NRG Energy's fiscal year ending December 31, 2001. The adoption of SFAS No. 140 is not expected to have a significant impact on NRG Energy's consolidated financial position or results of operations. CALIFORNIA LIQUIDITY CRISIS NRG Energy owns approximately 1,569 MW of net generating capacity in California, which represented approximately 11% of its net MW of operating projects and projects under construction as of December 31, 2000. Due to the acquisition and construction of projects outside of California, NRG Energy expects that by December 31, 2001, this percentage will decrease to approximately 7% of its net MW of operating projects and projects under construction. Net income from NRG Energy's California assets represented approximately 33% of its net income in 2000. Due both to the acquisition and construction of projects outside of California and to an expected decrease in earnings from NRG Energy's California assets, NRG Energy expects this percentage will decrease to approximately 14% of its net income in 2001. 34 37 NRG Energy's California generation assets consist primarily of interests in the Crockett and Mt. Poso facilities and a 50% interest in West Coast Power LLC, formed in 1999 with Dynegy Inc. Through the California Power Exchange (PX) and the California Independent System Operator (ISO), the West Coast Power facilities sell power to Pacific Gas and Electric Company (PG&E), Southern California Edison Company (SCE), and San Diego Gas and Electric Company (SDG&E), the three major California investor-owned utilities. Crockett, Mt. Poso and certain of NRG Energy's other California facilities also sell directly to PG&E, SCE and SDG&E. The liquidity crisis faced by both PG&E and SCE, as a result of tight electricity supplies, rising wholesale electric prices and caps on the rates that PG&E and SCE may charge their retail customers, has caused both PG&E and SCE to partially suspend payments to the California PX and the California ISO. NRG Energy's share of the total amounts owed to its California affiliates by the California PX, the California ISO, and the three major California utilities totaled approximately $303 million as of February 28, 2001, based upon financial information provided to NRG Energy by such affiliates. This total amount consists of NRG Energy share of (a) accounts receivable, which constituted a majority of such total amount, and (b) amounts that are currently treated as "disputed revenues" and are not recorded as accounts receivable in the financial statements of NRG Energy's California affiliates. In March 2001, certain affiliates of West Coast Power entered into an agreement with the California Department of Water Resources pursuant to which these affiliates have agreed to sell up to 1,000 MW to CDWR for the remainder of 2001 and up to 2,300 MW from January 1, 2002 through December 31,2004. NRG Energy believes at this time that the amounts that have been recorded as accounts receivable will ultimately be collected in full; however, if some form of financial relief or support is not provided to PG&E and SCE, the collectibility of these receivables will become more questionable in terms of both timing and amount. With respect to disputed revenues, these amounts relate to billing disputes arising in the ordinary course of business and to disputes that have arisen as a result of the California ISO imposing various revenue caps on the wholesale price of electricity. None of these disputed revenues will be recorded in the financial statements of NRG Energy's California affiliates until after the particular issue that caused them to be excluded from the financial statements is resolved. The FERC has jurisdiction over sales for resale of electricity in the California wholesale power markets. In March 2001, FERC issued orders that presumptively approved prices up to $273/MWh during January 2001 and $430/MWh during February 2001. The orders direct electricity suppliers to either refund a portion of their January and February sales or justify prices charged above these approved prices. The orders, if finalized, could require West Coast Power to refund approximately $45 million in revenues from January and February, of which NRG Energy's share would be approximately $22.5 million. Dynegy Power Marketing, Inc., as the power marketer for West Coast Power, has submitted notice of its intent to submit information justifying each component of the prices charged. The delayed collection of receivables owed to West Coast Power resulted in a covenant default under its credit agreement. West Coast Power is working with its lenders to secure their agreement to forbear exercising their remedies under the credit agreement with respect to such covenant default. While a similar covenant default could be called under NRG Energy's Crockett facilities credit agreement, NRG Energy is working with the lenders under that agreement to avert a default. Defaults under the Crockett and West Coast Power credit agreements do not trigger defaults under any of NRG Energy corporate-level financing facilities. Various legislative, regulatory and legal remedies to the liquidity crisis faced by PG&E and SCE have been implemented or are being pursued. Assembly Bill 1X,which authorizes the California Department of Water Resources to enter into contracts for the purchase of electric power through January 1, 2003 and to issue revenue bonds to fund such purchases, was signed into law by the Governor of California on February 1, 2001. Assembly Bill 18X, which provides a framework for the recovery of PG&E and SCE's uncollected expenses for purchasing power for delivery to their retail customers, is currently under consideration in the California legislature. Additionally, on March 27, the California Public Utilities Commission (PUC) approved an approximately 40% increase in the energy component of the retail electric rates paid by certain 35 38 California rate payers. This proposed increase would be in addition to the 9% increase approved in January and a 10% increase expected to take effect next year. The PUC also ordered the utilities to pay qualifying facilities for power delivered on a go-forward basis. However, the order did not address repayment of amounts already owed for past deliveries. ITEM 7 A -- QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK NRG Energy uses a variety of financial instruments to manage its exposure to fluctuations in foreign currency exchange rates on its international project cash flows, interest rates on its cost of borrowing and energy and energy related commodities prices. CURRENCY EXCHANGE RISK NRG Energy 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, 2000, if the value of the Czech koruna decreases by 10 percent in relation to the U.S. dollar and the German deutsche mark, NRG Energy would record a $3.6 million loss (after tax) on the currency transaction adjustment. If the value of the Czech koruna increased by 10 percent, NRG Energy would record a $3.6 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 NRG Energy has at this time with this type of debt structure. INTEREST RATE RISK NRG Energy has historically used interest rate hedging contracts to mitigate the risks associated with movements in interest rates and, when deemed appropriate, has entered into swap agreements effectively converting floating rate obligations into fixed rate obligations. As of December 31, 2000, NRG energy had four-interest rate swap agreements with notional amounts totaling approximately $530 million. If the swaps had been discontinued on December 31, 2000, NRG Energy would have owed the counter parties approximately $28.9 million. Based on the investment grade rating of the counter parties, NRG Energy believes that its exposure to credit risk due to nonperformance by the counter parties to its hedging contracts is insignificant. - NRG Energy entered into a swap agreement effectively converting 6.96% floating rate on AUD$105 million debt into fixed rate debt. The swap expires on September 8, 2012. - A second swap effectively converts a $16 million issue of non-recourse variable rate debt into a fixed rate debt. The swap expires on September 30, 2002 and is secured by the Camas Power Boiler assets. - A third swap converts $177 million of non-recourse variable rate debt into fixed rate debt. The swap expires on December 17, 2014 and is secured by the Crockett Cogeneration assets. - A fourth swap converts (pounds) 188 million of non-recourse variable rate debt into fixed rate debt. The swap expires on June 30, 2019 and is secured by the Killingholme assets. NRG Energy and its subsidiaries have both long and short term-debt instruments that subject it to the risk of loss associated with movements in market interest rates. As of December 31, 2000, NRG Energy does not have a material interest rate exposure as a result of interest rate swaps, which convert floating rate debt into fixed rate debt. COMMODITY PRICE RISK NRG Energy is exposed to commodity price variability in electricity, emission allowances and natural gas, oil and coal used to meet fuel requirements. To manage earnings volatility associated with these commodity price risks, NRG Energy enters into financial instruments, which may take the form of fixed price, floating price or indexed sales or purchases, and options, such as puts, calls, basis transactions and swaps. 36 39 NRG Energy utilizes a "Value-at-Risk" (VAR) model to determine the maximum potential three-day loss in the fair value of the commodity price related financial instruments. Various modeling techniques can be used in VAR computations. The VAR for NRG Energy assumes a 95% confidence interval and reflects NRG Energy's merchant strategy, the generation assets, load obligations and bilateral physical and financial transactions of NRG Energy. The volatility estimate is based on a lognormal calculation of closing prices for the latest 30 days for forward markets where NRG Energy has exposure. This model encompasses the following generating regions, Entergy, NEPOOL and NYPP. NRG Energy is in the process of expanding the model into other geographic areas. The estimated maximum potential three-day loss in fair value of the commodity price related financial instruments, calculated using the VAR model is as follows: CREDIT RISK NRG Energy is exposed to credit risk in its risk management activities. Credit risk relates to the risk of loss resulting from the nonperformance by a counter party of its contractual obligations. NRG Energy maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes in scope of operations. NRG Energy conducts standard credit reviews for all of its counter parties. 37
(IN MILLIONS) ------------- Year end December 31, 2000.................................. $116.0 Average..................................................... 80.0 High........................................................ 125.0 Low......................................................... 50.0 40 ITEM 8 -- FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The financial statements of NRG Energy, Inc. as of December 31, 2000 and 1999, and for the years then ended together with the Report of Independent Accountants are included in this Form 10-K on the pages indicated below. 38
PAGE NO. -------- Report of Independent Accountants........................... 39 Consolidated Statement of Income............................ 40 Consolidated Statement of Cash Flows........................ 41 Consolidated Balance Sheet.................................. 42 Consolidated Statement of Stockholders' Equity.............. 43 Notes to Consolidated Financial Statements.................. 44 Schedule II. Valuation and Qualifying Accounts.............. 73 41 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Stockholders of NRG Energy, Inc.: In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of NRG Energy, Inc. and its subsidiaries at December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, 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 our opinion. /s/ PRICEWATERHOUSECOOPERS LLP PricewaterhouseCoopers LLP Minneapolis, Minnesota March 2, 2001 39 42 NRG ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF INCOME See notes to consolidated financial statements. 40
YEAR ENDED DECEMBER 31, ---------------------------------------- 2000 1999 1998 ---- ---- ---- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) OPERATING REVENUES AND EQUITY EARNINGS Revenues from majority-owned operations............... $2,018,622 $432,518 $100,424 Equity in earnings of unconsolidated affiliates....... 139,364 67,500 81,706 ---------- -------- -------- Total operating revenues and equity earnings..... 2,157,986 500,018 182,130 ---------- -------- -------- OPERATING COSTS AND EXPENSES Cost of majority-owned operations..................... 1,289,471 269,900 52,413 Depreciation and amortization......................... 122,953 37,026 16,320 General, administrative and development............... 172,489 83,572 56,385 ---------- -------- -------- Total operating costs and expenses............... 1,584,913 390,498 125,118 ---------- -------- -------- OPERATING INCOME........................................ 573,073 109,520 57,012 ---------- -------- -------- OTHER INCOME (EXPENSE) Minority interest in earnings of consolidated subsidiaries....................................... (11,335) (2,456) (2,251) Gain on sale of interest in projects.................. -- 10,994 29,950 Write-off of project investments...................... -- -- (26,740) Other income, net..................................... 7,857 6,432 8,420 Interest expense...................................... (293,922) (93,376) (50,313) ---------- -------- -------- Total other expense................................ (297,400) (78,406) (40,934) ---------- -------- -------- INCOME BEFORE INCOME TAXES.............................. 275,673 31,114 16,078 INCOME TAX EXPENSE (BENEFIT)............................ 92,738 (26,081) (25,654) ---------- -------- -------- NET INCOME.............................................. $ 182,935 $ 57,195 $ 41,732 ========== ======== ======== WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - BASIC................................... 165,861 147,605 147,605 EARNINGS PER WEIGHTED AVERAGE COMMON SHARE - BASIC...... $ 1.10 $ 0.39 $ 0.28 WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - DILUTED................................. 166,989 147,605 147,605 EARNINGS PER WEIGHTED AVERAGE COMMON SHARES - DILUTED... $ 1.10 $ 0.39 $ 0.28 43 NRG ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF CASH FLOWS See notes to consolidated financial statements. 41
YEAR ENDED DECEMBER 31, --------------------------------------- 2000 1999 1998 ---- ---- ---- (IN THOUSANDS) CASH FLOWS FROM OPERATING ACTIVITIES Net income............................................. $ 182,935 $ 57,195 $ 41,732 Adjustments to reconcile net income to net cash provided by (used in) operating activities Undistributed equity in earnings of unconsolidated affiliates.......................................... (43,258) (27,181) (23,391) Depreciation and amortization....................... 122,953 37,026 16,320 Deferred income taxes and investment tax credits.... 38,458 (3,401) 7,618 Minority interest................................... 4,993 857 (5,019) Investment write-downs.............................. -- -- 26,740 Gain on sale of investments......................... -- (10,994) (29,950) Cash provided by (used in) changes in certain working capital items, net of effects from acquisitions and dispositions Accounts receivable............................... (198,091) (99,608) 297 Accounts receivable-affiliates.................... 10,703 9,964 21,657 Inventory......................................... (12,316) (17,287) (28) Prepayments and other current assets.............. (608) (13,433) 469 Accounts payable.................................. 143,045 40,616 (8,082) Accrued income taxes.............................. 39,137 25,834 (24,861) Accrued property and sales taxes.................. 3,743 1,740 (553) Accrued salaries, benefits, and related costs..... (8,153) 1,955 4,735 Accrued interest.................................. 38,479 5,192 1,050 Other current liabilities......................... (5,136) (3,533) (2,219) Cash provided by (used by) changes in other assets and liabilities................................... 45,100 (16,322) (4,517) ----------- ----------- --------- NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES...... 361,984 (11,380) 21,998 ----------- ----------- --------- CASH FLOWS FROM INVESTING ACTIVITIES Businesses and assets acquired, net of liabilities assumed............................................. (1,912,957) (1,519,365) -- Consolidation of equity subsidiaries................... -- 20,181 -- Cash from sale of investments.......................... 8,917 43,500 18,053 Decrease /(increase) in restricted cash................ 5,306 (13,067) (2,433) (Increase)/decrease in notes receivable................ (5,444) 58,331 16,858 Capital expenditures................................... (223,560) (94,853) (31,719) Proceeds from sale of property......................... 9,785 -- -- Investment in decommissioning fund..................... (306) -- -- Investments in projects................................ (86,195) (163,340) (132,379) ----------- ----------- --------- NET CASH USED BY INVESTING ACTIVITIES.................... (2,204,454) (1,668,613) (131,620) ----------- ----------- --------- CASH FLOWS FROM FINANCING ACTIVITIES Net (payments)/borrowings under line of credit agreement........................................... (367,766) 216,000 2,000 Proceeds from issuance of stock........................ 453,719 -- -- Capital contributions from parent...................... -- 250,000 100,000 Proceeds from issuance of long-term debt............... 3,034,909 575,633 23,169 Proceeds from issuance of note......................... -- 682,096 -- Principal payments on long-term debt................... (1,214,992) (18,634) (21,152) ----------- ----------- --------- NET CASH PROVIDED BY FINANCING ACTIVITIES................ 1,905,870 1,705,095 104,017 ----------- ----------- --------- EFFECT OF EXCHANGE RATE CHANGES ON CASH AND CASH EQUIVALENTS............................................ 360 -- -- ----------- ----------- --------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS..... 63,760 25,102 (5,605) CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR........... 31,483 6,381 11,986 =========== =========== ========= CASH AND CASH EQUIVALENTS AT END OF YEAR................. $ 95,243 $ 31,483 $ 6,381 =========== =========== ========= 44 NRG ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET See notes to consolidated financial statements. 42
YEAR ENDED DECEMBER 31, ------------------------ 2000 1999 ---- ---- (IN THOUSANDS) ASSETS CURRENT ASSETS Cash and cash equivalents................................. $ 95,243 $ 31,483 Restricted cash........................................... 12,135 17,441 Accounts receivable-trade, less allowance for doubtful accounts of $21,199 and $186............................ 360,075 126,376 Inventory................................................. 174,864 119,181 Current portion of notes receivable....................... 267 287 Prepayments and other current assets...................... 30,074 29,202 ---------- ---------- Total current assets.................................... 672,658 323,970 ---------- ---------- PROPERTY, PLANT AND EQUIPMENT, AT ORIGINAL COST In service................................................ 4,106,653 2,078,804 Under construction........................................ 206,992 53,448 ---------- ---------- Total property, plant and equipment..................... 4,313,645 2,132,252 Less accumulated depreciation............................. (271,977) (156,849) ---------- ---------- Net property, plant and equipment....................... 4,041,668 1,975,403 ---------- ---------- OTHER ASSETS Investments in projects................................... 973,261 932,591 Capitalized project costs................................. 10,262 2,592 Notes receivable, less current portion.................... 76,745 71,281 Decommissioning fund investments.......................... 3,863 -- Intangible assets, net of accumulated amortization of $6,770 and $4,308....................................... 61,352 55,586 Debt issuance costs, net of accumulated amortization of $6,443 and $6,640....................................... 48,773 20,081 Other assets, net of accumulated amortization of $12,809 and $8,909.............................................. 90,410 50,180 ---------- ---------- Total other assets...................................... 1,264,666 1,132,311 ---------- ---------- TOTAL ASSETS................................................ $5,978,992 $3,431,684 ---------- ---------- LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES Current portion of long-term debt......................... $ 146,469 $ 30,462 Revolving line of credit.................................. 8,000 340,000 Revolving line of credit, non-recourse.................... -- 35,766 Accounts payable-trade.................................... 255,917 61,211 Accounts payable-affiliate................................ 7,191 6,404 Accrued income taxes...................................... 43,870 4,730 Accrued property and sales taxes.......................... 10,531 4,998 Accrued salaries, benefits and related costs.............. 24,830 9,648 Accrued interest.......................................... 51,962 13,479 Other current liabilities................................. 14,220 17,657 ---------- ---------- Total current liabilities............................... 562,990 524,355 OTHER LIABILITIES Consolidated project-level, long-term, non-recourse debt.................................................... 2,146,953 1,026,398 Corporate level long-term, recourse debt.................. 1,503,896 915,000 Deferred income taxes..................................... 55,642 16,940 Postretirement and other benefit obligations.............. 83,098 24,613 Other long-term obligations and deferred income........... 149,640 16,351 Minority interest......................................... 14,685 14,373 ---------- ---------- Total liabilities....................................... 4,516,904 2,538,030 ---------- ---------- STOCKHOLDERS' EQUITY Class A - Common stock; $.01 par value; 250,000 shares authorized; 147,605 shares issued and outstanding....... 1,476 1,476 Common stock; $.01 par value; 550,000 shares authorized; 32,396 shares issued and outstanding.................... 324 -- Additional paid-in capital................................ 1,233,833 780,438 Retained earnings......................................... 370,145 187,210 Accumulated other comprehensive income.................... (143,690) (75,470) ---------- ---------- Total Stockholders' Equity.............................. 1,462,088 893,654 ---------- ---------- Commitments and Contingencies TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY............ $5,978,992 $3,431,684 ========== ========== 45 NRG ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY See notes to consolidated financial statements. 43
CLASS A ACCUMULATED COMMON COMMON ADDITIONAL OTHER TOTAL ---------------- --------------- PAID-IN RETAINED COMPREHENSIVE STOCKHOLDERS' STOCK SHARES STOCK SHARES CAPITAL EARNINGS INCOME EQUITY ----- ------ ----- ------ ---------- -------- ------------- ------------- (IN THOUSANDS) BALANCES AT DECEMBER 31, 1997.... $1,476 147,605 $ -- -- $ 430,438 $ 88,283 $ (69,499) $ 450,698 ------ ------- ------ ------ ---------- -------- --------- ---------- Net Income..................... 41,732 41,732 Foreign currency translation adjustments................ (13,098) (13,098) ---------- Comprehensive income for 1998....................... 28,634 Capital contribution from parent..................... 100,000 100,000 ------ ------- ------ ------ ---------- -------- --------- ---------- BALANCES AT DECEMBER 31, 1998.... $1,476 147,605 $ -- -- $ 530,438 $130,015 $ (82,597) $ 579,332 ====== ======= ====== ====== ========== ======== ========= ========== Net Income..................... 57,195 57,195 Foreign currency translation adjustments................ 7,127 7,127 ---------- Comprehensive income for 1999....................... 64,322 Capital contribution from parent..................... 250,000 250,000 ------ ------- ------ ------ ---------- -------- --------- ---------- BALANCES AT DECEMBER 31, 1999.... $1,476 147,605 $ -- -- $ 780,438 $187,210 $ (75,470) $ 893,654 ====== ======= ====== ====== ========== ======== ========= ========== Net Income..................... 182,935 182,935 Foreign currency translation adjustments................ (68,220) (68,220) ---------- Comprehensive income for 2000....................... 114,715 Issuance of Common stock, net of issuance costs of $32.2 million.................... 324 32,396 453,395 453,719 ------ ------- ------ ------ ---------- -------- --------- ---------- BALANCES AT DECEMBER 31, 2000.... $1,476 147,605 $ 324 32,396 $1,233,833 $370,145 $(143,690) $1,462,088 ====== ======= ====== ====== ========== ======== ========= ========== 46 NOTE 1 -- ORGANIZATION NRG Energy, Inc., (NRG Energy), was incorporated as a Delaware Corporation on May 29, 1992. Beginning in 1989, NRG Energy conducted business through its predecessor companies, NRG Energy, Inc. and NRG Group, Inc., Minnesota corporations, which were merged into NRG Energy subsequent to its incorporation. NRG Energy and its wholly owned subsidiaries and affiliates are principally engaged in the acquisition, development, construction, ownership, operation and maintenance of power generation facilities and the sale of energy, capacity and related products. On June 5, 2000, NRG Energy completed its initial public offering. Prior to completing its initial public offering, NRG Energy was a wholly owned subsidiary of Northern States Power Company (NSP). During August 2000, NSP and New Century Energies, Inc. completed their merger. The surviving company operates under the new name Xcel Energy, Inc. (Xcel). The shares of NRG Energy's class A common stock previously held by NSP are now owned by Xcel. As of December 31, 2000, Xcel owned an 82% interest in NRG Energy's outstanding common and class A common stock, representing 98% of the total voting power of NRG Energy's common stock and class A common stock. NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES PRINCIPLES OF CONSOLIDATION AND BASIS OF PRESENTATION The consolidated financial statements include NRG Energy's accounts and those of its subsidiaries. All significant intercompany transactions and balances have been eliminated in consolidation. Accounting policies for all of NRG Energy's operations are in accordance with accounting principles generally accepted in the United States of America. As discussed in Note 6, NRG Energy 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 AND CASH EQUIVALENTS Cash equivalents include highly liquid investments (primarily commercial paper) with an original 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, spare parts, coal, kerosene 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: The assets and related accumulated depreciation amounts are adjusted for asset retirements and disposals with the resulting gain or loss included in operations. NRG Energy analyzes property, plant and equipment quarterly for potential impairment, assessing the appropriateness of lives and recoverability of net balances in 44
Facilities and improvements................................. 10-45 years Machinery and equipment..................................... 7-30 years Office furnishings and equipment............................ 3-5 years 47 accordance with Statement of Financial Accounting Standards No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of (SFAS No. 121). Long-lived assets and intangibles are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the assets to the future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or fair value less the cost to sell. 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 approximately $2,667,000, $287,000, and $172,000 in 2000, 1999 and 1998, respectively. DEVELOPMENT COSTS AND CAPITALIZED PROJECT COSTS Development costs and capitalized project costs include third party professional services, permits, and other costs which are incurred incidental to a particular project. Such costs are expensed as incurred until an acquisition agreement or letter of intent is signed, and the project has been approved by NRG Energy's Board of Directors. Additional costs incurred after this point are capitalized. When project operations begin, previously capitalized project costs are 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 are capitalized and 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 amortized using the straight-line method over 20 to 30 years. NRG Energy evaluates the recovery of goodwill and other intangibles quarterly, 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 thirty years. INCOME TAXES NRG Energy is included in the consolidated tax returns of Xcel. NRG Energy calculates its income tax provision on a separate return basis under a tax sharing agreement with Xcel as discussed in Note 10. Current federal and state income taxes are payable to or receivable from Xcel. NRG Energy 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. NRG Energy's policy for income taxes related to international operations is discussed in Note 10. 45 48 REVENUE RECOGNITION Revenues from the sale of electricity and steam are recorded based upon the output delivered and capacity provided at rates as specified under contract terms or prevailing market rates. 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. Several of NRG Energy's power plants rely on one power sales contract with a single customer for the majority of the plant's revenues. The prolonged failure of any of these customers to fulfill contractual obligations or make required payments could have a substantial negative impact on NRG Energy's results of operations. NRG Energy enters into financial instrument contracts to hedge purchase and sale commitments, fuel requirements and inventories to minimize the risk of market fluctuations. Gains and losses on these hedge transactions are recognized into income in the periods for which the underlying commodity is hedged. FOREIGN CURRENCY TRANSLATION The local currencies are generally the functional currency of NRG Energy's foreign operations. Foreign currency denominated assets and liabilities are translated at end-of-period rates of exchange. Revenues, expenses and cashflows are translated at weighted-average rates of exchange for the period. The resulting currency adjustments are accumulated and reported as a separate component of stockholders' equity. CONCENTRATIONS OF CREDIT RISK Financial instruments which potentially subject NRG Energy to concentrations of credit risk consist primarily of cash, accounts receivable, and notes receivable. Cash accounts are generally held in federally insured banks. Accounts receivable and notes receivable are concentrated within entities engaged in the energy industry. These industry concentrations may impact NRG Energy's overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. Receivables are generally not collateralized; however, NRG Energy believes the credit risk posed by industry concentration is offset by the diversification and creditworthiness of its customer base. See Note 17. DERIVATIVE FINANCIAL INSTRUMENTS In the normal course of business, NRG Energy employs a variety of off-balance sheet instruments to manage its exposure to fluctuations in foreign currency exchange rates, interest rates and energy and energy related commodities prices. NRG Energy does not enter into transactions for speculative purposes. Accordingly, NRG Energy classifies its derivative financial instruments as held or issued for purposes other than trading. Foreign currency exchange rates To preserve the U.S. dollar value of projected foreign currency cash flows, NRG Energy may hedge, or protect, 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 NRG Energy's known and anticipated cash flows. NRG Energy 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. NRG Energy defers expected losses on these agreements, unless it appears that the deferral would result in recognizing a loss later. Interest rates From time to time NRG Energy 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 Investment In Projects when the hedging instrument relates to a project that has financial statements that are not consolidated into NRG Energy's financial statements. Otherwise, these gains and losses are reported as part of debt. 46 49 Energy and energy related commodities NRG Energy is exposed to commodity price variability in electricity, emission allowances, natural gas, oil and coal used to meet fuel requirements. In order to manage these commodity price risks, NRG Energy enters into transactions for physical delivery of particular commodities for a specific period. These financial instruments are used to hedge physical deliveries, which may take the form of fixed price, floating price or indexed sales or purchases, and options, such as puts, calls, basis transactions and swaps. These transactions are utilized to: - Manage and hedge fixed-price purchase and sales commitments; - Reduce exposure to the volatility of spot market prices; - Hedge fuel requirements at generation facilities; and - Protect investment in fuel inventories. USE OF ESTIMATES The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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. Actual results could differ from these estimates. In recording transactions and balances resulting from business operations, NRG Energy 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 (the FASB) issued Statement No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133), subsequently amended by SFAS No. 137 and SFAS No. 138. SFAS No. 133 requires NRG Energy to record all derivatives on the balance sheet at fair value. Changes in derivative fair values will either be recognized in earnings as offsets to the changes in fair value of related hedged assets, liabilities and firm commitments, or, for forecasted transactions, deferred and recorded as a component of other accumulated comprehensive income until the hedged transactions occur and are recognized in earnings. The ineffective portion of a hedging derivative's change in fair value will be immediately recognized in earnings. SFAS No. 133 will apply to NRG Energy's energy and energy related commodities financial instruments, long-term power sales contracts and long-term gas purchase contracts used to mitigate variability in earnings due to fluctuations in spot market prices, hedge fuel requirements at generation facilities and protect investment in fuel inventories. SFAS No. 133 will also apply to various interest rate swaps used to mitigate the risks associated with movements in interest rates. NRG Energy has adopted SFAS No. 133 effective January 1, 2001. The effect of adopting SFAS No. 133 was as follows: - A one-time after-tax unrealized loss of approximately $22.6 million recorded to other accumulated comprehensive income related to the initial adoption of SFAS No. 133 during the quarter ended March 31, 2001; and - Increased volatility in future earnings is possible due to the impact of market fluctuations on derivative instruments used by NRG Energy. In September 2000, the FASB issued Statement No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities -- A Replacement of FASB Statement No. 125 (SFAS 47 50 No. 140). SFAS No. 140 revises the standards for accounting for securizations and other transfers of financial assets and collateral and requires certain disclosures, but it carries over most of SFAS No. 125's provisions without reconsideration. SFAS No. 140 is effective for NRG Energy's fiscal year ending December 31, 2001. The adoption of SFAS No. 140 is not expected to have a significant impact on NRG Energy's consolidated financial position or results of operations. RECLASSIFICATIONS Certain prior-year amounts have been reclassified for comparative purposes. These reclassifications had no effect on net income or total stockholders' equity as previously reported. NOTE 3 -- ASSET ACQUISITIONS AND DIVESTITURES In March 2000, NRG Energy acquired the assets of the Killingholme A generation facility from National Power plc for (pound)390 million (approximately $615 million at the time of acquisition), subject to post- closing adjustments. Killingholme is a combined cycle gas-fired baseload facility located in North Lincolnshire, England. The facility comprises three units with a total generating capacity of 680 megawatts (MW). NRG Energy owns and operates the facility, which sells power into the wholesale electricity market of England and Wales. In March 2000, NRG Energy acquired 1,708 MW of coal and gas-fired generation assets in Louisiana for approximately $1,055.9 million (the Cajun facilities). These assets were formally owned by Cajun Electric Power Cooperative, Inc. (Cajun Electric). NRG Energy sells a significant amount of the energy and capacity of the Cajun facilities to 11 of Cajun Electric's former power cooperative members. Seven of these cooperatives have entered into 25-year power purchase agreements with NRG Energy, and four have entered into two to four year power purchase agreements. In addition, NRG Energy sells power under contract to two municipal power authorities and one investor-owned utility that were former customers of Cajun Electric. See Note 21 for unaudited pro forma results of operations as if the acquisition of the Cajun facilities had occurred at the beginning of the periods disclosed. In September 2000, NRG Energy completed the acquisition of Flinders Power in South Australia. NRG Energy paid approximately AUD $314.4 million (U.S.$180 million as of the date of the acquisition) for a 100-year lease of the Flinders Power assets. Flinders Power includes two power stations totaling 760 MW: the Leigh Creek coal mine and a dedicated rail line. The lease agreement also includes managing the long-term fuel supply and power purchase agreement of the 180 MW Osborne Cogeneration Station. NOTE 4 -- PROPERTY, PLANT AND EQUIPMENT The major classes of property, plant and equipment at December 31 were as follows: 48
2000 1999 ---- ---- (IN THOUSANDS) Facilities and equipment............................ $4,009,244 $2,003,173 Land and improvements............................... 79,190 64,330 Office furnishings and equipment.................... 18,219 11,301 Construction in Progress............................ 206,992 53,448 ---------- ---------- Total property, plant and equipment............ 4,313,645 2,123,252 Accumulated depreciation (271,977) (156,849) ---------- ---------- Net property, plant and equipment................... $4,041,668 $1,975,403 ========== ========== 51 NOTE 5 -- INVENTORY Inventory, which is stated at the lower of weighted average cost or market, at December 31, consists of: NOTE 6 -- INVESTMENTS ACCOUNTED FOR BY THE EQUITY METHOD NRG Energy 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 NRG Energy 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. A summary of NRG Energy's significant equity-method investments which were in operation at December 31, 2000 is as follows:
2000 1999 ---- ---- (IN THOUSANDS) Fuel oil............................................... $ 48,541 $ 35,987 Coal................................................... 17,439 16,404 Kerosene............................................... 1,524 1,395 Spare parts............................................ 85,136 56,766 Other.................................................. 22,224 8,629 -------- -------- Total Inventory................................. $174,864 $119,181 ======== ======== 49
GEOGRAPHIC ECONOMIC NAME AREA INTEREST ---- -------------- -------- Loy Yang Power A............................................ Australia 25.37% Enfield Energy Center....................................... Europe 25.00% Gladstone Power Station..................................... Australia 37.50% COBEE (Bolivian Power Co. Ltd.)............................. South America 49.10% ECK Generating.............................................. Czech Republic 44.50% MIBRAG GmbH................................................. Europe 33.33% Cogeneration Corp. of America............................... USA 20.00% Schkopau Power Station...................................... Europe 20.95% Long Beach Generating....................................... USA 50.00% El Segundo Generating....................................... USA 50.00% Encina...................................................... USA 50.00% San Diego Combustion Turbines............................... USA 50.00% Energy Developments Limited................................. Australia 29.14% Scudder Latin American Power................................ Latin America 6.63% 52 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: In accordance with SFAS No. 121, NRG Energy 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, NRG Energy wrote down accumulated project development expenditures of $26.7 million. NRG Energy's West Java, Indonesia, project totaling $22.0 million was written off due to the uncertainties surrounding infrastructure projects in Indonesia. Also during 1998, NRG Energy 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. NOTE 7 -- RELATED PARTY TRANSACTIONS OPERATING AGREEMENTS NRG Energy has two agreements with Xcel for the purchase of thermal energy. Under the terms of the agreements, Xcel charges NRG Energy for certain costs (fuel, labor, plant maintenance, and auxiliary power) incurred by Xcel to produce the thermal energy. NRG Energy paid Xcel $5.5 million, $4.4 million and $5.1 million in 2000, 1999 and 1998, respectively under these agreements. NRG Energy has a renewable 10-year agreement with Xcel, expiring on December 31, 2001, whereby Xcel agrees to purchase refuse-derived fuel for use in certain of its boilers and NRG Energy agrees to pay Xcel a burn incentive. Under this agreement, NRG Energy received $1.5 million, $1.4 million and $1.4 million from Xcel, and paid $2.8 million, $2.7 million and $3.1 million to Xcel in 2000, 1999 and 1998, respectively. ADMINISTRATIVE SERVICES AND OTHER COSTS NRG Energy has an administrative services agreement in place with Xcel. Under this agreement NRG Energy reimburses Xcel for certain overhead and administrative costs, including benefits administration, engineering support, accounting, and other shared services as requested by NRG Energy. In addition, NRG Energy employees participate in certain employee benefit plans of Xcel as discussed in Note 11. NRG Energy received services from Xcel of $4.7 million, $6.4 million and $5.2 million, during 2000, 1999 and 1998, respectively under this agreement. 50
2000 1999 1998 ---- ---- ---- (THOUSANDS OF DOLLARS) Operating revenues....................................... $2,349,108 $1,732,521 $1,491,197 Costs and expenses....................................... 1,991,086 1,531,958 1,346,569 ---------- ---------- ---------- Net income.......................................... $ 358,022 $ 200,563 $ 144,628 ---------- ---------- ---------- Current assets........................................... $1,000,670 $ 742,674 $ 710,159 Noncurrent assets........................................ 7,470,766 7,322,219 7,938,841 ---------- ---------- ---------- Total assets........................................ $8,471,436 $8,064,893 $8,649,000 ---------- ---------- ---------- Current liabilities...................................... $1,094,304 $ 708,114 $ 527,196 Noncurrent liabilities................................... 4,306,142 5,168,893 5,854,284 Equity................................................... 3,070,990 2,187,886 2,267,520 ---------- ---------- ---------- Total liabilities and equity........................ $8,471,436 $8,064,893 $8,649,000 NRG's share of equity.................................... $ 973,261 $ 932,591 $ 800,924 NRG's share of income.................................... $ 139,364 $ 67,500 $ 81,706 53 NOTE 8 -- 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: NOTE 9 -- LONG-TERM DEBT Long-term debt consists of the following:
2000 1999 ---- ---- (THOUSANDS OF DOLLARS) Central Texas Commercial Air Conditioning & Heating, Inc., due July 10, 2001, 10%.................................... $ 60 $ -- O'Brien Cogen II note, due 2008, non-interest bearing....... 513 465 Southern Minnesota-Praireland Solid Waste, note due 2003, 7%........................................................ 34 44 Omega Energy, LLC, due 2004, 12.5%.......................... 3,745 3,745 Omega Energy, LLC, due 2009, 11%............................ 1,533 1,533 ------- ------- Notes receivable - non-affiliates......................... 5,885 5,787 Various secured notes due 2000 and later, non-interest and interest bearing.......................................... -- 224 NEO notes to various affiliates due primarily 2012, prime +2%....................................................... 23,277 21,572 TOSLI, various notes due 2000, LIBOR plus 4.0%, 6.56% at December 31, 2000......................................... 207 207 Pacific Generation, various notes, prime +2% to 12%......... 3,368 3,368 NRGenerating International BV notes to various affiliates, non-interest bearing...................................... 44,275 40,410 ------- ------- Notes receivable - affiliates............................. 71,127 65,781 ------- ------- Total................................................. $77,012 $71,568 ======= ======= 51
2000 1999 ---- ---- (THOUSANDS OF DOLLARS) COBEE, due upon demand, non-interest bearing................ 69 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%...................................................... 1,283 1,729 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%......... 5,525 6,800 San Francisco Thermal LP, October 5, 2004, 10.61%........... 4,984 5,905 NRG Energy senior notes, due February 1, 2006, 7.625%....... 125,000 125,000 Note payable to Xcel, due December 1, 1995-2006, 5.40%-6.75%............................................... -- 6,495 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%............................................... 14,526 17,087 Camas Power Boiler LP, revenue bonds, due August 1, 2007, 4.65%..................................................... 9,130 9,130 Various NEO debt due 2005-2008, 9.35%....................... 27,186 28,615 NRG Energy senior notes, due June 1, 2009, 7.50%............ 300,000 300,000 NRG Energy senior notes, due September 15, 2010, 8.25%...... 350,000 -- Flinders Power Finance Pty, due September 2012, 7.58%....... 83,820 -- NRG Energy Center, Inc. senior secured notes due June 15, 2013,7.31%................................................ 65,762 68,881 NRG Energy senior notes, due Nov. 1, 2013, 8.00%............ 240,000 240,000 Crockett Corp. LLP, due December 31, 2014, 8.13%............ 245,229 255,000 NRG Northeast Generating LLC term loan...................... -- 646,564 NRG Northeast Generating LLC senior bonds,due various dates through December 15, 2024, various interest rates......... 700,000 -- NRG South Central Generating LLC senior bonds, due various dates through September 15, 2024, various interest rates..................................................... 788,750 -- NRG Energy ROARS, due March 15, 2005, 7.97%................. 239,386 -- Sterling Luxemburg #3, term loan due June 30, 2019, 7.86%,.................................................... -- LIBOR+1.31%............................................... 346,668 -- ---------- ---------- 3,797,318 1,971,860 Less current maturities..................................... (146,469) (30,462) ---------- ---------- Total................................................. $3,650,849 $1,941,398 ========== ========== 54 As of December 31, 2000, NRG Energy had a $500 million revolving credit facility under a commitment fee arrangement that matures in March of 2001. This facility provides short-term financing in the form of bank loans. At December 31, 2000, NRG Energy had $8 million outstanding under this facility. In March 2001, the revolving credit facility will terminate and be replaced with a substantially similar facility, terminating in March 2002. During the period ended December 31, 2000 the facility bore interest at a floating rate of 9.5% and had a weighted average interest rate of 7.986%. As of December 31, 1999, NRG Energy had $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, NRG Energy had $340.0 million outstanding under this revolving credit agreement. NRG Energy had $63.0 million and $116.0 million in outstanding letters of credit as of December 31, 2000 and 1999, respectively. 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, 2000. The NRG Energy $125 million, $250 million, $300 million, $240 million and $350 million senior notes are unsecured and are used to support equity requirements for projects acquired and in development. The interest is generally paid semi-annually. The $240 million 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 on May 1, and November 1, of each year through 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 NRG Energy at prices discussed in the indenture. The notes are unsecured debt that rank senior to all of NRG Energy's existing and future subordinated indebtedness. 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. NEO was in compliance with these covenants at December 31, 2000. The Camas Power Boiler LP notes are secured principally by its 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, 2000. The Crockett Corporation term loan is secured by primarily the long-term assets of the Crockett Cogeneration project. On February 22, 2000, NRG Northeast Generating LLC, an indirect, wholly-owned subsidiary of NRG Energy issued $750 million of project level 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% due in 2004, $130 million with an interest rate of 8.842% due in 2015 and $300 million with an interest rate of 9.292% due in 2024. The bonds are jointly and severally guaranteed by each of NRG Northeast's existing and future subsidiaries. The bonds are secured by a security interest in NRG Northeast's membership or other ownership interests in the guarantors and its rights under all intercompany notes between NRG Northeast and the guarantors. Approximately $646.6 million of the proceeds from these bonds were used to repay short-term borrowings outstanding at December 31, 1999; accordingly, $646.6 million of short-term debt was re-classified as long-term debt, based on this refinancing. In December, 2000, NRG Northeast Generating LLC exchanged all of its outstanding bonds for bonds registered under the Securities Act of 1933. As of December 31, 2000, there remains $700 million of outstanding bonds. 52 55 In March 2000, NRG Energy issued $250 million of 8.70% ROARS due March 15, 2005. Each security represents a fractional interest in the assets of an unconsolidated grantor trust that pays interest semi-annually on March 15, and September 15, of each year through 2005. The sole assets of the Trust consists of (pound)160 million of Reset senior notes due March 15, 2020 issued by NRG Energy pursuant to the Indenture and certain other defined rights. The Reset senior notes were used principally to finance NRG Energy's acquisition of the Killingholme facility. On March 15, 2005, these senior notes may be remarketed by Bank of America, N.A. at a fixed rate of interest through the maturity date or, at a floating rate of interest for up to one year and then at a fixed rate of interest through 2020. Interest is payable semi-annually on these securities beginning September 15, 2000 through March 15, 2005, and then at intervals and interest rates established in the remarketing process. Additionally, three of NRG Energy's foreign subsidiaries entered into a (pounds) 325 million (US $517 million at March 31, 2000) secured borrowing facility agreement with Bank of America International Limited. Under this facility, the financial institutions have made available to our subsidiaries various term loans totaling (pounds)235 million (US $374 million at March 31, 2000) for purposes of financing the acquisition of the Killingholme facility and (pounds)90 million (US $143 million at March 31, 2000) of revolving credit and letter of credit facilities to provide working capital for operating the Killingholme facility. The final maturity date of the facility is the earlier of June 30, 2019, or the date on which all borrowings and commitments under the largest tranche of the term facility have been repaid or cancelled. In March 2000, NRG South Central Generating LLC, an indirect wholly-owned subsidiary of NRG Energy issued $800 million of senior secured bonds in a two-part offering, to finance its acquisition of the Cajun generating facilities. The first tranche was for $500 million with a coupon of 8.962% and a maturity of 2016. The second tranche was for $300 million with a coupon of 9.479% and a maturity of 2024. The bonds are secured by a security interest in NRG Central U.S. LLC's and South Central Generating Holding LLC's membership interests in NRG South Central and NRG South Central's membership interests in Louisiana Generating and all of the assets related to the Cajun facilities including its rights under a guarantor loan agreement and all intercompany notes between it and Louisiana Generating and a revenue account and a debt service reserve account. In January 2001, NRG South Central Generating LLC exchanged all of its outstanding bonds for bonds registered under the Securities Act of 1933. In September 2000, Flinders Power Finance Pty, an Australian wholly owned subsidiary, entered into a twelve year AUD $150 million promissory note (US $81.4 million at September 2000). The interest has a fixed and variable component. At December 31, 2000, the effective interest rate was 8.25% and is paid semi annually. In December 1999, NRG Energy filed a shelf registration statement with the SEC to issue up to $500 million of unsecured debt securities. During 2000, NRG Energy issued $350 million of debt under this shelf for general corporate purposes, which includes financing, development and construction of new facilities, additions to working capital and financing capital expenditures and pending or potential acquisitions. The remaining $150 million was combined with NRG Energy's recently filed shelf registration made in December 2000. In December 2000, NRG Energy filed a shelf registration with the SEC to issue up to $1,650.0 million of an indeterminate amount of debt securities, preferred stock, common stock, depository shares, debt warrants, stock purchase contracts, stock purchase units and hybrid securities. This shelf registration includes $150 million of securities that are being carried forward from NRG Energy's previous shelf registration filed in December 1999. 53 56 Annual maturities of long-term debt for the years ending after December 31, 2000 are as follows: GUARANTEES NRG Energy is 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. 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 NRG Energy's generation facilities in the United States, NRG Energy may be required to guarantee a portion of the obligations of certain of its subsidiaries. As of December 31, 2000, NRG Energy's obligations pursuant to its guarantees of the performance, equity and indebtedness obligations of its subsidiaries totaled approximately $493 million. NOTE 10 -- INCOME TAXES NRG Energy and its parent, Xcel, 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 NRG Energy, along with its subsidiaries, is in a taxable income position, NRG Energy 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 NRG Energy, along with its subsidiaries, is in a tax loss position, NRG Energy will be currently reimbursed to the extent its combined losses are utilized in a consolidated return, and (3) if NRG Energy, along with its subsidiaries, generates tax credits, NRG Energy will be currently reimbursed to the extent its tax credits are utilized in a consolidated return. The provision (benefit) for income taxes consists of the following:
(THOUSANDS OF DOLLARS) ---------------------- 2001....................................................... $ 146,469 2002....................................................... 166,075 2003....................................................... 98,269 2004....................................................... 91,324 2005....................................................... 51,332 Thereafter................................................. 3,243,849 ---------- Total................................................. $3,797,318 ========== 54
2000 1999 1998 ---- ---- ---- (THOUSANDS OF DOLLARS) Current Federal................................................ $ 49,048 $ 3,620 $(10,773) State.................................................. 39,972 1,041 (3,940) Foreign................................................ (614) 4,040 2,358 -------- -------- -------- 88,406 8,701 (12,355) Deferred Federal................................................ 25,836 (2,792) 8,828 State.................................................. 5,475 (3,901) 1,541 Foreign................................................ 7,104 (7,668) (7,736) -------- -------- -------- 38,415 (14,361) 2,633 Tax credits recognized................................... (34,083) (20,421) (15,932) -------- -------- -------- Total income tax (benefit).......................... $ 92,738 $(26,081) $(25,654) ======== ======== ======== Effective tax rate....................................... 34% (84)% (160)% 57 The components of the net deferred income tax liability at December 31 were: The effective income tax rate for 2000 differs from the statutory federal income tax rate of 35% as follows:
2000 1999 ---- ---- (THOUSANDS OF DOLLARS) Deferred tax liabilities Differences between book and tax basis of property........ $82,392 $37,713 Investments in projects................................... 29,475 17,308 Goodwill.................................................. 2,015 1,117 Other..................................................... 10,546 5,544 ------- ------- Total deferred tax liabilities............................ 124,428 61,682 Deferred tax assets Deferred revenue.......................................... 280 841 Deferred compensation, accrued vacation and other reserves............................................... 23,703 10,996 Development costs......................................... 13,891 6,768 Deferred investment tax credits........................... 345 450 Steam capacity rights..................................... 778 844 Foreign tax loss carryforwards............................ 25,063 20,919 Other..................................................... 4,726 3,924 ------- ------- Total deferred tax assets................................. 68,786 44,742 ------- ------- Net deferred tax liability................................ $55,642 $16,940 ======= ======= For the year ended December 31, 2000, income tax expense was $92.7 million, compared to an income tax benefit of $26.1 million for the year ended December 31, 1999, an increase of $118.8 million. The increase in tax expense compared to 1999 is due primarily to higher domestic taxable income. This increase was partially offset by additional IRC Section 29 energy tax credits. For the year ended December 31, 2000, NRG Energy's overall effective income tax rate was approximately 34%. NRG Energy's effective income tax rate before recognition of tax credits was approximately 46%. This rate is higher than a combined federal and Minnesota statutory rate because a significant portion of NRG Energy's income is generated in New York City, an area with high state and local tax rates. In addition, NRG Energy has recorded a valuation allowance on certain state and foreign tax losses, also increasing the effective tax rate. The effective income tax rate for the years 1999 and 1998 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 are not subject to U.S. taxes (as discussed below). NRG Energy 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 $232 million and $195 million at December 31, 2000 and 1999. 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. 55
Net Income before income taxes................. $275,673 Tax at 35%..................................... 96,486 35.00% State taxes (net of federal benefit)........... 29,541 10.72% Foreign operations............................. (10,692) (3.88)% Tax credits.................................... (34,083) (12.36)% Permanent differences, reserves and other...... 11,486 4.16% -------- -------- Income tax expense............................. $ 92,738 33.64% ======== ======== 58 NOTE 11 -- BENEFIT PLANS AND OTHER POSTRETIREMENT BENEFITS PENSION BENEFITS PENSION BENEFITS NRG Energy participates in the portion of Xcel's noncontributory, defined benefit pension plan which was formerly administered by NSP, and covers substantially all of NRG's employees. Benefits are based on a combination of years of service, and in most cases the employee's highest average pay. Some formulas also take into account Social Security benefits. During 2000, the pension benefits attributable to NRG Energy's 1999 acquisitions were combined with Xcel's plan. Plan assets principally consist of the common stock of public companies, corporate bonds and U.S. government securities. NRG Energy's net annual periodic pension cost includes the following components: COMPONENTS OF NET PERIODIC BENEFIT COST The funded status of the pension plan in which NRG Energy employees participate is as follows at December 31: RECONCILIATION OF FUNDED STATUS
2000 1999 1998 ---- ---- ---- (THOUSANDS OF DOLLARS) Service cost benefits earned................................ $ 5,769 $ 1,602 $ 1,303 Interest cost on benefit obligation......................... 6,728 1,739 1,417 Expected return on plan assets.............................. (11,227) (2,866) (2,226) Amortization of prior service cost.......................... 394 393 172 Recognized actuarial gain................................... (5,355) (2,053) (1,878) -------- ------- ------- Net periodic benefit credit............................... $ (3,691) $(1,185) $(1,212) ======== ======= ======= 56
2000 1999 -------------------------- -------------------------- XCEL PLAN NRG PORTION XCEL PLAN NRG PORTION --------- ----------- --------- ----------- (UNAUDITED) (UNAUDITED) (THOUSANDS OF DOLLARS) Benefit obligation at Jan. 1.................. $1,247,849 $ 24,289 $1,143,464 $20,112 Service cost.................................. 36,895 5,769 36,421 1,602 Interest cost................................. 99,254 6,728 86,429 1,739 Plan amendments............................... 1,925 -- 184,255 2,214 Actuarial (gain)/loss......................... (27,446) 5,357 (105,634) (178) Acquisitions.................................. 52,800 52,800 -- -- Benefit payments......................... (135,462) (4,371) (97,086) (1,200) ---------- -------- ---------- ------- Benefit obligation at Dec. 31............ $1,275,815 $ 90,572 $1,247,849 $24,289 ========== ======== ========== ======= Fair value of plan assets at Jan. 1........... $2,418,637 $ 47,078 $2,221,819 39,079 Actual return on plan assets.................. 89,651 90,058 293,904 9,199 Benefit payments.............................. (135,462) (4,371) (97,086) (1,200) Acquisitions.................................. 38,412 38,412 -- -- ---------- -------- ---------- ------- Fair value of plan assets at Dec. 31..... $2,411,238 $171,177 $2,418,637 $47,078 ========== ======== ========== ======= Funded status at Dec. 31 - excess of assets over obligation............................. $1,135,423 $ 80,605 $1,170,788 $22,789 Unrecognized transition asset................. (235) -- (311) -- Unrecognized prior service cost............... 254,798 4,381 277,350 4,775 Unrecognized net gain......................... (1,276,435) (98,874) (1,381,889) (26,944) ---------- -------- ---------- ------- Accrued asset (liability) at Dec. 31..... $ 113,551 $(13,888) $ 65,938 $ 620 ========== ======== ========== ======= 59 AMOUNT RECOGNIZED IN THE BALANCE SHEET The weighted average discount rate used in determining the actuarial present value of the projected benefit obligation was 7.75% for December 31, 2000 and 1999. The rate of increase in future compensation levels used in determining the actuarial present value of the projected obligation was 4.5% in 2000 and 1999. The assumed long-term rate of return on assets used for cost determinations was 8.5% for 2000 and 1999. NRG Energy participates in Xcel's defined contribution 401(K) savings plan, as well as sponsoring several of its own defined contribution savings plans as a result of its 1999 and 2000 acquisition activity. Substantially all employees are covered by one of these plans. Total contributions to the plan were approximately $2.2 million, $0.5 million and $0.2 million for the years ended December 31, 2000, 1999 and 1998, respectively. NRG EQUITY PLAN During 1998 and 1999, NRG Energy's employees were eligible to participate in its Equity Plan (the Plan). The Plan granted, to employees, phantom equity units that were intended to simulate Stock options. Grant size was based on the participant's position in the Company and base salary. Equity unit valuations were performed annually by an outside valuation firm. The value of an equity unit was the approximate value per share of NRG Energy's stockholder equity as of the valuation date, less the value of Xcel's (formerly NSP) equity investments. The units were awarded to employees annually at the respective year's calculated share price (grant price). The Plan provided employees with a cash pay out for the unit's appreciation in value over the vesting period. The Plan had 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 2000, 1999 and 1998, NRG Energy recorded compensation expense of approximately $6.0 million, $13.0 million and $2.6 million, respectively, for the Plan. The Plan included a change of control provision, which allowed all shares to vest if NRG Energy's ownership were to change. Subsequent to the completion of NRG Energy's initial public offering in June 2000, the Plan was converted to a new stock option plan; see Note 14. POSTRETIREMENT HEALTH CARE NRG Energy participates in Xcel's contributory health and welfare benefit plan which was formerly administered by NSP, and provides health care and death benefits to substantially all NRG Energy retirees. The legacy Xcel plan was terminated for nonbargaining employees retiring after 1998 and for bargaining employees retiring after 1999. For covered retirees, the plan enables NRG Energy to share the cost of retiree health costs. Cost-sharing for bargaining employees is governed by the terms of the collective bargaining agreement. NRG Energy also provides postretirement health and welfare benefits for substantially all of its employees associated with the 1999 acquisition activity. The plan administered by NRG Energy provides eligible retirees with both health care and death benefits. Cost sharing varies by acquisition group and the terms of the collective bargaining agreements. The cost of these benefits was reported in the Xcel plan costs in 2000. Postretirement health care benefits for NRG Energy are determined and recorded under the provisions of SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." SFAS No. 106 57
2000 1999 -------------------------- -------------------------- XCEL PLAN NRG PORTION XCEL PLAN NRG PORTION --------- ----------- --------- ----------- (UNAUDITED) (UNAUDITED) (THOUSANDS OF DOLLARS) Prepaid benefit cost............................. $128,034 $ -- $65,938 $ 868 Accrued benefit liability........................ (14,483) (13,888) -- (248) -------- -------- ------- ----- Net amount recognized -- asset (liability)..... $113,551 $(13,888) $65,938 $ 620 ======== ======== ======= ===== 60 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. NRG Energy's net annual periodic benefit cost under SFAS No. 106 includes the following components: COMPONENTS OF NET PERIODIC BENEFIT COST Plan assets as of December 31, 2000 consisted of investments in equity mutual funds, fixed income securities and cash equivalents. NRG Energy's funding policy is to contribute to Xcel's benefits actually paid under the plan. The following table sets forth the funded status of the health care plan in which NRG Energy's employees participate at December 31: RECONCILIATION OF FUNDED STATUS
2000 1999 1998 ---- ---- ---- (THOUSANDS OF DOLLARS) Service cost benefits earned................................ $ 833 $ 9 $165 Interest cost on benefit obligation......................... 1,270 24 145 Amortization of transition asset............................ -- -- 17 Amortization of prior service cost.......................... (104) (104) (40) Recognized actuarial (gain)/loss............................ (28) (34) 2 ------ ----- ---- Net periodic benefit cost (credit)........................ $1,971 $(105) $289 ====== ===== ==== The assumed health care cost trend rates used in measuring the accumulated projected benefit obligation (APBO) at both December 31, 2000 and 1999, were 8.1% for those under age 65, and 6.1 % for those over age 58
2000 1999 -------------------------- -------------------------- XCEL PLAN NRG PORTION XCEL PLAN NRG PORTION --------- ----------- --------- ----------- (UNAUDITED) (UNAUDITED) (THOUSANDS OF DOLLARS) Benefit obligation at Jan. 1..................... $139,934 $ 421 $219,762 $1,517 Service cost..................................... 997 833 196 9 Interest cost.................................... 12,576 1,270 9,184 24 Employee contributions........................... 2,338 6 -- -- Plan amendments.................................. -- -- (80,840) (770) Actuarial loss/(gain)............................ 18,782 (755) 3,269 (359) Acquisitions..................................... 16,445 16,445 -- -- Benefit payments................................. (20,140) (_26) (16,637) -- -------- ------- -------- ------ Benefit obligation at Dec. 31.................. $170,932 $18,194 $134,934 $ 421 ======== ======= ======== ====== Fair Value of plan assets at Jan. 1.............. $ 35,198 $ -- $ 34,514 $ -- Actual return on plan assets..................... 527 -- 3,982 -- Employee contributions........................... 2,338 6 -- -- Employer contributions........................... 14,204 20 13,339 -- Benefit payments................................. (20,140) (26) (16,637) -- -------- ------- -------- ------ Fair value of plan assets at Dec. 31........... $ 32,127 $ -- $ 35,198 $ -- ======== ======= ======== ====== Funded status at Dec. 31-unfunded obligation..... $138,805 $18,194 $104,736 $ 421 Unrecognized transition obligation............... (20,376) -- (22,073) -- Unrecognized prior service cost.................. 2,637 1,348 2,926 1,452 Unrecognized net (gain)/loss..................... (29,901) 2,106 (10,580) 562 -------- ------- -------- ------ Accrued liability recorded at Dec. 31............ $ 91,165 $21,648 $ 75,009 $2,435 ======== ======= ======== ====== 61 65. The assumed cost trends are expected to decrease each year until they reach 5.5% 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 $1.8 million as of December 31, 2000. Service and interest cost components of the net periodic postretirement cost would increase by approximately $230,000 with a similar one percent increase in the assumed health care cost trend rate. A one percent decrease in the assumed health care cost trend rate would decrease the APBO by approximately $1.4 million as of December 31, 2000. Service and interest cost components of the net periodic post retirement cost would decrease by approximately $175,000 with a similar one percent decrease in the assumed health care cost trend rate. The assumed discount rate used in determining the APBO was 7.75% for both December 31, 2000 and 1999, compounded annually. The assumed long-term rate of return on assets used for cost determinations under SFAS No. 106 was 8% for 2000, 1999 and 1998. PENSION AND OTHER BENEFITS -- 1999 ACQUISITIONS During 1999, NRG Energy 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. Of the 1999 acquisitions where these obligations were assumed approximately 66 percent of such employees are represented by seven local labor unions under collective bargaining agreements, which expire between 2001 and 2003. For these employees, NRG Energy sponsored one noncontributory, defined benefit pension plan that covered most of the employees associated with the 1999 acquisitions. Generally, the benefits are based on a combination of years of service and in most cases the employee's highest average pay. Some formulas also take into account Social Security benefits. During the year 2000, the pension benefit attributable to NRG Energy's 1999 acquisitions were combined with Xcel's plan. The pension formulas remained unchanged. COMPONENTS OF NET PERIODIC BENEFIT COST 59
1999 ---- (THOUSANDS OF DOLLARS) Service cost benefits earned.............................. $ 968 Interest cost on benefit obligation....................... 1,115 Expected return on plan assets............................ (1,193) ------- Net periodic (benefit) cost............................. $ 890 ======= 62 RECONCILIATION OF FUNDED STATUS AMOUNT RECOGNIZED IN THE BALANCE SHEET
1999 ---- (THOUSANDS OF DOLLARS) Benefit obligation at beginning of year................... $ 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 year............ $ 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- unfunded obligation............. $(15,203) Unrecognized transition (asset) obligation................ -- Unrecognized prior service cost........................... -- Unrecognized net gain..................................... (2,996) -------- Accrued benefit obligation at Dec. 31................ $(18,199) 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. POSTRETIREMENT HEALTH CARE NRG Energy has also assumed post retirement health care benefits for some of its employees associated with the 1999 acquisitions. The plan enables NRG Energy 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 retirees under these plans as of December 31, 1999. The estimated net periodic postretirement benefit cost for 1999 is $0.85 million. The estimated accumulated post-retirement benefit obligation is $16 million at December 31, 1999. During the year 2000, the postretirement health care benefit obligations attributable to NRG Energy's 1999 acquisitions were combined with Xcel's plan. 401(K) PLANS NRG Energy 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 60
1999 ---- (THOUSANDS OF DOLLARS) Prepaid benefit cost...................................... $ -- Accrued benefit liability................................. (18,199) -------- Net amount recognized -- (liability).................... $(18,199) -------- 63 cover substantially all of our employees who are not covered by Xcel's 401(k) Plan. NRG Energy matches specified amounts of employee contributions to the plan. Employer contributions made to these plans were approximately $0.31 million in 1999, respectively. PENSION AND OTHER BENEFITS -- 2000 ACQUISITIONS Flinders Power, South Australia Flinders Power participates with other companies in the electric generation industry in South Australia, in making payments to pension funds, which are not administered by Flinders Power. Pension costs relating to multi-employer plans were approximately $1.3 million for the period ended August 3, 2000 (date of acquisition), to December 31, 2000. NOTE 12 -- SALES TO SIGNIFICANT CUSTOMERS During 2000, sales to two customers accounted for 22.2% and 12.2% of total revenues from majority owned operations in 2000. Sales to three customers accounted for 21.0%, 19.7% and 10.5% of total revenues from wholly owned operations in 1999. NRG Energy and the Ramsey/Washington Resource Recovery Project have a service agreement for waste disposal, which expires in 2006. In 1998, approximately 26.5% of NRG Energy'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 13 -- FINANCIAL INSTRUMENTS The estimated December 31 fair values of NRG Energy's recorded financial instruments are as follows: For cash and 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 Foreign currency exchange rates In the third quarter of 2000, NRG Energy entered into a contract with a notional amount of approximately $8.8 million to hedge or protect foreign currency denominated cash flows. This foreign currency exchange instrument was a hedge of a Killingholme project distribution and expired in January 2001. If this hedge had been discontinued on December 31, 2000, NRG Energy would have owed the counterparty approximately $700,000. Interest rates As of December 31, 2000, NRG Energy has four interest rate swap agreements with notional amounts totaling approximately $530 million. The contracts are used to manage NRG Energy's exposure to changes in interest rates. If the swaps had been discontinued on December 31, 2000, NRG Energy would have owed the counterparties approximately $28.9 million. 61
2000 1999 ------------------------ ------------------------ CARRYING FAIR CARRYING FAIR AMOUNT VALUE AMOUNT VALUE -------- ----- -------- ----- (THOUSANDS OF DOLLARS) Cash and cash equivalents..................... $ 95,243 $ 95,243 $ 31,483 $ 31,483 Restricted cash............................... 12,135 12,135 17,441 17,441 Notes receivable, including current portion... 77,012 77,012 71,568 71,568 Long-term debt, including current portion..... 3,797,318 3,838,627 1,971,860 1,931,969 64 Energy and energy related commodities As discussed in Note 2, NRG Energy is exposed to commodity price variability in electricity, emission allowances and natural gas, oil and coal used to meet fuel requirements. In order to manage these commodity price risks, NRG Energy enters into financial instruments, which may take the form of fixed price, floating price or indexed sales or purchases, and options, such as puts, calls, basis transactions and swaps. At December 31, 2000 and 1999, the net notional amount of such transactions was approximately $309 million and $207 million. If these contracts were terminated at December 31, 2000 and 1999, the Company would have received approximately $52.8 and $12 million based on price fluctuations to date. CREDIT RISK Management believes that NRG Energy'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. Counterparties consist principally of financial institutions and major energy companies. NOTE 14 -- CAPITAL STOCK SALE OF STOCK In June 2000, NRG Energy sold 32.4 million shares of common stock at $15.00 per share. Net proceeds from the offering were $453.7 million. NRG Energy has authorized capital stock consisting of 550,000,000 shares of common stock, and 250,000,000 shares of Class A common stock. At December 31, 2000, there were approximately 32,396,000 shares of common stock, and 147,605,000 shares of Class A common stock issued and outstanding. INCENTIVE COMPENSATION PLAN In June 2000, NRG Energy adopted a new incentive compensation plan (the New Stock Plan), which will be administered by the Board of Directors, or a committee appointed by the Board of Directors. The New Stock Plan provides for awards in the form of stock options, stock appreciation rights, restricted stock, performance units, performance shares, or cash based awards as determined by the Board of Directors. All officers, certain other employees, and non-employee directors are eligible to participate in the plan. Nine million shares of common stock are authorized for issuance under the Stock Plan. Initially, only stock option grants will be made to certain officers and employees under the plan. STOCK OPTIONS Each new option granted is valued at the fair market value per share at date of grant. The difference between the option price and the fair market value, if any, of each option on the date of grant is recorded as compensation expense over a vesting period. Options granted vest over a period of five years, with 25% vesting in each of the years two through five and generally expire ten years from the date of grant. The average exercise price of vested options at December 31, 2000 was $9.51 all of which were granted in replacement of units previously outstanding under the equity plan. Compensation expense related to options granted totaled $7.2 million, for the year ended December 31, 2000. 62 65 At December 31, 2000, no employee stock options were exercisable. Other options currently granted under the equity plan will fully vest periodically and become exercisable through the year 2005 at prices ranging from $5.75 to $17.25. Stock option transactions for 2000 were (shares in thousands): The following table summarizes information about stock options outstanding at December 31, 2000 (in thousands of shares):
YEAR ENDED DECEMBER 31, 2000 ---------------------- WEIGHTED AVERAGE SHARES OPTION PRICE ------ ------------ Outstanding at beginning of period.......................... -- $ -- Granted..................................................... 4,304 9.51 Exercised................................................... -- -- Canceled or expired......................................... -- -- Other, contingent share issuance............................ -- -- ------ ----- Outstanding at end of period................................ 4,304 $9.51 ------ ----- Exercisable at end of period................................ -- $ -- ------ ----- The fair value of each option grant was estimated on the date of grant using the Black-Scholes option-pricing model, with the following weighted-average assumptions used for grants in 2000.
OPTIONS OUTSTANDING OPTIONS EXERCISED ---------------------- ----------------------- WEIGHTED AVERAGE WEIGHTED WEIGHTED REMAINING AVERAGE AVERAGE TOTAL LIFE EXERCISE TOTAL EXERCISE RANGE OF EXERCISE PRICES OUTSTANDING (IN YEARS) PRICE EXERCISABLE PRICE ------------------------ ----------- ---------- -------- ----------- -------- $5.13 - $7.67............................... 1,340 3.1 $6.31 -- $-- $7.68 - $10.25.............................. 1,894 6.9 8.57 -- -- $10.26 - $15.38............................. 1,032 9.4 15.00 -- -- $15.39 - $17.94............................. 19 7.3 17.25 -- -- $17.95 - $23.06............................. 16 9.9 22.50 -- -- $23.07 - $25.63............................. 3 9.3 25.63 -- -- ----- --- ----- -------- -- Total..................................... 4,304 6.3 $9.51 -- $-- ===== === ===== ======== == Using the Black-Scholes option-pricing model, the weighted average fair value of NRG Energy's stock options granted for 2000 is $14.38. NRG Energy accounts for its stock option plan in accordance with Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, under which, no compensation cost has been recognized. Had compensation cost been determined consistent with SFAS No. 123, Accounting for Stock-Based 63
2000 ---- Dividends per year........................ -- Expected volatility....................... 50.26 Risk-free interest rate................... 5.01 Expected life (years)..................... 7 66 Compensation (SFAS No. 123), NRG Energy's net income and per share amounts would have approximated the following pro forma amounts for the year ended December 31, 2000. NOTE 15 -- EARNINGS PER SHARE Basic earnings per common share were computed by dividing net income by the weighted average number of common shares outstanding for the period. The dilutive effect of the potential exercise of outstanding options to purchase shares of common stock is calculated using the treasury stock method. NRG Energy's only common equivalent shares are those that result from dilutive common stock options. The reconciliation of basic earnings per common share to diluted earnings per share is shown in the following table (in thousands, except per share data):
2000 ---- Net income............................... As reported $182,935 Pro Forma 182,279 Earnings per share data: Basic earnings per share................. As reported $ 1.10 Pro Forma 1.10 Diluted earnings per share............... As reported 1.10 Pro Forma 1.09 As of December 31, 2000, 2,700 options have been excluded from the dilutive calculation above as their exercise price exceeded the average fair market value of NRG Energy's common stock. NOTE 16 -- CASHFLOW INFORMATION Detail of supplemental disclosures of cash flow and non-cash investing and financing information was:
FOR THE YEARS ENDED DECEMBER 31, ---------------------------------------------------------------------------------------------- 2000 1999 1998 ------------------------------ ----------------------------- ----------------------------- PER SHARE PER SHARE PER SHARE INCOME SHARES AMOUNT INCOME SHARES AMOUNT INCOME SHARES AMOUNT ------ ------ --------- ------ ------ --------- ------ ------ --------- Basic earnings per share Income before extraordinary items.... $182,935 165,861 $1.10 $57,195 147,605 $.39 $41,732 147,605 $.28 Effect of dilutive securities Stock options................ -- 1,128 -- -- -- -- -- -- -- -------- ------- ----- ------- ------- ---- ------- ------- ---- Diluted earnings per share.................... $182,935 166,989 $1.10 $57,195 147,605 $.39 $41,732 147,605 $.28 ======== ======= ===== ======= ======= ==== ======= ======= ==== NOTE 17 -- COMMITMENTS AND CONTINGENCIES OPERATING LEASE COMMITMENTS NRG Energy 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 64
2000 1999 1998 ---- ---- ---- (THOUSANDS OF DOLLARS) Interest paid (net of amount capitalized)................... $ 352,813 $ 82,891 $49,089 ---------- ---------- ------- Taxes paid/(refunds)........................................ $ 20,923 $ (54,384) $(6,797) ---------- ---------- ------- Detail of businesses and assets acquired: Current assets and other.................................. $ 97,970 $ 110,821 $ -- Fair value of non-current assets.......................... 1,896,113 1,433,370 -- Liabilities assumed, including deferred taxes............. (81,126) (24,826) -- ---------- ---------- ------- Cash paid net of cash acquired............................ $1,912,957 $1,519,365 $ -- ========== ========== ======= 67 $2.3 million, $2.2 million and $1.7 million in 2000, 1999 and 1998, respectively. Future minimum lease commitments under these leases for the years ending after December 31, 2000 are as follows: CAPITAL COMMITMENTS NRG Energy's management expects future capital expenditures related to projects listed below, as well as construction and the purchase of turbines, to total approximately $6,500 million in the years 2001 through 2005. NRG Energy anticipates funding its ongoing capital requirements through the issuance of debt, equity and equity like instruments, preferred stock and operating cash flows. NRG Energy has contractually agreed to the monetization of certain tax credits generated from landfill gas sales through the year 2007. In 1999, NRG Energy and its partners were selected as winning bidder to enter into a 20-year lease of the 600 MW Seyitomer Power Station and related lignite mine located in Kuthya, Turkey. In 1998, also with partners, NRG Energy won a bid to enter into a 20-year lease of the 457 MW coal-fired Kangal plant in central Turkey. A law has been introduced in the Turkish parliament that would require these projects, among others, to close by June 30, 2001 or be cancelled, and NRG Energy is working to meet this deadline. In January 2000, NRG Energy executed purchase agreements with subsidiaries of Conectiv to acquire 1,875 MW of coal, gas and oil-fired electric generating capacity and other assets in New Jersey, Delaware, Maryland and Pennsylvania. NRG Energy will pay approximately $800 million for the assets. NRG Energy expects the acquisition to close in the second quarter of 2001. In August 2000, NRG Energy signed a Heads of Terms Agreement with Eesti Energia, the Estonian state-owned electric utility, providing for the purchase for approximately $65.5 million of a 49% stake in Narva Power, the owner and operator of the oil shale-fired Eesti and Balti power plants, located near Narva, Estonia. The plants have a combined capacity of approximately 2,700 MW. NRG Energy expects the acquisition to close in the second quarter of 2001. In October 2000, NRG Energy signed an asset purchase agreement to acquire from Sierra Pacific Resources its 50% interest in the 522 MW coal-fired North Valmy Station located in Valmy, Nevada, and a 100% interest in 25 MW of peaking units near the North Valmy Station, for a purchase price of approximately $273 million. Idaho Power, the other 50% owner of the North Valmy Station, has a 180-day right of first refusal to purchase this 50%. The right of first refusal expires in May 2001. In addition, the California legislature recently enacted legislation prohibiting any public utility from selling any generation asset until 2006. This law applies to Sierra Pacific Resources because approximately 10% of its ratepayers are located in California. NRG Energy is working to have legislation introduced to exempt the North Valmy Station and the peaking units from the application of this law. In November 2000, NRG Energy agreed to form a partnership with Avista-STEAG LLC to build, operate and manage a 633 MW natural gas-fired power plant in Fort Bend County, Texas. NRG Energy expects to own 50% of the project. NRG Energy estimates that its investment in the project will total approximately $163 million. Construction of the plant is expected to begin in early 2001, with commercial operation expected in February 2003. 65
(THOUSANDS OF DOLLARS) ------------- 2001........................................................ $ 3,254 2002........................................................ 2,962 2003........................................................ 2,878 2004........................................................ 2,743 2005........................................................ 2,365 Thereafter.................................................. 11,434 ------- Total..................................................... $25,636 ======= 68 In November 2000, NRG Energy in conjunction with its partner Dynegy Inc., executed asset purchase agreements to acquire the 740 MW gas-fired Clark Station and 445 MW of the 605 MW coal-fired Reid Gardner Station, both located near Las Vegas, Nevada. The purchase price is approximately $634 million. NRG Energy expects to close the acquisition during the second quarter of 2001. In addition, NRG Energy and Dynegy are negotiating to acquire an additional 145 MW of the Reid Gardner Station. In December 2000, NRG Energy signed asset purchase agreements to acquire the 585 MW coal-fired Bridgeport Harbor Station and the 466 MW oil and gas-fired New Haven Harbor Station in Connecticut for approximately $325 million. NRG Energy expects the acquisition to close during the second quarter of 2001. In December 2000, NRG Energy and its partner, Dynegy Inc., submitted permit applications in respect of a planned repowering of our jointly-owned El Segundo Station in El Segundo, California. The planned repowering would add approximately 621 MW of generating capacity to the facility at a cost of approximately $368 million. Prior to the repowering, approximately 350 MW at the El Segundo Station will be decommissioned. The repowering project has a targeted operation date of June 2003. In December 2000, NRG Energy signed a purchase agreement to acquire a 540 MW natural gas-fired generation facility being developed in Meriden, Connecticut, for a purchase price of approximately $25 million. NRG Energy expects to close the acquisition in the first quarter of 2001. NRG Energy estimates costs of approximately $384 million to complete construction of the plant, which has a planned commercial operation date of June 2003. CONTINGENT REVENUES Regulatory Issue On March 30, 2000, NRG Energy received notification from the New York Independent System Operator (NYISO) of its petition to the Federal Energy Regulatory Commission (FERC) to place a $2.52 per megawatt hour market cap on ancillary service revenues. The NYISO also requested authority to impose this cap on a retroactive basis to March 1, 2000. On May 31, 2000, the FERC approved the NYISO's request to impose price limitations on one ancillary service, Ten Minute Non-Synchronized Reserves (TMNSR) on a prospective basis only, effective March 28, 2000. The FERC rejected the NYISO's request for authority to adjust the market-clearing prices for TMNSR on a retroactive basis. As a result of the FERC order, (unless the NYISO or other party successfully appeals the order), NRG Energy will retain approximately $8.0 million of revenues collected in February 2000. NRG Energy has included in revenues, but has not yet collected for March 2000, approximately $8.2 million, which has been fully reserved for as of December 31, 2000. Disputed Revenues As of December 31, 2000, NRG Energy had disputed revenues totaling $13.1 million relating to the interpretation of certain transmission power sales agreements and to sales to the New York Power Pool and New England Power Pool, conflicting meter readings, pricing of firm sales and other power pool reporting issues. NRG Energy is actively pursuing resolution and/or collection of these amounts. These amounts have not been recorded in the financial statements and will not be recognized as income until disputes are resolved and collection is assured. As of December 31, 2000, NRG Energy's portion of disputed revenues of its California affiliates totaled $17.4 million. These amounts relate to disputes arising in the ordinary course of business and to disputes that have arisen as a result of the California ISO imposing various revenue caps on the wholesale price of electricity. These amounts have not been recorded in the financial statements and will not be recognized as income until disputes are resolved and collection is assured. 66 69 California Liquidity Crisis NRG Energy owns approximately 1,569 MW of net generating capacity in California, which represented approximately 11% of its net MW of operating projects and projects under construction as of December 31, 2000. NRG Energy's California generation assets consist primarily of interests in the Crockett and Mt. Poso facilities and a 50% interest in West Coast Power LLC, formed in 1999 with Dynegy, Inc. Through the California Power Exchange (PX) and the California Independent System Operator (ISO), the West Coast Power facilities sell power to Pacific Gas and Electric Company (PG&E), Southern California Edison Company (SCE) and San Diego Gas and Electric Company (SDG&E), the three major California investor owned utilities. Crockett, Mt. Poso, and certain of NRG Energy's other California facilities also sell directly to PG&E, SCE and SDG&E. The liquidity crisis faced by both PG&E and SCE, as a result of tight electricity supplies, rising wholesale electric prices and caps on the rates that PG&E and SCE may charge their retail customers, has caused both PG&E and SCE to partially suspend payments to the California PX and the California ISO. NRG Energy's share of the accounts receivable owed to its California operations by the California PX, the California ISO and the three major California utilities totaled approximately $105 million as of December 31, 2000. NRG Energy believes that the amounts that have been recorded as accounts receivable will ultimately be collected in full; however, if some form of financial relief or support is not provided to PG&E and SCE, the collectibility of these receivables will become more questionable in terms of both timing and amount. CONTRACTUAL COMMITMENTS In connection with the recent acquisition of certain generating facilities NRG Energy has entered into various long-term transition agreements and standard offer agreements that obligated NRG Energy to provide its customers, primarily the previous owners of the acquired facilities, with a certain portion of the energy and capacity output of the acquired facilities. During 1999, NRG Energy acquired the Huntley and Dunkirk generating facilities from Niagara Mohawk Power Corporation (NiMo). In connection with this acquisition, NRG Energy entered into a 4-year agreement with NiMo that requires NRG Energy to provide to NiMo pursuant to a predetermined schedule fixed quantities of energy and capacity at a fixed price. During 1999, NRG Energy acquired certain generating facilities from Connecticut Light and Power Company (CL&P). NRG also entered into a 4-year standard offer agreement that requires NRG Energy to provide to CL&P a portion of its load requirements through the year 2003 at a substantially fixed rate. During 2000, NRG Energy acquired the non-nuclear generating assets of Cajun Electric. Upon acquisition of the facilities, NRG Energy entered into various long-term power purchase agreements with the former customers of Cajun Electric, primarily distribution cooperatives and municipalities. These agreements specify that NRG Energy provide these customers with all requirements necessary to satisfy the energy and capacity needs of their retail load. Also during 2000, NRG Energy acquired the Killingholme generating facilities from National Power plc. In connection with this acquisition, NRG Energy entered into certain agreements to provide the natural gas to operate the facility which generally sells its power into the spot market. NRG Energy has entered into two gas purchase agreements, the first being a 5-year agreement that provides approximately 30% of the generating facilities natural gas requirements and the second agreement being a 10-year agreement that provides approximately 70% of the generating facilities natural gas requirements. NRG Energy has also entered into a 5-year fixed price agreement to resell up to 15% of the gas it has contracted for at a slightly higher price. Also during 2000, NRG Energy acquired the Flinders Power operations in South Australia. Upon the closing of the acquisition, NRG Energy assumed a gas purchase and sales agreement relating to the Osborne generating plant with a remaining life of 18-years. These agreements require NRG Energy to purchase a 67 70 specified quantity of natural gas from a third party supplier at a fixed price for 18-years and resell the natural gas to Osborne at a fixed price for 13-years. The sales price is substantially lower than the purchase price. NRG Energy has recorded the loss associated with this out of the market contract on its balance sheet. In addition, NRG Energy has entered into a contract for differences agreement which provides for the sale of energy into the South Australian power pool through the year 2002. The agreement provides for a swap of the variable market price to a fixed price. ENVIRONMENTAL REGULATIONS NRG Energy, like most industrial enterprises, is subject to regulation with respect to the environmental impact of its operations, including air, water and land, limitations on land use, disposal of waste, aesthetics and other matters. Environmental laws and/or regulations derived therefrom generally require air emissions and water discharges to meet specified limits. They also impose potential joint and several liability, with regard to fault, on entities responsible for certain releases of hazardous substances to manage such materials properly and to clean up property affected by their production and discharge. NRG Energy expects to spend approximately $60 million for capital expenditures between 2001 and 2005 for environmental compliance, which includes the possible installation of Nitrogen oxides (NOx) control technology at the Somerset facility, resolution of consent orders for remediation at the Arthur Kill and Astoria facilities, the resolution of a consent order for water intake at the Arthur Kill facility, and completing remediation-related requirements under the Connecticut Transfer Act. During the years 2000, 1999 and 1998, NRG Energy recorded approximately $3.4 million, $0.3 million and $0 of expenditures related to environmental matters. In response to liabilities associated with these activities, accruals have been established when reasonable estimates are possible. As of December 31, 2000, NRG Energy has established such accruals in the amount of approximately $6.0 million. Such accruals primarily include estimated costs associated with remediation. NRG Energy has not used discounting in determining its accrued liabilities for environmental remediation and no claims for possible recovery from third party issuers or other parties related to environmental costs have been recognized in NRG Energy's consolidated financial statements. NRG Energy adjusts the accruals when new remediation responsibilities are discovered and probable costs become estimatable, or when current remediation estimates are adjusted to reflect new information. NOTE 18 -- SEGMENT REPORTING NRG Energy conducts its business within six segments: Independent Power Generation in North America, Independent Power Generation outside North America (Europe, Asia Pacific and Other Americas regions), Alternative Energy and Thermal projects. NRG Energy's Revenues from wholly owned operations attributable to Europe and Asia Pacific primarily relate to operations in the United Kingdom and Australia, respectively. These segments are distinct components with separate operating results and management structures in place. The "Other" category includes operations that do not meet the threshold for separate 68 71 disclosure and corporate charges (primarily interest expense) that have not been allocated to the operating segments.
POWER GENERATION ----------------------------------------------------- OTHER NORTH AMERICA EUROPE ASIA PACIFIC AMERICAS ------------- ------ ------------ -------- (THOUSANDS OF DOLLARS) 2000 OPERATING REVENUES AND EQUITY EARNINGS Revenues from majority-owned operations............................. $1,578,706 $197,718 $ 94,681 $ 291 Inter-segment Revenues................... -- -- -- -- Equity in earnings of unconsolidated Affiliates............................. 138,655 9,098 3,456 5,704 ---------- -------- --------- -------- Total operating revenues and equity earnings............................... 1,717,361 206,816 98,137 5,995 ---------- -------- --------- -------- Operating Income......................... 596,919 32,573 6,297 2,268 ---------- -------- --------- -------- Net Income............................... $ 241,846 $ 9,706 $ 9,343 $ 3,607 ========== ======== ========= ======== Total assets as of December 31, 2000, for North America, Europe, Asia Pacific and Other Americas total $4,411 million, $828 million, $599 million and $141 million, respectively.
ALTERNATIVE ENERGY THERMAL OTHER TOTAL ----------- ------- ----- ----- OPERATING REVENUES AND EQUITY EARNINGS Revenues from majority-owned Operations............................ $ 39,379 $ 87,802 $ 17,789 $2,016,366 Inter-segment Revenues.................. 2,256 -- -- 2,256 Equity in earnings of unconsolidated Affiliates............................ (17,300) (249) -- 139,364 ---------- -------- --------- ---------- Total operating revenues and equity earnings.............................. 24,335 87,553 17,789 2,157,986 ---------- -------- --------- ---------- Operating (Loss) Income................. (28,898) 20,303 (56,389) 573,073 ---------- -------- --------- ---------- Net Income (Loss)....................... $ 14,637 $ 7,590 $(103,794) $ 182,935 ========== ======== ========= ==========
POWER GENERATION ----------------------------------------------------- OTHER NORTH AMERICA EUROPE ASIA PACIFIC AMERICAS ------------- ------ ------------ -------- (THOUSANDS OF DOLLARS) 1999 OPERATING REVENUES AND EQUITY EARNINGS Revenues from majority-owned operations............................. $ 319,598 $ -- $ 3,155 $ 189 Inter-segment Revenues................... -- -- -- -- Equity in earnings of unconsolidated Affiliates............................. 31,052 22,840 9,915 5,879 ---------- -------- --------- -------- Total operating revenues and equity earnings............................... 350,650 22,840 13,070 6,068 ---------- -------- --------- -------- Operating Income......................... 114,628 9,168 7,901 2,916 ---------- -------- --------- -------- Net Income............................... $ 71,850 $ 9,509 $ 15,028 $ 3,502 ========== ======== ========= ======== 69
ALTERNATIVE ENERGY THERMAL OTHER TOTAL ----------- ------- ----- ----- OPERATING REVENUES AND EQUITY EARNINGS Revenues from majority-owned operations............................. $ 26,934 $ 76,277 $ 5,402 $431,555 Inter-segment Revenues................... 963 -- -- 963 Equity in earnings of unconsolidated Affiliates............................. (2,205) 19 -- 67,500 ---------- -------- --------- -------- Total operating revenues and equity Earnings............................... 25,692 76,296 5,402 500,018 ---------- -------- --------- -------- Operating Income (Loss).................. (13,288) 18,746 (30,551) 109,520 ---------- -------- --------- -------- Net Income (Loss)........................ $ 10,243 $ 6,506 $ (59,443) $ 57,195 ========== ======== ========= ======== 72 Total assets as of December 31, 1999, for North America, Europe, Asia Pacific and Other Americas total $2,789 million, $179 million, $346 million and $117 million, respectively.
POWER GENERATION ----------------------------------------------------- OTHER NORTH AMERICA EUROPE ASIA PACIFIC AMERICAS ------------- ------ ------------ -------- (THOUSANDS OF DOLLARS) 1998 OPERATING REVENUES AND EQUITY EARNINGS Revenues from majority-owned operations............................. $ 8,185 $ -- $ -- $ -- Intersegment Revenues.................... -- -- -- -- Equity in earnings of unconsolidated Affiliates............................. 49,354 13,561 17,264 1,769 ---------- -------- --------- -------- Total operating revenues and equity Earnings............................... 57,539 13,561 17,264 1,769 ---------- -------- --------- -------- Operating Income......................... 56,561 13,561 17,264 1,769 ---------- -------- --------- -------- Change of interest in projects........... 231 27,819 (22,023) (2,816) ---------- -------- --------- -------- Net Income (Loss)........................ $ 40,103 $ 31,160 $ 2,025 $ 118 ========== ======== ========= ======== Total assets as of December 31, 1998, for North America, Europe, Asia Pacific and Other Americas total $702 million, $168 million, $328 million and $95 million, respectively. NOTE 19 -- JOINTLY OWNED PLANT On March 31, 2000, NRG Energy acquired a 58% interest in the Big Cajun II, Unit 3 generation plant. Entergy Gulf States owns the remaining 42%. Big Cajun II, Unit 3 is operated and maintained by Louisiana Generating pursuant to a joint ownership participation and operating agreement. Under this agreement, Louisiana Generating and Entergy Gulf States are each entitled to their ownership percentage of the hourly net electrical output of Big Cajun II, Unit 3. All fixed costs are shared in proportion to the ownership interests. Fixed costs include the cost of operating common facilities. All variable costs are incurred in proportion to the energy delivered to the owners. NRG Energy's income statement includes our share of all fixed and variable costs of operating the unit. NRG Energy's 58% share of the original cost included in Plant, Property and Equipment at December 31, 2000 was $179.1 million. The corresponding accumulated depreciation and amortization was $3.4 million. NOTE 20 -- DECOMMISSIONING FUNDS NRG Energy is required by the State of Louisiana Department of Environmental Quality ("DEQ") to rehabilitate NRG Energy's Big Cajun II ash and wastewater impoundment areas, subsequent to the Big Cajun II facilities' removal from service. On July 1, 1989, a guarantor trust fund (the "Solid Waste Disposal Trust Fund") was established to accumulate the estimated funds necessary for such purpose. NRG Energy's predecessor deposited $1.06 million in the Solid Waste Disposal Trust Fund in 1989, and funded $116,000 annually thereafter, based upon an estimated future rehabilitation cost (in 1989 dollars) of approximately $3.5 million and the remaining estimated useful life of the Big Cajun II facilities. Cumulative contributions to the Solid Waste Disposal Trust Fund and earnings on the investments therein are accrued as a decommissioning 70
ALTERNATIVE ENERGY THERMAL OTHER TOTAL ----------- ------- ----- ----- OPERATING REVENUES AND EQUITY EARNINGS Revenues from majority-owned operations............................. $ 30,143 $ 52,699 $ 7,660 $ 98,687 Intersegment Revenues.................... 1,737 -- -- 1,737 Equity in earnings of unconsolidated Affiliates............................. (1,314) 1,215 (143) 81,706 ---------- -------- --------- -------- Total operating revenues and equity earnings............................... 30,566 53,914 7,517 182,130 ---------- -------- --------- -------- Operating Income......................... (3,780) 16,693 (45,056) 57,012 ---------- -------- --------- -------- Change of interest in projects........... -- -- -- 3,211 ---------- -------- --------- -------- Net Income (Loss)........................ $ 13,427 $ 6,600 $ (51,701) $ 41,732 ========== ======== ========= ======== 73 liability. At December 31, 2000, the carrying value of the trust fund investments and the related accrued decommissioning liability was approximately $3.9 million. The trust fund investments are comprised of various debt securities of the United States and are carried at amortized cost, which approximates their fair value. NOTE 21 -- UNAUDITED PRO FORMA RESULTS OF OPERATIONS -- CAJUN ACQUISITION During March 2000, NRG Energy completed its acquisition of two fossil fueled generating plants from Cajun Electric Power Cooperative, Inc. for approximately $1,056 million. The following information summarizes the unaudited pro forma results of operations as if the acquisition had occurred as of the beginning of the twelve-month period ended December 31, 2000 and 1999. The unaudited pro forma information presented is for informational purposes only and is not necessarily indicative of future earnings or financial position or of what the earnings and financial position would have been had the acquisition of the Cajun facilities been consummated at the beginning of the respective periods or as of the date for which unaudited pro forma financial information is presented. NOTE 22 -- SUBSEQUENT EVENTS LS Power Acquisition In January 2001, NRG Energy completed the acquisition of a 5,691 MW portfolio of operating projects and projects in construction and advanced development from LS Power, LLC for $708 million, subject to purchase price adjustments. Additionally, until December 31, 2005, NRG Energy has the opportunity to acquire ownership interests in the next 3,000 MW of generation projects developed and offered for sale by LS Power and its partners. This acquisition was initially financed in part by a $600 million bridge credit agreement which has a maturity date of December 31, 2001. At January 31, 2001, the weighted average interest rate was 6.425%. California Liquidity Crisis With respect to the liquidity crisis in California discussed in Note 17, various legislative, regulatory and legal remedies to the liquidity crisis faced by PG&E and SCE have been implemented or are being pursued. Assembly Bill 1X, which authorizes the California Department of Water Resources to enter into contracts for the purchase of electric power through January 1, 2003 and to issue revenue bonds to fund such purchases, was signed into law by the Governor of California on February 1, 2001. Assembly Bill 18X, which provides a 71
PRO FORMA PRO FORMA TWELVE TWELVE MONTHS MONTHS ENDED ENDED DECEMBER 31, DECEMBER 31, 2000 1999 ------------ ------------ (THOUSANDS OF DOLLARS, EXCEPT PER SHARE AMOUNTS) OPERATING REVENUES AND EQUITY EARNINGS Revenues from majority-owned operations................... $2,098,604 $801,080 Equity in earnings of unconsolidated affiliates........... 139,364 67,500 ---------- -------- TOTAL OPERATING REVENUES AND EQUITY EARNINGS................ 2,237,968 868,580 Total operating costs and expenses.......................... 1,653,021 678,915 ---------- -------- OPERATING INCOME............................................ 584,947 189,665 Other expense............................................... 315,191 153,524 ---------- -------- INCOME BEFORE INCOME TAXES.................................. 269,756 36,141 Income tax expense (benefit)................................ 90,290 (24,001) ---------- -------- NET INCOME.................................................. $ 179,466 $ 60,142 ========== ======== EARNINGS PER AVERAGE COMMON SHARE -- DILUTED................ $ 1.07 $ 0.41 74 framework for the recovery of PG&E and SCE's uncollected expenses for purchasing power for delivery to their retail customers, is currently under consideration in the California legislature. The delayed collection of receivables owed to West Coast Power resulted in a covenant default under its credit agreement. West Coast Power is working with its lenders to secure their agreement to forebear exercising their remedies under the credit agreement. NOTE 23 -- UNAUDITED QUARTERLY FINANCIAL DATA Summarized quarterly unaudited financial data is as follows:
QUARTER ENDED 2000 ------------------------------------------------------------- MAR 31 JUNE 30 SEPT 30 DEC 31 TOTAL YEAR(1) ------ ------- ------- ------ ------------- (THOUSANDS OF DOLLARS,EXCEPT PER SHARE AMOUNTS) Revenues and equity earnings............ $323,027 $522,009 $624,798 $688,152 $2,157,986 Operating Income........................ 62,937 154,128 227,209 128,799 573,073 Net income.............................. 8,746 43,581 88,604 42,004 182,935 Earnings per share: Basic................................. $ .06 $ .28 $ .49 $ .23 $ 1.10 Diluted............................... .06 .28 .49 .23 1.10 - - --------------- (1) The sum of earnings per share for the four quarters may not equal earnings per share for the total year due to changes in the average number of common shares outstanding. 72
QUARTER ENDED 1999 ------------------------------------------------------------- MAR 31 JUNE 30 SEPT 30 DEC 31 TOTAL YEAR(1) ------ ------- ------- ------ ------------- (THOUSANDS OF DOLLARS,EXCEPT PER SHARE AMOUNTS) Revenues and equity earnings............ $ 46,514 $ 66,659 $170,408 $216,437 $ 500,018 Operating (loss) income................. (2,145) 2,956 57,948 50,761 109,520 Net (loss) income....................... (940) 2,341 27,607 28,187 57,195 Earnings per share: Basic................................. $ (.01) $ .02 $ .19 $ .19 $ .39 Diluted............................... (.01) .02 .19 .19 .39 75 NRG ENERGY, INC. SCHEDULE II. VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998 - - --------------- Note: (1) Amounts deemed to be uncollectible, Net of recoveries. 73
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E - - -------------------------------------- ------------ ------------------------ ------------- ---------- ADDITIONS ------------------------ BALANCE AT CHARGED TO CHARGED TO BALANCE AT BEGINNING OF COSTS AND OTHER END OF DESCRIPTION PERIOD EXPENSES ACCOUNTS DEDUCTIONS(1) PERIOD ----------- ------------ ---------- ---------- ------------- ---------- (IN THOUSANDS) Allowance for doubtful accounts, deducted from accounts receivable in the balance sheet: 2000................................ $186 $25,885 $(4,872) $21,199 1999................................ 100 116 (30) 186 1998................................ 100 -- -- -- 100 76 ITEM 9 -- CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES None. PART III ITEM 10 -- DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Information regarding executive officers required by this Item is set forth as Part I Item 1 Business (pursuant to Instruction 3 to Item 401(b) of Regulation S-K). Other information required by this Item will be contained in NRG Energy's definitive Proxy Statement for its 2001 Annual Meeting of Stockholders, to be filed on or before April 30, 2001, and such information is incorporated herein by reference. ITEM 11 -- EXECUTIVE COMPENSATION Information required by this Item will be contained in NRG Energy's definitive Proxy Statement for its 2001 Annual Meeting of Stockholders, to be filed on or before April 30, 2001, and such information is incorporated herein by reference. ITEM 12 -- SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Information required by this Item will be contained in NRG Energy's definitive Proxy Statement for its 2001 Annual Meeting of Stockholders, to be filed on or before April 30, 2001, and such information is incorporated herein by reference. ITEM 13 -- CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Information required by this Item will be contained in NRG Energy's definitive Proxy Statement for its 2001 Annual Meeting of Stockholders, to be filed on or before April 30, 2001, and such information is incorporated herein by reference. 74 77 PART IV ITEM 14 -- EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K PENDING COMPLETION (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 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 75
3.1 Amended and Restated Certificate of Incorporation.(9) 3.2 By-Laws.(9) 4.1 Indenture, dated as of January 31, 1996, between the Company and Norwest Bank Minnesota, National Association, As Trustee.(1) 4.2 Indenture, dated as of June 1, 1997, between the Company and Norwest Bank Minnesota, National Association.(1) 4.3 Form of Exchange Notes.(1) 4.4 Indenture between the Company and Norwest Bank Minnesota, National Association, as Trustee dated as of May 25, 1999.(4) 4.5 Indenture, dated as of November 8, 1999, between the Company and Norwest Bank Minnesota, National Association as Trustee.(7) 4.6 Indenture, dated as of February 22, 2000, between the Company, NRG Northeast Generating LLC and Chase Manhattan Bank, as Trustee.(8) 4.7 NRG Energy Pass-Through Trust 2000-1, $250,000,000 8.70% Remarketable or Redeemable Securities ("ROARS") due March 15, 2005.(8) 4.8 Trust Agreement, dated March 20, 2000, between the Company and The Bank of New York, as Trustee.(8) 4.9 Indenture, dated March 20, 2000, between the Company and The Bank of New York, as Trustee, 160,000,000 pounds sterling Reset Senior Notes due March 15, 2020.(8) 4.10 Form of Common Stock Certificate.(9) 4.11 Indenture, dated September 11, 2000, between the Company and Wells Fargo Bank Minnesota, National Association, as Trustee.(10) 4.12 Form of Supplemental Indenture to be used in connection with the issuance of Debentures.(11) 4.13 Form of Indenture.(11) 4.14 Form of Purchase Contract Agreement between the Company and the Purchase Contract Agent to be named therein.(11)78 76
4.15 Form of Corporate Unit Certificate.(11) 4.16 Form of Pledge Agreement among the Company, the Collateral Agent and the Unit Agent, each to be named therein.(11) 4.17 Form of Remarketing Agreement among the Company, the Purchase Contract Agent and the Remarketing Agent, each to be named therein.(11) 4.18 Indenture, dated March 13, 2001, between the Company and The Bank of New York, a New York banking corporation, as Trustee.(12) 4.19 First Supplement Indenture, dated March 13, 2001, between the Company and The Bank of New York, a New York banking corporation, as Trustee.(12) 10.1 Employment Contract, dated as of June 28, 1995, between the Company and David H. Peterson.(1) 10.2 Note Agreement, dated August 20, 1993, between the Company, Energy Center, Inc. and each of the purchasers named therein.(1) 10.3 Master Shelf and Revolving Credit Agreement, dated August 20, 1993, between the Company, Energy Center, Inc., The Prudential Insurance Registrants of America and each Prudential Affiliate, which becomes party thereto.(1) 10.4 Energy Agreement, dated February 12, 1988, between the Company (formerly known as Norenco Corporation) and Waldorf Corporation (the "Energy Agreement").(1) 10.5 First Amendment to the Energy Agreement, dated August 27, 1993.(1) 10.6 Second Amendment to the Energy Agreement, dated January 31, 1996.(1) 10.7 Third Amendment to the Energy Agreement, dated August 25, 1997.(1) 10.8 Construction, Acquisition and Term Loan Agreement, dated September 2, 1997, between 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.(1) 10.9 Guaranty, dated September 12, 1997, by the Company in favor of Credit Lyonnais New York Branch, as agent for the Construction/Acquisition Lenders.(1) 10.10 Construction, Acquisition and Term Loan Agreement, dated September 2, 1997, between 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.(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.(1) 10.12 Non Operating Interest Acquisition Agreement dated as of September 12, 1997, between the Company and NEO Corporation.(1) 10.13 Employment Agreements, dated April 15, 1998, between the Company and certain officers.(3) 10.14 Wholesale Standard Offer Service Agreement, dated October 13, 1998, between Blackstone Valley Electric Company, Eastern Edison Company, Newport Electric Corporation and NRG Power Marketing, Inc.(5) 10.15 Asset Sales Agreement, dated December 23, 1998, between the Company and Niagara Mohawk Power Corporation.(5) 10.16 First Amendment to Wholesale Standard Offer Service Agreement, dated January 15, 1999, between Blackstone Valley Electric Company, Eastern Edison Company, Newport Electric Corporation and NRG Power Marketing, Inc.(5) 10.17 Generating Plant and Gas Turbine Asset Purchase and Sale Agreement for the Arthur Kill generating plants and Astoria gas turbines, dated January 27, 1999, between the Company and Consolidated Edison Company of New York, Inc.(5)79 77
10.18 Transition Energy Sales Agreement, dated June 1, 1999, between Arthur Kill Power LLC and Consolidated Edison Company of New York, Inc.(5) 10.19 Transition Power Purchase Agreement, dated June 1, 1999, between Astoria Gas Turbine Power LLC and Consolidated Edison Company of New York, Inc.(5) 10.20 Transition Power Purchase Agreement, dated June 11, 1999, between Niagara Mohawk Power Corporation and Huntley Power LLC.(5) 10.21 Transition Power Purchase Agreement, dated June 11, 1999, between Niagara Mohawk Power Corporation and Dunkirk Power LLC.(5) 10.22 Power Purchase Agreement, dated June 11, 1999, between Niagara Mohawk Power Corporation and Dunkirk Power LLC.(5) 10.23 Power Purchase Agreement, dated June 11, 1999, between Niagara Mohawk Power Corporation and Huntley Power LLC.(5) 10.24 Amendment to the Asset Sales Agreement, dated June 11, 1999, between the Company and Niagara Mohawk Power Corporation.(5) 10.25 Transition Capacity Agreement, dated June 25, 1999, between Astoria Gas Turbine Power LLC and Consolidated Edison Company of New York, Inc.(5) 10.26 Transition Capacity Agreement, dated June 25, 1999, between Arthur Kill Power LLC and Consolidated Edison Company of New York, Inc.(5) 10.27 First Amendment to the Employment Agreement of David H. Peterson, dated June 27, 1999.(6) 10.28 Second Amendment to the Employment Agreement of David H. Peterson, dated August 26, 1999.(6) 10.29 Third Amendment to the Employment Agreement of David H. Peterson, dated October 20, 1999.(6) 10.30 [Swap] Master Agreement, dated June 11, 1999, between Niagara Mohawk Power Corporation and NRG Power Marketing, Inc.(6) 10.31 Standard Offer Service Wholesale Sales Agreement, dated October 29, 1999, between the Connecticut Light And Power Company and NRG Power Marketing, Inc.(6) 10.32 Amended Agreement for the Sale of Thermal Energy, dated January 1, 1983, between the Company (formerly known as Norenco Corporation) and Northern States Power and Norenco Corporation.(9) 10.33 Operations and Maintenance Agreement, dated November 1, 1996, between the Company and Northern States Power.(9) 10.34 Agreement for the Sale of Thermal Energy and Wood Byproduct, dated December 1, 1986, between Northern States Power and Norenco Corporation.(9) 10.35 Federal and State Income Tax Sharing Agreement, dated April 4, 1991, between Northern States Power Company and NRG Group, Inc.(9) 10.36 Support Agreement, dated March 27, 2000, between Northern States Power Company and CitiCorp USA Inc.(9) 10.37 Administrative Services Agreement, dated January 1, 1992, between Northern States Power Company and NRG Thermal Corporation.(9) 10.38 Form of Option Agreement with Northern States Power Company.(9) 10.39 Form of Registration Rights Agreement with Northern States Power Company.(9) 10.40 Form of Indemnification Agreement.(9) 10.41 364 Day Revolving Credit Agreement dated as of March 9, 2001, among NRG Energy, Inc., The Financial Institutions Party Hereto and ABN AMRO Bank N.V. as agent. 21 Subsidiaries of the Company.80 - - --------------- (1) Incorporated herein by reference to the Company's Registration Statement on Form S-1, as amended, Registration No. 333-33397. (2) Incorporated herein by reference to the Company's annual report on Form 10-K for the year ended December 31, 1997. (3) Incorporated herein by reference to the Company's quarterly report on Form 10-Q for the quarter ended March 31, 1998. (4) Incorporated herein by reference to the Company's current report on Form 8-K filed on May 27, 1999. (5) Incorporated herein by reference to the Company's quarterly report on Form 10-Q for the quarter ended June 30, 1999. (6) Incorporated herein by reference to the Company's quarterly report on Form 10-Q for the quarter ended September 31, 1999. (7) Incorporated herein by reference to the Company's current report on Form 8-K filed on November 16, 1999. (8) Incorporated herein by reference to the Company's annual report on Form 10-K for the year ended December 31, 1999. (9) Incorporated herein by reference to the Company's Registration Statement on Form S-1, as amended, Registration No. 333-35096. (10) Incorporated herein by reference to the Company's current report on Form 8-K filed on September 13, 2000. (11) Incorporated herein by reference to the Company's Registration Statement on Form S-3, as amended, Registration No. 333-52508. (12) Incorporated herein by reference to the Company's current report on Form 8-K filed on March 15, 2001. 78
23.1 Consent of PricewaterhouseCoopers LLP. 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."81 79
(b) Reports on Form 8-K On October 31, 2000, NRG Energy filed a Form 8-K reporting under Item 5 -- Other Events. NRG Energy reported its financial results for the quarter ended September 30, 2000 On November 22, 2000, NRG Energy filed a Form 8-K reporting under Item 5 -- Other Events. NRG Energy announced that its pending acquisition in conjunction with Dynegy Inc., of 1,330 megawatts of power generation facilities from Sierra Pacific Resources will be accretive to earnings upon closing. On December 28, 2000, NRG Energy filed a Form 8-K reporting under Item 5 -- Other Events. NRG Energy announced that it signed an asset purchase agreement to acquire the Bridgeport and New Haven Harbor Stations in Connecticut from Wisconsin Energy Corp. for $325 million, subject to normal purchase price adjustments. On February 1, 2001, NRG Energy filed a Form 8-K reporting under Item 5 -- Other Events. NRG Energy reported its financial results for the year ended December 31, 2000. On February 9, 2001, NRG Energy filed a Form 8-K reporting under Item 2 - Acquisition or Disposition of Assets. NRG Energy announced the closing of its acquisition of a 5,633 megawatt portfolio of operating projects and projects in construction and advanced development from LS Power, LLC and its partners. On March 5, 2001, NRG Energy filed a Form 8-K reporting under Item 5-Other Events. NRG Energy filed as exhibit 99.1 the audited financial statements of NRG Energy Inc. for the year ended December 31, 2000. On March 9, 2001, NRG Energy filed a Form 8-K reporting under Item 7. Exhibits. NRG Energy filed an opinion of Gibson, Dunn & Gutcher LLP regarding certain tax matters in connection with its Form S-3 Registration Statement No. 333-52508. On March 15, 2001, NRG Energy filed a Form 8-K reporting under Item 5. Other Events. NRG Energy filed certain exhibits under Item 7. Exhibits in connection with its Registration Statement No. 333-52508. 82 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. NRG ENERGY, INC. March 27, 2001 By: /s/ LEONARD A. BLUHM ------------------------------------ Leonard A. Bluhm Executive Vice President and Chief Financial Officer Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated : 80
SIGNATURE TITLE DATE --------- ----- ---- /s/ DAVID H. PETERSON Chairman of the Board, President and March 27, 2001 - - --------------------------------------------- Chief Executive Officer (Principal David H. Peterson Executive Officer) /s/ LEONARD A. BLUHM Executive Vice President and Chief March 27, 2001 - - --------------------------------------------- Financial Officer (Principal Leonard A. Bluhm Financial Officer) /s/ WILLIAM T. PIEPER Controller (Principal Accounting March 27, 2001 - - --------------------------------------------- Officer) William T. Pieper /s/ WAYNE H. BRUNETTI Director March 27, 2001 - - --------------------------------------------- Wayne H. Brunetti /s/ LUELLA G. GOLDBERG Director March 27, 2001 - - --------------------------------------------- Luella G. Goldberg /s/ PIERSON M. GRIEVE Director March 27, 2001 - - --------------------------------------------- Pierson M. Grieve /s/ WILLIAM A. HODDER Director March 27, 2001 - - --------------------------------------------- William A. Hodder /s/ JAMES J. HOWARD Director March 27, 2001 - - --------------------------------------------- James J. Howard /s/ GARY R. JOHNSON Director March 27, 2001 - - --------------------------------------------- Gary R. Johnson /s/ RICHARD C. KELLY Director March 27, 2001 - - --------------------------------------------- Richard C. Kelly /s/ EDWARD J. MCINTYRE Director March 27, 2001 - - --------------------------------------------- Edward J. McIntyre
1 Exhibit 10.41 - - ----------------------------------------------------------------------------- 364-DAY REVOLVING CREDIT AGREEMENT DATED AS OF MARCH 9, 2001 AMONG NRG ENERGY, INC. THE FINANCIAL INSTITUTIONS PARTY HERETO, AND ABN AMRO BANK N.V. AS AGENT - - ------------------------------------------------------------------------------ 2 TABLE OF CONTENTS i
SECTION 1. DEFINITIONS; INTERPRETATION............................................................1 Section 1.1 Definitions...................................................................1 Section 1.2 Interpretation...............................................................10 SECTION 2. THE REVOLVING CREDIT..................................................................10 Section 2.1 The Loan Commitment..........................................................10 Section 2.2 [Intentionally Omitted]......................................................10 Section 2.3 Applicable Interest Rates....................................................10 Section 2.4 Minimum Borrowing Amounts....................................................12 Section 2.5 Manner of Borrowing Loans and Designating Interest Rates Applicable to Loans...........................................12 Section 2.6 Interest Periods.............................................................14 Section 2.7 Maturity of Loans............................................................15 Section 2.8 Prepayments..................................................................15 Section 2.9 Default Rate.................................................................16 Section 2.10 The Notes....................................................................16 Section 2.11 Funding Indemnity............................................................16 Section 2.12 Commitment Terminations......................................................17 SECTION 3. FEES..................................................................................17 Section 3.1 Fees.........................................................................17 SECTION 4. PLACE AND APPLICATION OF PAYMENTS.....................................................18 Section 4.1 Place and Application of Payments............................................18 SECTION 5. REPRESENTATIONS AND WARRANTIES........................................................18 Section 5.1 Corporate Organization and Authority.........................................18 Section 5.2 Subsidiaries.................................................................19 Section 5.3 Corporate Authority and Validity of Obligations..............................19 Section 5.4 Financial Statements.........................................................19 Section 5.5 No Litigation; No Labor Controversies........................................19 Section 5.6 Taxes........................................................................20 Section 5.7 Approvals....................................................................20 Section 5.8 Validity of Notes............................................................20 Section 5.9 ERISA........................................................................20 Section 5.10 Government Regulation........................................................20 Section 5.11 Margin Stock; Use of Proceeds................................................21 Section 5.12 Licenses and Authorizations; Compliance Laws.................................21 Section 5.13 Ownership of Property Liens..................................................21 Section 5.14 No Burdensome Restrictions; Compliance with Agreements...................................................21 Section 5.15 Full Disclosure..............................................................21 Section 5.16 Year 2000 Problem............................................................21 SECTION 6. CONDITIONS PRECEDENT..................................................................22 Section 6.1 Initial Credit Event.........................................................22 Section 6.2 All Credit Events............................................................23 3 ii
SECTION 7. COVENANTS.............................................................................23 Section 7.1 Corporate Existence; Subsidiaries............................................23 Section 7.2 Maintenance..................................................................23 Section 7.3 Taxes........................................................................24 Section 7.4 ERISA........................................................................24 Section 7.5 Insurance....................................................................24 Section 7.6 Financial Reports and Other Information......................................24 Section 7.7 Bank Inspection Rights.......................................................26 Section 7.8 Conduct of Business..........................................................27 Section 7.9 Liens........................................................................27 Section 7.10 Use of Proceeds; Regulation U................................................27 Section 7.11 Mergers, Consolidations and Sales of Assets..................................27 Section 7.12 Consolidated Net Worth.......................................................28 Section 7.13 Indebtedness to Consolidated Capitalization..................................28 Section 7.14 Compliance with Laws.........................................................28 Section 7.15 PUHCA........................................................................29 SECTION 8. EVENTS OF DEFAULT AND REMEDIES........................................................29 Section 8.1 Events of Default............................................................29 Section 8.2 Non-Bankruptcy Defaults......................................................31 Section 8.3 Bankruptcy Defaults..........................................................31 Section 8.4 [Intentionally Omitted]......................................................31 Section 8.5 Notice of Default............................................................31 Section 8.6 Expenses.....................................................................31 SECTION 9. CHANGE IN CIRCUMSTANCES...............................................................31 Section 9.1 Change of Law................................................................31 Section 9.2 Unavailability of Deposits or Inability to Ascertain, or Inadequacy of, LIBOR......................................................32 Section 9.3 Increased Cost and Reduced Return............................................32 Section 9.4 Lending Offices..............................................................34 Section 9.5 Discretion of Bank as to Manner of Funding...................................34 SECTION 10. THE AGENT.............................................................................34 Section 10.1 Appointment and Authorization of Agent.......................................34 Section 10.2 Agent and its Affiliates.....................................................35 Section 10.3 Action by Agent..............................................................35 Section 10.4 Consultation with Experts....................................................35 Section 10.5 Liability of Agent; Credit Decision..........................................35 Section 10.6 Indemnity....................................................................36 Section 10.7 Resignation of Agent and Successor Agent.....................................36 SECTION 11. MISCELLANEOUS.........................................................................37 Section 11.1 Withholding Taxes............................................................37 Section 11.2 No Waiver of Rights..........................................................38 Section 11.3 Non-Business Day.............................................................38 Section 11.4 Documentary Taxes............................................................38 Section 11.5 Survival of Representations..................................................38 4 iii
Section 11.6 Survival of Indemnities......................................................39 Section 11.7 Set-Off......................................................................39 Section 11.8 Notices......................................................................39 Section 11.9 Counterparts.................................................................41 Section 11.10 Successors and Assigns.......................................................41 Section 11.11 Participants and Note Assignees..............................................41 Section 11.12 Assignment of Commitments by Banks...........................................42 Section 11.13 Amendments...................................................................42 Section 11.14 Headings.....................................................................43 Section 11.15 Legal Fees, Other Costs and Indemnification..................................43 Section 11.16 Entire Agreement.............................................................43 Section 11.17 Construction.................................................................43 Section 11.18 Governing Law................................................................44 Section 11.19 Submission to Jurisdiction; Waiver of Jury Trial.............................44 5 364-DAY REVOLVING CREDIT AGREEMENT 364-DAY REVOLVING CREDIT AGREEMENT, dated as of March 9, 2001 among NRG Energy, Inc., a Delaware corporation (the "Borrower"), the financial institutions from time to time party hereto (each a "Bank," and collectively the "Banks") and ABN AMRO Bank N.V. in its capacity as agent for the Banks hereunder (in such capacity, the "Agent"). WITNESSETH THAT: WHEREAS, the Borrower desires to obtain the several commitments of the Banks to make available a revolving credit for loans (the "Revolving Credit"), as described herein; and WHEREAS, the Banks are willing to extend such commitments subject to all of the terms and conditions hereof and on the basis of the representations and warranties hereinafter set forth; NOW, THEREFORE, in consideration of the recitals set forth above and for other good and valuable consideration, the receipt and adequacy of which are hereby acknowledged, the parties hereto hereby agree as follows: SECTION 1. DEFINITIONS; INTERPRETATION. Section 1.1 Definitions. The following terms when used herein have the following meanings: "Adjusted LIBOR" is defined in Section 2.3(b) hereof. "Affiliate" means, as to any Person, any other Person which directly or indirectly controls, or is under common control with, or is controlled by, such Person. As used in this definition, "control" (including, with their correlative meanings, "controlled by" and "under common control with") means possession, directly or indirectly, of power to direct or cause the direction of management or policies of a Person (whether through ownership of securities or partnership or other ownership interests, by contract or otherwise), provided that, in any event for purposes of this definition: (i) any Person which owns directly or indirectly 5% or more of the securities having ordinary voting power for the election of directors or other governing body of a corporation or 5% or more of the partnership or other ownership interests of any other Person (other than as a limited partner of such other Person) will be deemed to control such corporation or other Person; and (ii) each director and executive officer of the Borrower or any Subsidiary shall be deemed an Affiliate of the Borrower and each Subsidiary. "Agent" is defined in the first paragraph of this Agreement and includes any successor Agent pursuant to Section 10.7 hereof. "Agreement" means this 364-Day Revolving Credit Agreement, including all Exhibits and Schedules hereto, as it may be amended, supplemented or otherwise modified from time to time in accordance with the terms hereof. 6 "Applicable Margin" means, at any time (i) with respect to Base Rate Loans, the Base Rate Margin and (ii) with respect to Eurocurrency Loans, the Eurocurrency Margin. "Applicable Telerate Page" is defined in Section 2.3(b) hereof. "Authorized Representative" means those persons shown on the list of officers provided by the Borrower pursuant to Section 6.1(e) hereof, or on any updated such list provided by the Borrower to the Agent, or any further or different officer of the Borrower so named by any Authorized Representative of the Borrower in a written notice to the Agent. "Bank" is defined in the first paragraph of this Agreement. "Base Rate" is defined in Section 2.3(a) hereof. "Base Rate Loan" means a Loan bearing interest prior to maturity at a rate specified in Section 2.3(a) hereof. "Base Rate Margin" means the percentage set forth in Schedule 1 hereto beside the then applicable Rating. "Borrower" is defined in the first paragraph of this Agreement. "Borrowing" means the total of Loans of a single type advanced, continued for an additional Interest Period, or converted from a different type into such type by the Banks on a single date and for a single Interest Period. Borrowings of Loans are made and maintained ratably from each of the Banks according to their Percentages. A Borrowing is "advanced" on the day Banks advance funds comprising such Borrowing to the Borrower, is "continued" on the date a new Interest Period for the same type of Loan commences for such Borrowing, and is "converted" when such Borrowing is changed from one type of Loan to the other, all as requested by the Borrower pursuant to Section 2.5(a). "Business Day" means any day other than a Saturday or Sunday on which Banks are not authorized or required to close in Chicago, Illinois or New York, New York and, if the applicable Business Day relates to the borrowing or payment of a Eurocurrency Loan, on which dealings in U.S. Dollars may be carried on by the Agent in the interbank eurodollar market. "Capital Lease" means at any date any lease of Property which, in accordance with GAAP, would be required to be capitalized on the balance sheet of the lessee. "Capitalized Lease Obligations" means, for any Person, the amount of such Person's liabilities under Capital Leases determined at any date in accordance with GAAP. "Code" means the Internal Revenue Code of 1986, as amended. "Commitments" means the Revolving Credit Commitments. 2 7 "Compliance Certificate" means a certificate in the form of Exhibit B hereto. "Consolidated Capitalization" means Consolidated Net Worth plus Indebtedness of the Borrower. "Consolidated Current Liabilities" means such liabilities of the Borrower on a consolidated basis as shall be determined in accordance with GAAP to constitute current liabilities. "Consolidated Net Income" means, for any period, the net income (or net loss) of the Borrower for such period computed on a consolidated basis in accordance with GAAP. "Consolidated Net Tangible Assets" means, as of the date of determination thereof, Consolidated Total Assets as of such date less the sum of (i) Consolidated Current Liabilities and (ii) Intangible Assets. "Consolidated Net Worth" means, as of the date of determination thereof, the amount which would be reflected as stockholders' equity upon a consolidated balance sheet of the Borrower (determined in accordance with GAAP) prior to making any adjustment thereto (i) as a result of application of the Financial Accounting Standards Board's Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities or (ii) in connection with the account entitled "currency translation account" on such balance sheet. "Consolidated Total Assets" means, as of the date of determination thereof, the total amount of all assets of the Borrower determined on a consolidated basis in accordance with GAAP. "Contingent Performance Guarantee" means a Performance Guarantee as to which (i) the guarantor's obligation cannot be reasonably quantified, and (ii) neither the Borrower nor any Subsidiary has information which raises a reasonable possibility that a demand under such Performance Guarantee may be made prior to, or within 18 months after, the Termination Date. A Contingent Performance Guarantee which for any reason fails to meet the criteria set forth in either clause (i) or (ii) of this definition shall immediately cease to be deemed a Contingent Performance Guarantee for purposes of this Agreement. "Contractual Obligation" means, as to any Person, any provision of any security issued by such Person or of any agreement, instrument or undertaking to which such Person is a party or by which it or any of its Property is bound. "Controlled Group" means all members of a controlled group of corporations and all trades and businesses (whether or not incorporated) under common control that, together with the Borrower or any of its Subsidiaries, are treated as a single employer under Section 414 of the Code. "Credit Documents" means this Agreement, the Notes and the Fee Letter. 3 8 "Credit Event" means the advancing of any Loan or the continuation of or conversion into a Eurocurrency Loan. "Default" means any event or condition the occurrence of which would, with the passage of time or the giving of notice, or both, constitute an Event of Default. "Effective Date" means March 9, 2001. "Environmental Law" means the Comprehensive Environmental Response, Compensation and Liability Act, 42 U.S.C. Section 9601 et seq., the Resource Conservation and Recovery Act, 42 U.S.C. Section 6901 et seq., the Hazardous Materials Transportation Act, 49 U.S.C. Section 1802 et seq., the Toxic Substances Control Act, 15 S.C. Section 2601 et seq., the Federal Water Pollution Control Act, 33 U.S.C. Section 1252 et seq., the Clean Water Act, 33 U.S.C. Section 1321 et seq., the Clean Air Act, 42 U.S.C. Section 7401 et seq., and any other federal, state, county, municipal, local or other statute, law, ordinance or regulation which may relate to or deal with human health or the environment, all as may be from time to time amended. "ERISA" is defined in Section 5.9 hereof. "Eurocurrency Loan" means a Loan bearing interest prior to maturity at the rate specified in Section 2.3(b) hereof. "Eurocurrency Margin" means the percentage set forth in Schedule 1 hereto beside the then applicable Rating. "Eurocurrency Reserve Percentage" is defined in Section 2.3(b) hereof. "Event of Default" means any of the events or circumstances specified in Section 8.1 hereof. "Existing Credit Agreement" means that certain 364-Day Revolving Credit Agreement dated as of March 10, 2000 among NRG Energy, Inc., ABN AMRO Bank N.V., as administrative agent, and the banks from time-to-time party thereto, as amended or otherwise modified from time to time. "Exchange Act" means the Securities Exchange Act of 1934, as amended. "Facility Fee Rate" means the percentage set forth in Schedule 1 hereto beside the then applicable Rating. "Federal Funds Rate" means the fluctuating interest rate per annum described in part (x) of clause (ii) of the definition of Base Rate set forth in Section 2.3(a) hereof. "Fee Letter" means that certain letter between the Agent and the Borrower dated as of the date hereof pertaining to fees to be paid by the Borrower to the Agent for the Agent's sole account and benefit. 4 9 "FinCo" means NRG Finance Company I LLC, a Delaware special purpose limited liability company which is a Wholly-Owned Subsidiary of the Borrower and whose sole purpose is to facilitate the financing of a revolving working capital, acquisition and construction loan facility. "FinCo Revolving Loan Facility" means a revolving working capital, acquisition and construction loan facility (i) under which FinCo is the sole borrower, (ii) as to which FinCo's obligations are or may be Guaranteed by some or all of the Borrower's Project Finance Subsidiaries whose projects or turbines are being financed by FinCo and for which there is no other financing on a senior basis being provided by any other Person, and (iii) which is unsecured by any assets of, or stock or other equity interest of or owned by, the Borrower or its Subsidiaries, other than (x) assets and/or the stock or other equity interest of FinCo, and (y) assets and/or the stock or other equity interest of such Project Finance Subsidiaries; provided, however, that any Guaranty of the Indebtedness of FinCo or any security therefor given by or in respect of a Project Finance Subsidiary to the extent permitted hereunder may continue in existence only until the financing received by the Project Finance Subsidiary from FinCo has been repaid. "GAAP" means generally accepted accounting principles as in effect in the United States from time to time, applied by the Borrower and its Subsidiaries on a basis consistent with the preparation of the Borrower's financial statements furnished to the Banks. "Guaranty" by any Person means all obligations (other than endorsements in the ordinary course of business of negotiable instruments for deposit or collection) of such Person guaranteeing or in effect guaranteeing any Indebtedness, dividend or other obligation (including, without limitation, limited or full recourse obligations in connection with sales of receivables or any other Property and Performance Guarantees) of any other Person (the "primary obligor") in any manner, whether directly or indirectly, including, without limitation, all obligations incurred through an agreement, contingent or otherwise, by such Person: (i) to purchase such Indebtedness or obligation or any Property or assets constituting security therefor, (ii) to advance or supply funds (x) for the purchase or payment of such Indebtedness or obligation, or (y) to maintain working capital or other balance sheet condition, or otherwise to advance or make available funds for the purchase or payment of such Indebtedness or obligation, or (iii) to lease property or to purchase Securities or other property or services primarily for the purpose of assuring the owner of such Indebtedness or obligation of the ability of the primary obligor to make payment of the Indebtedness or obligation, or (iv) otherwise to assure the owner of the Indebtedness or obligation of the primary obligor against loss in respect thereof. For the purpose of all computations made under this Agreement, the amount of a Guaranty in respect of any obligation shall be deemed to be equal to the maximum aggregate amount of such obligation or, if the Guaranty is limited to less than the full amount of such obligation, the maximum aggregate potential liability under the terms of the Guaranty. Notwithstanding anything in this definition to the contrary, a Person's support of its subsidiary's obligation to (a) make equity contributions or (b) pay liquidated damages under an operating and maintenance agreement should such subsidiary fail to comply with the terms thereof shall not be considered a "Guaranty" by such Person. 5 10 "Hazardous Material" means any substance or material which is hazardous or toxic, and includes, without limitation, (a) asbestos, polychlorinated biphenyls, dioxins and petroleum or its by-products or derivatives (including crude oil or any fraction thereof) and (b) any other material or substance classified or regulated as "hazardous" or "toxic" pursuant to any Environmental Law. "Indebtedness" means and includes, for any Person, all obligations of such Person, without duplication, which are required by GAAP to be shown as liabilities on its balance sheet, and in any event shall include all of the following whether or not so shown as liabilities: (i) obligations of such Person for borrowed money, (ii) obligations of such Person representing the deferred purchase price of property or services, (iii) obligations of such Person evidenced by notes, acceptances, or other instruments of such Person or arising out of letters of credit issued for such Person's account, (iv) obligations, whether or not assumed, secured by Liens or payable out of the proceeds or production from Property now or hereafter owned or acquired by such Person, (v) Capitalized Lease Obligations of such Person and (vi) obligations for which such Person is obligated pursuant to a Guaranty, provided that Contingent Performance Guarantees of the Borrower shall not be deemed "Indebtedness" for purposes of this Agreement. All calculations of the Indebtedness of any Person (and the components thereof) shall be performed on a consolidated basis, provided, that Indebtedness shall not include obligations which are required by GAAP to be shown as liabilities on such Person's balance sheet, but which are non-recourse to such Person. "Interest Period" is defined in Section 2.6 hereof. "Intangible Assets" means, as of the date of determination thereof, all assets of the Borrower properly classified as intangible assets determined on a consolidated basis in accordance with GAAP. "Investment Grade Rating" means, with respect to any Person, that its (i) Moody's Rating is at least Baa3 and (ii) S&P Rating is at least BBB-. If either clause (i) or (ii) is not satisfied, such Person shall not be deemed to have an "Investment Grade Rating". "Lending Office" is defined in Section 9.4 hereof. "LIBOR" is defined in Section 2.3(b) hereof. "LIBOR Index Rate" is defined in Section 2.3(b) hereof. "Lien" means any interest in Property securing an obligation owed to, or a claim by, a Person other than the owner of the Property, whether such interest is based on the common law, statute or contract, including, but not limited to, the security interest lien arising from a mortgage, encumbrance, pledge, conditional sale, security agreement or trust receipt, or a lease, consignment or bailment for security purposes. The term "Lien" shall also include reservations, exceptions, encroachments, easements, rights of way, covenants, conditions, restrictions, leases and other title exceptions and encumbrances affecting Property. For the purposes of this 6 11 definition, a Person shall be deemed to be the owner of any Property which it has acquired or holds subject to a conditional sale agreement, Capital Lease or other arrangement pursuant to which title to the Property has been retained by or vested in some other Person for security purposes, and such retention of title shall constitute a "Lien." "Loan" is defined in Section 2.1(a) hereof and, as so defined, includes a Base Rate Loan or Eurocurrency Loan, each of which is a "type" of Loan hereunder. "Material Adverse Effect" means any material adverse change in, or any adverse development which materially affects or could reasonably be expected to affect, the business, financial position or results of operations of the Borrower and its Subsidiaries, taken as a whole, or the ability of the Borrower to perform its obligations under the Credit Documents. "Material Subsidiary" means a Subsidiary of the Borrower whose total assets represent at least 5% of the total assets of the Borrower and its Subsidiaries determined based upon the most recent financial statements delivered pursuant to Section 7.6 (as determined in accordance with GAAP). "Minimum Consolidated Net Worth" means an amount, as of any determination thereof, equal to the sum of $1,000,000,000 plus 25% of Consolidated Net Income for the period from and including January 1, 2001 to such determination date but which amount shall in no event be less than $1,000,000,000. "Moody's Rating" means the rating assigned by Moody's Investors Service, Inc. and any successor thereto that is a nationally recognized rating agency to the outstanding senior unsecured non-credit enhanced long-term debt obligations of a Person (or if neither Moody's Investors Service, Inc. nor any such successor shall be in the business of rating long-term indebtedness, a nationally recognized rating agency in the U.S. as mutually agreed between the Required Banks and Holdings). Any reference in this Agreement to any specific rating is a reference to such rating as currently defined by Moody's Investors Service, Inc. (or such a successor) and shall be deemed to refer to the equivalent rating if such rating system changes. "Non-Conforming Period" is defined in Section 7.13 hereof. "Note" is defined in Section 2.10(a) hereof. "Obligations" means all fees payable hereunder, all obligations of the Borrower to pay principal or interest on Loans and all other payment obligations of the Borrower arising under or in relation to any Credit Document. "Percentage" means, for each Bank, the percentage of the Revolving Credit Commitments represented by such Bank's Revolving Credit Commitment or, if the Revolving Credit Commitments have been terminated, the percentage held by such Bank of the aggregate principal amount of all outstanding Obligations. 7 12 "Performance Guarantee" means a guarantee issued by the Borrower or a Subsidiary that the Borrower or such Subsidiary will cause some action (other than the payment of money) to be performed, whether by performing the action itself or paying others to perform such action. "Person" means an individual, partnership, corporation, association, trust, unincorporated organization or any other entity or organization, including a government or any agency or political subdivision thereof. "Plan" means at any time an employee pension benefit plan covered by Title IV of ERISA or subject to the minimum funding standards under Section 412 of the Code that is either (i) maintained by a member of the Controlled Group or (ii) maintained pursuant to a collective bargaining agreement or any other arrangement under which more than one employer makes contributions and to which a member of the Controlled Group is then making or accruing an obligation to make contributions or has within the preceding five plan years made contributions. "PBGC" is defined in Section 5.9 hereof. "Project Finance Subsidiary" means any special purpose Subsidiary of the Borrower formed solely to facilitate the financing of the assets of such Subsidiary, and as to which the recourse of any creditors of such Subsidiary is limited solely to such assets and the stock or other equity interest of such Subsidiary. "Property" means any interest in any kind of property or asset, whether real, personal or mixed, or tangible or intangible, whether now owned or hereafter acquired. "Rating" means the rating given to senior unsecured non-credit enhanced debt obligations of the Borrower by Moody's Investors Service, Inc. and Standard & Poor's Ratings Services, a division of The McGraw-Hill Companies, Inc. and any successors thereto. "Reference Banks" means ABN AMRO Bank N.V., and one other representative of the Banks. In the event that any of such Banks ceases to be a "Bank" hereunder or fails to provide timely quotations of interest rates to the Agent as and when required by this Agreement, then such Bank shall be replaced by a new reference bank jointly designated by the Agent and the Borrower. "Replaceable Bank" is defined in Section 11.13(iii). "Replacement Bank" is defined in Section 11.13(iii). "Required Banks" means, as of the date of determination thereof, Banks holding at least 66 2/3% of the Percentages. "Revolving Credit Commitment" is defined in Section 2.1 hereof. "SEC" means the Securities and Exchange Commission. 8 13 "Security" has the same meaning as in Section 2(l) of the Securities Act of 1933, as amended. "S&P Rating" means the rating assigned by Standard & Poor's Ratings Group, a division of The McGraw-Hill Companies, Inc. and any successor thereto that is a nationally recognized rating agency to the outstanding senior unsecured non-credit enhanced long-term debt obligations of a Person (or, if neither such division nor any successor shall be in the business of rating long-term indebtedness, a nationally recognized rating agency in the U.S. as mutually agreed between the Required Banks and Holdings). Any reference in this Agreement to any specific rating is a reference to such rating as currently defined by Standard & Poor's Ratings Group, a division of The McGraw-Hill Companies, Inc. (or such a successor) and shall be deemed to refer to the equivalent rating if such rating system changes. "Subsidiary" means, as to the Borrower, any active, domestic corporation or other entity of which one hundred percent (100%) of the outstanding stock or comparable equity interests having ordinary voting power for the election of the Board of Directors of such corporation or similar governing body in the case of a non corporation (irrespective of whether or not, at the time, stock or other equity interest of any other class or classes of such corporation or other entity shall have or might have voting power by reason of the happening of any contingency) is at the time directly owned by the Borrower. "Telerate Service" means the Dow Jones Telerate Service. "Termination Date" means March 8, 2002. "Unfunded Vested Liabilities" means, with respect to any Plan at any time, the amount (if any) by which (i) the present value of all vested nonforfeitable accrued benefits under such Plan exceeds (ii) the fair market value of all Plan assets allocable to such benefits, all determined as of the then most recent valuation date for such Plan, but only to the extent that such excess represents a potential liability of a member of the Controlled Group to the PBGC or the Plan under Title IV of ERISA. "Utilization" means the percentage obtained by dividing the aggregate outstanding principal amount of Loans on any date (after giving effect to any Borrowings and repayments occurring on such date) by the Commitments in effect on such date (after giving effect to any reductions thereof on such date). "U.S. Dollars" and "$" each means the lawful currency of the United States of America. "Voting Stock" of any Person means capital stock of any class or classes or other equity interests (however designated) having ordinary voting power for the election of directors or similar governing body of such Person. "Welfare Plan" means a "welfare plan," as defined in Section 3(1) of ERISA. 9 14 "Wholly-Owned" when used in connection with any Subsidiary of the Borrower means a Subsidiary of which all of the issued and outstanding shares of stock or other equity interests (other than directors' qualifying shares as required by law) shall be owned by the Borrower and/or one or more of its Wholly-Owned Subsidiaries. Section 1.2 Interpretation. The foregoing definitions shall be equally applicable to both the singular and plural forms of the terms defined. All references to times of day in this Agreement shall be references to Chicago, Illinois time unless otherwise specifically provided. Where the character or amount of any asset or liability or item of income or expense is required to be determined or any consolidation or other accounting computation is required to be made for the purposes of this Agreement, the same shall be done in accordance with GAAP, to the extent applicable, except where such principles are inconsistent with the specific provisions of this Agreement. SECTION 2. THE REVOLVING CREDIT. Section 2.1 The Loan Commitment. General Terms. Subject to the terms and conditions hereof, each Bank severally and not jointly agrees to make a loan or loans (individually a "Loan" and collectively "Loans") to the Borrower from time to time on a revolving basis in U.S. Dollars up to the amount of its revolving credit commitment set forth on the applicable signature page hereof (such amount, as reduced pursuant to Section 2.12 or changed as a result of one or more assignments under Section 11.12 or 11.13(iii), its "Revolving Credit Commitment" and, cumulatively for all the Banks, the "Revolving Credit Commitments") before the Termination Date. The aggregate amount of Loans at any time outstanding shall not exceed the Revolving Credit Commitments in effect at such time. Each Borrowing of Loans shall be made ratably from the Banks in proportion to their respective Percentages. As provided in Section 2.5(a) hereof, the Borrower may elect that each Borrowing of Loans be either Base Rate Loans or Eurocurrency Loans. Loans may be repaid and the principal amount thereof reborrowed before the Termination Date, subject to all the terms and conditions hereof. The initial amount of Revolving Credit Commitments under this Agreement equals $500,000,000. Section 2.2 [Intentionally Omitted]. Section 2.3 Applicable Interest Rates. (a) Base Rate Loans. Each Base Rate Loan made or maintained by a Bank shall bear interest during each Interest Period it is outstanding computed on the basis of a year of 365 or 366 days, as applicable, and actual days elapsed on the unpaid principal amount thereof from the date such Loan is advanced, continued or created by conversion from a Eurocurrency Loan until maturity (whether by acceleration or otherwise) at a rate per annum equal to the sum of the Applicable Margin plus the Base Rate from time to time in effect, payable on the last day of its Interest Period and at maturity (whether by acceleration or otherwise). "Base Rate" means for any day the greater of: 10 15 (i) the rate of interest announced by the Agent at its offices in Chicago, Illinois, from time to time as its prime rate, or equivalent, for U.S. Dollar loans as in effect on such day, with any change in the Base Rate resulting from a change in said prime rate to be effective as of the date of the relevant change in said prime rate; and (ii) the sum of (x) the rate determined by the Agent to be the prevailing rate per annum (rounded upwards, if necessary, to the nearest one hundred-thousandth of a percentage point) at approximately 10:00 a.m. (New York time) (or as soon thereafter as is practicable) on such day (or, if such day is not a Business Day, on the immediately preceding Business Day) for the purchase at face value of overnight Federal funds, as published by the Federal Reserve bank of New York, in an amount comparable to the principal amount owed to the Agent for which such rate is being determined, plus (y) 1/2 of 1% (0.50%). (b) Eurocurrency Loans. Each Eurocurrency Loan made or maintained by a Bank shall bear interest during each Interest Period it is outstanding (computed on the basis of a year of 360 days and actual days elapsed) on the unpaid principal amount thereof from the date such Loan is advanced, continued, or created by conversion from a Base Rate Loan until maturity (whether by acceleration or otherwise) at a rate per annum equal to the sum of the Applicable Margin plus the Adjusted LIBOR applicable for such Interest Period, payable on the last day of the Interest Period and at maturity (whether by acceleration or otherwise), and, if the applicable Interest Period is longer than three months, on each day occurring every three months after the commencement of such Interest Period. All payments of principal and interest on a Loan (whether a Base Rate Loan or Eurocurrency Loan) shall be made in U.S. Dollars. "Adjusted LIBOR" means, for any Borrowing of Eurocurrency Loans, a rate per annum determined in accordance with the following formula: Adjusted LIBOR = LIBOR ------------------------------------ 1 - Eurocurrency Reserve Percentage "LIBOR" means, for an Interest Period, (a) the LIBOR Index Rate for such Interest Period as from time to time quoted by the Telerate Service, if such rate is available, and (b) if the LIBOR Index Rate is not quoted by the Telerate Service, the arithmetic average of the rates of interest per annum (rounded upwards, if necessary, to the nearest one-sixteenth of one percent) at which deposits in U.S. Dollars in immediately available funds are offered to each Reference Bank at 11:00 a.m. (London, England time) two (2) Business Days before the beginning of such Interest Period by major banks in the interbank eurocurrency market for delivery on the first day of and for a period equal to such Interest Period in an amount equal or comparable to the principal amount of the Eurocurrency Loan scheduled to be made by the Agent as part of such Borrowing. 11 16 "LIBOR Index Rate" means, for any Interest Period, the rate per annum (rounded upwards, if necessary, to the next higher one-sixteenth of one percent) for deposits in U.S. Dollars for delivery on the first day of and for a period equal to such Interest Period in an amount equal or comparable to the principal amount of the Loan scheduled to be made by the Agent as part of such Borrowing, which appears on the Applicable Telerate Page, as of 11:00 a.m. (London, England time) on the day two (2) Business Days before the commencement of such Interest Period. "Applicable Telerate Page" means the display page designated as "Page 3750" on the Telerate Service (or such other page as may replace such pages, as appropriate, on that service or such other service as may be nominated by the British Bankers' Association as the information vendor for the purpose of displaying British Bankers' Association Interest Settlement Rates for deposits in U.S. Dollars). "Eurocurrency Reserve Percentage" means the daily average for the applicable Interest Period of the maximum rate, expressed as a decimal, at which reserves (including, without limitation, any supplemental, marginal and emergency reserves) are imposed during such Interest Period by the Board of Governors of the Federal Reserve System (or any successor) on "eurocurrency liabilities," as defined in such Board's Regulation D (or in respect of any other category of liabilities that includes deposits by reference to which the interest rate is determined or any category of extensions of credit or other assets that include loans by non-United States offices of any Bank to United States residents), subject to any amendments of such reserve requirement by such Board or its successor, taking into account any transitional adjustments thereto. For purposes of this definition, the Eurocurrency Loans shall be deemed to be "eurocurrency liabilities" as defined in Regulation D without benefit or credit for any prorations, exemptions or offsets under Regulation D. (c) Rate Determinations. The Agent shall determine each interest rate applicable to Obligations, and a determination thereof by the Agent shall be conclusive and binding except in the case of manifest error. Section 2.4 Minimum Borrowing Amounts. Each Borrowing of Base Rate Loans and Eurocurrency Loans denominated in U.S. Dollars shall be in an amount not less than $1,000,000 and in integral multiples of $1,000,000. Section 2.5 Manner of Borrowing Loans and Designating Interest Rates Applicable to Loans. (a) Notice to the Agent. The Borrower shall give written notice to the Agent by no later than 10:00 a.m. (Chicago time) (i) at least three (3) Business Days before the date on which the Borrower requests the Banks to advance a Borrowing of Eurocurrency Loans and (ii) on the date the Borrower requests the Banks to advance a Borrowing of Base Rate Loans. The Loans included in each Borrowing shall bear interest initially at the type of rate specified in such notice of a new Borrowing. Thereafter, the Borrower may 12 17 from time to time elect to change or continue the type of interest rate borne by each Borrowing or, subject to Section 2.4's minimum amount requirement for each outstanding Borrowing, a portion thereof, as follows: (i) if such Borrowing is of Eurocurrency Loans, on the last day of the Interest Period applicable thereto, the Borrower may continue part or all of such Borrowing as Eurocurrency Loans for an Interest Period or Interest Periods specified by the Borrower or convert part or all of such Borrowing into Base Rate Loans, (ii) if such Borrowing is of Base Rate Loans, on any Business Day, the Borrower may convert all or part of such Borrowing into Eurocurrency Loans for an Interest Period or Interest Periods specified by the Borrower. The Borrower shall give all such notices requesting the advance, continuation, or conversion of a Borrowing to the Agent by telephone or telecopy (which notice shall be irrevocable once given and, if by telephone, shall be promptly confirmed in writing). Notices of the continuation of a Borrowing of Eurocurrency Loans for an additional Interest Period or of the conversion of part or all of a Borrowing of Eurocurrency Loans into Base Rate Loans or of Base Rate Loans into Eurocurrency Loans must be given by no later than 10:00 a.m. (Chicago time) at least three (3) Business Days before the date of the requested continuation or conversion. All such notices concerning the advance, continuation, or conversion of a Borrowing shall specify the date of the requested advance, continuation or conversion of a Borrowing (which shall be a Business Day), the amount of the requested Borrowing to be advanced, continued, or converted, the type of Loans to comprise such new, continued or converted Borrowing and, if such Borrowing is to be comprised of Eurocurrency Loans, the Interest Period applicable thereto. The Borrower agrees that the Agent may rely on any such telephonic or telecopy notice given by any person it in good faith believes is an Authorized Representative without the necessity of independent investigation, and in the event any such notice by telephone conflicts with any written confirmation, such telephonic notice shall govern if the Agent has acted in reliance thereon. There may be no more than five different Interest Periods in effect at any one time. (b) Notice to the Banks. The Agent shall give prompt telephonic or telecopy notice to each Bank of any notice from the Borrower received pursuant to Section 2.5(a) above. The Agent shall give notice to the Borrower and each Bank by like means of the interest rate applicable to each Borrowing of Eurocurrency Loans and the amount thereof. (c) Borrower's Failure to Notify. Any outstanding Borrowing of Base Rate Loans shall, subject to Section 6.2 hereof, automatically be continued for an additional Interest Period on the last day of its then current Interest Period unless the Borrower has notified the Agent within the period required by Section 2.5(a) that it intends to convert such Borrowing into a Borrowing of Eurocurrency Loans or notifies the Agent within the period required by Section 2.8(a) that it intends to prepay such Borrowing. If the Borrower fails to give notice pursuant to Section 2.5(a) above of the continuation or conversion of any outstanding principal amount of a Borrowing of Eurocurrency Loans before the last day of its then current Interest Period within the period required by Section 2.5(a) and has not notified the Agent within the period required by Section 2.8(a) that it 13 18 intends to prepay such Borrowing, such Borrowing shall automatically be converted into a Borrowing of Base Rate Loans, subject to Section 6.2 hereof. (d) Disbursement of Loans. Not later than 11:00 a.m. (Chicago time) on the date of any requested advance of a new Borrowing of Eurocurrency Loans, and not later than 12:00 noon (Chicago time) on the date of any requested advance of a new Borrowing of Base Rate Loans, subject to Section 6 hereof, each Bank shall make available its Loan comprising part of such Borrowing in funds immediately available at the principal office of the Agent in Chicago, Illinois. The Agent shall make available to the Borrower Loans at the Agent's principal office in Chicago, Illinois or such other office as the Agent has previously agreed to, in writing, with the Borrower. (e) Agent Reliance on Bank Funding. Unless the Agent shall have been notified by a Bank before the date on which such Bank is scheduled to make payment to the Agent of the proceeds of a Loan (which notice shall be effective upon receipt) that such Bank does not intend to make such payment, the Agent may assume that such Bank has made such payment when due and the Agent may in reliance upon such assumption (but shall not be required to) make available to the Borrower the proceeds of the Loan to be made by such Bank and, if any Bank has not in fact made such payment to the Agent, such Bank shall, on demand, pay to the Agent the amount made available to the Borrower attributable to such Bank together with interest thereon in respect of each day during the period commencing on the date such amount was made available to the Borrower and ending on (but excluding) the date such Bank pays such amount to the Agent at a rate per annum equal to the Federal Funds Rate. If such amount is not received from such Bank by the Agent immediately upon demand, the Borrower will, on demand, repay to the Agent the proceeds of the Loan attributable to such Bank with interest thereon at a rate per annum equal to the interest rate applicable to the relevant Loan. Section 2.6 Interest Periods. As provided in Section 2.5(a) hereof, at the time of each request to advance, continue, or create by conversion a Borrowing of Eurocurrency Loans, the Borrower shall select an Interest Period applicable to such Loans from among the available options. The term "Interest Period" means the period commencing on the date a Borrowing of Loans is advanced, continued, or created by conversion and ending: (a) in the case of Base Rate Loans, on the last Business Day of the calendar quarter in which such Borrowing is advanced, continued, or created by conversion (or on the last day of the following calendar quarter if such Loan is advanced, continued or created by conversion on the last Business Day of a calendar quarter), and (b) in the case of Eurocurrency Loans, 1, 2, 3, or 6 months thereafter; provided, however, that: (a) any Interest Period for a Borrowing of Base Rate Loans that otherwise would end after the Termination Date shall end on the Termination Date; (b) for any Borrowing of Eurocurrency Loans, the Borrower may not select an Interest Period that extends beyond the Termination Date; 14 19 (c) whenever the last day of any Interest Period would otherwise be a day that is not a Business Day, the last day of such Interest Period shall be extended to the next succeeding Business Day, provided that, if such extension would cause the last day of an Interest Period for a Borrowing of Eurocurrency Loans to occur in the following calendar month, the last day of such Interest Period shall be the immediately preceding Business Day; and (d) for purposes of determining an Interest Period for a Borrowing of Eurocurrency Loans, a month means a period starting on one day in a calendar month and ending on the numerically corresponding day in the next calendar month; provided, however, that if there is no numerically corresponding day in the month in which such an Interest Period is to end or if such an Interest Period begins on the last Business Day of a calendar month, then such Interest Period shall end on the last Business Day of the calendar month in which such Interest Period is to end. Section 2.7 Maturity of Loans. Unless an earlier maturity is provided for hereunder (whether by acceleration or otherwise), each Loan shall mature and become due and payable by the Borrower on the Termination Date. Section 2.8 Prepayments. (a) The Borrower may prepay without premium or penalty and in whole or in part (but, if in part, then: (i) if such Borrowing is of Base Rate Loans, in an amount not less than $1,000,000, (ii) if such Borrowing is of Eurocurrency Loans in an amount not less than $1,000,000, and (iii) in an amount such that the minimum amount required for a Borrowing pursuant to Section 2.4 hereof remains outstanding) any Borrowing of Eurocurrency Loans upon three Business Days prior notice to the Agent or, in the case of a Borrowing of Base Rate Loans, notice delivered to the Agent no later than 10:00 a.m. (Chicago time) on the date of prepayment, such prepayment to be made by the payment of the principal amount to be prepaid and accrued interest thereon to the date fixed for prepayment. In the case of Eurocurrency Loans, such prepayment may only be made on the last day of the Interest Period then applicable to such Loans. The Agent will promptly advise each Bank of any such prepayment notice it receives from the Borrower. Any amount paid or prepaid before the Termination Date may, subject to the terms and conditions of this Agreement, be borrowed, repaid and borrowed again. (b) If the aggregate principal amount of outstanding Loans shall at any time for any reason exceed the Revolving Credit Commitments then in effect, the Borrower shall, immediately and without notice or demand, pay the amount of such excess to the Agent for the ratable benefit of the Banks as a prepayment of the Loans. Immediately upon determining the need to make any such prepayment the Borrower shall notify the Agent of such required prepayment. (c) Each such prepayment shall be accompanied by a payment of all accrued and unpaid interest on the Loans prepaid and shall be subject to Section 2.11. 15 20 Section 2.9 Default Rate. If any payment of any Obligation is not made when due (whether by acceleration or otherwise), such Obligation shall bear interest, computed on the basis of a year of 360 days and actual days elapsed (except for Base Rate Loans bearing interest based on the rate described in clause (i) of the definition of Base Rate, in which case such Loan shall bear interest computed on the basis of a year of 365 or 366 days, as applicable, and the actual number of days elapsed) from the date such payment was due until paid in full, payable on demand, at a rate per annum equal to: (a) for any Obligation other than a Eurocurrency Loan, the sum of two percent (2%) plus the Base Rate Margin plus the Base Rate from time to time in effect; and (b) for any Eurocurrency Loan, the sum of two percent (2%) plus the rate of interest in effect thereon at the time of such default until the end of the Interest Period applicable thereto and, thereafter, at a rate per annum equal to the sum of two percent (2%) plus the Base Rate Margin plus the Base Rate from time to time in effect. Section 2.10 The Notes. (a) The Loans made to the Borrower by a Bank shall be evidenced by a single promissory note of the Borrower issued to such Bank in the form of Exhibit A hereto. Each such promissory note is hereinafter referred to as a "Note" and collectively such promissory notes are referred to as the "Notes." (b) Each Bank shall record on its books and records or on a schedule to its Note the amount of each Loan advanced, continued, or converted by it, all payments of principal and interest and the principal balance from time to time outstanding thereon, the type of such Loan, and, for any Eurocurrency Loan, the Interest Period and the interest rate applicable thereto. The record thereof, whether shown on such books and records of a Bank or on a schedule to any Note, shall be prima facie evidence as to all such matters; provided, however, that the failure of any Bank to record any of the foregoing or any error in any such record shall not limit or otherwise affect the obligation of the Borrower to repay all Loans made to it hereunder together with accrued interest thereon. At the request of any Bank and upon such Bank tendering to the Borrower the Note to be replaced, the Borrower shall furnish a new Note to such Bank to replace any outstanding Note, and at such time the first notation appearing on a schedule on the reverse side of, or attached to, such Note shall set forth the aggregate unpaid principal amount of all Loans, if any, then outstanding thereon. Section 2.11 Funding Indemnity. If any Bank shall incur any loss, cost or expense (including, without limitation, any loss of profit, and any loss, cost or expense incurred by reason of the liquidation or re-employment of deposits or other funds acquired by such Bank to fund or maintain any Eurocurrency Loan or the relending or reinvesting of such deposits or amounts paid or prepaid to such Bank) as a result of: 16 21 (a) any payment (whether by acceleration or otherwise), prepayment or conversion of a Eurocurrency Loan on a date other than the last day of its Interest Period, (b) any failure (because of a failure to meet the conditions of Section 6 or otherwise) by the Borrower to borrow or continue a Eurocurrency Loan, or to convert a Base Rate Loan into a Eurocurrency Loan, on the date specified in a notice given pursuant to Section 2.5(a) or established pursuant to Section 2.5(c) hereof, (c) any failure by the Borrower to make any payment of principal on any Eurocurrency Loan (x) when due (whether by acceleration or otherwise), or (y) on the date specified in a notice of prepayment, or (d) any acceleration of the maturity of a Eurocurrency Loan as a result of the occurrence of any Event of Default hereunder, then, upon the demand of such Bank, the Borrower shall pay to such Bank such amount as will reimburse such Bank for such loss, cost or expense. If any Bank makes such a claim for compensation, it shall provide to the Borrower, with a copy to the Agent, a certificate executed by an officer of such Bank setting forth the amount of such loss, cost or expense in reasonable detail (including an explanation of the basis for and the computation of such loss, cost or expense) and the amounts shown on such certificate if reasonably calculated shall be conclusive absent manifest error. Section 2.12 Commitment Terminations. The Borrower shall have the right at any time and from time to time, upon five (5) Business Days prior written notice to the Agent, to terminate the Revolving Credit Commitments without premium or penalty, in whole or in part, any partial termination to be (i) in an amount not less than $5,000,000, and (ii) allocated ratably among the Banks in proportion to their respective Percentages, provided that the Revolving Credit Commitments may not be reduced to an amount less than the amount of all Loans then outstanding. The Agent shall give prompt notice to each Bank of any such termination of Commitments. Any termination of Revolving Credit Commitments pursuant to this Section 2.12 may not be reinstated. SECTION 3. FEES. Section 3.1 Fees. (a) Certain Fees. The Borrower shall pay, or cause to be paid, to the Agent certain fees set forth in the Fee Letter at the time specified in the Fee Letter for payment of such amounts. (b) Facility Fee. For the period from the Effective Date to and including the Termination Date, the Borrower shall pay to the Agent for the ratable account of the Banks in accordance with their Percentages a facility fee accruing at a rate per annum equal to the Facility Fee Rate on the average daily amount of the Commitments (whether 17 22 used or unused), or if the Commitments have expired or terminated, on the principal amount of Loans. Such facility fee is payable in arrears on the last Business Day of each calendar quarter and on the Termination Date, unless the Revolving Credit Commitments are terminated in whole on an earlier date, in which event the fee for the period to but not including the date of such termination shall be paid in whole on the date of such termination. (c) Closing Fees. On the Effective Date the Borrower shall pay to the Agent for the account of each Bank a closing fee of 0.05% on the amount of such Bank's Revolving Credit Commitment in effect on the Effective Date. (d) Fee Calculations. All fees payable under this Agreement shall be payable in U.S. Dollars and shall be computed on the basis of a year of 360 days, for the actual number of days elapsed. All determinations of the amount of fees owing hereunder (and the components thereof) shall be made by the Agent and shall be conclusive absent manifest error. SECTION 4. PLACE AND APPLICATION OF PAYMENTS. Section 4.1 Place and Application of Payments. All payments of principal of and interest on the Loans, and of all other amounts payable by the Borrower under this Agreement, shall be made by the Borrower to the Agent by no later than 12:00 Noon (Chicago time) on the due date thereof at the principal office of the Agent in Chicago, Illinois (or such other location in the United States as the Agent may designate to the Borrower). Any payments received after such time shall be deemed to have been received by the Agent on the next Business Day. All such payments shall be made free and clear of, and without deduction for, any set-off, counterclaim, levy, withholding or any other deduction of any kind in U.S. Dollars, in immediately available funds at the place of payment. The Agent will promptly thereafter cause to be distributed like funds relating to the payment of principal or interest on Loans or applicable fees ratably to the Banks and like funds relating to the payment of any other amount payable to any Person to such Person, in each case to be applied in accordance with the terms of this Agreement. SECTION 5. REPRESENTATIONS AND WARRANTIES. The Borrower hereby represents and warrants to each Bank as to itself and, where the following representations and warranties apply to Subsidiaries, as to each of its Subsidiaries, as follows: Section 5.1 Corporate Organization and Authority. The Borrower and each of its Subsidiaries is duly organized, validly existing and in good standing under the laws of its jurisdiction of organization, except where such failure to be in good standing would not, individually or in the aggregate, have a Material Adverse Effect. Each is duly qualified to transact business in each jurisdiction in which such qualification is required, whether by reason of ownership or leasing of property or the conduct of business or otherwise, except where failure 18 23 to be so qualified would not, individually or in the aggregate, have a Material Adverse Effect. Each has the power and authority required to own, lease and operate its properties and to conduct its business as currently conducted, except where failure to have such power and authority would not, individually or in the aggregate, have a Material Adverse Effect. Section 5.2 Subsidiaries. Schedule 5.2 (as updated quarterly pursuant to Section 7.6(b) hereof or otherwise from time to time in writing by the Borrower) hereto identifies each Subsidiary and the jurisdiction of its incorporation. All of the issued and outstanding shares of capital stock of each Subsidiary are validly issued and outstanding and fully paid and nonassessable except as set forth on Schedule 5.2 hereto. All such shares owned by the Borrower are owned beneficially, and of record, and, except in the case of (i) Liens granted in connection with the FinCo Revolving Loan Facility, and (ii) any Project Finance Subsidiary, free of any Lien. Section 5.3 Corporate Authority and Validity of Obligations. The Borrower has full right and authority to enter into this Agreement and the other Credit Documents to which it is a party, to make the borrowings herein provided for, to issue its Notes in evidence thereof, and to perform all of its obligations under the Credit Documents to which it is a party. Each Credit Document to which it is a party has been duly authorized, executed and delivered by the Borrower and constitutes valid and binding obligations of the Borrower enforceable in accordance with its terms. No Credit Document, nor the performance or observance by the Borrower of any of the matters or things therein provided for, contravenes any provision of law or any charter or by-law provision of the Borrower or any material Contractual Obligation of or affecting the Borrower or any of its Properties or results in or requires the creation or imposition of any Lien on any of the Properties or revenues of the Borrower. Section 5.4 Financial Statements. All financial statements heretofore delivered to the Banks showing historical performance of the Borrower for each of the Borrower's fiscal years ending on or before December 31, 1999, and for the Borrower's quarter ended September 30, 2000 have been prepared in accordance with generally accepted accounting principles applied on a basis consistent, except as otherwise noted therein, with that of the previous fiscal year. Each of such financial statements fairly presents on a consolidated basis the financial condition of the Borrower as of the dates thereof and the results of operations for the periods covered thereby. The Borrower and its Subsidiaries have no material contingent liabilities other than those disclosed in such financial statements referred to in this Section 5.4 or in comments or footnotes thereto, or in any report supplementary thereto, heretofore furnished to the Banks. Since December 31, 1999, there has been no material adverse change in the business, operations, Property or financial or other condition, or business prospects, of the Borrower or any of its Subsidiaries. Section 5.5 No Litigation; No Labor Controversies. (a) Except as set forth on Schedule 5.5 (as updated quarterly pursuant to Section 7.6(b) hereof or otherwise from time to time in writing by the Borrower), there is no litigation or governmental proceeding pending, or to the knowledge of the Borrower, 19 24 threatened, against the Borrower or any Subsidiary which, if adversely determined, could (individually or in the aggregate) have a Material Adverse Effect. (b) Except as set forth on Schedule 5.5 (as updated quarterly pursuant to Section 7.6(b) hereof or otherwise from time to time in writing by the Borrower), there are no labor controversies pending or, to the best knowledge of the Borrower, threatened against the Borrower or any Subsidiary which could have a Material Adverse Effect. Section 5.6 Taxes. The Borrower and its Subsidiaries have filed all United States federal tax returns, and all other tax returns, required to be filed and have paid all taxes due pursuant to such returns or pursuant to any assessment received by the Borrower or any Subsidiary, except such taxes, if any, as are being contested in good faith and for which adequate reserves have been provided. No notices of tax liens have been filed and no claims are being asserted concerning any such taxes, which liens or claims are material to the financial condition of the Borrower or any of its Subsidiaries (individually or in the aggregate). The charges, accruals and reserves on the books of the Borrower and its Subsidiaries for any taxes or other governmental charges are adequate. Section 5.7 Approvals. Except as contemplated by Section 7.14, no authorization, consent, license, exemption, filing or registration with any court or governmental department, agency or instrumentality, nor any approval or consent of the stockholders of the Borrower or any Subsidiary or from any other Person, is necessary to the valid execution, delivery or performance by the Borrower or any Subsidiary of any Credit Document to which it is a party. Section 5.8 Validity of Notes. When executed, authenticated and delivered pursuant to the provisions of this Agreement against payment of the consideration therefor, the Notes will be duly issued and will constitute legal, valid and binding obligations of the Borrower, enforceable in accordance with their terms, except for the effect of bankruptcy, insolvency, reorganization, moratorium and other similar laws relating to or affecting the rights of creditors generally, and will rank pari passu with all other outstanding unsecured indebtedness of the Borrower. Section 5.9 ERISA. With respect to each Plan, the Borrower and each other member of the Controlled Group has fulfilled its obligations under the minimum funding standards of and is in compliance in all material respects with the Employee Retirement Income Security Act of 1974, as amended ("ERISA"), and with the Code to the extent applicable to it and has not incurred any liability to the Pension Benefit Guaranty Corporation ("PBGC") or a Plan under Title IV of ERISA other than a liability to the PBGC for premiums under Section 4007 of ERISA. The Borrower does not have any contingent liabilities for any post-retirement benefits under a Welfare Plan, other than liability for continuation coverage described in Part 6 of Title I of ERISA. Section 5.10 Government Regulation. Neither the Borrower nor any Subsidiary is an "investment company" within the meaning of the Investment Company Act of 1940, as amended. 20 25 Section 5.11 Margin Stock; Use of Proceeds. Neither the Borrower nor any Subsidiary is engaged principally, or as one of its primary activities, in the business of extending credit for the purpose of purchasing or carrying margin stock ("margin stock" to have the same meaning herein as in Regulation U of the Board of Governors of the Federal Reserve System). The proceeds of the Loans are to be used solely for the purposes set forth in and permitted by Section 7.10. The Borrower will not use the proceeds of any Loan in a manner that violates any provision of Regulation U or X of the Board of Governors of the Federal Reserve System. Section 5.12 Licenses and Authorizations; Compliance Laws. The Borrower and each of its Subsidiaries has all necessary licenses, permits and governmental authorizations to own and operate its Properties and to carry on its business as currently conducted and contemplated. The Borrower and each of its Subsidiaries is in compliance with all applicable laws, regulations, ordinances and orders of any governmental or judicial authorities except for any such law, regulation, ordinance or order which, the failure to comply therewith, could not reasonably be expected to have a Material Adverse Effect. Section 5.13 Ownership of Property Liens. The Borrower and each Subsidiary has good title to or valid leasehold interests in all its Property. None of the Borrower's Property is subject to any Lien, except as permitted in Section 7.9. Section 5.14 No Burdensome Restrictions; Compliance with Agreements. Neither the Borrower nor any Subsidiary is (a) party or subject to any law, regulation, rule or order, or any Contractual Obligation that (individually or in the aggregate) could have a Material Adverse Effect or (b) in default in the performance, observance or fulfillment of any of the obligations, covenants or conditions contained in, nor has any event occurred (and is continuing) that constitutes or would (whether or not with the giving of notice and/or with the passage of time and/or the fulfillment of any other requirement) constitute, to the knowledge of the Borrower, a default or any breach or failure to perform by the Borrower under any indenture, mortgage, loan agreement, lease or other agreement or instrument to which it is a party, which default could have a Material Adverse Effect. Section 5.15 Full Disclosure. All information heretofore furnished by the Borrower to the Agent or any Bank for purposes of or in connection with the Credit Documents or any transaction contemplated thereby is, and all such information hereafter furnished by the Borrower to the Agent or any Bank will be, true and accurate in all material respects and not misleading on the date as of which such information is stated or certified. Section 5.16 Year 2000 Problem. On the basis of a comprehensive review and assessment of the Borrower's and its Subsidiaries' systems and equipment and inquiry made of the Borrower's and its Subsidiaries' material suppliers, vendors and customers, and based on its operations since January 1, 2000, the Borrower has no reason to believe that the Year 2000 Problem, including costs of remediation, has resulted or will result in a Material Adverse Effect. As used herein, "Year 2000 Problem" means any significant risk that computer hardware, software or equipment containing embedded microchips essential to the businesses or operations of the Borrower and its Subsidiaries will not, in the case of dates or time periods occurring after 21 26 December 31, 1999, function at least as effectively as in the case of dates or time periods occurring prior to January 1, 2000. SECTION 6. CONDITIONS PRECEDENT. The obligation of each Bank to advance, continue, or convert any Loan shall be subject to the following conditions precedent: Section 6.1 Initial Credit Event. Before or concurrently with the initial Credit Event: (a) The Agent shall have received for each Bank (i) the favorable written opinion of counsel to the Borrower in form and substance satisfactory to the Agent and its counsel, and (ii) the closing fee referred to in Section 3.1(c) hereof; (b) The Agent shall have received for each Bank copies of (i) the Articles of Incorporation, together with all amendments, and a certificate of good standing, for the Borrower, both certified as of a date not earlier than 20 days prior to the date hereof by the appropriate governmental officer of the Borrower's jurisdiction of incorporation and (ii) the Borrower's bylaws (or comparable constituent documents) and any amendments thereto, certified in each instance by its Secretary or an Assistant Secretary; (c) The Agent shall have received for each Bank copies of resolutions of the Borrower's Board of Directors authorizing the execution and delivery of the Credit Documents and the consummation of the transactions contemplated thereby together with specimen signatures of the persons authorized to execute such documents on the Borrower's behalf, all certified in each instance by its Secretary or Assistant Secretary; (d) The Agent shall have received for each Bank such Bank's duly executed Note of the Borrower dated the date hereof and otherwise in compliance with the provisions of Section 2.10(a) hereof; (e) The Agent shall have received for each Bank a list of the Borrower's Authorized Representatives and such other documents as any Bank may reasonably request; (f) All legal matters incident to the execution and delivery of the Credit Documents shall be satisfactory to the Banks; (g) The Existing Credit Agreement shall have terminated and the Borrower shall have no further obligations thereunder (except obligations which by their terms survive the termination of the Existing Credit Agreement). (h) The Agent shall have received a certificate by the chief financial officer, treasurer, vice president of finance or corporate controller of the Borrower, stating that on the date of such initial Credit Event no Default or Event of Default has occurred and is continuing. 22 27 Section 6.2 All Credit Events. As of the time of each Credit Event hereunder (including the initial Credit Event): (a) The Agent shall have received the notice required by Section 2.5 hereof; (b) Each of the representations and warranties set forth in Section 5 hereof shall be and remain true and correct in all material respects as of said time, taking into account any amendments to such Section (including, without limitation, any amendments to the Schedules referenced therein) made after the date of this Agreement in accordance with its provisions, except that if any such representation or warranty relates solely to an earlier date it need only remain true as of such date, provided that solely for purposes of this Section 6.2(b) the representations relating to the Borrower's Subsidiaries set forth in Section 5.2 hereof shall be deemed representations relating only to the Borrower's Material Subsidiaries; (c) The Borrower shall be in full compliance with all of the terms and conditions hereof, and no Default or Event of Default shall have occurred and be continuing or would occur as a result of such Credit Event; (d) No event of default by the Borrower has been declared and is continuing under any existing debt agreements; and (e) Such Credit Event shall not violate any order, judgment or decree of any court or other authority or any provision of law or regulation applicable to any Bank (including, without limitation, Regulation U of the Board of Governors of the Federal Reserve System). Each request for a Borrowing hereunder shall be deemed to be a representation and warranty by the Borrower on the date of such Credit Event as to the facts specified in paragraphs (b) and (c) of this Section 6.2, provided, that solely in the case of a Credit Event which is a continuation of a previous Borrowing, the Borrower shall not be deemed to have made any representation or warranty with regard to the matters set forth in Section 5.5(a) and (b) hereof. SECTION 7. COVENANTS. The Borrower covenants and agrees that, so long as any Loan is outstanding hereunder, or any Commitment is available to or in use by the Borrower hereunder, except to the extent compliance in any case is waived in writing by the Required Banks: Section 7.1 Corporate Existence; Subsidiaries. The Borrower shall, and shall cause each of its Subsidiaries to, preserve and maintain its corporate existence, subject to the provisions of Section 7.11 hereof. Section 7.2 Maintenance. The Borrower will maintain, preserve and keep its plants, Properties and equipment necessary to the proper conduct of its business in reasonably good repair, working order and condition and will from time to time make all reasonably necessary 23 28 repairs, renewals, replacements, additions and betterments thereto so that at all times such plants, Properties and equipment shall be reasonably preserved and maintained, and the Borrower will cause each of its Subsidiaries to do so in respect of Property owned or used by it; provided, however, that nothing in this Section 7.2 shall prevent the Borrower or a Subsidiary from discontinuing the operation or maintenance of any such Properties if such discontinuance is not disadvantageous to the Banks or the holders of the Notes, and is, in the judgment of the Borrower, desirable in the conduct of its business or the business of its Subsidiary. Section 7.3 Taxes. The Borrower will duly pay and discharge, and will cause each of its Subsidiaries duly to pay and discharge, all taxes, rates, assessments, fees and governmental charges upon or against it or against its Properties, in each case before the same becomes delinquent and before penalties accrue thereon, unless and to the extent that the same is being contested in good faith by appropriate proceedings and reserves in conformity with GAAP have been provided therefor on the books of the Borrower. Section 7.4 ERISA. The Borrower will promptly pay and discharge all obligations and liabilities arising under ERISA of a character which if unpaid or unperformed might result in the imposition of a Lien against any of its properties or assets and will promptly notify the Agent of (i) the occurrence of any reportable event (as defined in ERISA) affecting a Plan, other than any such event of which the PBGC has waived notice by regulation, (ii) receipt of any notice from PBGC of its intention to seek termination of any Plan or appointment of a trustee therefor, (iii) its intention to terminate or withdraw from any Plan, and (iv) the occurrence of any event affecting any Plan which could result in the incurrence by the Borrower of any material liability, fine or penalty, or any material increase in the contingent liability of the Borrower under any post-retirement Welfare Plan benefit. The Agent will promptly distribute to each Bank any notice it receives from the Borrower pursuant to this Section 7.4. Section 7.5 Insurance. The Borrower will insure, and keep insured, and will cause each of its Subsidiaries to insure, and keep insured, with good and responsible insurance companies, all insurable Property owned by it of a character usually insured by companies similarly situated and operating like Property. To the extent usually insured (subject to self-insured retentions) by companies similarly situated and conducting similar businesses, the Borrower will also insure, and cause each of its Subsidiaries to insure, employers' and public and product liability risks with good and responsible insurance companies. The Borrower will upon request of the Agent furnish to the Agent a summary setting forth the nature and extent of the insurance maintained pursuant to this Section 7.5. Section 7.6 Financial Reports and Other Information. (a) The Borrower will maintain a system of accounting in accordance with GAAP and will furnish to the Banks and their respective duly authorized representatives such information respecting the business and financial condition of the Borrower and its subsidiaries as any Bank may reasonably request; and without any request, the Borrower will furnish each of the following to each Bank: 24 29 (i) within 120 days after the end of each fiscal year of the Borrower, (A) a copy of the Borrower's audited financial statements for such fiscal year, including the consolidated balance sheet of the Borrower for such year and the related statement of income and statement of cash flow, as certified by independent public accountants of recognized national standing selected by the Borrower in accordance with GAAP with such accountants unqualified opinion to the effect that the financial statements have been prepared in accordance with GAAP and present fairly in all material respects in accordance with GAAP the consolidated financial position of the Borrower and its subsidiaries as of the close of such fiscal year and the results of their operations and cash flows for the fiscal year then ended and that an examination of such accounts in connection with such financial statements has been made in accordance with generally accepted auditing standards and accordingly, such examination included such tests of the accounting records and such other auditing procedures as were considered necessary in the circumstances; (B) a copy of the Borrower's unaudited consolidating financials for such fiscal year, including a consolidating unaudited balance sheet of the Borrower, and the related statement of income and shall use its best efforts to provide a statement of cash flow in a format acceptable to the Agent; all of the foregoing prepared by the Borrower in reasonable detail in accordance with GAAP and certified by the Borrower's chief financial officer, treasurer, vice president of finance or corporate controller as fairly presenting the financial condition as at the dates thereof and the results of operations for the periods covered thereby; (ii) within 60 days after the end of each of the first three quarterly fiscal periods of the Borrower, a condensed consolidated unaudited balance sheet of the Borrower, and the related statement of income and statement of cash flow, as of the close of such period, all of the foregoing prepared by the Borrower in reasonable detail in accordance with GAAP and certified by the Borrower's chief financial officer, treasurer, vice president of finance or corporate controller as fairly presenting the financial condition as at the dates thereof and the results of operations for the periods covered thereby (subject to year end adjustments): (iii) within the period provided in subsection (i) above, the written statement of the accountants who certified the audit report thereby required that in the course of their audit they have obtained no knowledge of any Default or Event of Default, or, if such accountants have obtained knowledge of any such Default or Event of Default, they shall disclose in such statement the nature and period of the existence thereof; (iv) promptly after the sending or filing thereof, copies of all proxy statements, financial statements and reports the Borrower sends to its shareholders, and copies of all other regular, periodic and special reports and all registration statements the Borrower files with the SEC or any successor thereto, or with any national securities exchanges. 25 30 (b) Each financial statement furnished to the Banks pursuant to subsection (i) or (ii) of Section 7.6(a) shall be accompanied by (A) a written certificate signed by the Borrower's chief financial officer, vice president of finance, corporate controller or treasurer (i) to the effect that no Default or Event of Default has occurred during the period covered by such statements or, if any such Default or Event of Default has occurred during such period, setting forth a description of such Default or Event of Default and specifying the action, if any, taken by the Borrower to remedy the same, (ii) to the effect that the representations and warranties contained in Section 5 hereof are true and correct in all material respects as though made on the date of such certificate (other than those made solely as of an earlier date, which need only remain true as of such date), taking into account any amendments to such Section (including, without limitation, any amendments to the Schedules referenced therein) made after the date of this Agreement in accordance with its provisions and except as otherwise described therein, (iii) notifying the Banks (x) of any litigation or governmental proceeding of the type described in Section 5.5 hereof or (y) of any change in the information set forth on the Schedules hereto and (B) a Compliance Certificate in the form of Exhibit B hereto showing the Borrower's compliance with the covenants set forth in Sections 7.9, 7.11, 7.12 and 7.13 hereof. (c) The Borrower will (i) promptly (and in any event within three Business Days after an officer of the Borrower has knowledge thereof) give notice to the Agent and each Bank (x) of the occurrence of any Default or Event of Default or (y) of any payment default or payment event of default aggregating $50,000,000 or more under any Contractual Obligation of the Borrower and (ii) promptly (and in any event within ten Business Days after an officer of the Borrower has knowledge thereof) give notice to the Agent and each Bank of any material adverse change in the business, operations, Property or financial or other condition of the Borrower and its Subsidiaries (individually or in the aggregate). Section 7.7 Bank Inspection Rights. Upon reasonable notice from any Bank, the Borrower will, at the Borrower's expense (such expenses to be reasonably incurred), permit such Bank (and such Persons as any Bank may designate) during normal business hours to visit and inspect, under the Borrower's guidance, any of the properties of the Borrower or any of its Subsidiaries, to examine all of their books of account, records, reports and other papers, to make copies and extracts therefrom, and to discuss their respective affairs, finances and accounts with their respective officers, employees and with their independent public accountants (and by this provision the Borrower authorizes such accountants to discuss with the Banks (and such Persons as any Bank may designate subject to confidentiality agreements reasonably acceptable to the Borrower) the finances and affairs of the Borrower and its Subsidiaries) all at such reasonable times and as often as may be reasonably requested; provided, however, that except upon the occurrence and during the continuation of any Default or Event of Default, not more than one such set of visits and inspections may be conducted each calendar quarter. 26 31 Section 7.8 Conduct of Business. The Borrower will not engage in any line of business other than business associated with or related to energy generation, transmission, marketing and distribution or other infrastructure lines of business. Section 7.9 Liens. The Borrower shall cause the Obligations to at all times rank at least pari passu with all other senior unsecured obligations of the Borrower. The Borrower will not create, incur, permit to exist or to be incurred any Lien of any kind on any Property owned by the Borrower; provided, however, that this Section 7.9 shall not apply to nor operate to prevent: (a) Liens upon any Property acquired by the Borrower to secure any Indebtedness (which for purposes of this Section 7.9(a) shall include non-recourse obligations) of the Borrower incurred to finance or refinance the purchase price of such Property (including Property which was initially purchased with equity), provided that any such Lien shall apply only to the Property that was so acquired and the aggregate principal amount of Indebtedness secured by such Liens shall not exceed the cost or value of the acquired Property; (b) Other Liens not to exceed 10% of Consolidated Net Tangible Assets; (c) Liens on the stock or other equity interests (i) granted in connection with the FinCo Revolving Loan Facility and (ii) of Project Finance Subsidiaries; and (d) Any extension, renewal or replacement (or successive extensions, renewals or replacements) in whole or in part of any Lien referred to in the foregoing paragraphs (a) through (c), inclusive. Section 7.10 Use of Proceeds; Regulation U. The proceeds of each Borrowing will be used by the Borrower to repay indebtedness outstanding under the Existing Credit Agreement, and for working capital and general corporate purposes. The Borrower will not use any part of the proceeds of any of the Borrowings directly or indirectly to purchase or carry any margin stock (as defined in Section 5.11 hereof) or to extend credit to others for the purpose of purchasing or carrying any such margin stock. Section 7.11 Mergers, Consolidations and Sales of Assets. (a) The Borrower will not consolidate with or merge into any other Person or sell, convey, transfer or lease its properties and assets substantially as an entirety to any Person, and the Borrower shall not permit any Person to consolidate with or merge into the Borrower, unless: (i) immediately prior to and immediately following such consolidation, merger, sale or lease, and after giving effect thereto, no Default or Event of Default shall have occurred and be continuing; and (ii) the Borrower is the surviving or continuing corporation, or the surviving or continuing corporation that acquires by sale, conveyance, transfer or lease (a) has a Rating equal to or better than the Rating of the Borrower in effect prior to such consolidation or merger and (y) is incorporated in the 27 32 United States and expressly assumes the payment and performance of all Obligations of the Borrower under the Credit Documents pursuant to documentation in form and substance satisfactory to the Required Banks. (b) Except for the sale of the properties and assets of the Borrower substantially as an entirety pursuant to subsection (a) above, and other than assets required to be sold to conform with governmental regulations, the Borrower shall not sell or otherwise dispose of any assets (other than short-term, readily marketable investments purchased for cash management purposes with funds not representing the proceeds of other asset sales) if on a pro forma basis, the aggregate net book value of all such sales during the most recent 12-month period would exceed ten percent (10%) of Consolidated Net Tangible Assets computed as of the end of the most recent fiscal quarter preceding such sale; provided, however, that any such sales -------- ------- shall be disregarded for purposes of this ten percent (10%) limitation if the proceeds are invested in assets in similar or related lines of business of the Borrower and, provided further, that the Borrower may sell or otherwise dispose of assets in excess of such ten percent (10%) if the proceeds from such sales or dispositions, which are not reinvested as provided above, are retained by the Borrower as cash or cash equivalents at all times until invested in assets in similar or related lines of business of the Borrower. Section 7.12 Consolidated Net Worth. The Borrower will at all times cause its Consolidated Net Worth to be equal to or greater than the Minimum Consolidated Net Worth. Section 7.13 Indebtedness to Consolidated Capitalization. The Borrower will at the end of each of its fiscal quarters maintain a ratio of its Indebtedness to Consolidated Capitalization of not more than 0.68 to 1.00, provided that for not more than two consecutive months in any six month period (any such two month period being referred to herein as a "Non-Conforming Period"), the ratio of the Borrower's Indebtedness to Consolidated Capitalization may increase to not more than 0.72 to 1.00 so long as the Borrower delivers to the Agent within 30 days after the end of any such Non-Conforming Period written affirmation from Moody's Investors Service, Inc. and Standard and Poor's Ratings Service, Inc. that the respective Ratings which were in effect prior to such Non-Conforming Period remains in effect and that the Borrower has not been placed in any "credit-watch with negative implications" or similar type of category. For purposes of this covenant, only fifty percent (50%) of any Indebtedness of the Borrower constituting Performance Guarantees of obligations of the Borrower's Affiliates shall be deemed Indebtedness, provided that if any demand has been made on such guarantee, the full amount of such guarantee shall be included in calculating Indebtedness. Section 7.14 Compliance with Laws. Without limiting any of the other covenants of the Borrower in this Section 7, the Borrower will conduct its business, and otherwise be, in compliance with all applicable laws, regulations, ordinances, writs, judgments, injunctions, decrees, awards and orders of any governmental or judicial authorities; provided, however, that the Borrower shall not be required to comply with any such law, rule, regulation, ordinance, writ, judgments, injunction, decree, award or order if the failure to comply therewith could not reasonably be expected to have a Material Adverse Effect. 28 33 Section 7.15 PUHCA. The Borrower has obtained, and will maintain in full force and effect, all necessary approvals, if any, under the Public Utility Holding Company Act of 1935, as amended, in connection with the Borrower's performance under the Credit Documents. SECTION 8. EVENTS OF DEFAULT AND REMEDIES. Section 8.1 Events of Default. Any one or more of the following shall constitute an Event of Default: (a) The Borrower shall (i) fail to make when due any payment of principal on the Notes, or (ii) fail to make when due, and continuance of such failure for three or more Business Days, payment of interest on the Notes or any fee or other amount required to be made to the Agent pursuant to the Credit Documents; (b) Any representation or warranty made or deemed to have been made by or on behalf of the Borrower in the Credit Documents or on behalf of the Borrower in any certificate, statement, report or other writing furnished by or on behalf of the Borrower to the Agent pursuant to the Credit Documents or any other instrument, document or agreement shall prove to have been false or misleading in any material respect on the date as of which the facts set forth are stated or certified or deemed to have been stated or certified; (c) The Borrower shall fail to comply with Section 7 hereof and such failure to comply shall continue for 30 calendar days after the earlier to occur of (i) notice thereof to the Borrower by the Agent and (ii) first actual knowledge thereof by an officer of the Borrower; (d) The Borrower shall fail to comply with any agreement, covenant, condition, provision or term contained in the Credit Documents (and such failure shall not constitute an Event of Default under any of the other provisions of this Section 8) and such failure to comply shall continue for 30 calendar days after the earlier to occur of (i) notice thereof to the Borrower by the Agent and (ii) first actual knowledge thereof by an officer of the Borrower; (e) The Borrower shall become insolvent or shall generally not pay its debts as they mature or shall apply for, shall consent to, or shall acquiesce in the appointment of a custodian, trustee or receiver of the Borrower or for a substantial part of the property thereof or, in the absence of such application, consent or acquiescence, a custodian, trustee or receiver shall be appointed for the Borrower or for a substantial part of the property thereof and shall not be discharged within 90 days; (f) Any bankruptcy, reorganization, debt arrangement or other proceedings under any bankruptcy or insolvency law shall be instituted by or against the Borrower, and, if instituted against the Borrower, shall have 29 34 been consented to or acquiesced in by the Borrower, or shall remain undismissed for 90 days, or an order for relief shall have been entered against the Borrower, or the Borrower shall take any corporate action to approve institution of, or acquiescence in, such a proceeding; (g) Any dissolution or liquidation proceeding shall be instituted by or against the Borrower and, if instituted against the Borrower, shall be consented to or acquiesced in by the Borrower or shall remain for 90 days undismissed, or the Borrower shall take any corporate action to approve institution of, or acquiescence in, such a proceeding; (h) A judgment or judgments, decrees or orders of any court, tribunal, arbitrator, administrative or other governmental body or entity for the payment of money in excess of the sum of $50,000,000 in the aggregate shall be rendered against the Borrower (excluding the amount thereof covered by insurance) or any of the Borrower's properties and such judgment, decree or order shall remain unvacated and undischarged and unstayed for 90 consecutive days, except while being contested in good faith by appropriate proceedings; (i) The institution by the Borrower of steps to terminate any Plan if in order to effectuate such termination, the Borrower would be required to make a contribution to such Plan, or would incur a liability or obligation to such Plan, in excess of $50,000,000, or the institution by the PBGC of steps to terminate any Plan; (j) Either (A) a default shall occur under that certain Credit Agreement dated as of November 30, 1999 among NRG Energy, Inc., the banks party thereto and Australia and New Zealand Banking Group Limited, as Administrative Agent, as such agreement may from time to time be restated, amended or otherwise modified or any substitute or replacement credit agreement with respect thereto (the "LC Agreement"), and as a result of such default is (x) the termination of the commitments under the LC Agreement, (y) the Borrower is required to provide cash collateral pursuant to the LC Agreement, or (z) the bank and/or the agent under the LC Agreement exercise any right or remedy thereunder, or (B) (i) a default in payment of any principal of or any interest aggregating $50,000,000 or more on any bond, debenture, note or other evidence of indebtedness of the Borrower or under any indenture or other instrument under which any such evidence of indebtedness has been issued or (ii) a default shall occur under any bond, debenture, note or other evidence of indebtedness of the Borrower or under any indenture or other instrument under which any such evidence of indebtedness has been issued and such default shall continue for a period of time sufficient to permit the holder or beneficiary of such indebtedness or a trustee therefor to cause the acceleration of the maturity of any such indebtedness of principal of or any interest aggregating $50,000,000 or more or any mandatory unscheduled prepayment, purchase or funding thereof; or (k) if at any time both (i) Xcel Energy Inc., a Minnesota corporation, or its successors, ceases to own a majority of the outstanding Voting Stock of the Borrower and (ii) the Borrower does not have an Investment Grade Rating. 30 35 Section 8.2 Non-Bankruptcy Defaults. When any Event of Default other than those described in subsections (e), (f) or (g) of Section 8.1 hereof has occurred and is continuing, the Agent shall, by written notice to the Borrower: (a) if so directed by the Required Banks, terminate the remaining Commitments and all other obligations of the Banks hereunder on the date stated in such notice (which may be the date thereof); and (b) if so directed by the Required Banks, declare the principal of and the accrued interest on all outstanding Notes to be forthwith due and payable and thereupon all outstanding Notes, including both principal and interest thereon, shall be and become immediately due and payable together with all other amounts payable under the Credit Documents without further demand, presentment, protest or notice of any kind. The Agent, after giving notice to the Borrower pursuant to Section 8.1(c), 8.1(d) or this Section 8.2, shall also promptly send a copy of such notice to the other Banks, but the failure to do so shall not impair or annul the effect of such notice. Section 8.3 Bankruptcy Defaults. When any Event of Default described in subsections (e), (f) or (g) of Section 8.1 hereof has occurred and is continuing, then all outstanding Notes shall immediately and automatically become due and payable together with all other amounts payable under the Credit Documents without presentment, demand, protest or notice of any kind and the obligation of the Banks to extend further credit pursuant to any of the terms hereof shall immediately and automatically terminate. Section 8.4 [Intentionally Omitted] Section 8.5 Notice of Default. The Agent shall give notice to the Borrower under Section 8.1(c) or 8.1(d) hereof promptly upon being requested to do so by any Bank and shall thereupon notify all the Banks thereof. Section 8.6 Expenses. The Borrower agrees to pay to the Agent and each Bank, and any other holder of any Note outstanding hereunder, all reasonable costs and expenses incurred or paid by the Agent or such Bank or any such holder, including attorneys' fees and court costs, in connection with any Default or Event of Default by the Borrower hereunder or in connection with the enforcement of any of the Credit Documents. SECTION 9. CHANGE IN CIRCUMSTANCES. Section 9.1 Change of Law. Notwithstanding any other provisions of this Agreement or any Note if at any time after the date hereof any change in applicable law or regulation or in the interpretation thereof makes it unlawful for any Bank to make or continue to maintain Eurocurrency Loans or to perform its obligations as contemplated hereby, such Bank shall promptly give notice thereof to the Borrower and such Bank's obligations to make or maintain Eurocurrency Loans under this Agreement shall terminate until it is no longer unlawful for such Bank to make or maintain Eurocurrency Loans. The Borrower shall prepay on demand the outstanding principal amount of any such affected Eurocurrency Loans, together with all interest accrued thereon at a rate per annum equal to the interest rate applicable to such Loan; provided, however, subject to all of the terms and conditions of this Agreement, the Borrower may then elect to borrow the principal amount of the affected Eurocurrency Loans from such Bank by 31 36 means of Base Rate Loans from such Bank, which Base Rate Loans shall not be made ratably by the Banks but only from such affected Bank. Section 9.2 Unavailability of Deposits or Inability to Ascertain, or Inadequacy of, LIBOR. If on or prior to the first day of any Interest Period for any Borrowing of Loans: (a) the Agent determines that deposits in U.S. Dollars (in the applicable amounts) are not being offered to it in the federal funds or eurocurrency interbank market, as applicable, for such Interest Period, or that by reason of circumstances affecting the federal funds or interbank eurocurrency market, as applicable, adequate and reasonable means do not exist for ascertaining the applicable Federal Funds Rate or LIBOR; or (b) Banks having 25% or more of the aggregate amount of the Revolving Credit Commitments reasonably determine and so advise the Agent that the Federal Funds Rate or LIBOR, as applicable, as reasonably determined by the Agent will not adequately and fairly reflect the cost to such Banks or Bank of funding their or its Loans or Loan for such Interest Period; then the Agent shall forthwith give notice thereof to the Borrower and the Banks, whereupon until the Agent notifies the Borrower that the circumstances giving rise to such suspension no longer exist, the obligations of the Banks or of the relevant Bank to make Base Rate Loans bearing interest at the Federal Funds Rate or Eurocurrency Loans in the currency so affected, as applicable, shall be suspended. Section 9.3 Increased Cost and Reduced Return. (a) If, on or after the date hereof, the adoption of any applicable law, rule or regulation, or any change therein, or any change in the interpretation or administration thereof by any governmental authority, central bank or comparable agency charged with the interpretation or administration thereof, or compliance by any Bank (or its Lending Office) with any request or directive (whether or not having the force of law but, if not having the force of law, compliance with which is customary in the relevant jurisdiction) of any such authority, central bank or comparable agency: (i) shall subject any Bank (or its Lending Office) to any tax, duty or other charge with respect to its Eurocurrency Loans, its Notes, or its obligation to make Eurocurrency Loans, or shall change the basis of taxation of payments to any Bank (or its Lending Office) of the principal of or interest on its Eurocurrency Loans, or any other amounts due under this Agreement in respect of its Eurocurrency Loans or its obligation to make Eurocurrency Loans (except for changes in the rate of tax on the overall net income or profits of such Bank or its Lending Office imposed by the jurisdiction in which such Bank or its lending office is incorporated in which such Bank's principal executive office or Lending Office is located); or 32 37 (ii) shall impose, modify or deem applicable any reserve, special deposit or similar requirement (including, without limitation, any such requirement imposed by the Board of Governors of the Federal Reserve System, but excluding with respect to any Eurocurrency Loans any such requirement included in an applicable Eurocurrency Reserve Percentage) against assets of, deposits with or for the account of, or credit extended by, any Bank (or its Lending Office) or shall impose on any Bank (or its Lending Office) or on the interbank market any other condition affecting its Eurocurrency Loans, its Notes, or its obligation to make Eurocurrency Loans; and the result of any of the foregoing is to increase the cost to such Bank (or its Lending Office) of making or maintaining any Eurocurrency Loan, or to reduce the amount of any sum received or receivable by such Bank (or its Lending Office) under this Agreement or under its Notes with respect thereto, by an amount deemed by such Bank to be material, then, within fifteen (15) days after demand by such Bank (with a copy to the Agent), the Borrower shall be obligated to pay to such Bank such additional amount or amounts as will compensate such Bank for such increased cost or reduction. In the event any law, rule, regulation or interpretation described above is revoked, declared invalid or inapplicable or is otherwise rescinded, and as a result thereof a Bank is determined to be entitled to a refund from the applicable authority for any amount or amounts which were paid or reimbursed by Borrower to such Bank hereunder, such Bank shall, so long as no Event of Default has occurred and is then continuing, refund such amount or amounts to Borrower without interest. (b) If, after the date hereof, any Bank or the Agent shall have determined that the adoption of any applicable law, rule or regulation regarding capital adequacy, or any change therein (including, without limitation, any revision in the Final Risk-Based Capital Guidelines of the Board of Governors of the Federal Reserve System (12 CFR Part 208, Appendix A; 12 CFR Part 225, Appendix A) or of the Office of the Comptroller of the Currency (12 CFR Part 3, Appendix A), or in any other applicable capital rules heretofore adopted and issued by any governmental authority), or any change in the interpretation or administration thereof by any governmental authority, central bank or comparable agency charged with the interpretation or administration thereof, or compliance by any Bank (or its Lending Office) with any request or directive regarding capital adequacy (whether or not having the force of law but, if not having the force of law, compliance with which is customary in the applicable jurisdiction) of any such authority, central bank or comparable agency, has or would have the effect of reducing the rate of return on such Bank's capital, or on the capital of any corporation controlling such Bank, as a consequence of its obligations hereunder to a level below that which such Bank could have achieved but for such adoption, change or compliance (taking into consideration such Bank's policies with respect to capital adequacy) by an amount deemed by such Bank to be material, then from time to time, within fifteen (15) days after demand by such Bank (with a copy to the Agent), the Borrower shall pay to such Bank such additional amount or amounts as will compensate such Bank for such reduction. 33 38 (c) Each Bank that determines to seek compensation under this Section 9.3 shall notify the Borrower and the Agent of the circumstances that entitle the Bank to such compensation pursuant to this Section 9.3 and will designate a different Lending Office if such designation will avoid the need for, or reduce the amount of, such compensation and will not, in the sole judgment of such Bank, be otherwise disadvantageous to such Bank. A certificate of any Bank claiming compensation under this Section 9.3 and setting forth the additional amount or amounts to be paid to it hereunder shall be conclusive in the absence of manifest error. In determining such amount, such Bank may use any reasonable averaging and attribution methods. (d) If any Bank (other than ABN AMRO Bank N.V.) has demanded compensation or given notice of its intention to demand compensation under this Section 9.3 or the Borrower is required to pay any additional amount to any Bank under Section 9.3, the Borrower shall have the right, with the assistance of the Agent, to seek a substitute Bank or Banks reasonably satisfactory to the Agent (which may be one or more of the Banks) to replace such Bank under this Agreement and on the date of replacement, the Borrower shall pay all accrued interest and fees to the Bank being replaced. The Bank to be so replaced shall cooperate with the Borrower and substitute Bank to accomplish such substitution, provided that all of such Bank's Loan Commitment is replaced. Section 9.4 Lending Offices. Each Bank may, at its option, elect to make its Loans hereunder at the branch, office or affiliate specified on the appropriate signature page hereof or in the assignment agreement which any assignee bank executes pursuant to Section 11.12 hereof (each a "Lending Office") for each type of Loan available hereunder or at such other of its branches, offices or affiliates as it may from time to time elect and designate in a written notice to the Borrower and the Agent. Section 9.5 Discretion of Bank as to Manner of Funding. Notwithstanding any other provision of this Agreement, each Bank shall be entitled to fund and maintain its funding of all or any part of its Loans in any manner it sees fit, it being understood, however, that for the purposes of this Agreement all determinations hereunder shall be made as if each Bank had actually funded and maintained each Eurocurrency Loan through the purchase of deposits of U.S. Dollars in the eurocurrency interbank market having a maturity corresponding to such Loan's Interest Period and bearing an interest rate equal to LIBOR for such Interest Period. SECTION 10. THE AGENT. Section 10.1 Appointment and Authorization of Agent. Each Bank hereby appoints ABN AMRO Bank N.V. as the Agent under the Credit Documents and hereby authorizes the agent to take such action as Agent on its behalf and to exercise such powers under the Credit Documents as are delegated to the Agent by the terms thereof, together with such powers as are reasonably incidental thereto. The Agent shall have no duties or responsibilities except those expressly set forth in this 34 39 Agreement and the Credit Documents. The duties of the Agent shall be mechanical and administrative in nature; the Agent shall not have by reason of this Agreement or any other Credit Document a fiduciary relationship in respect of any Bank, the holder of any Note or any other Person; and nothing in this Agreement or any other Credit Document, expressed or implied, is intended to or shall be so construed as to impose upon the Agent any obligations in respect of this Agreement or any other Credit Document except as expressly set forth herein or therein. Section 10.2 Agent and its Affiliates. The Agent shall have the same rights and powers under this Agreement and the other Credit Documents as any other Bank and may exercise or refrain from exercising the same as though it were not the Agent, and the Agent and its affiliates may accept deposits from, lend money to, and generally engage in any kind of business with the Borrower or any Affiliate of the Borrower as if it were not the Agent under the Credit Documents. The term "Bank" as used herein and in all other Credit Documents, unless the context otherwise clearly requires, includes the Agent in its individual capacity as a Bank. References in Section 2 hereof to the Agent's Loans, or to the amount owing to the Agent for which an interest rate is being determined, refer to the Agent in its individual capacity as a Bank. Section 10.3 Action by Agent. If the Agent receives from the Borrower a written notice of an Event of Default pursuant to Section 7.6(c)(i) hereof, the Agent shall promptly give each of the Banks written notice thereof. The obligations of the Agent under the Credit Documents are only those expressly set forth therein. Without limiting the generality of the foregoing, the Agent shall not be required to take any action hereunder with respect to any Default or Event of Default, except as expressly provided in Sections 8.2 and 8.5. In no event, however, shall the Agent be required to take any action in violation of applicable law or of any provision of any Credit Document, and the Agent shall in all cases be fully justified in failing or refusing to act hereunder or under any other Credit Document unless it shall be first indemnified to its reasonable satisfaction by the Banks against any and all costs, expense, and liability which may be incurred by it by reason of taking or continuing to take any such action. The Agent shall be entitled to assume that no Default or Event of Default exists unless notified to the contrary by a Bank or the Borrower. In all cases in which this Agreement and the other Credit Documents do not require the Agent to take certain actions, the Agent shall be fully justified in using its discretion in failing to take or in taking any action hereunder and thereunder. Section 10.4 Consultation with Experts. The Agent may consult with legal counsel, independent public accountants and other experts selected by it and shall not be liable for any action taken or omitted to be taken by it in good faith in accordance with the advice of such counsel, accountants or experts. Section 10.5 Liability of Agent; Credit Decision. Neither the Agent nor any of its directors, officers, agents, or employees shall be liable for any action taken or not taken by it in connection with the Credit Documents (i) with the consent or at the request of the Required Banks or (ii) in the absence of its own gross negligence or willful misconduct. Neither the Agent nor any of its directors, officers, agents or employees shall be responsible for or have any duty to ascertain, inquire into or verify: (i) any statement, warranty or representation made in connection with this Agreement, any other Credit Document or any Credit Event; (ii) the performance or observance of any of the covenants or agreements of the Borrower or any other party contained 35 40 herein or in any other Credit Document; (iii) the satisfaction of any condition specified in Section 6 hereof, except receipt of items required to be delivered to the Agent; or (iv) the validity, effectiveness, genuineness, enforceability, perfection, value, worth or collectability hereof or of any other Credit Document or of any other documents or writing furnished in connection with any Credit Document; and the Agent makes no representation of any kind or character with respect to any such matter mentioned in this sentence. The Agent may execute any of its duties under any of the Credit Documents by or through employees, agents, and attorneys-in-fact and shall not be answerable to the Banks, the Borrower, or any other Person for the default or misconduct of any such agents or attorneys-in-fact selected with reasonable care. The Agent shall not incur any liability by acting in reliance upon any notice, consent, certificate, other document or statement (whether written or oral) believed by it to be genuine or to be sent by the proper party or parties. In particular and without limiting any of the foregoing, the Agent shall have no responsibility for confirming the accuracy of any Compliance Certificate or other document or instrument received by it under the Credit Documents. The Agent may treat the payee of any Note as the holder thereof until written notice of transfer shall have been filed with the Agent signed by such payee in form satisfactory to the Agent. Each Bank acknowledges that it has independently and without reliance on the Agent or any other Bank, and based upon such information, investigations and inquiries as it deems appropriate, made its own credit analysis and decision to extend credit to the Borrower in the manner set forth in the Credit Documents. It shall be the responsibility of each Bank to keep itself informed as to the creditworthiness of the Borrower and any other relevant Person, and the Agent shall have no liability to any Bank with respect thereto. Section 10.6 Indemnity. The Banks shall ratably, in accordance with their respective Percentages, indemnify and hold the Agent, and its directors, officers, employees, agents and representatives harmless from and against any liabilities, losses, costs or expenses suffered or incurred by it under any Credit Document or in connection with the transactions contemplated thereby, regardless of when asserted or arising, except to the extent they are promptly reimbursed for the same by the Borrower and except to the extent that any event giving rise to a claim was caused by the gross negligence or willful misconduct of the party seeking to be indemnified. The obligations of the Banks under this Section 10.6 shall survive termination of this Agreement. Section 10.7 Resignation of Agent and Successor Agent. The Agent may resign at any time by giving written notice thereof to the Banks and the Borrower. Upon any such resignation of the Agent, the Required Banks shall have the right to appoint a successor Agent with the consent of the Borrower, provided, that at any time an Event of Default has occurred and is continuing, no such consent shall be required. If no successor Agent shall have been so appointed by the Required Banks, and shall have accepted such appointment, within thirty (30) days after the retiring Agent's giving of notice of resignation, then the retiring Agent may, on behalf of the Banks, with the consent of the Borrower, appoint a successor Agent, which shall be any Bank hereunder or any commercial bank organized under the laws of the United States of America or of any State thereof and having a combined capital and surplus of at least $200,000,000. Upon the acceptance of its appointment as the Agent hereunder, such successor Agent shall thereupon succeed to and become vested with all the rights and duties of the retiring or removed Agent under the Credit Documents, and the retiring Agent shall be discharged from 36 41 its duties and obligations thereunder. After any retiring Agent's resignation hereunder as Agent, the provisions of this Section 10 and all protective provisions of the other Credit Documents shall inure to its benefit as to any actions taken or omitted to be taken by it while it was Agent. SECTION 11. MISCELLANEOUS. Section 11.1 Withholding Taxes. (a) Payments Free of Withholding. Subject to Section 11.1(b) hereof, each payment by the Borrower under this Agreement or the other Credit Documents shall be made without withholding for or on account of any present or future taxes (other than overall net income taxes on the recipient). If any such withholding is so required, the Borrower shall make the withholding, pay the amount withheld to the appropriate governmental authority before penalties attach thereto or interest accrues thereon and forthwith pay such additional amount as may be necessary to ensure that the net amount actually received by each Bank and the Agent free and clear of such taxes (including such taxes on such additional amount) is equal to the amount which that Bank or the Agent (as the case may be) would have received had such withholding not been made. If the Agent or any Bank pays any amount in respect of any such taxes, penalties or interest the Borrower shall reimburse the Agent or that Bank for that payment on demand in the currency in which such payment was made. If the Borrower pays any such taxes, penalties or interest, it shall deliver official tax receipts evidencing that payment or certified copies thereof to the Bank or Agent on whose account such withholding was made (with a copy to the Agent if not the recipient of the original) on or before the thirtieth day after payment. If any Bank or the Agent determines it has received or been granted a credit against or relief or remission for, or repayment of, any taxes paid or payable by it because of any taxes, penalties or interest paid by the Borrower and evidenced by such a tax receipt, such Bank or Agent shall, to the extent it can do so without prejudice to the retention of the amount of such credit, relief, remission or repayment, pay to the Borrower such amount as such Bank or Agent determines is attributable to such deduction or withholding and which will leave such Bank or Agent (after such payment) in no better or worse position than it would have been in if the Borrower had not been required to make such deduction or withholding. Nothing in this Agreement shall interfere with the right of each Bank and the Agent to arrange its tax affairs in whatever manner it thinks fit nor oblige any Bank or the Agent to disclose any information relating to its tax affairs or any computations in connection with such taxes. (b) U.S. Withholding Tax Exemptions. Each Bank that is not a United States person (as such term is defined in Section 7701(a)(30) of the Code) shall submit to the Borrower and the Agent on or before the earlier of the date the initial Borrowing is made hereunder and thirty (30) days after the date hereof, two duly completed and signed copies of either Form W8BEN (relating to such Bank and entitling it to a complete exemption from withholding under the Code on all amounts to be received by such Bank, including fees, pursuant to the 37 42 Credit Documents and the Loans) or Form W8ECI (relating to all amounts to be received by such Bank, including fees, pursuant to the Credit Documents and the Loans) of the United States Internal Revenue Service. Thereafter and from time to time, each Bank shall submit to the Borrower and the Agent such additional duly completed and signed copies of one or the other of such Forms (or such successor forms as shall be adopted from time to time by the relevant United States taxing authorities) as may be (i) requested by the Borrower in a written notice, directly or through the Agent, to such Bank and (ii) required under then-current United States law or regulations to avoid or reduce United States withholding taxes on payments in respect of all amounts to be received by such Bank, including fees, pursuant to the Credit Documents or the Loans. (c) Inability of Bank to Submit Forms. If any Bank determines, as a result of any change in applicable law, regulation or treaty, or in any official application or interpretation thereof, that it is unable to submit to the Borrower or Agent any form or certificate that such Bank is obligated to submit pursuant to subsection (b) of this Section 11.1 or that such Bank is required to withdraw or cancel any such form or certificate previously submitted or any such form or certificate otherwise becomes ineffective or inaccurate, such Bank shall promptly notify the Borrower and Agent of such fact and the Bank shall to that extent not be obligated to provide any such form or certificate and will be entitled to withdraw or cancel any affected form or certificate, as applicable. Section 11.2 No Waiver of Rights. No delay or failure on the part of the Agent or any Bank or on the part of the holder or holders of any Note in the exercise of any power or right under any Credit Document shall operate as a waiver thereof, nor as an acquiescence in any default, nor shall any single or partial exercise thereof preclude any other or further exercise of any other power or right, and the rights and remedies hereunder of the Agent, the Banks and the holder or holders of any Notes are cumulative to, and not exclusive of, any rights or remedies which any of them would otherwise have. Section 11.3 Non-Business Day. If any payment of principal or interest on any Loan or of any other Obligation shall fall due on a day which is not a Business Day, interest or fees (as applicable) at the rate, if any, such Loan or other Obligation bears for the period prior to maturity shall continue to accrue on such Obligation from the stated due date thereof to and including the next succeeding Business Day, on which the same shall be payable. Section 11.4 Documentary Taxes. The Borrower agrees that it will pay any documentary, stamp or similar taxes payable in respect to any Credit Document, including interest and penalties, in the event any such taxes are assessed, irrespective of when such assessment is made and whether or not any credit is then in use or available hereunder. Section 11.5 Survival of Representations. All representations and warranties made herein or in certificates given pursuant hereto shall survive the execution and delivery of this Agreement and the other Credit Documents, and shall continue in full force and effect with respect to the date as of which they were made as long as any credit is in use or available hereunder. 38 43 Section 11.6 Survival of Indemnities. All indemnities and all other provisions relative to reimbursement to the Banks of amounts sufficient to protect the yield of the Banks with respect to the Loans, including, but not limited to, Section 2.11, Section 9.3 and Section 11.15 hereof, shall survive the termination of this Agreement and the other Credit Documents and the payment of the Loans and all other Obligations. Section 11.7 Set-Off. (a) In addition to any rights now or hereafter granted under applicable law and not by way of limitation of any such rights, upon the occurrence of any Event of Default, each Bank, each Affiliate of a Bank, and each subsequent holder of any Note is hereby authorized by the Borrower at any time or from time to time, without notice to the Borrower or to any other Person, any such notice being hereby expressly waived, to set off and to appropriate and to apply any and all deposits (general or special, including, but not limited to, Indebtedness evidenced by certificates of deposit, whether matured or unmatured, and in whatever currency denominated) and any other Indebtedness at any time held or owing by that Bank, its Affiliate or that subsequent holder to or for the credit or the account of the Borrower, whether or not matured, against and on account of the obligations and liabilities of the Borrower to that Bank, its Affiliate or that subsequent holder under the Credit Documents, including, but not limited to, all claims of any nature or description arising out of or connected with the Credit Documents, irrespective of whether or not (a) that Bank, its Affiliate or that subsequent holder shall have made any demand hereunder or (b) the principal of or the interest on the Loans or Notes and other amounts due hereunder shall have become due and payable pursuant to Section 8 and although said obligations and liabilities, or any of them, may be contingent or unmatured. (b) Each Bank agrees with each other Bank a party hereto that if such Bank shall receive and retain any payment, whether by set-off or application of deposit balances or otherwise, on any of the Loans in excess of its ratable share of payments on all such obligations then outstanding to the Banks, then such Bank shall purchase for cash at face value, but without recourse, ratably from each of the other Banks such amount of the Loans, or participations therein, held by each such other Bank (or interest therein) as shall be necessary to cause such Bank to share such excess payment ratably with all the other Banks; provided, however, that if any such purchase is made by any Bank, and if such excess payment or part thereof is thereafter recovered from such purchasing Bank, the related purchases from the other Banks shall be rescinded ratably and the purchase price restored as to the portion of such excess payment so recovered, but without interest unless the purchasing Bank is required to pay interest thereon, in which case each Bank returning funds to such purchasing Bank shall pay its pro rata share of such interest. Section 11.8 Notices. Except as otherwise specified herein, all notices under the Credit Documents shall be in writing (including telecopy or other electronic communication) and shall be given to a party hereunder at its address or telecopier number set forth below or such other address or telecopier number as such party may hereafter specify by notice to the Agent and the Borrower, given by courier, by United States certified or registered mail, or by other 39 44 telecommunication device capable of creating a written record of such notice and its receipt. Notices under the Credit Documents to the Banks shall be addressed to their respective addresses, telecopier or telephone numbers set forth on the signature pages hereof or in the assignment agreement which any assignee bank executes pursuant to Section 11.12 hereof, and to the Borrower and to the Agent to: If to the Borrower: NRG Energy, Inc. 1221 Nicollet Mall Suite 700 Minneapolis, MN 55403-2445 Attention: Treasurer Facsimile: (612) 373-5341 Telephone: (612) 373-5306 If to the Agent: ABN AMRO Bank Agency Services 1325 Avenue of the Americas 9th Floor New York, New York 10019 Attention: Linda Boardman Facsimile: (212) 314-1712 Telephone: (212) 314-1724 With copies to: ABN AMRO Bank N.V. 135 South LaSalle Street Suite 710 Chicago, Illinois 60603 Attention: David B. Bryant Facsimile: (312) 904-1466 Telephone: (312) 904-2799 ABN AMRO Bank N.V. 208 South LaSalle Street Suite 1500 Chicago, Illinois 60604-1003 Attention: Ken Keck Facsimile: (312) 992-5111 Telephone: (312) 992-5134 40 45 Each such notice, request or other communication shall be effective (i) if given by telecopier, when such telecopy is transmitted to the telecopier number specified in this Section 11.8 or on the signature pages hereof and a confirmation of receipt of such telecopy has been received by the sender, (ii) if given by courier, when delivered, (iii) if given by mail, three business days after such communication is deposited in the mail, registered with return receipt requested, addressed as aforesaid or (iv) if given by any other means, when delivered at the addresses specified in this Section 11.8; provided that any notice given pursuant to Section 2 hereof shall be effective only upon receipt. Section 11.9 Counterparts. This Agreement may be executed in any number of counterpart signature pages, and by the different parties on different counterparts, each of which when executed shall be deemed an original but all such counterparts taken together shall constitute one and the same instrument. Section 11.10 Successors and Assigns. This Agreement shall be binding upon the Borrower and its successors and assigns, and shall inure to the benefit of each of the Banks and the benefit of their respective successors and assigns, including any subsequent holder of any Note. The Borrower may not assign any of its rights or obligations under any Credit Document without the written consent of all of the Banks. Section 11.11 Participants and Note Assignees. Each Bank shall have the right at its own cost to grant participations (to be evidenced by one or more agreements or certificates of participation) in the Loans made and/or Revolving Credit Commitments held by such Bank at any time and from time to time, and to assign its rights under such Loans or the Note evidencing such Loans to a federal reserve bank; provided that (i) no such participation or assignment shall relieve any Bank of any of its obligations under this Agreement, (ii) no such assignee or participant shall have any rights under this Agreement except as provided in this Section 11.11, and (iii) the Agent shall have no obligation or responsibility to such participant or assignee, except that nothing herein is intended to affect the rights of an assignee of a Note to enforce the Note assigned. Any party to which such a participation or assignment has been granted shall have the benefits of Section 2.11 and Section 9.3, but shall not be entitled to receive any greater payment under either such Section than the Bank granting such participation would have been entitled to receive in connection with the rights transferred. Any agreement pursuant to which any Bank may grant such a participating interest shall provide that such Bank shall retain the sole right and responsibility to enforce the obligations of the Borrower hereunder, including, without limitation, the right to approve any amendment, modification or waiver of any provision of this Agreement; provided that such participation agreement may provide that such Bank will not agree to any modification, amendment or waiver of this Agreement that would (A) increase any Revolving Credit Commitment of such Bank if such increase would also increase the participant's obligations, (B) forgive any amount of or postpone the date for payment of any principal of or interest on any Loan or of any fee payable hereunder in which such participant has an interest or (C) reduce the stated rate at which interest or fees in which such participant has an interest accrue hereunder. 41 46 Section 11.12 Assignment of Commitments by Banks. Each Bank shall have the right at any time, with the written consent (except in the case of an assignment to (i) an Affiliate of such Bank, or (ii) another Bank) of the Borrower and Agent (which consent shall not be unreasonably withheld), to assign all or any part of its Revolving Credit Commitment (including the same percentage of its Note and outstanding Loans) to one or more other Persons; provided that such assignment is in an amount of at least $10,000,000 or the entire Revolving Credit Commitment of such Bank, and if such assignment is not for such Bank's entire Revolving Credit Commitment then such Bank's Revolving Credit Commitment after giving effect to such assignment shall not be less than $10,000,000; and provided further that neither the consent of the Borrower nor of the Agent shall be required for any Bank to assign all or part of its Revolving Credit Commitment to any Affiliate of the assigning Bank. Each such assignment shall set forth the assignee's address for notices to be given under Section 11.8 hereof hereunder and its designated Lending Office pursuant to Section 9.4 hereof. Upon any such assignment, delivery to the Agent of an executed copy of such assignment agreement and the forms referred to in Section 11.1 hereof, if applicable, and, except in the case of an assignment to an Affiliate of the assigning Bank, the payment of a $3,500 recordation fee to the Agent, the assignee shall become a Bank hereunder, all Loans and the Revolving Credit Commitment it thereby holds shall be governed by all the terms and conditions hereof and the Bank granting such assignment shall have its Revolving Credit Commitment, and its obligations and rights in connection therewith, reduced by the amount of such assignment; provided, however, in the event a Bank assigns all of its Revolving Credit Commitment to an Affiliate or at the request of the Borrower, pursuant to Section 11.13(iii), no recordation fee shall be required hereunder. Notwithstanding any other provision set forth in this Agreement, any Bank may at any time create a security interest in all or any portion of its rights under this Agreement (including, without limitation, the Loans owing to it and the Note held by it) in favor of any Federal Reserve Bank in accordance with Regulation A of the Board of Governors of the Federal Reserve System. Section 11.13 Amendments. Any provision of the Credit Documents may be amended or waived if, but only if, such amendment or waiver is in writing and is signed by (a) the Borrower, (b) the Required Banks, and (c) if the rights or duties of the Agent are affected thereby, the Agent; provided that: (i) no amendment or waiver pursuant to this Section 11.13 shall (A) increase any Commitment of any Bank without the consent of such Bank or (B) reduce the stated rate at which interest or fees accrue or reduce the amount of or postpone any fixed date for payment of any principal of or interest on any Loan or of any fee payable hereunder without the consent of each Bank; and (ii) no amendment or waiver pursuant to this Section 11.13 shall, unless signed by each Bank, change this Section 11.13, or the definition of Required Banks, or affect the number of Banks required to take any action under the Credit Documents. If the Borrower requests an amendment to this Agreement which requires the approval of all of the Banks and one of the Banks (a "Replaceable Bank") does not approve it, the Borrower 42 47 may propose that another bank which is reasonably acceptable to the Agent (a "Replacement Bank") be substituted for and replace the Replaceable Bank for purposes of this Agreement. If a Replacement Bank is so substituted for the Replaceable Bank, the Replaceable Bank shall enter into an assignment agreement with the Replacement Bank, the Borrower and the Agent to assign and transfer to the Replacement Bank, the Replaceable Bank's Commitment hereunder, which shall provide, among other things, for the payment of all Obligations owing to the Replaceable Bank; provided, however, if a Replacement Bank cannot be found, then the Borrower may elect to take out the Replaceable Bank and reduce the facility accordingly by making a prepayment in the amount of such Replaceable Bank's outstanding Loans plus all accrued and unpaid interest thereon and all fees and all other Obligations due and owing to the Replaceable Bank on the date of replacement. Notwithstanding anything to the contrary contained herein, in no event shall the Agent be a Replaceable Bank. Section 11.14 Headings. Section headings used in this Agreement are for reference only and shall not affect the construction of this Agreement. Section 11.15 Legal Fees, Other Costs and Indemnification. The Borrower agrees to pay all reasonable costs and expenses of the Agent in connection with the preparation and negotiation of the Credit Documents, including, without limitation, the reasonable fees and disbursements of counsel to the Agent, in connection with the preparation and execution of the Credit Documents and any amendment, waiver or consent related hereto, whether or not the transactions contemplated herein are consummated. The Borrower further agrees to indemnify each Bank, the Agent, and their respective Affiliates, directors, agents, officers and employees, against all losses, claims, damages, penalties, judgments, liabilities and expenses (including, without limitation, all expenses of litigation or preparation therefor, whether or not the indemnified Person is a party thereto) which any of them may incur or reasonably pay arising out of or relating to any Credit Document or any of the transactions contemplated thereby or the direct or indirect application or proposed application of the proceeds of any Loan other than those which arise from the gross negligence or willful misconduct of the party claiming indemnification. The Borrower, upon demand by the Agent or a Bank at any time, shall reimburse the Agent or Bank for any reasonable legal or other expenses incurred in connection with investigating or defending against any of the foregoing except if the same is directly due to the gross negligence or willful misconduct of the party to be indemnified. Section 11.16 Entire Agreement. The Credit Documents constitute the entire understanding of the parties thereto with respect to the subject matter thereof and any prior or contemporaneous agreements, whether written or oral, with respect thereto are superseded thereby. Section 11.17 Construction. The parties hereto acknowledge and agree that neither this Agreement nor the other Credit Documents shall be construed more favorably in favor of one than the other based upon which party drafted the same, it being acknowledged that all parties hereto contributed substantially to the negotiation of this Agreement and the other Credit Documents. 43 48 Section 11.18 Governing Law. This Agreement and the other Credit Documents, and the rights and duties of the parties hereto, shall be construed and determined in accordance with the internal laws of the State of New York. Section 11.19 Submission to Jurisdiction; Waiver of Jury Trial. EACH OF THE BORROWER, EACH BANK AND THE AGENT HEREBY SUBMITS TO THE NONEXCLUSIVE JURISDICTION OF THE UNITED STATES DISTRICT COURT FOR THE SOUTHERN DISTRICT OF NEW YORK AND OF ANY NEW YORK STATE COURT SITTING IN THE CITY OF NEW YORK FOR PURPOSES OF ALL LEGAL PROCEEDINGS ARISING OUT OF OR RELATING TO THIS AGREEMENT, THE OTHER CREDIT DOCUMENTS OR THE TRANSACTIONS CONTEMPLATED HEREBY OR THEREBY. EACH OF THE BORROWER, EACH BANK AND THE AGENT IRREVOCABLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY LAW, ANY OBJECTION WHICH IT MAY NOW OR HEREAFTER HAVE TO THE LAYING OF THE VENUE OF ANY SUCH PROCEEDING BROUGHT IN SUCH A COURT AND ANY CLAIM THAT ANY SUCH PROCEEDING BROUGHT IN SUCH A COURT HAS BEEN BROUGHT IN AN INCONVENIENT FORUM. EACH OF THE BORROWER, EACH BANK AND THE AGENT HEREBY IRREVOCABLY WAIVES ANY AND ALL RIGHT TO TRIAL BY JURY IN ANY LEGAL PROCEEDING ARISING OUT OF OR RELATING TO ANY CREDIT DOCUMENT OR THE TRANSACTIONS CONTEMPLATED THEREBY. [SIGNATURE PAGE FOLLOWS] 44 49 In Witness Whereof, the parties hereto have caused this Agreement to be duly executed and delivered in New York, New York by their duly authorized officers as of the day and year first above written. NRG ENERGY, INC. By: ______________________ Name: Brian B. Bird Title: Vice President & Treasurer 45 50 Commitment: $20,000,000.00 ABN AMRO BANK N.V., in its individual capacity as a Bank and as Agent By: ___________________________ Name: David B. Bryant Title: Senior Vice President By: ___________________________ Name: Saad B. Qais Title: Assistant Vice President Address for notices: ABN AMRO Bank N.V. 135 South LaSalle Street Suite 710 Chicago, Illinois 60603 Attention: David B. Bryant Facsimile: (312) 904-1466 Telephone: (312) 904-2799 With copy to: CREDIT ADMINISTRATION ABN AMRO Bank N.V. 208 South LaSalle Street Suite 1500 Chicago, Illinois 60604 Attention: Ken Keck Facsimile: (312) 992-5111 Telephone: (312) 992-5134 Lending Offices: Base Rate Loans: 208 South LaSalle Street Suite 1500 Chicago, Illinois 60604 Attention: Loan Administration Eurocurrency Loans: Same as for Base Rate Loans 51 EXHIBIT A NOTE March 9, 2001 For Value Received, the undersigned, NRG Energy, Inc., a Delaware corporation (the "Borrower"), promises to pay to the order of _______________________________(the "Bank") on the Termination Date of the hereinafter defined Credit Agreement, at the principal office of ABN AMRO Bank N.V., Chicago Branch, in Chicago, Illinois, in U.S. Dollars, the aggregate unpaid principal amount of all Loans made by the Bank to the Borrower pursuant to the Credit Agreement, together with interest on the principal amount of each Loan from time to time outstanding hereunder at the rates, and payable in the manner and on the dates, specified in the Credit Agreement. The Bank shall record on its books or records or on a schedule attached to this Note, which is a part hereof, each Loan made by it pursuant to the Credit Agreement, together with all payments of principal and interest and the principal balances from time to time outstanding hereon, whether the Loan is a Base Rate Loan or a Eurocurrency Loan, the interest rate and Interest Period applicable thereto, provided that prior to the transfer of this Note all such amounts shall be recorded on a schedule attached to this Note. The record thereof, whether shown on such books or records or on a schedule to this Note, shall be prima facie evidence of the same, provided, however, that the failure of the Bank to record any of the foregoing or any error in any such record shall not limit or otherwise affect the obligation of the Borrower to repay all Loans made to it pursuant to the Credit Agreement together with accrued interest thereon. This Note is one of the Notes referred to in the 364-Day Revolving Credit Agreement dated as of March 9, 2001, among the Borrower, ABN AMRO Bank N.V., as Agent, and the Banks party thereto (the "Credit Agreement"), and this Note and the holder hereof are entitled to all the benefits provided for thereby or referred to therein, to which Credit Agreement reference is hereby made for a statement thereof. All defined terms used in this Note, except terms otherwise defined herein, shall have the same meaning as in the Credit Agreement. This Note shall be governed by and construed in accordance with the internal laws of the State of New York. Prepayments may be made hereon and this Note may be declared due prior to the expressed maturity hereof, all in the events, on the terms and in the manner as provided for in the Credit Agreement. The Borrower hereby waives demand, presentment, protest or notice of any kind hereunder. NRG ENERGY, INC. By: ______________________ Name: Brian B. Bird Title: Vice President & Treasurer A-1 52 EXHIBIT B COMPLIANCE CERTIFICATE This Compliance Certificate is furnished to ABN AMRO Bank N.V., as Agent pursuant to the 364-Day Revolving Credit Agreement (the "Credit Agreement") dated as of March 9, 2001, by and among NRG Energy, Inc., the financial institutions from time to time party thereto and ABN AMRO Bank N.V., as Agent. Unless otherwise defined herein, the terms used in this Compliance Certificate have the meanings ascribed thereto in the Credit Agreement. The undersigned hereby certifies that: 1. I am the duly elected or appointed __________ of NRG Energy, Inc.; 2. I have reviewed the terms of the Credit Agreement and I have made, or have caused to be made under my supervision, a detailed review of the transactions and conditions of NRG Energy, Inc. and its Subsidiaries during the accounting period covered by the attached financial statements; 3. The examinations described in paragraph 2 did not disclose, and I have no knowledge of, the existence of any condition or event which constitutes a Default or an Event of Default during or at the end of the accounting period covered by the attached financial statements or as of the date of this Compliance Certificate, except as set forth below; and 4. Schedule B-1 attached hereto sets forth financial data and computations evidencing compliance with certain covenants of the Credit Agreement, all of which data and computations are true, complete and correct. All computations are made in accordance with the terms of the Credit Agreement. Described below are the exceptions, if any, to paragraph 3 by listing, in detail, the nature of the condition or event, the period during which it has existed and the action which the Borrower has taken, is taking, or proposes to take with respect to each such condition or event: ------------------------------------------------------------------- ------------------------------------------------------------------- ------------------------------------------------------------------- The foregoing certifications, together with the computations set forth in Schedule 1 hereto and the financial statements delivered with this Compliance Certificate in support hereof are made and delivered this ___________day of ____________, ______. ------------------------------- B-1 53 COMPLIANCE CERTIFICATE SCHEDULE B-1 COMPLIANCE CALCULATIONS FOR CREDIT AGREEMENT CALCULATION AS OF __________, 20_____ A. Liens (Section 7.9) 1. Total Liens $_______ (Line A1 not to exceed 10% of Consolidated Net Tangible Assets) B. Sale of Assets (Section 7.11) 1. Net book value of assets sold during this fiscal year $_______ (Line B1 not to exceed 10% of Consolidated Net Tangible Assets) C. Consolidated Net Worth (Section 7.12) 1. Consolidated stockholders equity $_______ 2. Effect of currency translation account on consolidated stockholders equity $_______ 3. Effect of application FASB's Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities on consolidated stockholders equity $_______ 4. Consolidated Net Worth (Line C1 adjusted by Lines C2 and C3) $_______ D. Consolidated Capitalization 1. Consolidated Net Worth (Line C4) $_______ 2. Indebtedness of the Borrower (excluding performance guarantees under which demand has not been made) $_______ 3. 50% of Indebtedness of Borrower consisting of performance guarantees under which demand has not been made $_______________ B-2 54 4. Adjusted Indebtedness of Borrower (line D2-D3) $_______________ 5. Consolidated Capitalization (Sum of line D1 and D4) $_______ E. Indebtedness to Consolidated Capitalization 1. Adjusted Indebtedness of the Borrower (line D4) $__________________ 2. Consolidated Capitalization (line D5) $_________________ 3. Ratio of Adjusted Indebtedness of Consolidated Capitalization __ to __ (Line E1 to E2) (ratio not to exceed 0.68 to 1.00 unless a Non-Conforming Period, in which case ratio can not exceed 0.72 to 1.00) B-3 55 SCHEDULE 1 PRICING GRID provided, that (A) the Facility Fee shall be increased by 0.075% over the Facility Fee set forth in the above grid during any Non-Conforming Period and (B) the Eurocurrency Margins and the Base Rate Margins shall be increased by 0.175% over the Eurocurrency Margins and the Base Rate Margins set forth in the above grid during any Non-Conforming Period. Any change in the Borrower's Moody's Rating or S&P Rating (and in any fees or interest payable hereunder based on such Ratings) shall be effective as of the date on which Moody's or S&P, as the case may be, announces the applicable change in such Rating. Any change in the Utilization shall be effective as of the date of such change. In the event of a split Rating (i.e. the Moody's Rating and the S&P Rating fall into different Levels in the above grid), the lower Rating shall prevail. In the event neither a Moody's Rating nor a S&P Rating is in effect, Level V pricing shall prevail unless otherwise agreed by the Required Banks.
- - ----------------------------------------------------------------------------------------------------------------------------------- Level If the Borrower's The If the If the If the If the If the If the Moody's/S&P Annual Utilization Utilization is Utilization Utilization Utilization Utilization Rating Is: Facility is equal to greater than is greater is equal is greater is greater Fee is: or less than 33% but less than 66%, to or less than 33% but than 66%, 33%, the than or equal the than 33%, less than or the Base Eurocurrency to 66%, the Eurocurrency the Base equal to 66%, Rate Margin Margin is: Eurocurrency Margin is: Rate the Base Rate is: Margin is: Margin is: Margin is: - - ----------------------------------------------------------------------------------------------------------------------------------- I Greater than or 0.10% 0.400% 0.475% 0.525% 0.000% 0.075% 0.125% equal to A3/A- - - ----------------------------------------------------------------------------------------------------------------------------------- II Below Level I, 0.125% 0.500% 0.575% 0.625% 0.000% 0.075% 0.125% but greater than or equal to Baa1/BBB+ - - ----------------------------------------------------------------------------------------------------------------------------------- III Below Level II, 0.150% 0.600% 0.725% 0.850% 0.000% 0.125% 0.250% but greater than or equal to Baa2/BBB - - ----------------------------------------------------------------------------------------------------------------------------------- IV Below Level III, 0.175% 0.825% 0.950% 1.075% 0.000% 0.125% 0.250% but greater than or equal to Baa3/BBB- - - ----------------------------------------------------------------------------------------------------------------------------------- V Below Level IV 0.375% 1.375% 1.500% 1.625% 0.000% 0.125% 0.250% - - ----------------------------------------------------------------------------------------------------------------------------------- 56 SCHEDULE 5.2 SUBSIDIARIES - - ------------------------------------------------------------------------------- SUBSIDIARY NAME STATE OF INCORPORATION/ FORMATION - - ------------------------------------------------------------------------------- 1. NRG Connecticut Ancillary Assets LLC Delaware - - ------------------------------------------------------------------------------- 2. Cobee Holdings Inc. Delaware - - ------------------------------------------------------------------------------- 3. Elk River Resource Recovery, Inc. Minnesota - - ------------------------------------------------------------------------------- 4. Graystone Corporation Minnesota - - ------------------------------------------------------------------------------- 5. Meriden Gas Turbines LLC Delaware - - ------------------------------------------------------------------------------- 6. MidAtlantic Generation Holding LLC Delaware - - ------------------------------------------------------------------------------- 7. NEO Corporation Minnesota - - ------------------------------------------------------------------------------- 8. NRG Connecticut Power Assets LLC Delaware - - ------------------------------------------------------------------------------- 9. Northeast Generation Holding LLC Delaware - - ------------------------------------------------------------------------------- 10. NRG Affiliate Services Inc. Delaware - - ------------------------------------------------------------------------------- 11. NRG Asia-Pacific, Ltd. Delaware - - ------------------------------------------------------------------------------- 12. NRG Cadillac Inc. Delaware - - ------------------------------------------------------------------------------- 13. NRG Central U.S. LLC Delaware - - ------------------------------------------------------------------------------- 14. NRG ComLease LLC Delaware - - ------------------------------------------------------------------------------- 15. NRG Connecticut Affiliate Services Inc. Delaware - - ------------------------------------------------------------------------------- 16. NRG del Coronado Inc. Delaware - - ------------------------------------------------------------------------------- 17. NRG Eastern LLC Delaware - - ------------------------------------------------------------------------------- 18. NRG El Segundo Inc. Delaware - - ------------------------------------------------------------------------------- 19. NRG Energy Center, Inc. Minnesota - - ------------------------------------------------------------------------------- 20. NRG Energy Jackson Valley I, Inc. California - - ------------------------------------------------------------------------------- 21. NRG Energy Jackson Valley II, Inc. California - - ------------------------------------------------------------------------------- 22. NRG Granite Acquisition LLC Delaware - - ------------------------------------------------------------------------------- 23. NRG International Services Company Delaware - - ------------------------------------------------------------------------------- 24. NRG International Development Inc. Delaware - - ------------------------------------------------------------------------------- 25. NRG International, Inc. Delaware - - ------------------------------------------------------------------------------- 26. NRG Kaufman LLC Delaware - - ------------------------------------------------------------------------------- 27. NRG Lakefield Inc. Delaware - - ------------------------------------------------------------------------------- 28. NRG Latin America Inc. Delaware - - ------------------------------------------------------------------------------- 57 29. NRG Louisiana LLC Delaware - - ------------------------------------------------------------------------------- 30. NRG Mextrans Inc. Delaware - - ------------------------------------------------------------------------------- 31. NRG MidAtlantic LLC Delaware - - ------------------------------------------------------------------------------- 32. NRG Mesquite LLC Delaware - - ------------------------------------------------------------------------------- 33. NRG Northeast Affiliate Services Inc. Delaware - - ------------------------------------------------------------------------------- 34. NRG Operating Services, Inc. Delaware - - ------------------------------------------------------------------------------- 35. NRG PacGen Inc. Delaware - - ------------------------------------------------------------------------------- 36. NRG Power Marketing Inc. Delaware - - ------------------------------------------------------------------------------- 37. NRG Processing Solutions LLC Delaware - - ------------------------------------------------------------------------------- 38. NRG San Diego Inc. Delaware - - ------------------------------------------------------------------------------- 39. NRG San Francisco Thermal Inc. Delaware - - ------------------------------------------------------------------------------- 40. NRG Services Corporation Delaware - - ------------------------------------------------------------------------------- 41. NRG Sunnyside Operations GP Inc. Delaware - - ------------------------------------------------------------------------------- 42. NRG Sunnyside Operations LP Inc. Delaware - - ------------------------------------------------------------------------------- 43. NRG Thermal Corporation Delaware - - ------------------------------------------------------------------------------- 44. NRG Valmy Power LLC Delaware - - ------------------------------------------------------------------------------- 45. NRG Valmy Power Holdings LLC - - ------------------------------------------------------------------------------- 46. NRG West Coast Inc. Delaware - - ------------------------------------------------------------------------------- 47. NRG Western Affiliate Services Inc. Delaware - - ------------------------------------------------------------------------------- 48. O Brien Cogeneration, Inc. II Delaware - - ------------------------------------------------------------------------------- 49. Okeechobee Power I, Inc. Delaware - - ------------------------------------------------------------------------------- 50. Okeechobee Power II, Inc. Delaware - - ------------------------------------------------------------------------------- 51. Okeechobee Power III, Inc. Delaware - - ------------------------------------------------------------------------------- 52. Power Operations, Inc. Delaware - - ------------------------------------------------------------------------------- 53. San Joaquin Valley Energy I, Inc. California - - ------------------------------------------------------------------------------- 54. San Joaquin Valley Energy IV, Inc. California - - ------------------------------------------------------------------------------- 55. Scoria Incorporated Minnesota - - ------------------------------------------------------------------------------- 56. South Central Generation Holding LLC Delaware - - ------------------------------------------------------------------------------- 58 SCHEDULE 5.5 LITIGATION/GOVERNMENTAL PROCEEDINGS SUMMARY Fortistar (Oswego) In July 1999, Fortistar Capital, Inc. ("Fortistar") commenced an action against NRG Energy, Inc. (the "Company") in Hennepin County (Minnesota) District Court, seeking damages in excess of $100 million and an order restraining the Company from consummating the acquisition of Niagara Mohawk Power Corporation's Oswego generating station. Fortistar's motion for a temporary restraining order was denied. A temporary injunction hearing was held on September 27, 1999. The acquisition was consummated in October 1999. On January 14, 2000, the court denied Fortistar's request for a temporary injunction. In April and December 2000, the Company filed summary judgment motions to dispose of the litigation respecting both liability and damages, and a hearing on these motions was held on January 26, 2001. No ruling has been issued to date. A trial date has been scheduled for early April 2001. The Company has asserted numerous counterclaims against Fortistar and will continue to vigorously defend the suit. New York Environmental Investigation In May 2000, the New York Department of Environmental Conservation issued a Notice of Violation to the Company and the prior owner of the Company's Huntley and Dunkirk facilities in New York, relating to physical changes made at those facilities prior to our assumption of ownership. The Notice of Violation alleges that these changes represent major modifications undertaken without the proper permits having been obtained. Although the Company has a right to indemnification by the previous owner for fines, penalties, assessments and related losses resulting from the previous owner's failure to comply with environmental laws and regulations, if these facilities did not comply with the applicable permit requirements, the Company could be required, among other things, to install specified pollution control technology to further reduce pollutant emissions from the Huntley and Dunkirk facilities, and the Company could become subject to fines and penalties associated with the current and prior operation of the facilities. The Company is currently in settlement discussions with the Department of Environmental Conservation and the State Attorney General's Office. Station Power Litigation Niagara Mohawk Power Corporation, the former owner of the Company's Huntley, Dunkirk and Oswego Harbor generating stations, has asserted that it can require these facilities to obtain power for these stations under a retail tariff, rather than allowing the plants to treat station power as net/negative generation at wholesale prices. On September 21, 2000, the Company filed an action before the Federal Energy Regulatory Commission ("FERC"), seeking its declaration that these facilities are entitled to station power at wholesale prices. On September 28, 2000, Niagara Mohawk instituted separate actions against 59 Huntley Power LLC, Dunkirk Power LLC and Oswego Harbor Power LLC in the State Supreme Court of New York, seeking approximately $8 million plus late payment fees accrued, less payments received, which produces a current balance in dispute of approximately $7 million. The Company has pending in the New York State Supreme Court a motion to stay these state court actions pending a ruling by the FERC on the Company's claims, and Niagara Mohawk has pending a partial summary judgment motion, in which it is claiming that the Company has already been heard on these arguments before the New York Public Service Commission and is therefore collaterally estopped to again assert that FERC has exclusive jurisdiction over these disputes. EEOC Claims Approximately thirty-four former employees of Cajun Electric Power Cooperative are claiming that race discrimination and/or sex discrimination caused the termination of their employment at the Cajun facilities following the Company's acquisition of these facilities. The Equal Employment Opportunity Commission has issued "Dismissal and Notice of Rights" (right to sue) letters to several of the claimants and the Company expects that the EEOC will issue such letters to all of the claimants. These letters afford the claimants the opportunity to assert in either federal or state court both federal and state claims. The federal claims have a cumulative cap on punitive and compensatory damages of $300,000 per claim, and there are no caps on state claims. Prevailing parties in such claims are entitled to attorneys' fees. The Company denies that race discrimination or sex discrimination prompted any of the employee dismissals. Fortistar Methane LLC v. NEO Corporation In May 2000, Fortistar Methane LLC sued NEO Corporation in New York Federal District Court, requesting an injunction barring NEO from claimed interference with the management activities of Minnesota Methane LLC's Executive Financial Officer, Scott Contino of Fortistar; declaring NEO to be in default of the Operating Agreement between the parties; requiring NEO to turn over all books and records; and awarding damages. Minnesota Methane is 50% owned by the Company's subsidiary NEO Corporation, and 50% owned by Fortistar Methane LLC. In August 2000, the case was transferred to the Minnesota Federal District Court. On January 5, 2001, the judge ruled from the bench, granting NEO's motions to dismiss the claims of Fortistar. This ruling was confirmed by the court's written order of January 19, 2000. On January 8, 2001, NEO Corporation, on its own behalf and on behalf of Minnesota Methane, brought suit against Fortistar in Hennepin County District Court in Minnesota, claiming breach of contract, breach of covenant of good faith and fair dealing, fraud, defamation, and business disparagement. Fortistar's reponse to this complaint is due at the end of January 2001. 60 California Actions The Company has been named as a defendant in certain private plaintiff class actions filed in the Superior Court of the State of California for the County of San Diego in San Diego, California on November 27, 2000 (Pamela R. Gordon v. Reliant Energy, Inc., et al.) and November 29, 2000 (Ruth Hendricks v. Dynegy Power Marketing Inc., et al.), and in the Superior Court of the State of California, City and County of San Francisco (Pier 23 Restaurant v. PG&E Energy Trading, et al., filed January 24, 2001). The Company has also been named in another suit filed on January 16, 2001 in the Superior Court of the State of California for the County of San Diego, brought by three California water districts, as consumers of electricity (Sweetwater Authority v. Dynegy Inc., et al.), and in a suit filed on January 18, 2001 in Superior Court of the State of California, County of San Francisco, brought by the San Francisco City Attorney on behalf of the People of the State of California (The People of the State of California v. Dynegy Power Marketing, Inc., et al.). Although the complaints contain a number of allegations, the basic claim is that, by underbidding forward contracts and exporting electricity to surrounding markets, the defendants, acting in collusion, were able to drive up wholesale prices on the Real Time and Replacement Reserve markets, through the Western Systems Coordinating Council and otherwise. The complaints allege that the conduct violated California antitrust and/or unfair competition laws. The Company does not believe that it has engaged in any illegal activities, and intends to vigorously defend these lawsuits. LABOR DISPUTE SUMMARY None.
1 Exhibit 21 -- Subsidiaries of the Registrant NRG ENERGY, INC. SUBSIDIARY LIST AS OF MARCH 26, 2001
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- Arthur Kill Power LLC 03/11/1999 Delaware entity holding title to 842-MW Arthur Kill Generating Station, located on Staten Island, New York, includes two steam generating units designed to burn gas and oil Astoria Gas Turbine Power LLC 03/11/1999 Delaware entity holding title to 614-MW Astoria Gas Turbine Sites, located in Queens, New York, consist of 20 gas turbines, grouped into 11 units B.L. England Operations Inc. 05/08/2000 Delaware to act as a special purpose operating company to provide O&M services pursuant to a contract with B.L. England Power LLC B.L. England Power LLC 05/08/2000 Delaware entity holding title to 447 MW coal and oil-fired generating facility in Beesley's Point, New Jersey Big Cajun I Peaking Power LLC 08/03/2000 Delaware develop, own and operate the Cajun expansion project Bioconversion Partners, L.P. 12/10/1993 California supplies biomass fuel in California Bridgeport Harbor Power LLC 01/25/2001 Delaware entity to hold title to 585 MW fossil fuel-fired generating facility located in southern Connecticut Brimsdown Power Limited 12/11/1998 United Kingdom project company for peaking unit associated with Enfield Energy Centre Limited in England Cabrillo Power I LLC 12/11/1998 Delaware owns and operates Encina electric generation station in San Diego, California Cabrillo Power II LLC 12/11/1998 Delaware entity holding title to 17 SDG&E combustion turbines in San Diego, California Cadillac Renewable Energy LLC 02/27/1997 Delaware owns Cadillac wood fired power plant in Michigan 2
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- Camas Power Boiler Limited 02/06/1990 Oregon owns waste-wood fired steam boiler in Partnership Camas paper mill in Washington Camas Power Boiler, Inc. 02/06/1990 Oregon general partner in Camas Boiler Limited Partnership Carolina Energy, Limited Partnership 01/12/1993 Delaware holds remaining non-generating assets of the Carolina Energy transfer station and waste-to-energy facility in North Carolina Carquinez Strait Preservation 04/15/1994 California non-profit corporation which provides Trust, Inc. monetary support to the communities surrounding the Crockett cogeneration facility in California Central and Eastern Europe Power 11/25/1999 Bermuda Fund, Ltd. Clark Power LLC 11/15/2000 Delaware 740 MW gas-fired Clark power station and related assets in Nevada Cobee Energy Development LLC 04/02/1998 Delaware provides international business development services in Latin America for Compania Boliviana de Energia Electrica S.A. Cobee Holdings Inc. 12/16/1996 Delaware domestic holding company for Tosli Investments B.V. in Latin America Cogeneration Corporation of America 12/05/1983 Delaware develops, owns and operates cogeneration facilities in U.S. Collinsville Operations Pty Ltd 11/30/1995 Australia operates Collinsville coal fired power plant in Australia Collinsville Power Joint Venture 01/24/1996 Australia owns Collinsville coal fired power (unincorporated) plant in Australia 3
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- Compania Boliviana de Energia 04/17/1925 Canada (Nova owns and operates hydroelectric Electrica S.A. Scotia) facilities in Bolivia (Latin America) Compania Electrica Central Bulo 09/10/1999 Bolivia will eventually be the Bulo Bulo Bulo S.A. project company owned by Inversiones Bulo Bulo S.A. Conemaugh Power LLC 05/08/2000 Delaware entity holding title to 1,711 MW coal fired generating facility located Conemaugh, Pennsylvania Coniti Holding B.V. 06/09/1995 Netherlands international holding company for the Bulo Bulo project in La Paz, Bolivia Connecticut Jet Power LLC 07/30/1999 Delaware sells electricity Croatia Power Group 12/16/1999 Cayman Islands Cayman Island entity which holds 20% interest in the Central and Eastern Europe Project Power Fund (CEEP) Crockett Cogeneration, A California 01/11/1986 California owns Crockett cogeneration facility in Limited Partnership California Curtis/Palmer Hydroelectric Company 12/01/1985 New York owns Curtis/Palmer hydroelectric power plant in New York Deepwater Operations Inc. 05/08/2000 Delaware to act as a special purpose operating company to provide O&M services pursuant to a contract with Deepwater Power LLC Deepwater Power LLC 05/08/2000 Delaware entity holding title to 239 MW fossil fuel generating facility Pensville, New Jersey Denver City Energy Associates, L.P. 11/06/1996 4
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- Devon Power LLC 07/30/1999 Delaware sells electricity and thermal energy 401-MW generation capacity located on the Housatonic River at Milford, Conn. Dunkirk Power LLC 03/10/1999 Delaware entity holding title to Dunkirk Station, a four-unit, 600 MW plant, is located 55 miles southwest of Buffalo, New York ECK Generating, s.r.o. 11/30/1995 Czech Republic owns new 300+ MW coal fired power plant expansion under construction in Kladno, Czech Republic El Segundo Power II LLC 11/13/2000 Delaware project entity to install new units #5, #6 and #7 at the El Segundo Generating Station in California, with a target net electrical output of 641 MW El Segundo Power, LLC 11/25/1997 Delaware owns El Segundo gas fired power plant in California Elk River Resource Recovery, Inc. 02/06/1995 Minnesota inactive - proposed owner of Elk River waste processing facility in Minnesota Energeticke Centrum Kladno, s.r.o. 09/30/1992 Czech Republic owns existing coal fired power plant in Kladno, Czech Republic Energy Developments Limited 08/30/1991 Australia develops, owns and operates power (Queensland) generation and waste-to-energy projects in Australia, New Zealand, Asia and England Energy Investors Fund, L.P. 01/06/1988 Delaware domestic investment company which holds limited partner interests in Crockett, Curtis/Palmer, Windpower 87 and Windpower 88 projects; also a funding vehicle for numerous other unrelated projects in the U.S. Energy National, Inc. 09/13/1984 Utah domestic holding company which holds limited partner interests in Crockett, Curtis/Palmer, Maine Energy Recovery Company, Penobscot Energy Recovery Company, PowerSmith, Windpower 87, Windpower 88 projects; general partner in Penobscot Energy Recovery Co. Enfield Energy Centre Limited 03/05/1993 United Kingdom owns Enfield gas fired power plant in England 5
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- Enfield Holdings B.V. 03/27/1996 Netherlands international holding company for Enfield Energy Centre Limited project in England. Enfield Operations (UK) Limited 11/04/1997 United Kingdom holds employees for Enfield Operations, L.L.C. in England Enfield Operations, L.L.C. 08/07/1997 Delaware operates Enfield gas fired power plant in England ENI Chester, Limited Partnership 10/05/1992 Oregon inactive - was limited partner in Beaver Wood Project (wood burning project) in Chester, Maine ENI Crockett Limited Partnership 04/10/1995 Oregon limited partner in Crockett Cogeneration, A California Limited Partnership ENI Curtis Falls, Limited 10/05/1992 Oregon limited partner in Curtis/Palmer Partnership Hydroelectric Company Enifund, Inc. 04/22/1988 Utah holds property (house at Crockett cogeneration facility) and provides consulting services to Maine Energy Recovery Company Enigen, Inc. 08/17/1987 Utah general partner in The PowerSmith Cogeneration Project, Limited Partnership Entrade d.o.o. 07/14/2000 Slovenia Slovenian branch of Entrade GmbH Entrade Deutschland GmbH 06/02/2000 Berlin, Germany German branch of Entrade GmbH Entrade GmbH 01/23/1998 Switzerland Swiss energy trading company 6
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- Entrade Holdings B.V. 04/07/2000 Netherlands international holding company registered to do business in Switzerland for Entrade GmbH ESOCO Crockett, Inc. 12/09/1992 Oregon operates Crockett cogeneration facility in California ESOCO Fayetteville, Inc. 08/30/1996 Oregon inactive - proposed operator of Fayetteville waste-to-energy facility in North Carolina ESOCO Molokai, Inc. 02/06/1990 Utah inactive - proposed operator of Molokai biomass fueled power plant in Hawaii ESOCO Orrington, Inc. 02/01/1989 Utah operates Penobscot Energy Recovery Company in Maine ESOCO Soledad, Inc. 02/06/1990 Utah inactive - proposed operator of Soledad wood burning power plant in California ESOCO Wilson, Inc. 09/17/1996 Oregon inactive - proposed operator of Carolina Energy waste-to-energy facility and transfer station in North Carolina ESOCO, Inc. 02/01/1989 Utah domestic holding company for individual Esoco O&M companies European Generating S.a.r.l. 10/16/2000 Luxembourg Project holding company for Rybnik project Flinders Coal Pty Ltd 03/31/2000 Australia entity holding title to 760 MW coal fired station in Leigh Creek, South Australia Flinders Labuan (No. 1) Ltd. 08/03/2000 Labuan Holding company for Flinders project in South Australia 7
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- Flinders Labuan (No. 2) Ltd. 08/03/2000 Labuan Holding company for Flinders project in South Australia Flinders Osborne Trading Pty Ltd 08/17/2000 Australia trading entity for 760 MW coal fired station in Leigh Creek, South Australia Flinders Power Finance Pty Ltd 08/14/2000 Australia finance holding title to 760 MW coal fired station in Leigh Creek, South Australia Four Hills, LLC 08/19/1996 Delaware landfill gas collection system for Nashua project in New Hampshire Gladstone Power Station Joint 03/30/1994 Australia owns Gladstone coal fired power plant Venture (unincorporated) in Australia GPP Investors I, LLC 06/23/1997 Delaware Granite II Holding, LLC 07/16/1999 Delaware Granite Power Partners II, L.P. 01/31/1996 Delaware Graystone Corporation 05/25/1989 Minnesota general partner in Louisiana Energy Services, L.P. Gunwale B.V. 11/19/1979 Netherlands holds shares in NRGenerating Holdings (No. 4) B.V. for Loy Yang project in Australia Huntley Power LLC 03/10/1999 Delaware entity holding title to the Huntley Station, located three miles north of Buffalo, is Niagara Mohawk's largest coal-fired plant and is comprised of six units with a total nominal rating of 760 MW 8
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- Indian River Operations Inc. 05/08/2000 Delaware to act as a special purpose operating company to provide O&M services pursuant to a contract with Indian River Power LLC Indian River Power LLC 05/08/2000 Delaware entity holding titlec to 784 MW coal fired generating facility located in Millsboro, Delaware Inversiones Bulo Bulo S.A. 09/10/1999 Bolivia holding company that will eventually indirectly own the Bulo Bulo project. Itiquira Energetica S.A. 09/15/2000 Brazil entity formed to develop, construct, own and operate a 156 MW hydroelectric power generation facility in the State of Mato Grosso, Brazil Jackson Valley Energy Partners, L.P. 05/21/1991 California owns and operates waste lignite/cogeneration plant and lignite mining and reclamation operation in California Kanel Kangal Elektrik Limited 04/14/1998 Turkey will own 450 MW coal-fired Kangal plant Sirketi in central Turkey Kaufman Cogen LP 05/24/1999 Delaware Keystone Power LLC 05/08/2000 Delaware entity holding title to 1,711 MW coal fired generating facility located near Pittsburgh, Pennsylvania Kiksis B.V. 12/30/1985 Netherlands inactive - was to be used for first tier Dutch B.V. for Estonia project Killingholme Generation Limited 10/11/1999 United Kingdom project company for Killingholme Power Station in England Killingholme Holdings Limited 02/20/2000 United Kingdom additional holding company formed to hold interest in Killingholme Power Station through KGL in England 9
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- Killingholme Power Limited 05/25/1999 United Kingdom project company for 665MW gas-fired Killingholme A combined-cycle, gas-turbine power station in North Lincolnshire, England. Kingston Cogeneration Limited Canada (Ontario) owns Kingston cogeneration facility in Partnership Ontario, Canada Kissimee Power Partners, Limited 02/18/1992 Delaware limited partner in Cypress Energy Partnership Partners, Limited Partnership in Florida Kladno Power (No. 1) B.V. 01/23/1995 Netherlands international holding company in Energeticke Centrum Kladno, s.r.o. in Czech Republic Kladno Power (No. 2) B.V. 01/23/1995 Netherlands international holding company in Matra Powerplant Holding B.V. in Czech Republic (ECKG) Kraftwerk Schkopau Germany operates Schkopau coal fired power Betriebsgesellschaft mbH plant in Germany Kraftwerk Schkopau GbR Germany owns Schkopau coal fired power plant assets in Germany KUSEL Kutahya Seyitomer Elektrik 04/19/2000 Turkey will own as a part of a consortium Limited Sirketi Seyitomer 600 MW lignite-fired plant plant in Turkey Lakefield Junction LLC 06/30/1998 Delaware owns peaking plant 550-megawatt (MW) generation facility consisting of six natural gas-fired combustion turbine generators Lambique Beheer B.V. 01/06/1977 Netherlands international holding company in MIBRAG B.V. and Mitteldeutsche Braunkohlengesellschaft mbH in Germany Landfill Power LLC 05/02/1994 Wyoming owns and operates Flying Cloud landfill gas fueled power generation facility in Eden Prairie, Minnesota 10
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- Langage Energy Park Limited 11/30/1999 United Kingdom will own land for project in Plymouth England???? Le Paz Incorporated 06/01/1990 Minnesota limited partner in Louisiana Energy Services, L.P. LFG Partners, L.L.C. 08/10/1995 Delaware inactive - landfill gas collection system for Yaworski project in Connecticut Long Beach Generation LLC 02/04/1998 Delaware owns Long Beach gas fired power plant in California Long Island Cogeneration, L.P. 11/01/1997 New York inactive - holds contracts for Long Island cogeneration facility in New York which was never constructed Louisiana Energy Services, L.P. 04/09/1990 Delaware owns uranium enrichment facility under development in Louisiana Louisiana Generating LLC 06/14/1996 Delaware will own Cajun non-nuclear generating assets in Louisiana (including gas and coal fired generation) 1,708MW Loy Yang Power Management Pty Ltd 03/25/1997 Australia operates Loy Yang coal fired power (Victoria) plant in Australia Loy Yang Power Partners 04/17/1997 Australia Name of Partnership (4 owners) for owns Loy Yang coal fired power plant in Australia Loy Yang Power Projects Pty Ltd 03/25/1997 Australia provides technical services to Loy Yang (Victoria) coal fired power plant in Australia LS Power Management, LLC 07/29/1998 Delaware 11
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- LSP Batesville Funding Corporation 08/03/1998 Delaware LSP Batesville Holding, LLC 07/29/1998 Delaware LSP Energy Limited Partnership 02/07/1996 Delaware LSP Energy, Inc. 02/01/1996 Delaware LSP Equipment, LLC 10/19/1999 Delaware LSP-Denver City, Inc. 10/01/1996 Delaware LSP-Hardee Energy, LLC 08/25/2000 Delaware LSP-Kendall Energy, LLC 11/02/1998 Delaware LSP-Nelson Energy, LLC 03/01/1999 Delaware LSP-Pike Energy, LLC 01/21/2000 Delaware Maine Energy Recovery Company 06/30/1983 Maine owns waste-to-energy facility in Biddeford, Maine 12
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- Matra Powerplant Holding B.V. 11/28/1995 Netherlands international holding company in ECK Generating, s.r.o. in Czech Republic Meriden Gas Turbines LLC 12/20/2000 Delaware project entity to hold 540 MW greenfield natural gas-fired combined cycle electric generating facility in central Connecticut MESI Fuel Station #1 LLC 10/28/1999 Delaware Project company for MIBRAG B.V. 12/09/1993 Netherlands owns 99% of MIBRAG coal mines and coal fired power plants in Germany MidAtlantic Generation Holding LLC 08/20/2000 Delaware domestic holding company for MidAtlantic region Mid-Continent Power Company, L.L.C. 12/12/1997 Delaware owns Mid-Continent Power Company cogeneration facility in Oklahoma Middletown Power LLC 07/30/1999 Delaware sells electricity and thermal energy- 856MW steam-powered plant located beside the Connecticut River in Middletown, Conn Minnesota Methane Holdings LLC 04/08/1996 Delaware inactive - domestic holding company Minnesota Methane II LLC 04/08/1997 Delaware owns and operates original 3 NEO/Ziegler landfill gas projects (Edward Kraemer in Burnsville, MN; Flying Cloud in Eden Prairie, MN and Nashua in New Hampshire) Minnesota Methane LLC 10/15/1993 Wyoming owns and operates 18 landfill gas projects in the U.S. financed by Lyon Credit Minnesota Waste Processing Company, 11/01/1993 Delaware owns municipal solid waste processing L.L.C. facility and transfer station in Minnesota 13
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- Mitteldeutsche 11/30/1993 Germany operates MIBRAG coal mines and coal Braunkohlengesellschaft mbH fired power plants in Germany MM Albany Energy LLC 01/08/1997 Delaware landfill gas fueled power generation for project in New York MM Biogas Power LLC 04/08/1996 Delaware domestic holding company - owns 100% interest in landfill gas fueled power generation projects not being financed MM Burnsville Energy LLC 10/14/1997 Delaware landfill gas fueled power generation for Edward Kraemer landfill in Minnesota MM Corona Energy LLC 01/08/1997 Delaware landfill gas fueled power generation for O'Brien project in California MM Cuyahoga Energy LLC 06/18/1997 Delaware landfill gas fueled power generation for project in Cleveland, Ohio MM El Sobrante Energy LLC 02/10/2000 Delaware landfill gas power generation in California MM Erie Power LLC 08/17/1999 Delaware landfill gas fueled power generation for project in Denver, Colorado MM Ft. Smith Energy LLC 10/14/1997 Delaware will sell landfill gas to other companies in Arkansas - not a GENCO MM Hackensack Energy LLC 04/08/1997 Delaware landfill gas fueled power generation for HMDC/Balefill/Kingsland O'Brien projects in Lyndhurst, New Jersey MM Hartford Energy LLC 05/16/1997 Delaware landfill gas fueled power generation for project in Connecticut 14
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- MM Lopez Energy LLC 12/13/1996 Delaware landfill gas fueled power generation for Lopez Canyon project in Los Angeles, California MM Lowell Energy LLC 01/08/1997 Delaware landfill gas fueled power generation for project in Massachusetts MM Martinez Energy LLC 08/17/1999 Delaware landfill gas fueled power generation for project in California MM Nashville Energy LLC 06/20/1997 Delaware landfill gas fueled power generation for project in Tennessee MM Northern Tier Energy LLC 03/11/1997 Delaware landfill gas fueled power generation for project in Pennsylvania MM Phoenix Energy LLC 01/20/1998 Delaware landfill gas fueled power generation for project in Arizona MM Prima Deshecha Energy LLC 01/08/1997 Delaware landfill gas fueled power generation for project in Orange County, California MM Prince William Energy LLC 06/18/1997 Delaware landfill gas fueled power generation for project in Virginia MM Riverside LLC 12/19/1996 Delaware landfill gas fueled power generation for project in California MM San Bernardino Energy LLC 11/13/2000 Delaware MM San Diego LLC 01/08/1997 Delaware landfill gas fueled power generation for Miramar project in California 15
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- MM SKB Energy LLC 06/20/1997 Delaware landfill gas fueled power generation for project in Pennsylvania MM Spokane Energy LLC 01/08/1997 Delaware landfill gas fueled power generation for project in Washington MM Tacoma LLC 12/19/1996 Delaware landfill gas fueled power generation for project in Washington MM Tajiguas Energy LLC 01/20/1998 Delaware landfill gas fueled power generation for project in Santa Barbara, California MM Taunton Energy LLC 01/08/1997 Delaware landfill gas fueled power generation for project in Massachusetts MM Tomoka Farms Energy LLC 03/11/1997 Delaware landfill gas fueled power generation for Volusia project in Florida MM Tri-Cities Energy LLC 02/10/2000 Delaware landfill gas power generation in California MM Tulare Energy LLC 05/16/1997 Delaware landfill gas fueled power generation for Visalia project in California MM West Covina LLC 12/04/1995 Delaware landfill gas fueled power generation for BKK project in California MM Woodville Energy LLC 02/11/1998 Delaware landfill gas fueled power generation for project in California MM Yolo Power LLC 02/14/1996 Delaware landfill gas fueled power generation for project in California 16
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- MMSB Transco Holdings LLC 12/30/1998 Delaware transport landfill gas for re-sale Montville Power LLC 07/30/1999 Delaware sells electricity and thermal energy -498MW Montville Station is located on the Thames River in Uncasville, Conn Mt. Poso Cogeneration Company, A 10/15/1986 California owns Mt. Poso cogeneration facility in California Limited Partnership California NEO Albany, L.L.C. 09/12/1995 Delaware landfill gas collection system for project in New York NEO Burnsville, LLC 10/25/1996 Delaware landfill gas collection system for Edward Kraemer landfill in Minnesota NEO California Power LLC 09/21/2000 Delaware entity formed to submit bid to California ISO on 3,000 MW of distributed generation. NEO Chester-Gen LLC 07/13/2000 Delaware owns 3.4 MW cogeneration facility in Chester, Pennsylvania NEO Corona LLC 01/08/1997 Delaware landfill gas collection system for O'Brien project in California NEO Corporation 05/27/1993 Minnesota develops, owns and operates landfill gas, hydroelectric and small cogeneration projects in the U.S. NEO Cuyahoga, LLC 10/31/1996 Delaware landfill gas collection system for project in Cleveland, Ohio NEO ECO 11 LLC 05/09/2000 Delaware will own a 50% interest in a Synthetic coal processing facility - currently inactive - will close within a month or so 17
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- NEO Edgeboro, LLC 01/06/1997 Delaware landfill gas collection system for O'Brien project in New Jersey NEO El Sobrante LLC 02/10/2000 Delaware landfill gas collection system NEO Erie LLC 08/17/1999 Delaware landfill gas collection system for project in Denver, Colorado NEO Fitchburg LLC 01/16/1997 Delaware landfill gas collection system for project in Massachusetts NEO Freehold-Gen LLC 07/13/2000 Delaware owns 2.1 MW cogeneration facility in Freehold, NJ NEO Ft. Smith LLC 10/14/1997 Delaware landfill gas collection system for project in Arkansas NEO Hackensack, LLC 01/06/1997 Delaware landfill gas collection system for HMDC/Balefill/Kingsland O'Brien projects in Lyndhurst, New Jersey NEO Hartford, LLC 10/13/1995 Delaware landfill gas collection system for project in Connecticut NEO Landfill Gas Holdings Inc. 04/08/1996 Delaware domestic holding company - provides O&M services for landfill gas projects NEO Landfill Gas Inc. 04/08/1996 Delaware domestic holding company - holds 99% interest in landfill gas collection system projects financed by Lyon Credit NEO Lopez Canyon LLC 01/04/1996 Delaware landfill gas collection system for project in Los Angeles, California 18
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- NEO Lowell LLC 01/16/1997 Delaware landfill gas collection system for project in Massachusetts NEO Martinez LLC 08/18/1999 Delaware landfill gas collection system for project in California NEO MESI LLC 10/12/1999 Delaware produce and sell synthetic fuel (coal briquettes) in Kentucky NEO Nashville LLC 06/20/1997 Delaware landfill gas collection system for project in Tennessee NEO Northern Tier LLC 03/11/1997 Delaware landfill gas collection system for project in Pennsylvania NEO Phoenix LLC 01/04/1996 Delaware landfill gas collection system for project in Arizona NEO Power Services Inc. 04/11/2000 Delaware NEO Prima Deshecha LLC 01/16/1997 Delaware landfill gas collection system for project in Orange County, California NEO Prince William, LLC 10/30/1996 Delaware landfill gas collection system for project in Virginia NEO Riverside LLC 12/19/1996 Delaware landfill gas collection system for project in California NEO San Bernardino LLC 06/26/1998 Delaware landfill gas collection system for project in California 19
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- NEO San Diego LLC 10/12/1995 Delaware landfill gas collection system for Miramar project in California NEO SKB LLC 10/14/1997 Delaware landfill gas collection system for project in Pennsylvania NEO Spokane LLC 11/22/1995 Delaware landfill gas collection system for project in Washington NEO Tacoma, L.L.C. 10/31/1995 Delaware landfill gas collection system for project in Washington NEO Tajiguas LLC 12/05/1995 Delaware landfill gas collection system for project in Santa Barbara, California NEO Taunton LLC 01/16/1997 Delaware landfill gas collection system for project in Massachusetts NEO Toledo-Gen LLC 07/13/2000 Delaware owns 1.0 MW cogeneration facility in Toledo, Ohio NEO Tomoka Farms LLC 12/05/1995 Delaware landfill gas collection system for Volusia project in Florida NEO Tri-Cities LLC 02/10/2000 Delaware landfill gas collection system in California NEO Tulare LLC 12/05/1995 Delaware landfill gas collection system for Visalia project in California NEO West Covina LLC 07/16/1997 Delaware landfill gas collection system for BKK project in California 20
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- NEO Woodville LLC 02/11/1998 Delaware landfill gas collection system for project in California NEO Yolo LLC 12/23/1996 Delaware landfill gas collection system for project in California New Haven Harbor Power LLC 01/25/2001 Delaware entity to hold title to 466 MW fossil fuel-fired generating facility located in southern Connecticut North American Thermal Systems 07/27/1995 Ohio develops district heating and cooling Limited Liability Company projects in the U.S.; general partner in Pittsburgh Thermal, Limited Partnership and San Francisco Thermal, Limited Partnership Northbrook Acquisition Corp. 12/23/1994 Delaware domestic holding company in STS Hydropower Ltd. Northbrook Carolina Hydro, L.L.C. 10/05/1995 Delaware owns and operates hydroelectric power plants in North Carolina and South Carolina Northbrook Energy, L.L.C. 11/04/1994 Delaware develops hydroelectric power projects in the U.S. Northbrook New York LLC 06/21/1999 Delaware Project company Northeast Generation Holding LLC 04/29/1999 Delaware to hold 50% interest in NRG Northeast Generating LLC Norwalk Power LLC 07/30/1999 Delaware sells electricity and thermal energy-353MW on Manresa Island at the mouth of Norwalk Harbor NR(Gibraltar) 12/11/1998 Gibraltar inactive company utilized during the Enfield transactions in England 21
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- NRG Affiliate Services Inc. 01/11/2000 Delaware sponsor and hold the contracts and 401k plans for CL&P, Somerset and other entities. NRG Arthur Kill Operations Inc. 04/29/1999 Delaware Special purpose operating company to provide O&M services contract to Arthur Kill Power LLC NRG Asia-Pacific, Ltd. 04/23/1993 Delaware provides international business development services in Australia and the Pacific Rim region NRG Astoria Gas Turbine Operations 04/29/1999 Delaware Special purpose operating company to Inc. provide O&M services contract to Astoria Gas Turbine Power LLC NRG Bridgeport Harbor Operations 12/13/2000 Delaware Operating entity for Bridgeport Harbor Inc. Station, a 585 MW fossil fuel-fired generating facility located in southern Connecticut NRG Cabrillo Power Operations Inc. 04/19/1999 Delaware Special purpose operating company to provide O&M services contract to Cabrillo Power I LLC and Cabrillo Power II LLC NRG Cadillac Inc. 04/15/1997 Delaware domestic holding company in Cadillac Renewable Energy LLC NRG Cadillac Operations Inc. 08/15/1997 Delaware proposed operator for Cadillac wood fired power plant in Michigan NRG Caymans Company 12/07/1999 Cayman Islands Cayman Island holding company for Croatia Power Group NRG Caymans-C 12/09/1999 Cayman Islands Cayman Island holding company for SLAP-C corporation interests NRG Caymans-P 12/09/1999 Cayman Islands Cayman Island holding company for SLAP-P partnership interests 22
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- NRG Central U.S. LLC 01/12/2000 Delaware to hold 50% interest in NRG Central Generating LLC (issuer in the Cajun deal) NRG Collinsville Operating Services 11/23/1995 Australia international holding company in Pty Ltd Collinsville Operations Pty Ltd in Australia NRG ComLease LLC 10/03/2000 Delaware entity used to hold Lease Agreements for placement of cell towers on NRG owned stacks NRG Connecticut Affiliate Services 09/23/1999 Delaware This entity will house the payroll for Inc. the four Connecticut Operations, sponsor the Pension, 401(k), Welfare plans, etc. (NRG Middletown Operations Inc., NRG Montville Operations Inc., NRG Norwalk Harbor Operations Inc., NRG Devon Operations Inc.) NRG Connecticut Ancillary Assets LLC 01/25/2001 Delaware project entity for Bridgeport Harbor Station, a 585 MW fossil fuel-fired generating facility located in southern Connecticut NRG Connecticut Generating LLC 12/09/1999 Delaware Sole Member of Devon Power LLC, Norwalk Power LLC, Middletown Power LLC, Montville Power LLC and Connecticut Jet Power LLC NRG Connecticut Power Assets LLC 01/25/2001 Delaware project entity for New Haven Harbor Station, a 466 MW fossil fuel-fired generating facility located in southern Connecticut NRG Development Company Inc. 08/30/1999 Delaware entity created to limit development exposure on projects where NRG Energy, Inc. is pursuing the transaction with certain types of partners on DOMESTIC transactions NRG Devon Operations Inc. 08/23/1999 Delaware special purpose operating company to provide O&M services contract to Devon Power LLC NRG Dunkirk Operations Inc. 04/29/1999 Delaware Special purpose operating company to provide O&M services contract to Dunkirk Power LLC NRG Eastern LLC 04/29/1999 Delaware to hold 50% interest in NRG Northeast Generating LLC 23
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- NRG El Segundo Operations Inc. 01/20/1998 Delaware proposed operator for El Segundo (and Long Beach as soon NRG Long Beach Operations Inc. is merged into this entity) gas fired power plants in California NRG Energeticky Provoz, s.r.o. 06/06/1997 Czech Republic operates coal fired power plants in Kladno, Czech Republic NRG Energy Center Dover LLC 07/12/2000 Delaware own 18 MW cogeneration facility and 80 MW expansion project in Dover, Delaware. NRG Energy Center Grand Forks LLC 10/27/1999 Delaware owns assets in connection with a contract to provide steam at the Grand Forks Air Force Base NRG Energy Center Harrisburg Inc. 04/25/2000 Delaware entity to provide steam to the central business district of Harrisburg, PA NRG Energy Center Minneapolis LLC 10/27/1999 Delaware owns and operates the district heating and cooling system serving customers in the downtown Minneapolis area NRG Energy Center Paxton Inc. 04/25/2000 Delaware will own the cogen and sell steam to NRG Energy Center Harrisburg Inc. NRG Energy Center Pittsburgh LLC 10/27/1999 Delaware eventually will own and operate the Pittsburgh Thermal district heating and cooling plant which currently serves approx 25 customers in the Pittsburgh area. Will be regulated under the Pennsylvania Public Utility Commission Rules NRG Energy Center Rock Tenn LLC 10/27/1999 Delaware owns assets in connection with the sale of steam to Rock-Tenn Corporation in St. Paul. NRG Energy Center Round Mountain LLC 01/12/2001 Delaware will own and operate a 44 MW cogeneration facility to be located in Bakersfield, CA NRG Energy Center San Diego LLC 10/27/1999 Delaware eventually will own and operate San Diego Power & Cooling, a chilled water plant serving customers in downtown San Diego area 24
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- NRG Energy Center San Francisco LLC 07/30/1991 Delaware provides district heating and cooling services in California NRG Energy Center Washco LLC 10/27/1999 Delaware Owns assets in connection with the sale of steam to Anderson Corporation and the State of Minnesota Correctional Facility NRG Energy CZ, s.r.o. 11/01/1995 Czech Republic provides international business development services in the Czech Republic and Europe NRG Energy Development GmbH 08/16/1994 Germany provides international business development services in Germany and Europe NRG Energy Jackson Valley I, Inc. 04/10/1991 California general partner in Jackson Valley Energy Partners, L.P. NRG Energy Jackson Valley II, Inc. 04/10/1991 California limited partner in (i) Jackson Valley Energy Partners, L.P., (ii) San Joaquin Valley Energy Partners I, L.P., (iii) San Joaquin Valley Energy Partners IV, L.P. and (iv) Bioconversion Partners, L.P. NRG Energy Ltd. 10/19/1993 United Kingdom provides international business development services in the U.K. and Europe NRG Energy PL Sp. z o.o. 10/01/1999 Poland provides international business development services in Poland NRG Energy, Inc. 05/29/1992 Delaware develops, builds, acquires, owns and operates non-regulated energy-related businesses world-wide NRG Finance Company I LLC 02/06/2001 Delaware Will act as the borrower under the proposed $2 billion construction revolver NRG Flinders Operating Services Pty 08/14/2000 Australia operating entity for 760 MW coal fired Ltd station in Leigh Creek, South Australia 25
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- NRG Gladstone Operating Services 09/23/1993 Australia operates Gladstone coal fired power Pty Ltd plant in Australia NRG Gladstone Superannuation Pty Ltd 10/29/1993 Australia holds pension assets for employees of Gladstone coal fired power plant in Australia NRG Granite Acquisition LLC 11/03/2000 Delaware Holding company for LS Power acquisition NRG Huntley Operations Inc. 04/29/1999 Delaware Special purpose operating company to provide O&M services contract to Huntley Power LLC NRG International Development Inc. 10/14/1999 Delaware entity created to limit development exposure on projects where NRG Energy, Inc. is pursuing the transaction with certain types of partners on INTERNATIONAL transactions NRG International II Inc. 12/04/1997 Delaware domestic holding company NRG International III Inc. 11/17/2000 Delaware domestic holding company - Dutch restructuring NRG International Services Company 01/21/1998 Delaware holds service agreements with expatriates and international consultants NRG International, Inc. 10/21/1992 Delaware domestic holding company NRG Kaufman LLC 12/11/2000 Delaware holding company for power generation project near Mesquite, Texas. The general partner of Kaufman Cogen LP NRG Lakefield Inc. 02/05/1999 Delaware special purpose entity to hold NRG's 50% member interest in Lakefield Junction LLC 26
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- NRG Lakefield Junction LLC 02/17/2000 Delaware entity formed to act as limited partner in Lakefield Junction L.P. in order to develop, construct, own and operate peaking power generating facility in Martin County, Minnesota NRG Latin America Inc. 08/18/1997 Delaware provides international business development services in Latin America NRG Louisiana LLC 04/07/2000 Delaware Hold for potential Conoco project. NRG Mesquite LLC 12/11/2000 Delaware project company for power generation project near Mesquite, Texas. The limited partner of Kaufman Cogen LP NRG Mextrans Inc. 09/21/1999 Delaware This entity will develop a transmission line from Palo Verde power station through Arizona, into Mexico and back up into California, per a Presidential Permit (in development stage). NRG MidAtlantic Affiliate Services 02/14/2001 Delaware Payroll company for O&M employees Inc. arising out of Conectiv acquisition. Will have 300-400 employees first year. NRG MidAtlantic Generating LLC 05/08/2000 Delaware holds 50% interest in MidAtlantic Generation Holding LLC NRG MidAtlantic LLC 08/23/2000 Delaware holds 50% interest in MidAtlantic Generation Holding LLC NRG Middletown Operations Inc. 08/23/1999 Delaware special purpose operating company to provide O&M services contract to Middletown Power LLC NRG Montville Operations Inc. 08/23/1999 Delaware special purpose operating company to provide O&M services contract to Montville Power LLC NRG New England Affiliate Services 02/14/2001 Delaware Payroll company for O&M employees Inc. arising out of Wisvest acquisition. Will have 150-200 employees first year. 27
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- NRG New Haven Harbor Operations Inc. 12/13/2000 Delaware Operating entity for New Haven Harbor Station, a 466 MW fossil fuel-fired generating facility located in southern Connecticut NRG New Roads Generating LLC 07/19/1996 Delaware inactive - alternative domestic holding company for Cajun non-nuclear generating assets in Louisiana (including gas and coal fired generation) NRG New Roads Holdings LLC 03/07/2000 Delaware Holding company to hold title to certain Cajun assets that, due to federal regulatory reasons could not be held by Louisiana Generating LLC NRG Northeast Affiliate Services 05/19/1999 Delaware manage payroll and benefits for Huntley Inc. and Dunkirk (approximately 330 employees) NRG Northeast Generating LLC 03/11/1999 Delaware special purpose holding company entity to facilitate east coast pool financing NRG Norwalk Harbor Operations Inc. 08/23/1999 Delaware Special purpose operating company to provide O&M services contract to Oswego Power LLC and Norwalk Power LLC NRG Operating Services, Inc. 10/21/1992 Delaware currently provides O&M services for Artesia, Cadillac, Collinsville, Gladstone and Minneapolis Energy Center projects NRG Oswego Harbor Power Operations 04/29/1999 Delaware Special purpose operating company to Inc. provide O&M services contract to Oswego Power LLC NRG PacGen Inc. 10/28/1997 Delaware domestic holding company which acquired 100% of the stock of Pacific Generation Company NRG Pensions Limited United Kingdom Entity to hold pensions for UK Employees/Killingholme NRG Power Marketing Inc. 08/18/1997 Delaware holds power marketing license 28
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- NRG Processing Solutions LLC 08/23/2000 Delaware formed to own certain assets for the intake, separation, processing and sale of yard waste and separated organize compost (acquire assets from SKB Environmental) NRG Rocky Road LLC 10/04/1999 Delaware special purpose LLC formed to hold the 50% membership interest in Rocky Road LLC (a potential acquisition from Dynegy) (single member LLC) natural gas-fired, simple-cycle peaking facility in East Dundee, Il. NRG Sabine River Works GP LLC 11/13/2000 Delaware general partner of the Sabine River 450 MW gas-fired cogeneration project under construction in Orange, Texas NRG Sabine River Works LP LLC 11/13/2000 Delaware limited partner of the Sabine River 450 MW gas-fired cogeneration project under construction in Orange, Texas NRG Services Corporation 06/06/1996 Delaware provides payroll and benefits services through service agreements with individual O&M companies NRG South Central Affiliate 02/14/2001 Delaware Payroll company for O&M employees Services Inc. arising out of acquisition in the south central region. Will have 50 employees first year. NRG South Central Generating LLC 01/12/2000 Delaware special purpose holding company entity to facility central pool financing NRG Sterlington Power LLC 11/13/1998 Delaware entity holding title to 200 MW simply cycle gas peaking facility in Sterlington, Louisiana NRG Sunnyside Operations GP Inc. 02/15/1995 Delaware general partner in Sunnyside Operations Associates L.P. NRG Sunnyside Operations LP Inc. 02/15/1995 Delaware limited partner in Sunnyside Operations Associates L.P. NRG Thermal Corporation 10/25/1999 Delaware the sole member of all the llcs under the new thermal restructuring 29
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- NRG Thermal Operating Services LLC 10/27/1999 Delaware at this time has no assets NRG Thermal Services Inc. 07/05/2000 Delaware This entity will hold the chiller plant assets and diesel services business for NRG Energy Center Harrisburg Inc. NRG Valmy Power Holdings LLC 11/15/2000 Delaware holding company for 50% interest in Valmy Power LLC NRG Valmy Power LLC 11/15/2000 Delaware holding company for 50% interest in Valmy Power LLC NRG Victoria I Pty Ltd 12/10/1996 Australia international holding company in NRG Victoria II Pty Ltd and NRG Victoria III Pty Ltd in Australia NRG Victoria II Pty Ltd 12/10/1996 Australia international holding company in NRG Victoria III Pty Ltd in Australia NRG Victoria III Pty Ltd 12/10/1996 Australia international holding company in Energy Developments Limited in Australia NRG West Coast Inc. 06/02/1999 Delaware to act as holding company for West coast limited liability companies NRG Western Affiliate Services Inc. 08/27/1999 Delaware manage payroll and benefits for El Segundo and Long Beach NRGenerating (Gibraltar) 08/11/2000 Gibraltar Gibraltar entity formed to assist with the NRGIBV/Australian holding structure through Luxembourg NRGenerating Energy Trading Ltd. 02/20/2000 United Kingdom international power marketing entity held under NRGenerating, Ltd. in England 30
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- NRGenerating Holdings (No. 1) B.V. 06/12/1995 Netherlands international holding company in Collinsville Power Joint Venture in Australia NRGenerating Holdings (No. 11) B.V. 07/08/1996 Netherlands will own assets for Langage Energy Park project in Plymouth England NRGenerating Holdings (No. 13) B.V. 03/17/1999 Netherlands will own land for power plant on greenfield site at Langage England (f/k/a Plymouth Energy Centre) NRGenerating Holdings (No. 14) B.V. 03/17/1999 Netherlands international holding company registered to do business in Estonia NRGenerating Holdings (No. 15) B.V. 03/17/1999 Netherlands Dutch holding company registered to do business in England for use with the Killingholme project NRGenerating Holdings (No. 16) B.V. 03/17/1999 Netherlands inactive - international holding company registered to do business in [HOLD FOR SHAUN] NRGenerating Holdings (No. 17) B.V. 03/17/1999 Netherlands Dutch holding company registered to do business in TURKEY will hold interest in consortium called KUSEL Kutahya Seyitomer Elektrik Limited Sirketi NRGenerating Holdings (No. 18) B.V. 04/07/2000 Netherlands international holding company for Rybnik project in Poland NRGenerating Holdings (No. 19) B.V. 04/07/2000 Netherlands inactive - international holding company registered to do business in NRGenerating Holdings (No. 2) GmbH 08/15/2000 Switzerland Swiss holding company for Flinders project in South Australia NRGenerating Holdings (No. 21) B.V. 04/07/2000 Netherlands inactive - international holding company registered to do business in 31
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- NRGenerating Holdings (No. 22) B.V. 04/07/2000 Netherlands inactive - international holding company registered to do business in NRGenerating Holdings (No. 23) B.V. 04/07/2000 Netherlands inactive - international holding company registered to do business in NRGenerating Holdings (No. 3) B.V. 09/04/1995 Netherlands inactive - Dutch holding company registered to do business in Australia - hold for Flinders bid in Australia (development projects) [HOLD for SHAUN] NRGenerating Holdings (No. 4) B.V. 09/04/1995 Netherlands Dutch holding company in Loy Yang Power Partners, Loy Yang Power Management Pty Ltd and Loy Yang Power Projects Pty Ltd in Australia NRGenerating Holdings (No. 5) B.V. 02/09/1996 Netherlands Dutch holding company in NRG Energeticky Provoz, s.r.o. in the Czech Republic NRGenerating Holdings (No. 6) B.V. 02/09/1996 Netherlands inactive - Dutch holding company registered to do business in Australia - hold for Ecogen assets in Victoria / Transalta and AGL) [HOLD for SHAUN] NRGenerating Holdings (No. 7) B.V. 03/27/1996 Netherlands inactive - international holding company for West Java O&M company in formation in Indonesia NRGenerating Holdings (No. 8) B.V. 03/27/1996 Netherlands inactive - international holding company for West Java O&M company in formation in Indonesia NRGenerating Holdings (No. 9) B.V. 03/27/1996 Netherlands Dutch holding company registered to do business in Turkey for consortium called Kanel Kangal Elektrik Limited Sirketi NRGenerating Holdings GmbH 12/03/1999 Switzerland Swiss holding company for SLAP NRGenerating II (Gibraltar) 10/06/2000 Gibraltar inactive - Gibraltar entity formed to assist with the ___________ holding structure through Luxembourg 32
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- NRGenerating III (Gibraltar) 10/06/2000 Gibraltar inactive - Gibraltar entity formed to assist with the ___________ holding structure through Luxembourg NRGenerating International B.V. 07/15/1993 Netherlands Dutch holding company NRGenerating Luxembourg (No. 1) 08/08/2000 Luxembourg Luxembourg entity formed in connection S.a.r.l. with the Flinders project NRGenerating Luxembourg (No. 2) 08/08/2000 Luxembourg Luxembourg entity formed in connection S.a.r.l. with the Flinders project NRGenerating Rupali B.V. 06/12/1995 Netherlands inactive - international holding company for Rupali oil fired power plant bid in Pakistan NRGenerating, Ltd. 01/04/2000 United Kingdom UK holding company for Killingholme structure in England O Brien Biogas (Mazzaro), Inc. 02/26/1990 Delaware landfill gas collection system for project in Pennsylvania O Brien Biogas IV LLC 07/08/1997 Delaware landfill gas fueled power generation for Edgeboro project in New Jersey O Brien California Cogen Limited 01/12/1988 California owns Artesia cogeneration facility in California O Brien Cogeneration, Inc. II 12/31/1985 Delaware general partner in O'Brien California Cogen Limited O Brien Standby Power Energy, Inc. 12/06/1988 Delaware landfill gas fueled power generation for SKB project in Pennsylvania 33
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- Okeechobee Power I, Inc. 02/05/1992 Delaware general partner in Cypress Energy Partners, Limited Partnership Okeechobee Power II, Inc. 02/05/1992 Delaware general partner in Kissimee Power Partners, Limited Partnership Okeechobee Power III, Inc. 02/05/1992 Delaware limited partner in Kissimee Power Partners, Limited Partnership ONSITE Energy, Inc. 01/22/1986 Oregon domestic holding company for ONSITE Soledad, Inc. and ONSITE Marianas Corporation; also indirectly holds general partner interest in Mt. Poso project and limited partner interest in Turners Falls project ONSITE Funding Corporation 06/10/1988 Oregon inactive - provides funding to various ONSITE projects ONSITE Limited Partnership No. 1 06/08/1987 Oregon inactive - owned cogeneration facilities for bakery in Los Angeles or dairy in Michigan ONSITE Marianas Corporation 04/06/1988 Commonwealth of inactive - owned and operated Marianas the Northern solar energy plant in the Commonwealth Marianas Islands of Northern Mariana Islands in Pacific Ocean ONSITE Soledad, Inc. 02/06/1989 Oregon inactive - owned and operated Soledad wood burning power plant in California ONSITE/US Power Limited Partnership New Jersey inactive - owned Crossroads No. 1 cogeneration facility in New Jersey Orrington Waste, Ltd. Limited 01/13/1993 Oregon provides waste disposal services to Partnership municipalities to be delivered to waste disposal operators in Maine, including Penobscot Energy Recovery Company Oswego Harbor Power LLC 03/30/1999 Delaware This company was formed for the purpose of acquiring, operating and owning two, 850 MW oil-fired operating units and four retired units 34
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- OU Nrg Energy Est 07/14/2000 Estonia provides international business development services in Estonia P.T. Dayalistrik Pratama 05/15/1996 Indonesia will own and construct West Java coal fired power plant in Indonesia Pacific Crockett Energy, Inc. 02/06/1997 Utah general partner in Crockett Cogeneration, A California Limited Partnership Pacific Crockett Holdings, Inc. 02/14/1991 Oregon domestic holding company for Pacific Crockett Energy, Inc. Pacific Generation Company 08/03/1984 Oregon domestic holding company acquired by NRG (formerly a wholly owned subsidiary of PacifiCorp Holdings, Inc. which developed, built, owned, operated and managed energy production facilities); also a limited partner in Camas Power Boiler Limited Partnership Pacific Generation Development Oregon inactive - provided domestic business Company development services Pacific Generation Holdings Company 01/12/1995 Oregon domestic holding company for Pacific Generation Funding and Pacific Recycling Energy; holds limited partner interests in Carolina Energy, Ltd Ptshp and Project Finance Fund III; and indirectly holds general partner interest in Kingston Cogen Ltd Ptshp Pacific Generation Resources Company 11/21/1991 Oregon domestic holding company which holds limited partner interest in Long Island Cogeneration, L.P.; holds limited and general partner interests in Curtis/Palmer, Windpower 87 and Windpower 88 projects; general partner in ENI Chester, Limited Partnership Pacific Kingston Energy, Inc. 12/21/1995 Canada (Ontario) general partner in Kingston Cogeneration Limited Partnership Pacific Orrington Energy, Inc. 11/24/1992 Oregon holds general and limited partner interests in Orrington Waste, Ltd., Limited Partnership Pacific Recycling Energy, Inc. 12/15/1995 Oregon inactive - provided business development services for waste-to-energy projects 35
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- Pacific-Mt. Poso Corporation 06/08/1987 Oregon general partner in Mt. Poso Cogeneration Company, A California Limited Partnership Penobscot Energy Recovery Company, 08/15/1985 Maine owns waste-to-energy facility in Limited Partnership Orrington, Maine Power Operations, Inc. 11/06/1996 Delaware provides O&M services for Artesia, Cadillac, Newark and Parlin projects Project Finance Fund III, L.P. 10/28/1994 Delaware funding vehicle for various (primarily) international operating projects Prva Regulacna s.r.o. 08/10/1998 Slovakia Slovakian branch of Entrade GmbH Pyro-Pacific Operating Company 06/19/1987 California operates Mt. Poso cogeneration facility in California Reid Gardner Power LLC 11/15/2000 Delaware 605 MW four coal-fired units of the Reid Gardner power station and certain other related assets in Nevada Rocky Road Power, LLC Delaware holding ownership in generation facility in Dundee, Illinois. Rybnik Power B.V. 03/17/1999 Netherlands international holding company for Rybnik project in Poland Saale Energie GmbH 11/10/1993 Germany German holding company in Kraftwerk Schkopau Betriebsgesellschaft mbH, Kraftwerk Schkopau GbR and Saale Energie Services GmbH Saale Energie Services GmbH 12/16/1994 Germany provides consulting services to MIBRAG (Germany) 36
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- Sachsen Holding B.V. 02/04/1994 Netherlands Dutch holding company ifor P.T. Dayalistrik Pratama in Indonesia San Bernardino Landfill Gas Limited 09/18/1997 California limited partner to landfill gas Partnership, a California limited collection system for project in partnership California San Joaquin Valley Energy I, Inc. 01/21/1992 California general partner in San Joaquin Valley Energy Partners I, L.P. San Joaquin Valley Energy IV, Inc. 04/29/1992 California general partner in San Joaquin Valley Energy Partners IV, L.P. and Bioconversion Partners, L.P. San Joaquin Valley Energy Partners 04/30/1992 California owns and operates three biomass I, L.P. waste-fuel power plants (Chowchilla II, El Nido and Madera) in California San Joaquin Valley Energy Partners 05/20/1992 California holds remaining non-operating assets of IV, L.P. biomass waste-fuel power plant (Chowchilla I) in California Scoria Incorporated 07/20/1990 Minnesota holds license for synthetic coal technology Scudder Latin American Power I-C 07/05/1995 Cayman Islands, investment company which owns L.D.C. British West (primarily passive) investments in Indies Latin American power projects Scudder Latin American Power II-C 12/15/1997 Cayman Islands, investment company which owns L.D.C. British West (primarily passive) investments in Indies Latin American power projects - phase II Scudder Latin American Power 12/15/1997 Cayman Islands, investment company which owns II-Corporation A British West (primarily passive) investments in Indies Latin American power projects - phase II Scudder Latin American Power 12/15/1997 Cayman Islands, investment company which owns II-Corporation B British West (primarily passive) investments in Indies Latin American power projects - phase II 37
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- Scudder Latin American Power II-P 12/15/1997 Cayman Islands, investment company which owns L.D.C. British West (primarily passive) investments in Indies Latin American power projects - phase II Scudder Latin American Power I-P 07/05/1995 Cayman Islands, investment company which owns L.D.C. British West (primarily passive) investments in Indies Latin American power projects Somerset Operations Inc. 11/17/1998 Delaware proposed operator for Somerset coal fired power plant in Massachusetts Somerset Power LLC 11/17/1998 Delaware This company was formed for the purpose of acquiring, operating and owning the electric generating plant in Somerset, Massachusetts South Central Generation Holding LLC 01/12/2000 Delaware to hold 50% interest in NRG Central Generating LLC (issuer in the Cajun deal) Southwest Generation LLC 11/15/2000 Delaware holding company for Clark and Reid Gardner project companies Southwest Power Holdings LLC 11/15/2000 Delaware holding company for Southwest Generation LLC and Clark and Reid Gardner project in Nevada SRW Cogeneration Limited Partnership owner of the Sabine River 450 MW gas-fired cogeneration project under construction in Orange, Texas Sterling (Gibraltar) 02/08/2000 Gibraltar Gibraltar entity formed to assist with the NRGenerating, Ltd./UK holding structure through Luxembourg Sterling Luxembourg (No. 1) s.a.r.l. 02/11/2000 Luxembourg Luxembourg entity formed to hold Luxco2 as a part of the NRGenerating, Ltd. holding structure in the UK Sterling Luxembourg (No. 2) s.a.r.l. 02/11/2000 Luxembourg Luxembourg entity formed to hold the Swiss branch as a part of the NRGenerating, Ltd. holding structure in the UK 38
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- Sterling Luxembourg (No. 3) s.a.r.l. 03/10/2000 Luxembourg Luxembourg entity formed as a part of the Sterling holding structure in the UK Sterling Luxembourg (No. 4) s.a.r.l. 03/10/2000 Luxembourg Luxembourg entity formed as a part of the Sterling holding structure in the UK STS Hydropower Ltd. 08/11/1987 Michigan owns and operates hydroelectric projects in California, Colorado, Michigan, Virginia and Washington Suncook Energy LLC 10/14/1997 Delaware landfill gas fueled power generation for Nashua project in New Hampshire Sunnyside Operations Associates L.P. 02/15/1995 Delaware operates waste coal power plant in Utah Sunshine State Power (No. 2) B.V. 02/24/1994 Netherlands Dutch holding company which holds a 17.5% undivided interest in Gladstone Power Station Joint Venture in Australia Sunshine State Power B.V. 11/11/1993 Netherlands Dutch holding company which holds a 20% undivided interest in Gladstone Power Station Joint Venture in Australia Tacoma Energy Recovery Company 06/24/1999 Delaware operate and manage power plant for City of Tacoma Termo Santander Holding (Alpha), entity formed to purchase and L.L.C. thereafter sell certain equipment to Rocky Road Power, LLC The PowerSmith Cogeneration 09/03/1987 Delaware owns PowerSmith cogeneration facility Project, Limited Partnership in Oklahoma Tosli (Gibraltar) B.V. 05/24/1999 Netherlands Dutch company formed to assist with Cobee tender offer 39
SUBSIDIARY NAME DATE OF STATE OF DESCRIPTION --------------- INCORPORATION INCORPORATION ----------- ------------- ------------- Tosli Acquisition B.V. 05/28/1999 Netherlands Dutch company formed to tender Cobee shares Tosli Investments N.V. 05/14/1987 Netherlands Dutch holding company for Compania Boliviana de Energia Electrica S.A. in Latin America Tosli Luxembourg (No. 1) s.a.r.l. 10/01/1999 Luxembourg Luxembourg entity formed in connection with the Bulo-Bulo greenfield project Tosli Luxembourg (No. 2) s.a.r.l. 10/01/1999 Luxembourg Luxembourg entity formed in connection with the Bulo-Bulo greenfield project (Swiss branch) Turners Falls Limited Partnership Massachusetts owns Turners Falls cogeneration facility in Massachusetts Valmy Power LLC 10/16/2000 Delaware holding company for NRG's 50% interest in the two coal-fired units of the Valmy power station (which SPR owns jointly with Idaho Power Company), and its 100% interest in two related gas and oil fired units, together with certain other related assets Vienna Operations Inc. 05/08/2000 Delaware to act as a special purpose operating company to provide O&M services pursuant to a contract with Vienna Power LLC Vienna Power LLC 05/08/2000 Delaware entity holding title to 170 MW oil fired generating station located in Vienna, Maryland Wainstones Power Limited 11/10/1997 United Kingdom will build, own and operate 800MW combined cycle gas turbine power plant on greenfield site at Langage England (f/k/a Plymouth Energy Centre) WCP (Generation) Holdings LLC 06/17/1999 Delaware Holding company for West Coast Financing West Coast Power LLC 02/09/1999 Delaware West coast holding company entity designed to facilitate west coast asset pool financing (El Segundo, Long Beach, Cabrill I&II)
1 EXHIBIT 23.1 CONSENT OF INDEPENDENT ACCOUNTS CONSENT OF INDEPENDENT ACCOUNTANTS We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-52508) and Form S-8 (No. 333-38892) of NRG Energy, Inc. of our report dated March 2, 2001 relating to the consolidated financial statements and financial statement schedule, which appears in this Form 10-K. /s/ PricewaterhouseCoopers LLP - - ------------------------------- PricewaterhouseCoopers LLP Minneapolis, Minnesota March 27, 2001
1 EXHIBIT 99.1 DELOITTE & TOUCHE GmbH DELOITTE Wirtschaftspruefungsgesellschaft &TOUCHE Financial Statements of "MIBRAG" MITTELDEUTSCHE BRAUN- KOHLENGESELLSCHAFT MBH, THEISSEN Report on the audit of the financial statements for the years ended December 31, 2000, 1999 and 1998 in accordance with German GAAP and on the audit of the respective U.S. GAAP reconciliations Am Kirchtor 7 Postfach 11 01 43 Tel (03 45) 21 99-6 06108 Halle/Saale 06015 Halle/Saale Fax (03 45) 21 99-800 www.deloitte.de 2 MITTELDEUTSCHE BRAUNKOHLENGESELLSCHAFT MBH INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page ---- Report of Independent Auditors 1 Consolidated Financial Statements Consolidated Statements of Operations for the years ended December 31, 2000, 1999 and 1998 2 Consolidated Balance Sheets at December 31, 2000 and 1999 3 Consolidated Statements of Cash Flows for the years ended December 31, 2000, 1999 and 1998 4 Consolidated Statements of Shareholders`Equity for the years ended December 31, 2000, 1999 and 1998 5 Notes to the Consolidated Financial Statements 6 3 REPORT OF INDEPENDENT AUDITORS To the Shareholders of MIBRAG mbH Theissen, Germany We have audited the accompanying consolidated balance sheets of Mitteldeutsche Braunkohlengesellschaft mbH and its subsidiaries (MIBRAG or Group) as of December 31, 2000 and 1999, and the related consolidated statements of operations, shareholders' equity, and cash flows for each of the years in the three-year period ended December 31, 2000. These consolidated financial statements are the responsibility of the Group's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in Germany and the United States of America. Those standards 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of MIBRAG as of December 31, 2000 and 1999, and the consolidated results of its operations and cash flows for each of the years in the three-year period ended December 31, 2000, in conformity with accounting principles generally accepted in Germany. Generally accepted accounting principles in Germany vary in certain significant respects from generally accepted accounting principles in the United States of America. Application of generally accepted accounting principles in the United States of America would have affected the results of operations for each of the years in the three-year period ended December 31, 2000 and shareholders' equity as of December 31, 2000 and 1999 to the extent summarized in Note C to the consolidated financial statements. Deloitte & Touche GmbH Wirtschaftsprufungsgesellschaft Halle, Germany March 13, 2001 4 MITTELDEUTSCHE BRAUNKOHLENGESELLSCHAFT MBH CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS OF EURO) See accompanying Notes to Consolidated Financial Statements. 2
YEAR ENDED DECEMBER 31, ----------------------------------------------------- 2000 1999 1998 -------------- --------------- -------------- Sales revenue 272,220 254,027 240,517 Changes in inventories 1,675 11,091 2,594 Own costs capitalized 502 3,276 8,182 Other operating income 14,372 18,496 34,147 -------------- --------------- -------------- Total performance 288,769 286,890 285,440 -------------- --------------- -------------- Cost of materials 65,033 59,388 55,662 Personnel expenses 93,351 100,185 107,370 Depreciation on intangible and tangible fixed assets 49,059 51,654 75,882 Other operating expenses 62,879 66,698 75,227 -------------- --------------- -------------- Total operating expenses 270,322 277,925 314,141 -------------- --------------- -------------- Operating result 18,447 8,965 -28,701 Income from associated company and from companies in which participations are held 2,089 995 1,730 Income from financial assets 2,992 3,165 3,241 Depreciation on financial assets and short term investments -- -- -100 Interest expense, net -7,620 -8,164 -5,507 -------------- --------------- -------------- Net income (loss) from ordinary activities 15,908 4,961 -29,337 Income taxes 42 -- -- Other taxes 1,288 978 1,066 -------------- --------------- -------------- Net income (loss) 14,578 3,983 -30,403 ============== =============== ============== 5 MITTELDEUTSCHE BRAUNKOHLENGESLLSCHAFT MBH CONSOLIDATED BALANCE SHEETS (IN THOUSANDS OF EURO)
AT DECEMBER 31, ------------------------------ NOTE 2000 1999 --------- ------------- ------------- ASSETS NON-CURRENT ASSETS Intangible assets Concessions, trade marks, patents and licenses B, E 8,592 9,405 Property, plant and equipment 1. Land B, E 39,505 36,632 2. Buildings B, E 57,814 52,462 3. Strip mines B, E 40,263 41,194 4. Technical equipment and machinery B, E 225,704 187,611 5. Factory and office equipment B, E 24,072 18,790 6. Payments on account and assets under construction 6,672 76,555 ------------- ------------- 394,030 413,244 Financial assets 1. Participations (including associated company) B, F 13,052 12,497 2. Loans granted to participation B, G 7,124 7,499 3. Other loans B, H 31,649 35,484 ------------- ------------- 51,825 55,480 TOTAL NON-CURRENT ASSETS 454,447 478,129 Overburden B, I 164,424 161,548 CURRENT ASSETS Inventories 1. Raw materials and supplies B 5,731 5,218 2. Unfinished services B 0 88 3. Finished and trade goods B 2,115 3,228 ------------- ------------- 7,846 8,534 Receivables and other assets 1. Trade receivables B, J 55,909 46,826 2. Receivables from enterprises in which participations are held B 899 1,389 3. Other assets B 13,086 13,135 ------------- ------------- 69,894 61,350 Investments Other investments B, K 56,076 67,691 Cash B 19,903 13,010 TOTAL CURRENT ASSETS 153,719 150,585 Prepaid expenses 3,201 3,399 ------------- ------------- TOTAL ASSETS 775,791 793,661 ============= ============= See accompanying Notes to Consolidated Financial Statements 3
AT DECEMBER 31, ------------------------------- NOTE 2000 1999 -------- -------------- -------------- SHAREHOLDERS' EQUITY AND LIABILITIES SHAREHOLDERS' EQUITY Subscribed capital 30,678 30,678 Capital reserve 310,421 317,007 Balance Sheet Profit : TEUR 14.578; 1999: TEUR 3.988 Less: Interim dividend paid: TEUR 9.504; 1999: TEUR 0 5,074 3,988 Minority interest -46,037 -44,643 thereof net income for the year: TEUR 6.626 (1999: TEUR 5.816) TOTAL SHAREHOLDERS' EQUITY 300,136 307,030 Special item for investment subsidies and incentives B 14,856 16,570 Provisions 1. Accruals for pensions and similar obligations L 8,861 6,651 2. Taxation accruals M 778 1,317 3. Environmental and mining provisions B, N 175,104 171,195 4. Other accruals O 18,833 18,297 -------------- -------------- 203,576 197,460 Liabilities 1. Liabilities to banks B, P, Q 212,817 226,690 2. Downpayments received B, Q 0 53 3. Trade payables B, Q 16,748 24,069 4. Payables to participations B, Q 2,702 2,493 5. Other payables B, Q 24,954 19,296 -------------- -------------- 257,221 272,601 Deferred income 2 -- -------------- -------------- TOTAL SHAREHOLDERS' EQUITY AND LIABILITIES 775,791 793,661 ============== ============== 6 MITTELDEUTSCHE BRAUNKOHLENGESELLSCHAFT MBH CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (IN THOUSANDS OF EURO) See accompanying Notes to Consolidated Financial Statements 5
Balance Subscribed Capital sheet profit/ Minority capital reserve net profit interest Total ------------- ------------ ------------- ------------- ------------- BALANCE AS OF JANUARY 1, 1998 30,678 352,612 26 -32,320 350,996 Net loss 1998 -27,279 -3,124 -30,403 Transfer from capital reserve -29,810 29,810 0 Distributions -2,531 -2,531 Withdrawals by minority shareholders -7,256 -7,256 ------------- ------------ ------------- ------------- ------------- BALANCE AS OF DECEMBER 31, 1998 30,678 322,802 26 -42,700 310,806 Net income/loss 1999 -1,833 5,816 3,983 Withdrawals by minority shareholders -7,759 -7,759 ------------- ------------ ------------- ------------- ------------- 30,678 322,802 -1,807 -44,643 307,030 Transfer from capital reserve based upon a June 2000 shareholders' resolution -5,795 5,795 0 ------------- ------------ ------------- ------------- ------------- BALANCE AS OF DECEMBER 31, 1999 30,678 317,007 3,988 -44,643 307,030 Net income 2000 7,952 6,626 14,578 Transfer from capital reserve -6,586 6,586 0 Distributions -13,452 -13,452 Withdrawals by minority shareholders -8,020 -8,020 ------------- ------------ ------------- ------------- ------------- BALANCE AS OF DECEMBER 31, 2000 30,678 310,421 5,074 -46,037 300,136 ============= ============ ============= ============= ============= 7 NOTE A ORIGINATION AND NATURE OF BUSINESS ORIGINATION: Mitteldeutsche Braunkohlengesellschaft mbH ("MIBRAG" or "MIBRAG mbH") was created from split-up of MIBRAG AG, which had been previously owned by the Treuhandanstalt (the German government privatization agency), into three separate entities. Effective January 1, 1994 a consortium comprising of NRG Energy, Inc., Morrison Knudsen Corporation, and PowerGen plc. jointly acquired 99 % of the active mining, power generation and related assets and liabilities from the Treuhandanstalt through its Dutch holding company, MIBRAG B.V.. The remaining 1 % was transferred on December 18, 1996 from the German government privatization agency to Lambique Beheer B.V., Amsterdam, a subsidiary of NRG Energy, Inc., Morrison Knudsen B.V., Amsterdam, and PowerGen Netherlands B.V., Amsterdam in equal portions (1/3 %) for each partner. NATURE OF BUSINESS: The operations of MIBRAG mbH include two opencast brown coal mines in Profen and Schleenhain and rights on future mining reserves. Operations also include over 200 MW of power generation and one coal briquetting plant. A significant portion of the sales of MIBRAG is made pursuant to long-term coal and energy supply contracts. NOTE B SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES BASIS OF PRESENTATION: The consolidated financial statements of MIBRAG mbH and subsidiaries have been prepared in accordance with the German Commercial Code, which represents accounting principles generally accepted in Germany ("German GAAP"). German GAAP varies in certain significant respects from accounting principles generally accepted in the United States of America ("US GAAP"). Application of U.S. GAAP would have affected the results of operations for each of the years in the three-year period ended December 31, 2000 and shareholders' equity as of December 31, 2000 and 1999 to the extent summarized in note C on the consolidated financial statements. On January 1, 1999, the Euro was introduced as the common legal currency of 11 member states of the European Economic and Monetary Union, including Germany. MIBRAG has adopted the Euro as its reporting currency in its Consolidated Financial Statements and translated all German marks (DM) amounts at the fixed exchange rate for German marks to Euro. Although these statements depict the same trends as would have been shown had they been presented in German marks, they may not be directly comparable to the financial statements of other companies that have also been restated in Euro. The Euro did not exist prior to January 1999, and accordingly historical ex-change rates for the Euro are not available. A comparison of the Consolidated Financial Statements and those of another company that had historically used a reporting currency other than the German mark that takes into account actual fluctuations in exchange rates could give a much different impression than a comparison of the Consolidated Financial Statements and those of another company as translated into Euro. All amounts herein are shown in thousands of Euro ("TEUR") unless otherwise noted. 6 8 PRINCIPLES OF CONSOLIDATION: All material companies in which MIBRAG has legal or effective control are fully consolidated. In 2000, MIBRAG consolidated 6 (1999: 6, 1998: 5) domestic subsidiaries. One significant investment, MUEG, in which MIBRAG has an ownership interest of 50%, is accounted for in accordance with the equity method. This investment is referred to as an associated company in these financial statements. All other investments are included at cost and are referred to as participations in these financial statements. All significant intercompany accounts and transactions have been eliminated in consolidation. USE OF ESTIMATES: The preparation of financial statements in conformity with generally accepted accounting principles necessarily requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the balance sheet dates and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates. TOTAL COST METHOD: The income statement has been presented according to the total cost (or type of expenditure) format as commonly used in Germany. According to this format, production and all other expenses incurred during the period are classified by type of expenses. REVENUE RECOGNITION: Revenue is recognized when title passes or services are rendered, net of discounts, customer bonuses and rebates granted. INTANGIBLE ASSETS: Intangible assets are valued at acquisition cost and are amortized on a straight-line basis over their respective useful lives (3 to 25 years). Property, Plant, and Equipment: Property, plant, and equipment acquired is recorded on the basis of acquisition or manufacturing cost, including capitalized mine development costs, and subsequently reduced by scheduled depreciation charges over the assets' useful lives as follows: buildings - 3 to 40 years, technical facilities and machinery - 4 to 25 years; and facilities, factory and office equipment - 5 to 10 years. Maintenance and repair costs are expensed as incurred. Depreciation is computed principally by the straight-line method over the expected useful lives of the assets. Low value items are expensed in the year of acquisition. Opportunities for special tax deductible depreciation were utilized for both book and tax purposes in 1998 and prior years. 7 9 Impairment tests of long-term assets are made when conditions indicate a possible loss. If an impairment is indicated, the asset is written down to its estimated fair value. If, at a later date, the conditions leading to impairment no longer exist, the impairment loss is reversed up to the value of such assets, if the asset had not been impaired. Investments: The long-term loans and investments are recorded at cost. OVERBURDEN: Overburden represents the costs of removing the surface above a coal field subsequent to the initial opening of the field to the extent that the removal exceeds what is needed for the current years coal extraction. These are costs incurred in advance in respect of future coal production. The overburden is valued on an average cost basis. INVENTORY: Inventories are carried at the lower of average or market cost. Obsolescence provisions are made to the extent that inventory risks are determinable. SECURITIES: Securities held as fixed assets as well as marketable securities are valued individually at cost or at lower quoted or market values. RECEIVABLES AND OTHER ASSETS: All receivables are valued at cost, reduced for appropriate valuation allowances. Cash: Cash includes cash-on-hand, checks, bank accounts and time deposits. INVESTMENT GRANTS: To support the acquisition of certain tangible assets, investment allowances and subsidies were granted by the German federal government and the states of Saxony and Saxony-Anhalt. The application, conditions and payments of investment grants are ruled by German law and regulations. Investment allowances and subsidies received and formally claimed are credited to the special item account. The special item is amortized into income over the normal operating useful lives of the underlying assets to which the allowances and subsidies relate. ENVIRONMENTAL AND MINING PROVISIONS: Accruals for environmental and mining-related matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated, based on current law and existing technologies. These accruals are adjusted periodically as assessment and utilization progress or as additional technical or legal information becomes available. FAIR VALUE OF FINANCIAL INSTRUMENTS: The fair value of cash, accounts payable and receivable as well as short term borrowings approximates book value because of the short maturity period and interest rates approximating market rates. The Company has determined the estimated fair value of long-term debts by using available market information and generally accepted valuation methodologies. The use of different market assumptions or estimation methodologies could have a material effect on the estimated fair value amounts. LIABILITIES: Liabilities are shown at their repayment amounts. 8 10 SUPPLEMENTAL CASH FLOW INFORMATION: The Group paid TEUR 42 income taxes in 2000 and TEUR 0 in 1999, 1998, respectively. Interest paid amounted to TEUR 14,563, TEUR 15,137 and TEUR 13,561 in 2000, 1999 and 1998, respectively. Per Share Amounts: Per share amounts are not disclosed in the financial statements. MIBRAG is a nonpublic enterprise. NOTE C SIGNIFICANT DIFFERENCES BETWEEN GERMAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES The MIBRAG consolidated financial statements comply with German GAAP, which differs in certain respects from US GAAP. The significant differences that affect the consolidated net income and shareholders' equity of MIBRAG are set out below. I. APPLICATION OF THE PURCHASE METHOD OF ACCOUNTING The German GAAP financial statements include the historical cost book values of assets transferred from a predecessor company. The acquisition of 99% of the shares in MIBRAG mbH on January 1, 1994 by MIBRAG B.V. was accounted for using the purchase method of accounting. The purchase price adjustments to the historical cost basis have been pushed down to MIBRAG mbH for purposes of the reconciliation to US GAAP. The excess (EUR 387 million) of the fair value of the net assets acquired over the purchase price was proportionally allocated to reduce the value assigned to non-current assets, excluding long-term investments. The US GAAP financial statements also recognize purchase price adjustments for certain incremental transportation costs incurred by MIBRAG for lignite transportation to one of its major customers. II. NOTES TO SIGNIFICANT US GAAP ADJUSTMENTS 1. FIXED ASSETS The differences relate primarily to the following: o In the US GAAP balance sheet as of January 1, 1994, fixed asset balances, other than financial assets, were adjusted to their fair market values, then reduced by the allocation of the difference between the net acquisition costs for the MIBRAG shares and the fair market value of MIBRAG's net assets. o The depreciation period of long term assets are based upon periods acceptable for German tax purposes, which differ from the useful lives for U.S. accounting purposes. 9 11 o In 1999, an impairment loss was recognized for US GAAP purposes to reduce the assets of the briquette plant Mumsdorf to their fair values as of December 31, 1999. o A write-up of previously impaired fixed assets of the briquette plant Deuben (made in 1999 for German GAAP purposes) is not allowed under US GAAP. o Special accelerated depreciation for tax purposes is recorded in the German financial statements for 1998 and prior years. Upon disposal, the above differences also resulted in differing gains or losses on disposition. FINANCIAL INVESTMENT IN MUEG For German GAAP purposes, MIBRAG accounted for the investment in MUEG as of January 1, 1994 using the cost method. Under US GAAP the book value was increased to account for the equity earnings that were not distributed to MIBRAG as of that date. 2. RELOCATION ACCRUALS The US GAAP results recognized liabilities and deferred costs of TEUR 45,357 to relocate three villages. The deferred costs are amortized in accordance with quantities of coal extracted. In accordance with German accounting principles accruals for the relocation of villages can not be accrued earlier than 2 years prior to the relocation, and certain relocation costs are to be expensed as incurred. 3. INVESTMENT IN POWER PLANTS In 1995 and 1996, third party investors paid in EUR 110 million into a MIBRAG subsidiary, MIBRAG Industriekraftwerke GmbH & Co. KG ("MI"), which operates three lignite-fired power plants. The investment is structured such that the third party investors obtain accelerated tax depreciation while retaining a put option to sell their investments back to MIBRAG at predetermined prices. The third party investments were considered additions to equity as minority interests for German GAAP, while these arrangements are accounted for as a financing in accordance with US GAAP. 4. TRANSPORTATION CREDITS An acquisition related liability, for US GAAP purposes, is reduced by the amount of excess incremental transportation costs incurred by MIBRAG for certain lignite shipments. The acquisition related liability is not reflected in MIBRAG's German financial statements. It was reduced to zero in 1998. 10 12 5. INTEREST CAPITALIZATION Interest is expensed in the German financial statements. Interest expense related to qualified assets, however, is capitalized and depreciated for US GAAP purposes. 6. RECEIVABLES/PAYABLES AT NON-MARKET INTEREST RATES Certain accounts receivable or loans payable are recorded in the German GAAP financial statements at their nominal values. As they carry non-market interest rates, these receivables and payables were adjusted to their market values. 7. OVERBURDEN Overburden in the German financial statements includes capitalized depreciation based upon the historical costs. Because of the purchase accounting adjustments, a different amount of depreciation is capitalized in overburden in the US GAAP financial statements. Additionally, overburden as of January 1, 1994 was written down to fair value. 8. ENVIRONMENTAL AND MINING PROVISIONS The ratable accrued end-lake provision was reduced in 1998 based upon a new estimate of total costs to be incurred. For US purposes, this adjustment would be accounted for prospectively. 9. ACCRUED LIABILITIES Certain mining and other accruals, which were provided for at January 1, 1994 in accordance with US GAAP purchase accounting, were not recorded in the German financial statements. 10. OTHER Certain costs and income in the German financial statements are capitalized or deferred for US GAAP purposes, respectively. 11 13 11. UNREALIZED HOLDING GAINS Unrealized holding gains on available-for-sale securities are not accounted for under German GAAP, but are recorded as other comprehensive income for US GAAP purposes. 12. DEFERRED TAXES The differences noted above result in temporary differences which, when combined with net operating loss carryforwards, would result in a net deferred tax asset of EUR 111 million and EUR 147 million at December 31, 2000 and December 31, 1999, respectively. Because of available negative evidence, a 100 % valuation allowance would have been recorded at each year-end. Because no net deferred taxes were recorded for German or US GAAP purposes, no adjustment to net income or shareholders equity is listed in the following reconciliation. 13. NEW ACCOUNTING PRONOUNCEMENTS SFAS No. 133, "Accounting for Derivative Instruments and Hedging activities" issued by the Financial Accounting Standards Board, (the "FASB") as amended by SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities--Deferral of the Effective Date of FASB Statement No. 133" and SFAS 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities" is effective for the Company as of January 1, 2001. This statement calls for that all derivative financial instruments to be reflected on the balance sheet at fair value. Changes in fair value must be recognized periodically in earnings or as a component of other comprehensive income, depending on the nature of the underlying item. Changes in the fair value of the derivative will be recognized currently in the statements of operations. As MIBRAG has not engaged in any transactions that would be considered derivative instruments or hedging activities, the adoption of this standard will not have an effect on the MIBRAG consolidated financial statements. In September 2000, the FASB issued SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities - a replacement of FASB Statement No. 125." This statement revises the standards for accounting for securitizations and other transfers of financial assets and collaterals and requires certain financial statement disclosures. SFAS No. 140 is effective for transactions occurring after March 31, 2001. The new disclosure requirements are effective for business years ending after December 15, 2000. Adoption of this standard is not anticipated to have a material effect on MIBRAG's consolidated financial statements. 12 14 RECONCILIATION TO US GAAP The following is a summary of the significant adjustments to net income for 2000, 1999 and 1998 and to shareholders' equity at December 31, 2000 and December 31, 1999, which would be required if US GAAP had been applied instead of German GAAP. 13
YEAR ENDED DECEMBER 31, ----------------------------------- 2000 1999 1998 NOTE TEUR TEUR TEUR -------- ----------- ----------- ----------- Net income as reported in the consolidated income statement under German GAAP 14,578 3,982 -30,404 Adjustments required to conform with U.S. GAAP: Fixed assets (1) 4,598 15,937 48,462 Relocation accruals (2) 802 871 3,916 Investment in power plants (3) -3,546 -3,775 -3,969 Transportation credits (4) 0 0 6,944 Interest capitalization (5) -221 2,585 973 Receivable/payables at non-market interest rates (6) -516 -511 -506 Overburden (7) 7,813 11,744 4,945 Environmental and mining provisions (8) 5,569 81 -18,154 Other (10) 404 403 245 ----------- ----------- ----------- NET INCOME IN ACCORDANCE WITH U.S. GAAP 29,481 31,317 12,453 =========== =========== =========== 15 14
YEAR ENDED DECEMBER 31, ---------------------------- 2000 1999 NOTE TEUR TEUR -------- ------------- ------------- Shareholders' equity as reported in the consolidated balance sheet under German GAAP 300,136 307,030 Adjustments required to conform with U.S. GAAP: Fixed assets (1) 110,764 108,893 Relocation accruals (2) 16,528 12,999 Investments in power plants (3) -77,962 -82,436 Interest capitalization (5) 6,241 6,462 Receivables/payables at non-market interest rates (6) 1,023 1,539 Overburden (7) -67,280 -75,093 Environmental and mining provisions (8) -12,504 -18,073 Accrued liabilities (9) -15,417 -15,417 Other (10) -8,062 -8,466 Unrealized holding gains (11) 450 1,981 ------------- ------------- SHAREHOLDERS' EQUITY IN ACCORDANCE WITH U.S. GAAP 253,918 239,420 ============= ============= 16 REPORTING OF COMPREHENSIVE INCOME Comprehensive income in accordance with SFAS No. 130, "Reporting Comprehensive Income", includes the impact of other comprehensive income. These are revenues, gains, expenses and losses that under U.S. GAAP are not included in net income. Statement of shareholders` equity:
Year ended December 31 --------------------------------------------- 2000 1999 1998 TEUR TEUR TEUR -------------- -------------- -------------- Net income in accordance with US GAAP 29,481 31,318 12,453 Other comprehensive income Unrealized holding gains on securities -1,531 -2,086 1,836 -------------- -------------- -------------- Comprehensive income 27,950 29,232 14,289 ============== ============== ============== 15
Year ended December 31 ------------------------------------------- 2000 1999 1998 TEUR TEUR TEUR -------------- -------------- ------------- Stockholders' equity according to US GAAP before accumulated other comprehensive income 253,468 237,439 206,119 Accumulated other comprehensive income: Unrealized holding gains on securities 450 1,981 4,067 -------------- -------------- ------------- Total stockholders' equity according to US GAAP including comprehensive income 253,918 239,420 210,186 ============== ============== ============= 17 NOTE D CONCENTRATION OF CREDIT RISK AND LONG-TERM COAL SALES AGREEMENTS MIBRAG mbH markets its coal principally to electric utilities in Germany. As of Decem-ber 31, 2000 and 1999 accounts receivable from electric utilities totaled TEUR 55,909 and TEUR 46,827, respectively. Credit is extended based on an evaluation of the customer's financial condition. Credit losses are provided for in the financial statements and consistently have been minimal. MIBRAG mbH is committed under several long-term contracts to supply raw brown coal and whirl fine coal to the Schkopau power station and the Lippendorf power station. Under the terms of the Schkopau Agreement, MIBRAG mbH may deliver annually up to 5.8 million tons of coal. The agreement is in effect until 2010, with an option for the purchaser to extend the agreement for another 10 years. The price to be paid by the Schkopau power station is a fixed price adjusted by an annual escalation rate. The Lippendorf Agreements provide for deliveries of up to 10 million tons of raw brown coal per year from 1999 through 2040 with an option for the customers to extend for an additional 3-year period. These Agreements were closed with Vereinigte Energiewerke AG (VEAG), Berlin, E.ON Kraftwerke GmbH, Hanover and EnBW Lippendorf Beteiligungsgesellschaft mbH, Stuttgart. The price to be paid by the Lippendorf power station is a base-price with escalation and adjustment based on quality of the coal delivered. The first bloc of the new Lippendorf power station went into full operation in October 1999 and the second bloc in May 2000. A substantial portion of the Company's coal reserves is dedicated to the production of coal for such agreements. NOTE E INTANGIBLE ASSETS AND PROPERTY, PLANT AND EQUIPMENT The group depreciation charges are as follows: TEUR 49,059 (2000), TEUR 51,654 (1999) and TEUR 75,882 (1998), including normal depreciation, unplanned depreciation and special tax depreciation (1998) in terms of section 4 of the German tax law, "Foerdergebietsgesetz". According to that law, certain tangible assets can for example be depreciated up to 50 % of the historical costs in the first five years of acquisition in addition to the normal depreciation. Special tax depreciation was EUR 23.067 in 1998. 16 18 The major categories of fixed assets are the following (in TEUR): MIBRAG reopened the briquette plant in Deuben and closed the briquette plant in Mumsdorf in the year 2000. The fixed assets of the briquette plant in Deuben were written up at December 31, 1999 for German GAAP purposes to their continued carrying values as if the assets had not been impaired in 1996. The fixed assets of the briquette plant in Mumsdorf were fully written down for German and US GAAP purposes in 2000. 17
2000 1999 --------------- --------------- Concessions, trade marks, patents and licenses cost 13,967 14,177 less: accumulated amortization -5,375 -4,772 --------------- --------------- net book value 8,592 9,405 =============== =============== Property, plant and equipment cost - land and land rights 39,504 36,632 - buildings 139,389 133,908 - strip mines 45,772 45,772 - technical equipment and machinery 747,008 677,601 - factory and office equipment 106,601 101,236 - payments on account and assets under Construction 6,672 76,555 --------------- --------------- total cost 1,084,946 1,071,704 --------------- --------------- less: accumulated depreciation -690,916 -658,460 --------------- --------------- net book value 394,030 413,244 =============== =============== 19 NOTE F PARTICIPATIONS (INCLUDING ASSOCIATED COMPANY) MIBRAG's investment in MUEG Mitteldeutsche Umwelt- und Entsorgungs GmbH, Braunsbedra, ("MUEG") is accounted for using the equity method. MUEG was founded in 1990 and coordinates the waste disposal activities in the Central German brown coal area. The equity value as of December 31, 2000 is TEUR 5,684, and the cost basis is TEUR 6,333. Investments in five (1999: six) other companies are accounted for at cost. NOTE G LOANS GRANTED TO PARTICIPATIONS In 1995, MIBRAG sold its district heating network assets to a company in which it holds a participation. The sales price is being repaid in equal installments of TEUR 375 over a period of 25 years. The interest rate is fixed at 5,4 percent beginning in 2000 (1999: 5,0%). The fair market value of the loan approximates the book value, which amounted to TEUR 7,124 and TEUR 7,499 at December 31, 2000 and 1999, respectively. NOTE H OTHER LOANS The other loans were granted to the third party investors in a subsidiary of MIBRAG mbH. These loans were financed by a borrowing from KfW (Kreditanstalt fuer Wieder-aufbau). KfW granted MIBRAG mbH a loan of TEUR 52,663 due on December 30, 2005 at fixed interest rates between 6.26 % and 6.82 %. The balance of the loan as of December 31, 2000 amounted to TEUR 31,649. The loans to the third party investors of the subsidiary of MIBRAG mbH were granted at the same conditions as those applicable to the loan between MIBRAG mbH and KfW. 18 20 NOTE I OVERBURDEN The reconciliation of the overburden costs is as follows: The basis for the determination of the overburden is the total quantity of partially exposed raw brown coal. NOTE J TRADE RECEIVABLES Trade receivables were disclosed in the balance sheet, net of allowances, as follows (in TEUR):
December 31, 2000 December 31, 1999 ------------------------------ ------------------------------ Tonnage Value Tonnage Value metric tons million EUR metric tons million EUR -------------- --------------- -------------- --------------- Profen 20.8 80,5 20.0 78,4 Schleenhain 21.9 83,9 20.0 83,2 -------------- --------------- -------------- --------------- 42.7 164,4 40.0 161,6 ============== =============== ============== =============== NOTE K OTHER INVESTMENTS At December 31, 2000 other investments were disclosed at an amount of TEUR 56,076. The balance consists of investment funds of MI (TEUR 44,549), which were specially set up to reinvest the additional liquidity resulting from the entry of new investors into a subsidiary of MIBRAG and to short-term investments (TEUR 11,527). 19
December 31, 2000 December 31, 1999 ----------------------- ----------------------- Trade receivables 56,518 47,236 Less allowances (608) (410) ----------------------- ----------------------- 55,910 46,826 ======================= ======================= 21 Net dividends distributed by the investment funds were partially reinvested in 1998 to 2000 and paid out in 2000. Realized gains of EUR 6.6 million, EUR 5.8 million and EUR 5.4 million were disclosed in interest income in, 2000, 1999 and 1998, respectively. NOTE L ACCRUALS FOR PENSIONS AND SIMILAR OBLIGATIONS The provision relates primarily to briquette benefit claims of active and retired employees on the basis of the collective bargaining agreement of November 9, 1993 in respect to allowances in kind. Individuals entitled must be employees of the company at the date of retirement. The entitlement does not vest and lapses with early termination of the working relationship or upon receipt of social plan benefits. The calculation is based on an actuarial valuation, which takes into account the entitlement to the redemption value of DM 185.00 per metric ton of briquettes as specified in the collective bargaining agreement, the employees entitled to benefits as of December 31, 2000, and official demographic tables. In addition, pension obligations for early retirement benefits were accrued. These amounts have also been calculated on the basis of actuarial valuations. NOTE M TAXATION ACCRUALS MIBRAG accrued TEUR 778 (1999: TEUR 1.317) for property taxes. MIBRAG did not provide for income taxes under German GAAP in spite of a positive result for the year 2000 because of tax losses brought forward from prior years. Deferred tax assets and liabilities have not been recorded because there are no significant differences between the German GAAP financial statement and the tax bases of the assets and liabilities. The German income tax rate applicable to MIBRAG (corporate income tax, solidarity surcharge, trade tax) is 50,17 % in 2000 (1999: 50,17%, 1998: 54,72 %) on undistributed income. Beginning in 2001 this tax rate will be 35,98 % according to changed tax laws. The company has an effective tax rate of 0 % because the company has no taxable income and the recording of a deferred tax benefit for net loss carryforwards is prohibited under German GAAP. The income taxes paid in 2000 (TEUR 42; 1999: TEUR 0; 1998: TEUR 0) relate to a subsidiary of MIBRAG. At December 31, 2000 the Company had approximately EUR 266 million net operating loss carry-forwards, which do not expire and may be applied against future taxable 20 22 income. The tax audit is currently taking place for the fiscal years 1994 through 1997. NOTE N ENVIRONMENTAL AND MINING PROVISIONS The following is a summary of environmental and mining provisions (in TEUR): 1) End-lake provision MIBRAG is responsible for reclaiming the mines Profen and Schleenhain. The mining field reclaimation of the Profen and Schleenhain mines after the ceasing of production is planned for 2029 to 2046 and 2041 to 2073, respectively. A legally binding closure plan laying down the principles for action plans in accordance with the Federal Mining Law (Bundesberggesetz) is normally approved two years in advance to the commencement of production by the relevant mining authorities. The liability to reclaim the area exists from the start of mining activities. In each year of coal extraction the reclaimation costs are accrued ratably using the relation of the coal mined to the total coal mine volume. The calculation of the total cost for reclaiming mining fields has been made on the basis of a third party opinion and estimations on the basis of current prices. The end-lake costs consist mainly of costs for reconstruction, bank reinforcement, dewatering and watering. 2) Provision for Environmental Measures The provision for the environmental measures is determined in respect to disposal sites and old locations of MIBRAG mbH in refinement and mining areas on which waste deposits can be found. The obligation at the accrued amount is derived from article 19.3 of the purchase and sales agreement. Qualifying costs that exceed the provision are to be reimbursed by the Bundesanstalt fuer vereinigungsbedingte Sonderaufgaben (BvS). 21
Balance as of Balance as of December 31, 2000 December 31, 1999 ----------------------- ---------------------- 1) End-lake provision 139,286 135,163 2) Provision for environmental pollution 5,100 5,100 3) Landscaping 5,876 6,560 4) Planting 4,331 5,040 5) Relocation of villages 20,511 19,332 ----------------------- ---------------------- 175,104 171,195 ======================= ====================== 23 3) Landscaping This provision includes costs for reclaiming disposal areas and leveling the area outside the embankments. These costs relate solely to continuous landscaping, while costs for closing down landscaping are included in the end-lake provision. 4) Planting Provision is made for costs in connection with temporary planting as of December 31, 2000 and December 31, 1999. 5) Relocation of villages The provision for the relocation of villages is in respect to the relocation of municipalities, which is necessary for the expansion of the Profen and Schleenhain mines. The calculation of the provision is based on a method that takes into account the cost for project planning, infrastructural development, cemetery relocation, demolition and landmark preservation. The provision is built up in equal annual amounts, commencing two years before the relocation starts and ending in the middle of the relocation year. NOTE O OTHER ACCRUALS Accrued liabilities are as follows (in TEUR): 22
December 31, 2000 December 31, 1999 --------------------- -------------------- 1) Severance payments 10,373 10,549 --------------------- -------------------- 2) Personnel expenses - Employment anniversaries 1,209 1,355 - Vacation and other compensated absences 311 276 - Other 61 124 --------------------- -------------------- 1,581 1,755 --------------------- -------------------- 3) Remaining accruals 6,879 5,993 --------------------- -------------------- 18,833 18,297 ===================== ==================== 24 1) Severance payments Basis for the provisions is signed social plan framework agreements in which the measures for the personnel adjustments are defined. The employees are entitled to a one-time severance payment if the company initiates termination or in case of retrenchments. The severance payments are limited to TEUR 26 per person. Employees participating in early retirement programs are entitled to additional compensation, mainly for the reduction in statutory pension payments due to early retirement. 2) Personnel expenses MIBRAG mbH grants awards in recognition of long service in the company, based on the collective bargaining agreement dated January 1, 1992 and the company agreement dated October 1, 1995. The employees are entitled to financial awards, which increase in proportion to their employment periods. The valuations of the benefits were based on actuarial valuations. The liability for vacation and other compensated absences arises from the days and shifts outstanding at balance sheet dates, which have been determined for each employee. 3) Remaining provisions Composition (in TEUR): 23
December 31, 2000 December 31, 1999 --------------------- --------------------- Outstanding invoices 2,913 1,834 Mine damages 1,790 1,790 Water usage fees 760 1,008 Professional service and litigation 1,052 747 Others 364 614 --------------------- --------------------- 6,879 5,993 ===================== ===================== 25 NOTE P LONG-TERM DEBT Long-term debt consists of the following (in TEUR): To a) These liabilities refer to three loans from the Kreditanstalt fuer Wiederaufbau, Frankfurt/Main: The first loan was granted December 9, 1992 for the construction of a raw brown coal powered industrial power station in Waehlitz of TEUR 71,187. The interest rate has been fixed at 7 % p.a. until December 9, 2002. The loan period is 25 years. The repayments are due in 40 equal amounts commencing from June 30, 1998. On April 3, 1995 two additional loan agreements were closed with Kreditanstalt fuer Wiederaufbau (KfW). One of these contracts was closed for partially financing the modernization and reshaping of both industrial power plants in Deuben and Mumsdorf (TEUR 61,355). The redemption period is 13 years starting on December 31, 1998. Interest has to be paid between 6.04 % and 6.80 %. These rates are fixed until January 2006 for loans of EUR 27.5 million, and 2007 for the remaining portion of the loans. The second loan in the amount of EUR 52,663 was granted to partially finance the limited partner capital contribution of investors. The redemption period is 13 years. In 1996, the loan was fully called up (TEUR 52,663). In 2000, TEUR 3,835 were redeemed. The interest rates are fixed at between 6.26 % and 6.82 % until 2005 at which time the rates will be adjusted to market rates. 24
December 31, 2000 December 31, 1999 --------------------- --------------------- a) Loan to finance the power stations - build up the power station of Waehlitz 60,509 64,068 - modernization of the power stations in Deuben and Mumsdorf 47,196 51,916 - finance the additional paid-in capital by the investors of MI 31,649 35,484 b) Loan to finance the Schleenhain mine investments 70,069 71,581 c) Loan for home construction 2,818 3,055 d) Deferred interest 576 586 --------------------- --------------------- 212,817 226,690 ===================== ===================== 26 Interest expense for the three loans amounted to EUR 10.2 million, EUR 11.3 million and EUR 12.2 million in 2000, 1999, and 1998, respectively. To b) In 1997 and 1998, loan contracts were closed with four banks to finance the capital expenditures at the Schleenhain mine, especially the construction of the blending yard and environmental measures for the conveyor belts. In 1998 EUR 61,355 million and in 1999 further EUR 10,226 million were called up at interest rates between 3.5 % and 5.4 %, which are fixed until 2008 and 2009, respectively. To c) The loans for home construction were granted by the Deutsche Bank AG and the Nord LB for relocation-related home construction purposes in Hohenmoelsen. For the loan granted by Deutsche Bank AG amounting to TEUR 1,333 an interest rate of 5.6 % was set for a period ending 2007. For the two loans granted by Nord LB at the amounts of TEUR 624 and TEUR 861 there are no interest payments due until 2007 and 2010, respectively. Thereafter the rate is fixed at 8 % p.a. The OTHER LIABILITIES (in TEUR) refer to: 25
December 31, 2000 December 31, 1999 --------------------- --------------------- Usage reimbursement for the mining rights 11,015 7,705 Wages and Salaries 4,440 3,077 Tax lease 2,475 2,774 Social security contributions 2,159 2,311 Tax authorities 3,366 1,914 Others 1,498 1,515 --------------------- --------------------- 24,953 19,296 ===================== ===================== 27 The payables due to the tax lease model relate to the equity commission and management fees. NOTE Q MATURITY PERIODS OF LIABILITIES The maturity periods of liabilities (in TEUR) are as follows: *) Liabilities to banks are fully collateralized by mortgages Annual maturities of liabilities to banks are as follows:
Down- Liabilities Trade Payables to Other payment to banks*) payables participations payables received Total ----------- -------- -------------- -------- -------- --------- Balance as of December 31, 1999 226,690 24,069 2,493 19,296 53 272,601 thereof: maturity period - up to 1 year 14,449 21,953 2,493 15,964 53 54,912 - 1-5 years 72,602 2,116 -- 2,405 -- 77,123 - more than 5 years 139,639 -- -- 927 -- 140,566 Balance as of December 31, 2000 212,817 16,749 2,702 24,953 -- 257,221 thereof: maturity period - up to 1 year 16,379 15,067 2,702 22,660 -- 56,808 - 1-5 years 78,770 1,682 -- 1,547 -- 81,999 - more than 5 years 117,668 -- -- 746 -- 118,414 26
Year of maturity Amount in TEUR - - ------------------------- ---------------------------------- 2001 16,379 2002 17,352 2003 17,490 2004 21,956 2005 21,972 -------------------- 78,770 Thereafter 117,668 -------------- Total 212,817 ============== 28 The estimated fair value of the Company's liabilities to banks at December 31, 2000 (1999), approximates TEUR 213.030 (TEUR 232.968) compared with the carrying value of TEUR 212,817 (TEUR 226.690). NOTE R COMMITMENTS AND CONTINGENCIES The other contractual obligations refer to long term investment projects in the mines Profen and Schleenhain. MIBRAG leases office equipment and railway-carriages, expiring at various dates. Rental and lease expenses amounted to TEUR 780, TEUR 849 and TEUR 852 in the years ended December 31, 2000, 1999 and 1998, respectively. The future minimum lease payments under operating leases amount to TEUR 637 (2001: TEUR 279, 2002: TEUR 254, 2003: TEUR 90, 2004: TEUR 11, 2005: TEUR 3 and no obligations thereafter). NOTE S SEGMENT INFORMATION MIBRAG operates as one segment. Sales were exclusively achieved in Germany, and all long-lived assets are located in Germany. Sales were almost completely limited to the new German Federal States, mainly to Saxony Anhalt, Thuringia, and Saxony. Net sales by product and service:
(in TEUR) At December 31, -------------------------------------------- 2000 1999 ---------------------- --------------------- Guarantees for indebtedness of others 19,672 19,705 Other contractual obligations 14,200 23,980 Several major customers account for 10 % or more of MIBRAG's revenues. As a percen-tage of total sales such customers accounted for 24 %, 21 % and 13 % in 2000, 31 %, 15 % and 10 % in 1999, and 35 % and 14 % in 1998. 27
2000 1999 1998 TEUR TEUR TEUR ------------ ------------- ------------ Raw brown coal and coal products 192,296 168,767 152,308 Electrical power, heating and steam 33,140 42,305 43,177 Other products and services 2,678 2,138 2,481 Further charging of transport services, ash disposal and others 44,106 40,817 42,551 ------------ ------------- ------------ 272,220 254,027 240,517 ============ ============= ============ 29 NOTE T RELATED PARTY TRANSACTIONS Agreements for consulting and management services were closed in respect to the mining operations and the refinement facilities between MIBRAG and two subsidiaries of the common parent companies NRG Energy Inc., Morrison-Knudsen Corp. and PowerGen plc. These contracts determine certain consulting services to be provided by the two subsidiaries Morrison-Knudsen Deutschland GmbH (MKD) and Saale Energie Service GmbH (SES) to MIBRAG or its subsidiaries. MIBRAG is obliged to determine and pay the cost-related remuneration for these services. Expenditures for MIBRAG amount to TEUR 7,669, TEUR 7,669 and TEUR 10,013 for 2000, 1999 and 1998, respectively. Part of the lignite deliveries from 1998 to 2000 to the Schkopau power plant were sales to Saale Energie GmbH (SEG), which is a subsidiary of the common parent companies of MIBRAG - NRG Energy Inc. and PowerGen plc. SEG is operating two blocs of the Schkopau power station with 400 MW. Sales to SEG amount to EUR 17.3 million, EUR 14.7 million, EUR 14.2 million in 2000, 1999 and 1998, respectively. The conditions of delivery are the same as to the other (third party) operator of the Schkopau power plant. 28
1 EXHIBIT 99.3 Financial Statements of "Sunshine" SUNSHINE STATE POWER B.V. ANNUAL FINANCIAL REPORT DECEMBER 31, 2000, 1999 AND 1998 2 SUNSHINE STATE POWER B.V. INDEX TO ANNUAL FINANCIAL REPORT DECEMBER 31, 2000, 1999 AND 1998 - - --------------------------------------------------------------------------------
PAGE(S) ------- Auditors' Report 1 Balance Sheet at December 31, 2000, 1999 and 1998 2 Statement of Income for the years ended December 31, 2000, 1999 and 1998 3 Statement of Cash Flows for the years ended December 31, 2000, 1999 and 1998 4 Notes to the Annual Accounts for the years ended December 31, 2000, 1999 and 1998 5-12 3 TO THE SHAREHOLDERS OF SUNSHINE STATE POWER B.V. AUDITORS' REPORT INTRODUCTION We have audited the accompanying balance sheet of Sunshine State Power B.V. as of December 31, 2000, 1999 and 1998, and the related statements of income and of cash flows for each of the three years ended December 31, 2000. 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. SCOPE We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. OPINION In our opinion, the financial statements give a true and fair view of the financial position of the Company as of December 31, 2000, 1999 and 1998 and of the results for the years then ended in accordance with accounting principles generally accepted in the Netherlands and comply with the financial reporting requirements included in Part 9, Book 2 of the Netherlands Civil Code. PRICEWATERHOUSECOOPERS N.V. March 2, 2001 Amsterdam, Netherlands 4 SUNSHINE STATE POWER B.V. BALANCE SHEET AT DECEMBER 31, 2000, 1999 AND 1998 (Amounts expressed in thousands of Australian dollars) - - -------------------------------------------------------------------------------- The accompanying notes form an integral part of the annual accounts. 2
ASSETS 2000 1999 1998 ----------- ----------- ---------- Fixed assets: Intangible fixed assets 6,513 6,984 7,455 Tangible fixed assets 153,210 155,857 157,432 ----------- ----------- ---------- 159,723 162,841 164,887 Current assets: Stocks 2,716 6,210 3,497 Receivables 5,740 4,891 5,521 Cash and bank balances 13,202 11,206 11,471 ----------- ----------- ---------- 21,658 22,307 20,489 ----------- ----------- ---------- Total assets 181,381 185,148 185,376 =========== =========== ========== SHAREHOLDERS' EQUITY AND LIABILITIES Shareholders' equity: Issued share capital 30 30 30 Retained earnings 42,472 32,406 26,580 Result for the year 3,169 10,066 5,826 ----------- ----------- ---------- 45,671 42,502 32,436 ----------- ----------- ---------- Provisions 19,824 18,369 17,918 Long-term liabilities 103,549 113,050 125,480 Current liabilities 12,337 11,227 9,542 ----------- ----------- ---------- Total shareholders' equity and liabilities 181,381 185,148 185,376 =========== =========== ========== 5 SUNSHINE STATE POWER B.V. STATEMENT OF INCOME FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998 (Amounts expressed in thousands of Australian dollars) - - -------------------------------------------------------------------------------- The accompanying notes form an integral part of the annual accounts. 3
2000 1999 1998 --------- ---------- --------- Net turnover: Enertrade 20,305 16,649 18,819 Boyne Smelters Limited 40,337 39,586 38,377 --------- ---------- --------- Total 60,642 56,235 57,196 Cost of turnover: Non-fuel 10,055 9,847 9,345 Fuel 28,050 24,541 24,864 --------- ---------- --------- Total 38,105 34,388 34,209 --------- ---------- --------- Gross profit on turnover 22,537 21,847 22,987 --------- ---------- --------- Operating expenses 1,541 2,236 1,624 Depreciation and amortization expense 4,750 4,806 6,409 --------- ---------- --------- Total expenses 6,291 7,042 8,033 --------- ---------- --------- Net profit on turnover 16,246 14,805 14,954 --------- ---------- --------- Interest expense 7,182 6,530 6,942 Interest income (652) (545) (566) Foreign exchange (gain) loss 5,141 (1,721) 995 Disposal of assets (gain) loss 48 135 19 --------- ---------- --------- Net financial expense 11,719 4,399 7,390 --------- ---------- --------- Result from ordinary operations before taxation 4,527 10,406 7,564 Taxation 1,358 340 1,738 --------- ---------- --------- Net result 3,169 10,066 5,826 ========= ========== ========= 6 SUNSHINE STATE POWER B.V. STATEMENT OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998 (Amounts expressed in thousands of Australian dollars) - - -------------------------------------------------------------------------------- The accompanying notes form an integral part of the annual accounts. 4
2000 1999 1998 --------- ---------- --------- Cash flows from operating activities: Net result 3,169 10,066 5,826 Adjustments to reconcile net result to net cash provided by operating activities: Depreciation and amortization 4,750 4,806 6,409 Deferred income taxes 1,358 340 1,738 Foreign exchange loss (gain) 5,141 (1,721) 995 (Gain) loss on sale of fixed assets 48 146 19 Changes in operating assets and liabilities: Stocks 3,494 (2,713) (1,243) Receivables (849) 630 (1,051) Provisions 97 111 (15) Current liabilities 435 1,060 164 --------- ---------- --------- Net cash flows provided by operating activities 17,643 12,725 12,842 --------- ---------- --------- Cash flows from investing activities: Purchases of tangible fixed assets (1,694) (2,918) (1,867) Proceeds from sale of fixed assets 14 12 23 --------- ---------- --------- Net cash flows used by investing activities (1,680) (2,906) (1,844) --------- ---------- --------- Cash flows from financing activities: Proceeds (repayments) of notes payable (7,367) (4,109) (4,974) Repayments of long-term debt (6,600) (5,975) (5,438) --------- ---------- --------- Net cash flows used by financing activities (13,967) (10,084) (10,412) --------- ---------- --------- Net increase (decrease) in cash and bank balances 1,996 (265) 586 Cash and bank balances: Beginning of year 11,206 11,471 10,885 --------- ---------- --------- End of year 13,202 11,206 11,471 ========= ========== ========= Supplemental disclosure of cash paid for interest 7,182 6,229 7,744 ========= ========== ========= 7 SUNSHINE STATE POWER B.V. NOTES TO THE ANNUAL ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998 (Amounts expressed in thousands of Australian dollars) - - -------------------------------------------------------------------------------- 1. GENERAL ACTIVITIES Sunshine State Power B.V. (the Company) was incorporated on November 11, 1993 and is seated in Amsterdam, the Netherlands. The Company's principal operating activity is the ownership of 20% of the Gladstone Power Station Joint Venture. The Gladstone Power Station Joint Venture owns and operates the Gladstone Power Station located in Queensland, Australia which it acquired on March 30, 1994. The Gladstone Power Station Joint Venture is an unincorporated joint venture and therefore not a separate legal entity. Accordingly, the Gladstone Power Station Joint Venture owners act as tenants in common owning their proportionate shares of the unincorporated joint venture's assets, liabilities and results of operations. The unincorporated joint venture's assets, liabilities, results of operations and cash flows have been taken up in this annual financial report on a proportionate basis. The accounts have been prepared for the years ended December 31, 2000, 1999 and 1998. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES GENERAL Unless otherwise stated assets and liabilities are carried at nominal value. BASIS OF PREPARATION The Company's financial statements have been prepared in accordance with generally accepted accounting principles in the Netherlands (Netherlands GAAP) which may differ in certain respects from generally accepted accounting principles in the United States (US GAAP). With regard to the Company's balance sheet and statement of income, there are no material differences between Netherlands GAAP and US GAAP. With regard to the Company's statement of cash flows, under US GAAP the foreign exchange loss (gain) would be classified under the cash flows from financing activities section as US GAAP requires that such items be netted with the related cash flow item. FOREIGN CURRENCIES Assets and liabilities at year-end and transactions during the period denominated in a foreign currency are translated into the Company's local currency (Australian dollars) at the exchange rates ruling at year-end and at the time of the transaction, respectively. Exchange adjustments are taken to the statement of income. INTANGIBLE FIXED ASSETS Project Development Expenditures - Project development expenditures represent the Company's share of project development expenditures incurred by the Gladstone Power Station Joint Venture to organize the acquisition of the Gladstone Power Station and operate it subsequent to the acquisition. Capitalized development expenditures are being amortized over the term of the Gladstone Power Station Power sales agreements (35 years), commencing from the date the investment in the project was consummated. The carrying values of capitalized development expenditures and the 5 8 SUNSHINE STATE POWER B.V. NOTES TO THE ANNUAL ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998 (Amounts expressed in thousands of Australian dollars) - - -------------------------------------------------------------------------------- amortization periods are reviewed annually and any necessary write down is charged against income. Research expenditures and expenditures on development of existing projects are charged against income in the year in which they are incurred. Financing Costs - Financing costs represent the Company's share of the costs incurred by the Gladstone Power Station Joint Venture to acquire the long-term debt used to finance the acquisition of the Gladstone Power Station. Capitalized financing costs are being amortized over a ten-year period, which represents the timeframe until the Company expects the long-term debt will be refinanced. TANGIBLE FIXED ASSETS All tangible fixed assets are stated at cost. The Company has not had any reevaluations performed on its tangible fixed assets. Tangible fixed assets, with the exception of land, are depreciated over their estimated useful lives or over the life of the power purchase agreement by the straight-line method. Ordinary maintenance and repairs are expensed as incurred; replacements and improvements are capitalized. The estimated useful lives are: STOCKS Stocks are carried at the lower of cost (principally by the FIFO method or another method which approximates FIFO) and net realizable value. In valuing stocks, appropriate allowance is made for obsolete or slow-moving items. TRADE DEBTORS Trade debtors are stated at nominal value. CASH AND BANK BALANCES The Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash. PROVISIONS Employee Provisions - Provisions are made for amounts expected to be paid to the operator of the Gladstone Power Station in respect of its employees for the pro rata entitlements for long service and annual leave. These amounts are accrued at actual pay rates having regard to experience of employee's departure and period of service. The provisions are divided into current (expected to be paid in the ensuing twelve months) and non-current portions. Deferred Tax - Provisions for deferred taxes have been set up where items entering into the determination of accounting profit for one period are recognized for taxation purposes in another. 6
Site roads and preparation 50 years Generators, systems, stacks, etc. 50 years Coal handling plant 10-50 years Other operating fixed assets 3-10 years 9 SUNSHINE STATE POWER B.V. NOTES TO THE ANNUAL ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998 (Amounts expressed in thousands of Australian dollars) - - -------------------------------------------------------------------------------- The principal difference arises in connection with the depreciation of fixed assets. In calculating the provision, current tax rates are applied. 7 10 SUNSHINE STATE POWER B.V. NOTES TO THE ANNUAL ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998 (Amounts expressed in thousands of Australian dollars) - - -------------------------------------------------------------------------------- COMPANY INCOME TAX Company income tax is based upon the results reported in the statement of income as adjusted for permanent differences. Current Australian tax rates are applied. CASH FLOW STATEMENT The cash flow statement has been prepared using the indirect method. COMPARATIVE AMOUNTS Comparative amounts are reclassified to conform with the current year's financial statement presentation. 3. INTANGIBLE FIXED ASSETS The movements in the intangible fixed assets are summarized as follows: 8
PROJECT DEVELOPMENT FINANCING EXPENDITURES COSTS TOTAL ------------ ---------- -------- COST Balance at December 31, 1998 6,984 2,707 9,691 Additions for the year ended December 31, 1999 -- -- -- -------- ------- ------- Balance at December 31, 1999 6,984 2,707 9,691 Additions for the year ended December 31, 2000 -- -- -- -------- ------- ------- Balance at December 31, 2000 6,984 2,707 9,691 -------- ------- ------- ACCUMULATED AMORTIZATION Balance at December 31, 1998 (949) (1,287) (2,236) Amortization for the year ended December 31, 1999 (200) (271) (471) Amortization for the year ended December 31, 2000 (200) (271) (471) -------- ------- ------- Balance at December 31, 2000 (1,349) (1,829) (3,178) -------- ------- ------- Net book value at December 31, 2000 5,635 878 6,513 ======== ======= ======= 11 SUNSHINE STATE POWER B.V. NOTES TO THE ANNUAL ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998 (Amounts expressed in thousands of Australian dollars) - - -------------------------------------------------------------------------------- 4. TANGIBLE FIXED ASSETS The movements in the tangible fixed assets are summarized as follows: As of January 1, 1999, the depreciation lives for site roads and preparation, generators, systems and stacks and the coal handling plant were prospectively changed from 35 to 50 years. This prospective change reduced 1999 depreciation expense by 1,677. 9
OTHER SITE ROADS GENERATORS, COAL OPERATING AND SYSTEMS, HANDLING FIXED LAND PREPARATION STACKS PLANT ASSETS TOTAL ------ ----------- ---------- --------- --------- -------- COST Balance at December 31, 1998 216 2,847 167,160 9,736 3,224 183,183 Additions -- 42 1,264 1,332 215 2,853 Disposals -- -- (135) -- (23) (158) ----- ------ -------- ------- ------- ------- Balance at December 31, 1999 216 2,889 168,289 11,068 3,416 185,878 Additions -- 11 902 61 153 1,127 Disposals -- -- (50) -- (12) (62) ----- ------ -------- ------- ------- ------- Balance at December 31, 2000 216 2,900 169,141 11,129 3,557 186,943 ===== ====== ======== ======= ======= ======= ACCUMULATED DEPRECIATION Balance at December 31, 1998 -- (488) (21,355) (2,749) (1,457) (26,049) Charge for the year -- (54) (3,352) (628) (301) (4,335) ----- ------ -------- ------- ------- ------- Balance at December 31, 1999 -- (542) (24,707) (3,377) (1,758) (30,384) Charge for the year -- (60) (3,189) (654) (376) (4,279) ----- ------ -------- ------- ------- ------- Balance at December 31, 2000 -- (602) (27,896) (4,031) (2,134) (34,663) ===== ====== ======== ======= ======= ======= Construction in progress at December 31, 2000 (construction in progress at December 31, 1999 and 1998 was AUD 363 and AUD 298, respectively) 930 ======= Net tangible fixed assets at December 31, 2000 153,210 ======= 12 SUNSHINE STATE POWER B.V. NOTES TO THE ANNUAL ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998 (Amounts expressed in thousands of Australian dollars) - - -------------------------------------------------------------------------------- 5. STOCKS 6. RECEIVABLES
DECEMBER 31 ------------------------------ 2000 1999 1998 --------- -------- --------- Coal 1,462 4,812 2,309 Fuel oils 164 159 84 Chemicals 9 10 7 Spares and consumables 1,081 1,229 1,097 --------- -------- --------- 2,716 6,210 3,497 ========= ======== ========= All receivables are due in less than one year. 7. CASH AND BANK BALANCES All cash and bank balances are held by banks and include investments with maturities of three months or less which are readily convertible to cash. The Company's long-term debt agreement places restrictions on the amount of cash and bank balances which must be maintained. At December 31, 2000, 1999 and 1998, the restricted cash and bank balances totaled AUD 7,292, AUD 6,460 and AUD 6,348, respectively. 8. ISSUED SHARE CAPITAL The authorized share capital consists of 2,000 shares each having a nominal value of 30 Australian dollars (40 Dutch Guilders), of which 1,000 shares have been issued and fully paid up at December 31, 2000, 1999 and 1998. In prior years, the Company's shares were owned by NRGenerating International B.V. (990) and Gunwale B.V. (10). Both NRGenerating International B.V. and Gunwale B.V. are wholly-owned by NRG Energy, Inc., which is incorporated in the United States of America. During 1999, the shares held by Gunwale B.V. were sold to NRGenerating International B.V. 10
DECEMBER 31 ------------------------------ 2000 1999 1998 --------- -------- --------- Trade debtors 5,651 4,701 5,444 Prepayments 89 190 77 --------- -------- --------- 5,740 4,891 5,521 ========= ======== ========= 13 SUNSHINE STATE POWER B.V. NOTES TO THE ANNUAL ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998 (Amounts expressed in thousands of Australian dollars) - - -------------------------------------------------------------------------------- 9. RETAINED EARNINGS 10. RESULT FOR THE PERIOD
2000 1999 --------- ---------- Balance at January 1 32,406 26,580 Appropriation of prior year's result 10,066 5,826 --------- ---------- Balance at December 31 42,472 32,406 ========= ========== 11. PROVISIONS
Balance at December 31, 1998 5,826 1998 net result appropriated to retained earnings (5,826) Net result for the year ended December 31, 1999 10,066 1999 net result appropriated to retained earnings (10,066) Net result for the year ended December 31, 2000 3,169 ---------- Balance at December 31, 2000 3,169 ========== Approximately AUD 713 of the employee provisions are current and expected to be paid during 2001. 11
EMPLOYEE DEFERRED PROVISIONS TAX TOTAL ---------- --------- ---------- Balance at December 31, 1998 1,229 16,689 17,918 Charged (released) to income 111 340 451 -------- --------- ---------- Balance at December 31, 1999 1,340 17,029 18,369 Charged (released) to income 97 1,358 1,455 -------- --------- ---------- Balance at December 31, 2000 1,437 18,387 19,824 ======== ========= ========== 14 SUNSHINE STATE POWER B.V. NOTES TO THE ANNUAL ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998 (Amounts expressed in thousands of Australian dollars) - - -------------------------------------------------------------------------------- 12. LONG-TERM LIABILITIES Secured long-term debt due to third parties: Current installments of bank long-term debt are included under current liabilities. The interest rate for long-term debt is variable based on an average of the bid rates quoted by the banks plus a margin of 1.5% at December 31, 2000, 1999 and 1998. The bank long-term debt is repayable as follows:
DECEMBER 31 --------------------------------- 2000 1999 1998 ---------- --------- ---------- Secured - with banks 83,533 90,808 97,408 ========== ========= ========== The bank long-term debt is secured by the Company's ownership interest in the Gladstone Power Station Joint Venture. Unsecured Subordinated Notes Payable (AUD'000) On March 25, 1994, the Company received loans from NRGenerating International B.V. and Gunwale B.V., the primary shareholders of the Company, in the amounts of AUD 48,312 and AUD 488, respectively. The notes payable are subordinated to all other liabilities of the Company, bear no interest and are to be repaid in US dollars. The Company repaid AUD 7,367 and AUD 4,109 to NRGenerating International B.V. during 2000 and 1999, respectively, and repaid AUD 4,655 and AUD 319 to NRGenerating International B.V. and Gunwale B.V. during 1998. Repayments on the notes payable are at the discretion of the Company, unless certain events of termination occur, as defined, and then the entire balance of the notes becomes due. The note balances, as adjusted for current period activity and foreign exchange fluctuations, were AUD 20,016, AUD 22,242 and AUD 0 to NRGenerating International B.V. and Gunwale B.V. at December 31, 2000 and 1999, respectively, and AUD 28,072 and AUD 0 to NRGenerating International B.V. and Gunwale B.V. at December 31, 1998, respectively. 12
2001 7,275 2002 8,013 2003 8,850 2004 9,738 2005 10,750 Thereafter 46,182 ---------- 90,808 ========== 15 SUNSHINE STATE POWER B.V. NOTES TO THE ANNUAL ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998 (Amounts expressed in thousands of Australian dollars) - - -------------------------------------------------------------------------------- 13. CURRENT LIABILITIES 14. RELATED PARTIES An affiliate of the Company, Sunshine State Power (No. 2) B.V. owns 17.5% of the Gladstone Power Station Joint Venture. Sunshine State Power (No. 2) B.V. is owned by the owners of the Company. The Gladstone Power Station is operated by NRG Gladstone Operating Services Pty. Ltd., which is ultimately a wholly-owned subsidiary of NRG Energy, Inc. NRG Gladstone Operating Services Pty. Ltd. operates the Gladstone Power Station under the terms of the Operation and Maintenance Agreement with the Gladstone Power Station Joint Venture. During the periods ended December 31, 2000 and 1999, the Company paid NRG Gladstone Operating Services Pty. Ltd. approximately AUD 332 and AUD 386, respectively, in operators fees under the terms of the Operation and Maintenance Agreement. 15. NUMBER OF EMPLOYEES The average number of persons employed at the Gladstone Power Station during 2000 was approximately 410 (1999: 400). These individuals are primarily employed in the operations and maintenance areas of the station. The Company is responsible for 20% of the related costs for these employees. The Company itself has no employees. 16. REMUNERATION OF DIRECTORS During the periods ended December 31, 2000, 1999 and 1998, none of the directors received remuneration for their services as directors of the Company. 13
DECEMBER 31 ---------------------------- 2000 1999 1998 -------- -------- -------- Current installments of bank long-term debt 7,275 6,600 5,975 Trade creditors/suppliers 782 819 538 Accrued coal/rail costs 2,635 2,433 2,337 Accrued interest 739 773 472 Other liabilities 906 602 220 -------- -------- -------- 12,337 11,227 9,542 ======== ======== ======== 16 SUNSHINE STATE POWER (NO. 2) B.V. ANNUAL FINANCIAL REPORT DECEMBER 31, 2000, 1999 AND 1998 17 SUNSHINE STATE POWER (NO. 2) B.V. INDEX TO ANNUAL FINANCIAL REPORT DECEMBER 31, 2000, 1999 AND 1998 - - --------------------------------------------------------------------------------
PAGE(S) ------- Auditors' Report 1 Balance Sheet at December 31, 2000, 1999 and 1998 2 Statement of Income for the years ended December 31, 2000, 1999 and 1998 3 Statement of Cash Flows for the years ended December 31, 2000, 1999 and 1998 4 Notes to the Annual Accounts for the years ended December 31, 2000, 1999 and 1998 5-13 18 TO THE SHAREHOLDERS OF SUNSHINE STATE POWER (NO. 2) B.V. AUDITORS' REPORT INTRODUCTION We have audited the accompanying balance sheet of Sunshine State Power (No. 2) B.V. as of December 31, 2000, 1999 and 1998, and the related statements of income and of cash flows for each of the three years ended December 31, 2000. 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. SCOPE We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. OPINION In our opinion, the financial statements give a true and fair view of the financial position of the Company as of December 31, 2000, 1999 and 1998 and of the results for the years then ended in accordance with accounting principles generally accepted in the Netherlands and comply with the financial reporting requirements included in Part 9, Book 2 of the Netherlands Civil Code. PRICEWATERHOUSECOOPERS N.V. March 2, 2001 Amsterdam, Netherlands 19 SUNSHINE STATE POWER (NO. 2) B.V. BALANCE SHEET AT DECEMBER 31, 2000, 1999 AND 1998 (Amounts expressed in thousands of Australian dollars) - - -------------------------------------------------------------------------------- The accompanying notes form an integral part of the annual accounts. 2
ASSETS 2000 1999 1998 ----------- ----------- ---------- Fixed assets: Intangible fixed assets 5,704 6,115 6,526 Tangible fixed assets 134,051 136,369 137,749 ----------- ----------- ---------- 139,755 142,484 144,275 Current assets: Stocks 2,377 5,434 3,060 Receivables 5,023 4,280 4,830 Cash and bank balances 11,556 9,816 10,037 ----------- ----------- ---------- 18,956 19,530 17,927 ----------- ----------- ---------- Total assets 158,711 162,014 162,202 =========== =========== ========== SHAREHOLDERS' EQUITY AND LIABILITIES Shareholders' equity: Issued share capital 30 30 30 Retained earnings 37,081 28,343 23,247 Result for the year 2,791 8,738 5,096 ----------- ----------- ---------- 39,902 37,111 28,373 ----------- ----------- ---------- Provisions 17,319 16,038 15,671 Long-term liabilities 90,591 98,937 109,669 Current liabilities 10,899 9,928 8,489 ----------- ----------- ---------- Total shareholders' equity and liabilities 158,711 162,014 162,202 =========== =========== ========== 20 SUNSHINE STATE POWER (NO. 2) B.V. STATEMENT OF INCOME FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998 (Amounts expressed in thousands of Australian dollars) - - -------------------------------------------------------------------------------- The accompanying notes form an integral part of the annual accounts. 3
2000 1999 1998 --------- ---------- --------- Net turnover: Enertrade 17,766 14,568 16,466 Boyne Smelters Limited 35,295 34,638 33,580 --------- ---------- --------- Total 53,061 49,206 50,046 Cost of turnover: Non-fuel 8,798 8,616 8,177 Fuel 24,544 21,473 21,756 --------- ---------- --------- Total 33,342 30,089 29,933 --------- ---------- --------- Gross profit on turnover 19,719 19,117 20,113 --------- ---------- --------- Operating expenses 1,349 2,068 1,424 Depreciation and amortization expense 4,157 4,205 5,608 --------- ---------- --------- Total expenses 5,506 6,273 7,032 --------- ---------- --------- Net profit on turnover 14,213 12,844 13,081 --------- ---------- --------- Interest expense 6,284 5,713 6,074 Interest income (602) (467) (458) Foreign exchange (gain) loss 4,502 (1,529) 833 Disposal of assets (gain) loss 42 119 17 --------- ---------- --------- Net financial expense 10,226 3,836 6,466 --------- ---------- --------- Result from ordinary operations before taxation 3,987 9,008 6,615 Taxation 1,196 270 1,519 --------- ---------- --------- Net result 2,791 8,738 5,096 ========= ========== ========= 21 SUNSHINE STATE POWER (NO. 2) B.V. STATEMENT OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998 (Amounts expressed in thousands of Australian dollars) - - -------------------------------------------------------------------------------- The accompanying notes form an integral part of the annual accounts. 4
2000 1999 1998 --------- ---------- --------- Cash flows from operating activities: Net result 2,791 8,738 5,096 Adjustments to reconcile net result to net cash provided by operating activities: Depreciation and amortization 4,157 4,205 5,608 Deferred income taxes 1,196 270 1,519 Foreign exchange loss (gain) 4,502 (1,529) 833 (Gain) loss on sale of fixed assets 42 139 17 Changes in operating assets and liabilities: Stocks 3,057 (2,374) (1,088) Receivables (743) 550 (920) Provisions 85 97 (12) Current liabilities 380 892 302 --------- ---------- --------- Net cash flows provided by operating activities 15,467 10,988 11,355 --------- ---------- --------- Cash flows from investing activities: Purchases of tangible fixed assets (1,482) (2,553) (1,633) Proceeds from sale of fixed assets 12 -- 19 --------- ---------- --------- Net cash flows used by investing activities (1,470) (2,553) (1,614) --------- ---------- --------- Cash flows from financing activities: Repayments of notes payable (6,482) (3,428) (4,481) Repayments of long-term debt (5,775) (5,228) (4,758) --------- ---------- --------- Net cash flows used by financing activities (12,257) (8,656) (9,239) --------- ---------- --------- Net increase (decrease) in cash and bank balances 1,740 (221) 502 Cash and bank balances: Beginning of year 9,816 10,037 9,535 --------- ---------- --------- End of year 11,556 9,816 10,037 --------- ---------- --------- Supplemental disclosure of cash paid for interest 6,284 5,450 5,998 ========= ========== ========= 22 SUNSHINE STATE POWER (NO. 2) B.V. NOTES TO THE ANNUAL ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998 (Amounts expressed in thousands of Australian dollars) - - -------------------------------------------------------------------------------- 1. GENERAL ACTIVITIES Sunshine State Power (No. 2) B.V. (the Company) was incorporated on February 24, 1994 and is seated in Amsterdam, the Netherlands. The Company's principal operating activity is the ownership of 17.5% of the Gladstone Power Station Joint Venture. The Gladstone Power Station Joint Venture owns and operates the Gladstone Power Station located in Queensland, Australia, which it acquired on March 30, 1994. The Gladstone Power Station Joint Venture is an unincorporated joint venture and therefore not a separate legal entity. Accordingly, the Gladstone Power Station Joint Venture owners act as tenants in common owning their proportionate shares of the unincorporated joint venture's assets, liabilities and results of operations. The unincorporated joint venture's assets, liabilities, results of operations and cash flows have been taken up in this annual financial report on a proportionate basis. The accounts have been prepared for the years ended December 31, 2000, 1999 and 1998. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES GENERAL Unless otherwise stated assets and liabilities are carried at nominal value. BASIS OF PREPARATION The Company's financial statements have been prepared in accordance with generally accepted accounting principles in the Netherlands (Netherlands GAAP) which may differ in certain respects from generally accepted accounting principles in the United States (US GAAP). With regard to the Company's balance sheet and statement of income, there are no material differences between Netherlands GAAP and US GAAP. With regard to the Company's statement of cash flows, under US GAAP the foreign exchange loss (gain) would be classified under the cash flows from financing activities section as US GAAP requires that such items be netted with the related cash flow item. FOREIGN CURRENCIES Assets and liabilities at year-end and transactions during the period denominated in a foreign currency are translated into the Company's local currency (Australian dollars) at the exchange rates ruling at year-end and at the time of the transaction, respectively. Exchange adjustments are taken to the statement of income. INTANGIBLE FIXED ASSETS Project Development Expenditures - Project development expenditures represent the Company's share of project development expenditures incurred by the Gladstone Power Station Joint Venture to organize the acquisition of the Gladstone Power Station and operate it subsequent to the acquisition. Capitalized development expenditures are being amortized over the term of the Gladstone Power Station Power sales agreements (35 years), commencing from the date the investment in the project was consummated. The carrying values of capitalized development expenditures and the 5 23 SUNSHINE STATE POWER (NO. 2) B.V. NOTES TO THE ANNUAL ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998 (Amounts expressed in thousands of Australian dollars) - - -------------------------------------------------------------------------------- amortization periods are reviewed annually and any necessary write down is charged against income. Research expenditures and expenditures on development of existing projects are charged against income in the year in which they are incurred. Financing Costs - Financing costs represent the Company's share of the costs incurred by the Gladstone Power Station Joint Venture to acquire the long-term debt used to finance the acquisition of the Gladstone Power Station. Capitalized financing costs are being amortized over a ten-year period, which represents the timeframe until the Company expects the long-term debt will be refinanced. TANGIBLE FIXED ASSETS All tangible fixed assets are stated at cost. The Company has not had any revaluations performed on its tangible fixed assets. Tangible fixed assets, with the exception of land, are depreciated over their estimated useful lives by the straight-line method. Ordinary maintenance and repairs are expensed as incurred; replacements and improvements are capitalized. The estimated useful lives are: STOCKS Stocks are carried at the lower of cost (principally by the FIFO method or another method which approximates FIFO) and net realizable value. In valuing stocks, appropriate allowance is made for obsolete or slow-moving items. TRADE DEBTORS Trade debtors are stated at nominal value net of provision for doubtful debtors. CASH AND BANK BALANCES The Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash. PROVISIONS Employee Provisions - Provisions are made for amounts expected to be paid to the operator of the Gladstone Power Station in respect of its employees for the pro rata entitlements for long service and annual leave. These amounts are accrued at actual pay rates having regard to experience of employee's departure and period of service. The provisions are divided into current (expected to be paid in the ensuing twelve months) and non-current portions. Deferred Tax - Provisions for deferred taxes have been set up where items entering into the determination of accounting profit for one period are recognized for taxation purposes in another. The principal difference arises in connection with the depreciation of fixed assets. In calculating the provision, current tax rates are applied. 6
Site roads and preparation 50 years Generators, systems, stacks, etc. 50 years Coal handling plant 10-50 years Other operating fixed assets 3-10 years 24 SUNSHINE STATE POWER (NO. 2) B.V. NOTES TO THE ANNUAL ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998 (Amounts expressed in thousands of Australian dollars) - - -------------------------------------------------------------------------------- COMPANY INCOME TAX Company income tax is based upon the results reported in the statement of income as adjusted for permanent differences. Current Australian tax rates are applied. CASH FLOW STATEMENT The cash flow statement has been prepared using the indirect method. COMPARATIVE AMOUNTS Comparative amounts are reclassified to conform with the current year's financial statement presentation. 3. INTANGIBLE FIXED ASSETS The movements in the intangible fixed assets are summarized as follows: 7
PROJECT DEVELOPMENT FINANCING EXPENDITURES COSTS TOTAL ------------ --------- ---------- COST Balance at December 31, 1998 6,111 2,369 8,480 Additions for the year ended December 31, 1999 -- -- -- ---------- --------- ---------- Balance at December 31, 1999 6,111 2,369 8,480 Additions for the year ended December 31, 2000 -- -- -- ---------- --------- ---------- Balance at December 31, 2000 6,111 2,369 8,480 ---------- --------- ---------- ACCUMULATED AMORTIZATION Balance at December 31, 1998 (829) (1,125) (1,954) Amortization for the year ended December 31, 1999 (175) (236) (411) Amortization for the year ended December 31, 2000 (174) (237) (411) ---------- --------- ---------- Balance at December 31, 2000 (1,178) (1,598) (2,776) ---------- --------- ---------- Net book value at December 31, 2000 4,933 771 5,704 ========== ========= ========== 25 SUNSHINE STATE POWER (NO. 2) B.V. NOTES TO THE ANNUAL ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998 (Amounts expressed in thousands of Australian dollars) - - -------------------------------------------------------------------------------- 4. TANGIBLE FIXED ASSETS The movements in the tangible fixed assets are summarized as follows: 8
OTHER SITE ROADS GENERATORS, COAL OPERATING AND SYSTEMS, HANDLING FIXED LAND PREPARATION STACKS PLANT ASSETS TOTAL ------ ----------- ----------- -------- --------- ----- COST Balance at December 31, 1998 189 2,491 146,267 8,525 2,813 160,285 Additions -- 36 1,106 1,165 188 2,495 Disposals -- -- (118) -- (20) (138) ------ ------- ---------- --------- ------- ---------- Balance at December 31, 1999 189 2,527 147,255 9,690 2,981 162,642 Additions -- 10 789 53 134 986 Disposals -- -- (43) -- (11) (54) ------ ------- ---------- --------- ------- ---------- Balance at December 31, 2000 189 2,537 148,001 9,743 3,104 163,574 ====== ======= ========== ========= ======= ========== ACCUMULATED DEPRECIATION Balance at December 31, 1998 -- (427) (18,640) (2,407) (1,321) (22,795) Charge for the year -- (48) (2,933) (550) (264) (3,795) ------ ------- ---------- --------- ------- ---------- Balance at December 31, 1999 -- (475) (21,573) (2,957) (1,585) (26,590) Charge for the year -- (53) (2,792) (572) (329) (3,746) ------ ------- ---------- --------- ------- ---------- Balance at December 31, 2000 -- (528) (24,365) (3,529) (1,914) (30,336) ====== ======= ========== ========= ======= ========== Construction in progress at December 31, 2000 (construction in progress at December 31, 1999 and 1998 was AUD 317 and AUD 259, respectively) 813 =========== Net tangible fixed assets at December 31, 2000 134,051 =========== 26 SUNSHINE STATE POWER (NO. 2) B.V. NOTES TO THE ANNUAL ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998 (Amounts expressed in thousands of Australian dollars) - - -------------------------------------------------------------------------------- As of January 1, 1999, the depreciation lives for site roads and preparation, generators, systems and stacks and the coal handling plant were prospectively changed from 35 to 50 years. This prospective change reduced 1999 depreciation expense by 1,468. 5. STOCKS 6. RECEIVABLES
DECEMBER 31 ------------------------------ 2000 1999 1998 --------- -------- --------- Coal 1,279 4,210 2,021 Fuel oils 144 140 73 Chemicals 8 9 6 Spares and consumables 946 1,075 960 --------- -------- --------- 2,377 5,434 3,060 ========= ======== ========= All receivables are due in less than one year. 7. CASH AND BANK BALANCES All cash and bank balances are held by banks and include investments with maturities of three months or less which are readily convertible to cash. The Company's long-term debt agreement places restrictions on the amount of cash and bank balances which must be maintained. At December 31, 2000, 1999 and 1998, the restricted cash and bank balances totaled AUD 6,380, AUD 5,653 and AUD 5,554, respectively. 9
DECEMBER 31 ------------------------------ 2000 1999 1998 --------- -------- --------- Trade debtors 4,946 4,114 4,763 Prepayments 77 166 67 --------- -------- --------- 5,023 4,280 4,830 ========= ======== ========= 27 SUNSHINE STATE POWER (NO. 2) B.V. NOTES TO THE ANNUAL ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998 (Amounts expressed in thousands of Australian dollars) - - -------------------------------------------------------------------------------- 8. ISSUED SHARE CAPITAL The authorized share capital consists of 2,000 shares each having a nominal value of 75 Australian dollars (100 Dutch Guilders), of which 400 shares have been issued and fully paid up at December 31, 2000, 1999 and 1998. In prior years, the Company's shares were owned by NRGenerating International B.V. (396) and Gunwale B.V. (4). Both NRGenerating International B.V. and Gunwale B.V. are wholly-owned by NRG Energy, Inc., which is incorporated in the United States of America. During 1999, the shares held by Gunwale B.V. were sold to NRGenerating International B.V. 9. RETAINED EARNINGS 10. RESULT FOR THE PERIOD
2000 1999 --------- ---------- Balance at January 1 28,343 23,247 Appropriation of prior year's result 8,738 5,096 --------- ---------- Balance at December 31 37,081 28,343 ========= ========== 10
Balance at December 31, 1998 5,096 1998 net result appropriated to retained earnings (5,096) Net result for the year ended December 31, 1999 8,738 1999 net result appropriated to retained earnings (8,738) Net result for the year ended December 31, 2000 2,791 ---------- Balance at December 31, 2000 2,791 ========== 28 SUNSHINE STATE POWER (NO. 2) B.V. NOTES TO THE ANNUAL ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998 (Amounts expressed in thousands of Australian dollars) - - -------------------------------------------------------------------------------- 11. PROVISIONS Approximately AUD 624 of the employee provisions are current and expected to be paid during 2001. 12. LONG-TERM LIABILITIES Secured long-term debt due to third parties:
EMPLOYEE DEFERRED PROVISIONS TAX TOTAL ---------- --------- ---------- Balance at December 31, 1998 1,076 14,595 15,671 Charged (released) to income 97 270 367 -------- --------- ---------- Balance at December 31, 1999 1,173 14,865 16,038 Charged (released) to income 85 1,196 1,281 -------- --------- ---------- Balance at December 31, 2000 1,258 16,061 17,319 ======== ========= ========== Current installments of bank long-term debt are included under current liabilities. The interest rate for long-term debt is variable based on an average of the bid rates quoted by the banks plus a margin of 1.5% at December 31, 2000. The bank long-term debt is repayable as follows:
DECEMBER 31 --------------------------------- 2000 1999 1998 --------- --------- --------- Secured - with banks 73,091 79,457 85,232 The bank long-term debt is secured by the Company's ownership interest in the Gladstone Power Station Joint Venture. 11
2001 6,366 2002 7,011 2003 7,744 2004 8,520 2005 9,406 Thereafter 40,410 ----------- 79,457 =========== 29 SUNSHINE STATE POWER (NO. 2) B.V. NOTES TO THE ANNUAL ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998 (Amounts expressed in thousands of Australian dollars) - - -------------------------------------------------------------------------------- Unsecured subordinated note payable (AUD'000) On March 25, 1994, the Company received loans from NRGenerating International B.V. and Gunwale B.V., the primary shareholders of the Company, in the amount of AUD 42,273 and AUD 427, respectively. The notes payable are subordinated to all other liabilities of the Company, bear no interest and are to be repaid in U.S. dollars. The Company repaid AUD 6,482 and AUD 3,428 to NRGenerating International B.V. during 2000 and 1999, respectively, and AUD 4,202 and AUD 279 to NRGenerating International B.V. and Gunwale B.V., respectively, during 1998. Repayments on the notes payable are at the discretion of the Company, unless certain events of termination occur, as defined, and then the entire balance of the notes becomes due. The note balances, as adjusted for current period activity and foreign exchange flunctuations, were AUD 17,500 and AUD 19,480 to NRGenerating International B.V. at December 31, 2000 and 1999, respectively, and AUD 24,437 and AUD 0 to NRGenerating International B.V. and Gunwale B.V., respectively, at December 31, 1998. 13. CURRENT LIABILITIES 14. RELATED PARTIES An affiliate of the Company, Sunshine State Power B.V. owns 20% of the Gladstone Power Station Joint Venture. Sunshine State Power B.V. is owned by the owners of the Company. The Gladstone Power Station is operated by NRG Gladstone Operating Services Pty. Ltd., which is ultimately a wholly-owned subsidiary of NRG Energy, Inc. NRG Gladstone Operating Services Pty. Ltd. operates the Gladstone Power Station under the terms of the Operation and Maintenance Agreement with the Gladstone Power Station Joint Venture. During the periods ended December 31, 2000, 1999 and 1998, the Company paid NRG Gladstone Operating Services Pty. Ltd. approximately AUD 291, AUD 338 and AUD 345, respectively, in operators fees under the terms of the Operation and Maintenance Agreement. 12
DECEMBER 31 ------------------------------ 2000 1999 1998 --------- -------- --------- Current installments of bank long-term debt 6,366 5,775 5,228 Trade creditors/suppliers 684 716 471 Accrued coal/rail costs 2,306 2,129 2,045 Accrued interest 646 677 413 Other accrued expenses 897 631 332 --------- -------- --------- 10,899 9,928 8,489 ========= ======== ========== 30 SUNSHINE STATE POWER (NO. 2) B.V. NOTES TO THE ANNUAL ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998 (Amounts expressed in thousands of Australian dollars) - - -------------------------------------------------------------------------------- 15. NUMBER OF EMPLOYEES The average number of persons employed at the Gladstone Power Station during 2000 was approximately 410 (1999: 400). These individuals are primarily employed in the operations and maintenance areas of the station. The Company is responsible for 17.5% of the related costs for these employees. The Company itself has no employees. 16. REMUNERATION OF DIRECTORS During the periods ended December 31, 2000, 1999 and 1998, none of the directors received remuneration for their services as directors of the Company. 13
1 EXHIBIT 99.4 Financial Statements of "West Coast Power" WEST COAST POWER LLC Consolidated Financial Statements As of December 31, 2000 Together With Auditors' Report REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS 2 To the Member of West Coast Power LLC: We have audited the accompanying consolidated balance sheets of West Coast Power LLC (a Delaware limited liability company) as of December 31, 2000 and 1999, and the related consolidated statements of operations, member equity and cash flows for the years then ended. 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 in accordance with auditing standards generally accepted in the United States. Those standards 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of West Coast Power LLC as of December 31, 2000 and 1999, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States. /s/ Arthur Andersen LLP - - ------------------------- Arthur Andersen LLP Houston, Texas March 19, 2001 3 WEST COAST POWER LLC CONSOLIDATED BALANCE SHEETS--DECEMBER 31, 2000 AND 1999 The accompanying notes are an integral part of these consolidated financial statements.
2000 1999 ------------- ------------- ASSETS CURRENT ASSETS: Cash and cash equivalents $ 41,617,872 $ 42,291,460 Accounts receivable 281,495,024 74,770,187 Less- Contingent revenues receivable (34,895,799) (15,905,719) ------------- ------------- - Accounts receivable, net 246,599,225 58,864,468 Inventories 30,522,385 15,603,482 Prepaid expenses 3,164,171 2,602,078 Loans to affiliates -- 11,465,643 ------------- ------------- Total current assets 321,903,653 130,827,131 ------------- ------------- PROPERTY, PLANT AND EQUIPMENT, at cost: Land 56,583,322 56,583,322 Plant and equipment 483,185,648 469,919,080 Less- Accumulated depreciation (59,719,649) (30,393,600) ------------- ------------- Property, plant and equipment, net 480,049,321 496,108,802 ------------- ------------- OTHER ASSETS: Goodwill, net of accumulated amortization of $9,283,968 and $5,696,859 for 2000 and 1999, respectively 41,833,689 48,290,798 Deferred financing costs, net of accumulated amortization of $2,313,084 and $771,030 for 2000 and 1999, respectively 3,855,127 5,397,186 ------------- ------------- Total other assets 45,688,816 53,687,984 ------------- ------------- Total assets $847,641,790 $680,623,917 ============= ============= LIABILITIES AND MEMBER EQUITY CURRENT LIABILITIES: Current maturities of long-term debt $ 24,000,000 $ 25,000,000 Accounts payable- Trade 14,799,923 16,166,426 Affiliates 165,757,432 13,696,198 Accrued liabilities 22,952,317 28,146,043 Deferred revenues - 21,927,348 Overhaul and maintenance reserve 2,762,223 11,190,440 ------------- ------------- Total current liabilities 230,271,895 116,126,455 LONG-TERM DEBT, net of current maturities 193,904,000 272,500,000 COMMITMENTS AND CONTINGENCIES (Note 7) MEMBER EQUITY 423,465,895 291,997,462 ------------- ------------- Total liabilities and member equity $847,641,790 $680,623,917 ============= ============= 4 WEST COAST POWER LLC CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2000 AND 1999 The accompanying notes are integral part of these consolidated financial statements.
2000 1999 -------------- -------------- REVENUES $ 910,145,395 $ 289,578,949 Less- Contingent revenues (34,895,799) (10,849,362) -------------- -------------- Net revenues 875,249,596 278,729,587 OPERATING COSTS: Nonaffiliate 50,295,186 54,823,242 Affiliate 507,402,366 152,117,104 -------------- -------------- Total operating costs 557,697,552 206,940,346 -------------- -------------- Operating margin 317,552,044 71,789,241 DEPRECIATION AND AMORTIZATION (34,455,219) (26,397,605) GENERAL AND ADMINISTRATIVE EXPENSES (4,711,184) (2,077,259) -------------- -------------- Income from operations 278,385,641 43,314,377 INTEREST EXPENSE (26,518,883) (16,616,034) OTHER EXPENSE (12,211,623) - INTEREST INCOME 5,724,794 2,346,407 -------------- -------------- NET INCOME $ 245,379,929 $ 29,044,750 ============= ============= 5 WEST COAST POWER LLC CONSOLIDATED STATEMENTS OF MEMBER EQUITY FOR THE YEARS ENDED DECEMBER 31, 2000 AND 1999 The accompanying notes are an integral part of these consolidated financial statements.
BALANCE, January 1, 1999 $ 134,850,078 Contributions 142,642,634 Net income 29,044,750 Distributions (14,540,000) -------------- BALANCE, December 31, 1999 291,997,462 Contributions 16,207,956 Net income 245,379,929 Distributions (130,119,452) -------------- BALANCE, December 31, 2000 $ 423,465,895 ============= 6 WEST COAST POWER LLC CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2000 and 1999 The accompanying notes are an integral part of these consolidated financial statements.
2000 1999 -------------- ------------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income $ 245,379,929 $ 29,044,750 Adjustments to reconcile net income to net cash provided by (used in) operating activities- Depreciation and amortization 34,455,219 26,397,605 Changes in assets and liabilities that provided (used) cash- Accounts receivable (206,724,837) (6,076,473) Contingent receivables 18,990,080 (22,849,885) Inventories (14,918,903) (65,213) Prepaid expenses (562,093) (1,554,054) Payables 150,694,731 22,449,400 Accrued liabilities (5,193,726) (84,399,090) Overhaul and maintenance reserve (8,428,217) 8,065,007 Deferred revenues (21,927,348) (3,023,449) Other assets, net 2,870,000 (5,901,933) -------------- ------------- Net cash provided by (used in) operating activities 194,634,835 (37,913,335) -------------- ------------- CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures (13,266,570) (3,523,332) Business acquisitions, net of cash acquired -- (352,500,064) -------------- ------------- Net cash used in investing activities (13,266,570) (356,023,396) -------------- ------------- CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from borrowings 10,000,000 378,366,037 Repayments of borrowings (89,596,000) (80,866,037) Loans to affiliates 11,465,643 (11,465,643) Contributions 16,207,956 142,642,634 Distributions (130,119,452) (14,540,000) -------------- ------------- Net cash provided by (used in) financing activities (182,041,853) 414,136,991 -------------- ------------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (673,588) 20,200,260 CASH AND CASH EQUIVALENTS, beginning of year 42,291,460 22,091,200 -------------- ------------- CASH AND CASH EQUIVALENTS, end of year $ 41,617,872 $ 42,291,460 ============== ============= SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid for interest $ 27,315,568 $ 15,086,581 ============== ============= 7 WEST COAST POWER LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. BACKGROUND AND NATURE OF OPERATIONS: Background Prior to 1999, Dynegy Power Corp. (DPC), a wholly owned subsidiary of Dynegy Inc. (Dynegy), and NRG Energy, Inc. (NRG), a majority owned subsidiary of Northern States Power until its merger with New Centuries Energies to form Xcel Energy, Inc., in August 2000 (collectively, the Sponsors) each held a 50 percent interest in two limited liability companies: El Segundo Power, LLC (ESP), and Long Beach Generation LLC (LBG) (collectively, the Historical LLCs). In May 1999, the Sponsors acquired the assets and liabilities which make up Cabrillo Power I LLC (Cabrillo I) and Cabrillo Power II LLC (Cabrillo II) (collectively, the New LLCs). Effective June 30, 1999, the Sponsors formed WCP Holdings LLC (Holdings) and West Coast Power LLC (WCP), a Delaware limited liability company. The Sponsors have an equal interest in Holdings and share in profits and losses equally. WCP is wholly owned by Holdings and serves as a holding company for the Historical LLCs and New LLCs. Upon formation of WCP, the assets and liabilities of the Historical LLCs were contributed to WCP by the Sponsors and were recorded at their historical costs because the transfer represented a reorganization of entities under common control. These financial statements include the results of operations of the Historical LLCs for all of 2000 and 1999 and the results of operations of the New LLCs since the date of their acquisition. Operations are governed by the executive committee with two representatives from each Sponsor. Nature of Operations ESP owns a 1,020-megawatt (MW) plant located in El Segundo, California, consisting of four steam electric generating units. ESP's assets were purchased from the Southern California Edison Company (SCE) through a competitive bid process for $88.3 million on April 4, 1998. The facility operates as a merchant plant, selling energy and ancillary services, as defined in the California Independent System Operator (ISO) tariff, to the deregulated California wholesale electric market. The facility also maintained a Must-Run Agreement (MRA) with the ISO that was terminated by the ISO on December 31, 1999. LBG owns a 560-MW plant located in Long Beach, California, consisting of seven 60-MW gas turbine generators, and also owns two 70-MW steam turbine units. LBG's assets were purchased from SCE on April 1, 1998, through a competitive bid process for $29.8 million. The facility operates as a merchant plant, selling energy and ancillary services through the deregulated California wholesale electric market. Cabrillo I owns a 965-MW plant located in Carlsbad, California, consisting of five steam electric generating units and one combustion turbine. Cabrillo I's assets were purchased from San Diego Gas & Electric (SDG&E) on May 22, 1999, at a purchase price of $283.4 million. The facility operates as a merchant plant, selling energy and ancillary services to the California wholesale electric market. The facility also maintains an MRA with the ISO. Cabrillo II owns 17 combustion turbines with an aggregate capacity of 253 MW located throughout San Diego County, California. Cabrillo II's assets were purchased on May 22, 1999, from SDG&E through a competitive bid process for a purchase price of $69.1 million. The facility operates as a merchant plant, selling energy and ancillary services to the California wholesale electric market. The facility also maintains an MRA with the ISO. 8 -2- 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: Cash and Cash Equivalents WCP considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. Inventories Inventories are stated at the lower of market or cost using last-in, first-out (LIFO) or average cost and are comprised of the following at December 31, 2000 and 1999: Emission credits represent costs paid by WCP to acquire additional NOx credits. WCP uses these credits to comply with emission caps imposed by various environmental laws under which it must operate. Plant and Equipment Plant and equipment costs are being depreciated on a straight-line basis over estimated useful lives of 3 to 29 years. Impairment of Long-Lived Assets In the event that facts and circumstances indicate that the carrying amounts of long-lived assets may be impaired, an evaluation of recoverability would be performed. If an evaluation is required, the estimated future undiscounted cash flows associated with the asset would be compared to the asset's carrying amount to determine if a write-down is required. If this review indicates that the assets will not be recoverable, the carrying value of WCP's assets would be reduced to their estimated market value. Goodwill Goodwill represents the excess purchase cost over the estimated fair value of the assets acquired and liabilities assumed and is being amortized on a straight-line basis over prorated 3 to 27 year estimated useful lives based on the useful life of the related plant and equipment. Overhaul and Maintenance Reserves WCP accrues major overhaul and maintenance costs expected to be incurred that are not covered by the operations and maintenance agreements. Other maintenance and repair costs are charged to expense as incurred. Federal Income Taxes WCP is not a taxable entity for federal income tax purposes. Accordingly, there is no provision for income taxes in the accompanying financial statements.
2000 1999 ------------ ----------- Emissions credits (average cost) $12,872,541 $ -- Materials and supplies (average cost) 10,372,169 11,016,854 Fuel oil (LIFO) 7,277,675 4,586,628 ------------ ----------- $30,522,385 $15,603,482 ============ =========== 9 -3- Revenue Recognition Revenues from the sale of energy and ancillary services are recorded based upon output delivered and/or service provided multiplied by contract terms where applicable and/or market pricing. Revenues received from the MRA are primarily derived from availability payments and amounts based on reimbursing variable costs. Historically, virtually all of WCP's sales have been to the ISO and the California Power Exchange. Revenues identified as being subject to future resolution are accounted for as discussed in Note 7. Environmental Costs Environmental costs relating to current operations are expensed. Liabilities are recorded when an environmental assessment indicates that remedial efforts are probable and the costs can be reasonably estimated. Risk Management Activities WCP enters into various derivative instruments to protect itself from fluctuating prices and interest rates. WCP uses physical forward contracts to hedge a portion of its exposure to price fluctuations of natural gas and electricity. Hedging gains and losses are recognized when the related sales transactions occur. WCP also enters into interest rate swap agreements, which effectively exchange variable interest rate debt for fixed interest rate debt. The agreements are used to reduce the exposure to possible increases in interest rates. WCP enters into these swap agreements with major financial institutions. Concentration of Credit Risk WCP sells its electricity production to purchasers of electricity in California, which, during the year ended December 31, 2000, included the California Power Exchange (PX) and the California Independent System Operator (ISO). Given recent developments in the California power and natural gas markets (see Note 7), the concentration of WCP's receivables from customers in the California market exposes WCP to substantial credit risk. Management believes that its net receivables from customers in the California market will ultimately be fully collected and has taken steps as discussed in Note 7 to limit its future exposure to credit risk in the California market. Use of Estimates in Financial Statement Preparation The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires estimates and assumptions that affect the reported amounts of assets and liabilities as well as certain disclosures. WCP's financial statements include amounts that are based on management's best estimates and judgments. Actual results could differ from those estimates. Fair Value of Financial Instruments WCP's financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable and debt instruments. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable are representative of their respective fair values due to the short-term maturity of these instruments. The fair value of WCP's debt instruments is discussed in Note 6. WCP has entered into certain interest rate swap agreements in order to fix its effective interest rate as discussed in Note 6 and electricity and gas options as discussed in Note 3. New Accounting Pronouncements WCP must adopt Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," effective January 1, 2001. Provisions in SFAS No. 133 will affect the accounting and disclosure for certain contractual arrangements and operations of WCP beginning in 2001. 10 -4- WCP will record the impact of the adoption as a cumulative effect adjustment in 2001. Adoption of SFAS No. 133 will not affect WCP's net income. The table below reflects the amounts that will be recorded as assets, liabilities and other comprehensive income upon adoption of SFAS No. 133 on January 1, 2001: Upon adoption of SFAS No. 133, WCP will account for its physical forward contracts as normal purchases and sales that are exempt from derivative accounting treatment under SFAS No. 133 because of the contracts will result in physical delivery. Reclassifications Certain reclassifications have been made to conform the prior year presentation to the current year presentation. 3. NATURAL GAS AND ELECTRICITY OPTIONS: WCP has purchased and sold gas and electricity options to manage the operating margins of its plants during 2001. The purchased gas call options have a fair value of approximately $1.4 million. The sold electricity call options have a fair value of approximately $(12.2) million. The purchased gas calls are accounted for as hedges and, accordingly, changes in the market value of these contracts and the premiums paid are deferred until the actual natural gas purchases occur. The sold electricity options do not qualify for hedge accounting, and changes in the market value of these contracts are recorded currently. For the year ended December 31, 2000, WCP had recorded expense of approximately $12.2 million related to the sold electricity options, which has been included in other expense in the consolidated statement of operations. 4. RELATED PARTIES: Affiliates of WCP provide various services for WCP. Charges for these services are included in WCP's operating and general and administrative expenses and consisted of the following for the years ended December 31, 2000 and 1999:
Interest Commodity Rate Financial Swaps Instruments ----------- ---------- Derivative assets $ -- $1,376,320 Derivative liabilities 1,523,871 -- ----------- ---------- Other comprehensive income (loss) $(1,523,871) $1,376,320 =========== ========== WCP purchases fuel for its plants under various natural gas supply agreements (GSAs) with Dynegy Marketing and Trade (DMT). Charges for fuel are based upon similar terms and conditions as could be obtained from third parties.
2000 1999 ------------- ------------- Operating expenses- Fuel $482,937,131 $147,503,316 EMA charges 9,091,528 3,869,387 OMSA and O&M charges 15,373,707 744,401 ------------- ------------- $507,402,366 $152,117,104 ============= ============= ASMA fees included in general and administrative expenses $ 776,403 $ 491,659 ============= ============= 11 -5- WCP contracted with Dynegy Power Marketing, Inc., an affiliate of WCP, to provide all power scheduling, power marketing and trading and risk management for WCP under an energy management agreement (the EMA). Additionally, WCP contracted with DMT to provide all scheduling and marketing of fuel supply for WCP under the EMA. WCP has also contracted with NRG West Coast, Inc., an affiliate of WCP, to manage the Operations and Management Services Agreement (the OMSA). These services consist primarily of overseeing the operations and maintenance efforts of SCE and SDG&E. SCE operated ESP and LBG until April 2000, when NRG took over operations of the facility under a renegotiated OMSA. Fees for such services are subject to executive committee approval if the amounts exceed a certain percentage of the applicable annual approved budget. WCP contracted with Dynegy Power Management Services, L.P., an affiliate of WCP, to manage the Administrative Services Management Agreement (the ASMA) which provides administrative services such as business management and accounting to WCP. Fees for such services are subject to executive committee approval if the amounts exceed a certain percentage of the applicable annual approved budget. 5. OPERATION AND MAINTENANCE AGREEMENTS: For the New LLCs' acquisition, WCP was required to enter into an operation and maintenance (O&M) agreement with SDG&E, which will expire in May 2001. For 1999, the Historical LLCs were operated under an O&M agreement with SCE which expired in early 2000. The SDG&E and SCE O&M agreements are cost-plus agreements based on SDG&E's and SCE's estimates of the direct and indirect service costs for operating and maintaining the plant sites. Expenses related to such services of $14,129,740 and $25,900,000 were included in operating costs in the accompanying consolidated statements of operations for the years ended December 31, 2000 and 1999, respectively. 6. LONG-TERM DEBT: WCP entered into a credit agreement with Bank of America Securities LLC, as agent, to arrange with a syndicate of banks a five-year, $322,500,000 amortizing term loan with a balloon payment and a $40,000,000 working capital facility line of credit (the Credit Agreement); the Credit Agreement matures in June 2004. At December 31, 2000, no amounts were outstanding under the working capital facility. The fair value of WCP's debt instruments is considered to approximate the carrying amount of these instruments as their interest rates are based on the London Interbank Offering Rate (LIBOR). The interest rate used on the outstanding loan balance is based upon LIBOR plus 2.0 percent, increasing in year three to 2.125 percent. WCP paid interest on these borrowings totaling $27,315,568 in 2000 and $13,218,000 in 1999. On September 30, 1999, WCP entered into two interest rate swap agreements related to WCP's debt. One agreement effectively fixed the interest rate at 6.435 percent for the first $60,000,000 and matures June 2004. The second swap agreement effectively fixed the interest rate at 6.230 percent for an incremental $40,000,000 and matures in June 2002. At December 31, 2000, the fair values of the swaps maturing in 2004 and 2002, were $(1,237,090) and $(286,781), respectively. These swaps are accounted for as hedges and any realized gains or losses on these contracts are recorded as interest expense in the consolidated statement of operations. The credit agreement is secured by all of WCP's assets and membership interests. The Sponsors have provided limited guarantees for environmental capital expenditures and interest. Environmental capital expenditures, as defined in the Credit Agreement, will be funded by the Sponsors, who will make capital contributions or subordinated loans to WCP to the extent necessary for environmental capital expenditures up to an aggregate of $80 million. 12 -6- Future principal maturities under the term loan are as follows: 7. COMMITMENTS AND CONTINGENCIES: California Power and Natural Gas Markets Since the fourth quarter of 2000, the power and natural gas markets in California have experienced substantial volatility driven principally by a fundamental imbalance in supply and demand and the retail electricity price caps imposed on the state's two largest utilities. Both Pacific Gas & Electric Company and Southern California Edison Company have defaulted on payments to the ISO and the PX as well as other creditors. As a result, the credit rating of both utilities has been cut to non-investment grade status, and the ISO and the PX have defaulted on payments due WCP. WCP is actively seeking the collection of its outstanding accounts receivable. However, due to previously discussed payment defaults, coupled with the lag time between receipts of revenues, payment of expenses and the increased fuel cost, WCP has been forced to defer payment for a portion of its fuel cost. This deferral of payment has caused WCP to be out of compliance with the terms of its GSAs. WCP's noncompliance has also caused WCP to be out of compliance with the terms of its Credit Agreement. The executive committee of WCP has taken steps to address WCP's liquidity issues created by the California market situation as well as the resulting events of noncompliance under WCP's GSAs and Credit Agreement. These steps include (a) a negotiated deferral of payments owed under the GSAs, (b) negotiating a forbearance agreement with certain key creditors and (c) seeking alternative creditworthy purchasers for WCP's prospective operations. Under the forbearance agreement being negotiated, certain WCP creditors would grant forbearances with respect to the past events of noncompliance discussed above, subject to certain parameters as described therein. WCP's management has had substantive discussions regarding the proposed forbearance terms with the lead member of its bank syndicate. A forbearance agreement has been presented to the bank consortium for its review and approval. Management believes that the forbearance agreement presented to the bank consortium will be executed and that the terms of that agreement will be sufficient to remedy the noncompliance issues under the Credit Agreement. The state of California, through legislation appropriating funds for power purchases by the Department of Water Resources (DWR), has entered the market as a purchaser of electricity for resale to the utilities. In March 2001, WCP entered into an agreement to sell power to the DWR through 2004. The agreement, which became effective on the date it was announced, provides for sales by WCP's subsidiaries of an aggregate of 1,000 MW through the remainder of 2001 and a substantial portion of WCP's capacity during the period from January 1, 2002, through December 31, 2004. The executive committee of WCP is actively monitoring the financial and liquidity impacts imposed on WCP by the current situation. It believes the combination of the forbearance agreement, the DWR agreement and the desire of the conflicted parties to resolve, on a long-term basis, the pertinent issues giving rise to the current situation will provide financial stability for WCP. However, a prolonged impasse on resolving the market issue, the inability of WCP to meet its commitments under the forbearance agreement or a continuing edict to produce electricity with delayed compensation for this service will negatively impact WCP's available discretionary cash flow, results of operations, financial position and, potentially, its financial stability.
2001 $ 24,000,000 2002 18,000,000 2003 18,000,000 2004 157,904,000 ------------- $217,904,000 ============= 13 -7- Litigation Class Action Lawsuits--There have been multiple class action lawsuits filed which name WCP as a defendant. These lawsuits are based on the events occurring in the California power market during the summer of 2000. The complaints allege violations of California's Business and Professions Code, Unfair Trade Practices Act and various other statutes. Specifically, the named plaintiffs allege that the defendants, including the owners of in-state generation and various power markets, conspired to manipulate the California wholesale power market to the detriment of California consumers. Included among the acts forming the basis of the plaintiffs' claims are the alleged improper sharing of generation outage data, improper withholding of generation capacity and the manipulation of power market bid practices. The plaintiffs seek unspecified treble damages. These lawsuits are at preliminary stages. Defendants have yet to file answers and, as noted above, the suits have been removed to federal court. The named plaintiffs have filed, or will shortly file, motions to remand the cases back to California state court. The defendants in the five lawsuits have formed various joint defense groups in an effort to coordinate the defense of the claims and to share certain costs of defense. CAISO FERC Filing--On March 1, 2001, the California Independent System Operator Corporation (CAISO) and the California Electricity Oversight Board (EOB) filed a motion with the FERC proposing, among other things, that they be given access to cost information that generators have filed with the FERC and that the FERC keep all sales in California subject to refund. WCP will vigorously oppose this motion because it believes that there is no basis for giving the state of California, a significant market participant, access to confidential generator information on bids and costs. In addition, WCP believes that there is no basis for the FERC to extend refund exposure on a generic, blanket basis, as such an extension would contradict the FERC's carefully crafted refund structure designed to minimize the obvious disincentives that refund exposure creates for suppliers. FERC Orders--On December 15, 2000, the FERC issued an order that, among other things, applied a "soft" price cap of $150/megawatt hour (MWh) to sales to the PX and the ISO. The "soft" cap allowed prices to exceed $150/MWh when justified by costs. In March 2001, the FERC issued orders that presumptively approved prices up to $273/MWh during January 2001 and $430/MWh during February 2001 based on the FERC's calculation of the marginal cost of producing power in the least efficient generating unit. The orders directed electricity suppliers to either refund a portion of their January and February sales or justify their prices above this approved price. The orders, if finalized, would obligate WCP to refund approximately $45 million in revenues. The FERC stated in its order that it would address December 2000 transactions in a separate order. These orders implement a departure from standard cost-based ratemaking and is likely to be appealed by both buyers and sellers of power. WCP is also subject to various other legal proceedings and claims that arise in the normal course of business. In the opinion of management, the amount of ultimate liability with respect to its litigation matters will not have a material adverse effect on WCP's financial position or results of operations. Contingent Revenues During December 2000, WCP entered into an interim agreement with the ISO. WCP has accrued an incremental $34,895,799 in revenues that management believes to be associated with sales under this agreement. There is an ongoing reconciliation process between the ISO and WCP regarding this matter and, accordingly, the $34,895,799 has been reserved as contingent. While there can be no assurance that these disputed amounts will be collected, management believes the contingent revenues are realizable based on contractual interpretations and compliance with required processes. Upon collection of this amount, such revenue will be recognized in earnings. 14 -8- As of December 31, 1999, WCP had accrued certain reserves pertaining to contingent revenues totaling $37,833,000 related to 1999 and prior periods. These reserves were provided for various disputes with customers that were subject to contract interpretations, compliance with processes and filed market disputes. Cash received totaling $11.4 million associated with deferred revenues was loaned in 1999 to the Sponsors until resolution of the disputed items. These reserves were settled during 2000, and all loans to affiliates were repaid. Adjustments related to the settlement were applied against the contingent reserves with an insignificant impact on the consolidated statement of operations in 2000. 8. ACQUISITION OF CABRILLO I AND CABRILLO II: In May 1999, the Sponsors acquired the assets and liabilities of Cabrillo I and Cabrillo II from a third party. The acquisition was accounted for using the purchase method of accounting. Accordingly, the purchase cost, net of working capital, was allocated to the assets acquired and liabilities assumed based on their estimated fair values at the date of acquisition. Consideration for the acquisition included cash paid of $352,500,000 and the assumption of $95,928,000 in liabilities. The following unaudited pro forma information presents a summary of consolidated results of operations of WCP for the year ended December 31, 1999, as if the acquisition of the New LLCs by the Sponsors and subsequent transfer to WCP had occurred on January 1, 1999:
Revenues $300,418,772 Net income 23,593,479