SEC Filing | NRG Energy, Inc.

1 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON APRIL 19, 2000 REGISTRATION NO. 333- - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 ------------------------------------ Form S-1 REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933 ------------------------------------ NRG ENERGY, INC. (Exact name of registrant as specified in its charter) DELAWARE 4911 41-1724239 (State or other jurisdiction of (Primary Standard Industrial (I.R.S. Employer Identification incorporation or organization) Classification Code Number) No.) ------------------------------------ 1221 NICOLLET MALL, SUITE 700 MINNEAPOLIS, MINNESOTA 55403 (612) 373-5300 (Address, including zip code, and telephone number, including area code, of registrant's principal executive offices) JAMES J. BENDER, ESQ. VICE PRESIDENT, GENERAL COUNSEL AND CORPORATE SECRETARY NRG ENERGY, INC. 1221 NICOLLET MALL, SUITE 700 MINNEAPOLIS, MINNESOTA 55403 (612) 373-5300 (Name, address, including zip code, and telephone number, including area code, of agent for service) ------------------------------------ WITH COPIES TO: RICHARD M. RUSSO, ESQ. STACY J. KANTER, ESQ. GIBSON, DUNN & CRUTCHER LLP SKADDEN, ARPS, SLATE, MEAGHER & FLOM, LLP 1801 CALIFORNIA STREET, SUITE 4100 FOUR TIMES SQUARE DENVER, COLORADO 80202 NEW YORK, NEW YORK 10036 303-298-5715 212-735-3000 ------------------------------------ APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As soon as practicable after this Registration Statement becomes effective. If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act, check the following box. [ ] If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [ ] If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [ ] If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [ ] If delivery of the prospectus is expected to be made pursuant to Rule 434, check the following box. [ ] ------------------------------------ CALCULATION OF REGISTRATION FEE - ------------------------------------------------------------------------------------------------------ PROPOSED MAXIMUM TITLE OF EACH CLASS AGGREGATE AMOUNT OF OF SECURITIES TO BE REGISTERED OFFERING PRICE(1) REGISTRATION FEE - ------------------------------------------------------------------------------------------------------ Common stock................................................ $600,000,000 $158,400 - ------------------------------------------------------------------------------------------------------ (1) Estimated solely for the purpose of computing the registration fee pursuant to Rule 457(o) under the Securities Act. THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(A) OF THE SECURITIES ACT OF 1933, AS AMENDED, OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME EFFECTIVE ON SUCH DATE AS THE SECURITIES AND EXCHANGE COMMISSION (THE "COMMISSION"), ACTING PURSUANT TO SAID SECTION 8(A), MAY DETERMINE. - -------------------------------------------------------------------------------- - --------------------------------------------------------------------------------

2 THE INFORMATION IN THIS PRELIMINARY PROSPECTUS IS NOT COMPLETE AND MAY BE CHANGED. THESE SECURITIES MAY NOT BE SOLD UNTIL THE REGISTRATION STATEMENT FILED WITH THE SECURITIES AND EXCHANGE COMMISSION IS EFFECTIVE. THIS PRELIMINARY PROSPECTUS IS NOT AN OFFER TO SELL NOR DOES IT SEEK AN OFFER TO BUY THESE SECURITIES IN ANY JURISDICTION WHERE THE OFFER OR SALE IS NOT PERMITTED. SUBJECT TO COMPLETION, DATED APRIL , 2000. PROSPECTUS SHARES NRG ENERGY, INC. COMMON STOCK [NRG LOGO] $ PER SHARE ------------------ NRG Energy, Inc. is selling shares of its common stock. The underwriters named in this prospectus may purchase up to additional shares of common stock from us under certain circumstances. This is an initial public offering of common stock. We currently expect the initial public offering price to be between $ and $ per share. We will apply to have the common stock listed on the under the symbol " ." The shares of common stock being sold will have one vote per share. The shares of class A common stock held by our parent company, Northern States Power Company, are identical to shares of common stock except that they have 10 votes per share. Upon completion of this offering, Northern States Power will control % of the combined voting power of our common stock and class A common stock. ------------------ INVESTING IN THE COMMON STOCK INVOLVES CERTAIN RISKS. SEE "RISK FACTORS" BEGINNING ON PAGE . Neither the Securities and Exchange Commission nor any other state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense. ------------------ PER SHARE TOTAL ----------- ----------- Public Offering Price $ $ Underwriting Discount $ $ Proceeds to NRG Energy, Inc. (before expenses) $ $ The underwriters are offering the shares subject to various conditions. The underwriters expect to deliver the shares to purchasers on or about , 2000. ------------------ SALOMON SMITH BARNEY ------------------ CREDIT SUISSE FIRST BOSTON ABN AMRO ROTHSCHILD A DIVISION OF ABN AMRO INCORPORATED BANC OF AMERICA SECURITIES LLC GOLDMAN, SACHS & CO. LEHMAN BROTHERS MERRILL LYNCH & CO. MORGAN STANLEY DEAN WITTER , 2000

3 INSIDE FRONT COVER PAGE -- DESCRIPTION OF ARTWORK NRG logo appears at the top center of the page. Underneath the NRG logo, text in the center of the page reads: "We are a leading global energy company engaged in the acquisition, development, ownership and operation of power generation facilities." At the bottom center of the page is a bar chart depicting megawatt growth between the years 1996 and 2000. INSIDE COVER GATEFOLD -- DESCRIPTION OF ARTWORK In the center of the page appears a map of the United States with the location of our facilities noted on the map. To the left of the United States map appears the following list of project names and locations: "El Segundo Power", "Encina", "Long Beach Generating", "Crockett Cogeneration", "San Diego Turbines", Artesia (California Cogen)", "Mt. Poso", " "San Joaquin Valley Energy" and "Jackson Valley Energy." Underneath the United States Map appears the following list of project names and locations: "South Central Region", "Louisiana Generating", "Rocky Road", "Morris Cogen", "Cogen America Pryor" and "Power Smith Cogeneration." To the right of the United States map appears the following list of project names and locations: "Oswego", "Middletown", "Arthur Kill", "Huntley", "Astoria Gas Turbines", "Dunkirk", "Montville", "Devon", "Norwalk", "Somerset Power", "Connecticut Remote Jets", "Kingston Cogeneration", "Parlin Cogen", "Cadillac", "Grays Ferry Cogen", "Newark Cogen", "Penobscot Energy Recovery", "Curtis-Palmer Hydroelectric", "Philadelphia Cogen", "Maine Energy Recovery" and "Turners Falls." At the bottom left corner of the page appears a map of Australia with the location of our facilities noted on the map. To the left of the Australia map appears the following list of project names and locations: "Gladstone Power Station", "Loy Yang Power A" and "Collinsville." At the bottom right of the page appears a map of Europe with the location of our facilities noted on the map. To the left of the Europe map appears the following list of project names and locations: "Killingholme", "Schkopau", "ECK Generating", "Enfield Energy Centre", "MIBRAG" and "Energy Center Kladno."

4 YOU SHOULD RELY ONLY ON INFORMATION CONTAINED IN THIS PROSPECTUS. NRG ENERGY, INC. HAS NOT AUTHORIZED ANYONE TO PROVIDE YOU WITH DIFFERENT INFORMATION. NRG ENERGY, INC. IS NOT MAKING AN OFFER OF THESE SECURITIES IN ANY STATE WHERE THE OFFER IS NOT PERMITTED. YOU SHOULD NOT ASSUME THAT THE INFORMATION PROVIDED BY THIS PROSPECTUS IS ACCURATE AS OF ANY DATE OTHER THAN THE DATE ON THE FRONT OF THIS PROSPECTUS. TABLE OF CONTENTS PAGE ---- Summary..................................................... 1 Risk Factors................................................ 7 Use of Proceeds............................................. 17 Dividend Policy............................................. 17 Capitalization.............................................. 18 Selected Consolidated Financial and Other Data.............. 19 Management's Discussion and Analysis of Financial Condition and Results of Operations................................. 21 Business.................................................... 29 Management.................................................. 63 Ownership of Capital Stock.................................. 72 Relationships and Related Transactions...................... 73 Description of Capital Stock................................ 75 Description of Indebtedness................................. 79 Shares Eligible for Future Sale............................. 84 Material United States Tax Consequences to Non-United States Holders................................................... 85 Underwriting................................................ 87 Legal Matters............................................... 89 Experts..................................................... 89 Available Information....................................... 89 Index to Financial Statements............................... F-1

5 SUMMARY The following summary is qualified in its entirety by, and should be read together with, the more detailed financial and other information included in this prospectus. All of the following information reflects a :1 split of our common stock, to be effective immediately prior to this offering, and assumes that the underwriters have not exercised their option to purchase an additional shares of common stock within 30 days of the date of this prospectus. Before you invest in our common stock, you should consider carefully the information contained in the section entitled "Risk Factors," beginning on page . NRG ENERGY, INC. NRG Energy, Inc. is a leading global energy company primarily engaged in the acquisition, development, ownership and operation of power generation facilities. We believe we are the second largest independent power generation company in the United States and the seventh largest independent power generation company in the world measured by our net ownership interest in power generation facilities. We own all or a portion of 57 generation projects that have a total generating capacity of 23,660 megawatts ("MW"); our net ownership interest in those projects is 13,664 MW. Upon the closing of our pending acquisition from Conectiv of interests in six power generation facilities, which we expect to occur later this year, we will have interests in projects having a total generating capacity of 28,722 MW; our net ownership interest in those projects will be 15,539 MW. In addition, we have an active acquisition and development program through which we are pursuing additional generation projects. As the following table illustrates, we have grown significantly during the last three years, primarily as a result of our success in acquiring domestic power generation facilities: YEAR ENDED DECEMBER 31, ------------------------------ 1997 1998 1999 ------- ------- -------- Net Generating Capacity (in MW at year end)................ 2,637 3,300 10,990 Operating Income (in thousands)............................ $18,109 $57,012 $109,520 We intend to continue our 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. To prepare for expansion, repowering and greenfield opportunities, we have recently agreed to purchase 16 turbine generators from GE Power Systems and two turbine generators from Siemens Westinghouse over a six year period commencing in 2001. These new turbines, which we expect to install at domestic facilities, will have a combined capacity of approximately 3,300 MW. We believe that our operational skills and experience give us a strong competitive position in the unregulated generation marketplace. We have organized our operations geographically such that inventories, maintenance, backup and other operational functions are pooled within a region. This approach enables us to realize cost savings and enhances our ability to meet our facility availability goals. Our availability goals are not driven by traditional benchmarks, such as daily or annual availability, but are focused on each facility's availability during periods when power prices are significantly above the variable cost of producing power at that facility -- what we call "in-market" availability. In addition to our power generation projects, we also have interests in district heating and cooling systems and steam transmission operations. Our thermal and chilled water businesses have a steam and chilled water capacity equivalent to approximately 1,204 MW. We believe that through our subsidiary NEO Corporation we are also one of the top three landfill gas generation companies in the United States, extracting methane from landfills to generate electricity. NEO owns 30 landfill gas collection systems and has 55 MW of net ownership interests in related electric generation facilities. NEO also has 35 MW of net ownership interests in 18 small hydroelectric facilities. 1

6 MARKET OPPORTUNITY The power industry is one of the largest industries in the world, accounting for approximately $220 billion in annual revenues and having approximately 730,000 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 upon cost of service pricing to a non- regulated competitive market. We believe that the power industry will continue to undergo substantial restructuring over the next several years and will experience significant growth in the future. As of January 2000, 22 states had enacted legislation to restructure their electric utility industries, four additional state public utility commissions had issued comprehensive restructuring orders and 20 additional states had active legislative or regulatory processes underway to study restructuring and propose implementing legislation. As a result, from January 1, 1997 through December 31, 1999, approximately 70,000 MW of the power generating capacity in the United States, had been sold or transferred by regulated electric utilities to independent power producers. We expect in excess of 70,000 additional MW to be sold to independent power producers by the end of 2002. We believe 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. In our view, these factors provide an attractive domestic environment for an independent power producer like us 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. We believe that these market trends will continue to create opportunities to acquire and develop power generation facilities globally. STRATEGY Our 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 diversified in terms of geographic location, fuel type and dispatch level. Currently, 80% of our generation is located in the United States in three core markets: our Northeast, South Central and West Coast regions. With our diversified asset base, we seek 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 and periods of constrained availability of generating capacity, fuels and transmission. The following charts illustrate our diversity: GEOGRAPHIC LOCATION(1) U.S. EUROPE AUSTRALIA OTHER - ---- ------ --------- ----- 80 9.00 10.00 1.00 PRIMARY FUEL TYPE(1)(2) COAL OIL GAS OTHER - ---- --- --- ----- 35 26.00 37.00 2.00 DISPATCH LEVEL(3) PEAKING INTERMEDIATE BASELOAD - ------- ------------ -------- 41 19.00 40.00 - --------------- (1) Based upon MW of net ownership interest as of March 31, 2000. (2) Several of our generation facilities, constituting approximately 3,900 MW of capacity, are capable of utilizing more than one fuel, which can be switched as fuel prices fluctuate. (3) Estimated for 2000 based upon historic dispatch data. We define "baseload" as facilities that we expect to operate greater than 60% of the year, "intermediate" as facilities that we expect to operate between 20% and 60% of the year and "peaking" as facilities that we expect to operate less than 20% of the year, assuming utilization of primary fuel type. 2

7 Our strategy is to capitalize on our acquisition, development and operating skills to build a balanced, global portfolio of power and thermal generation assets. We intend to implement this strategy by continuing an aggressive but thoughtful acquisition program and accelerating our development of existing site expansion projects and greenfield projects. By leveraging the talents of our regional management teams, focusing on our regional market expertise and operating and utilizing our asset base on a regional rather than a project basis, we believe we can best position ourselves for long term profitability. Achieving "critical mass" in core markets should allow us to capitalize on opportunities available in those markets. We neither own nor do we intend to own any interest in nuclear generation facilities. Domestic. We intend to focus our near-term domestic development plans on our existing three core markets, our Northeast, South Central and West Coast regions, and add the Mid-Atlantic region as our fourth core market to be established upon the closing of the planned acquisition from Conectiv. We will consider domestic projects outside of these markets if we believe that an opportunity exists to create a new core market or that the projected returns from a particular project warrant an investment. International. Based upon our assessment of market opportunities and our portfolio risk management criteria, we intend to leverage our reputation, experience and expertise in order to acquire foreign assets in selected countries. We are presently focusing our international development activities in the United Kingdom, Central Europe, Turkey, Australia, and to a lesser extent, Latin America. In the future, we will consider other areas that are consistent with our strategy. RECENT DEVELOPMENTS TURBINE ACQUISITIONS In February 2000, we executed a memorandum of understanding with GE Power Systems, a division of General Electric Company, to purchase 11 gas turbine generators and five steam turbine generators, with an option to purchase additional units. The purchases will take place over the next five years with the first delivery scheduled to be made in 2002. The 16 turbines will have an equivalent generation output of approximately 3,000 MW and an acquisition cost of approximately $500 million. In March 2000, we entered into an agreement with Great River Energy under which Great River assigned to us, for a purchase price of $43 million, all of its rights and obligations with respect to two 135 MW turbines being built for it by Siemens Westinghouse. The two turbines are scheduled for delivery in the first or second quarter of 2001. We expect to install the turbines described above at existing plant sites in the United States as well as new greenfield sites. RECENT AND PENDING GENERATION ACQUISITIONS CAJUN FACILITIES In March 2000, we acquired 1,708 MW of coal and gas-fired generation assets in Louisiana for approximately $1,026 million. These assets were formerly owned by Cajun Electric Power Cooperative, Inc., and we refer to them as the "Cajun facilities." We sell 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 us, and four have entered into two to four year power purchase agreements. In addition, we sell power under contract to two municipal power authorities and one investor-owned utility that were former customers of Cajun Electric. We estimate that payments under the contracts with the 11 cooperatives will account for approximately 72% of the Cajun facilities' projected 2001 revenues, and that payments under the contracts with the municipal power authorities and the investor-owned utility will account for approximately an additional 7% of such revenues. 3

8 KILLINGHOLME FACILITY In March 2000, we acquired the Killingholme A plant from National Power plc for L390 million (approximately $615 million at the time of the 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. We own and operate the facility, which sells its power into the wholesale electricity market of England and Wales. CONNECTICUT FACILITIES In December 1999, we acquired four gas, oil and jet fuel-fired electric generation facilities and six remote oil-fired turbine facilities from Connecticut Light & Power Company for approximately $519 million. These facilities are located throughout Connecticut and have a combined generating capacity of 2,235 MW. In October 1999, we entered into a four-year standard offer service wholesale sales agreement with Connecticut Light & Power pursuant to which we will supply at fixed prices a portion of its aggregate retail load. The quantity of power to be supplied is equal to 35% of Connecticut Light & Power's standard offer service load during calendar year 2000, 40% during calendar years 2001 and 2002, and 45% during calendar year 2003. We estimate that 45% of Connecticut Light & Power's standard offer service load in 2003 will be approximately 2,000 MW at peak requirement. CONECTIV FACILITIES In January 2000, we executed purchase agreements with subsidiaries of Conectiv to acquire 1,875 MW of coal, gas and oil-fired electric generating capacity and other assets. We will pay approximately $800 million for the assets, a portion of which will be financed by project-level debt. The assets include the BL England and Deepwater facilities in New Jersey, the Indian River facility in Delaware and the Vienna facility in Maryland, and interests in the Conemaugh (7.6%) and Keystone (6.2%) facilities in Pennsylvania. The purchase also includes excess emission allowances. Subject to receipt of required regulatory approvals, we expect the acquisition to close in the fourth quarter of 2000. Subject to final documentation, we will sell 500 MW of capacity and associated energy to a subsidiary of Conectiv under a five-year power purchase agreement commencing upon the closing of the acquisition. CORPORATE INFORMATION We have been acquiring and developing power generation projects since 1989, when we were formed as a wholly-owned subsidiary of Northern States Power Company, an investor-owned utility that serves customers in the upper Midwest and owns and operates approximately 7,100 MW of generating capacity. On March 24, 1999, Northern States Power and New Century Energies, Inc., a Colorado-based public utility holding company, entered into an agreement providing for the merger of the two companies. Following the merger, Northern States Power's utility assets will be held in a subsidiary of the surviving corporation in the merger, which will be renamed "Xcel Energy, Inc.", and the shares of our class A common stock that are now owned by Northern States Power will be transferred to a wholly-owned subsidiary of Xcel Energy. The merger has been approved by the shareholders of both companies and by the Federal Energy Regulatory Commission, but remains subject to standard closing conditions and other regulatory approvals. It is currently expected that the merger will be completed in the second or third quarter of 2000. We are incorporated in Delaware and our headquarters and principal executive offices are located at 1221 Nicollet Mall, Suite 700, Minneapolis, Minnesota 55403. Our telephone number is (612) 373-5300. 4

9 THE OFFERING Common stock offered by NRG... shares(1) Common stock to be outstanding after the offering.................... shares(2) Class A common stock to be outstanding after the offering.................... shares(3) Total common stock and class A common stock to be outstanding after the offering.................... shares Use of proceeds............... To repay $300 million of indebtedness owed to Citicorp USA, Inc. Remaining proceeds will be used for general corporate purposes, including working capital, capital expenditures and business acquisitions. None of the proceeds will be distributed to Northern States Power. See "Use of Proceeds." Listing....................... Proposed symbol............... " " - --------------- (1) Excludes shares of common stock that the underwriters have an option to purchase from us within 30 days of the date of this prospectus. (2) Excludes shares issuable upon the exercise of stock options granted to our employees and non-employee directors under the NRG Long-Term Incentive Plan. (3) Shares of class A common stock have 10 votes per share and are convertible on a share-for-share basis into shares of common stock. Shares of common stock have one vote per share. In all other respects, shares of class A common stock and shares of common stock have identical rights and privileges. All outstanding shares of class A common stock are held by Northern States Power. 5

10 SUMMARY CONSOLIDATED FINANCIAL AND OPERATING DATA The summary historical financial data set forth below as of December 31, 1997, 1998 and 1999, and for the years then ended, have been derived from our audited consolidated financial statements. The financial data set forth below as of March 31, 2000, and for the three-month periods then ended, have been derived from our unaudited financial statements, which were prepared on a basis consistent with our audited consolidated financial statements. We have supplied the selected capacity data set forth below under the caption "Other Generation Data." All dollar amounts are set forth in thousands, except per share amounts. YEAR ENDED THREE MONTHS DECEMBER 31, ENDED MARCH 31, ------------------------------------------------ ------------------- PRO PRO FORMA FORMA 1997 1998 1999 1999(1) 2000 2000(1) ---------- ---------- ---------- --------- -------- -------- CONSOLIDATED INCOME STATEMENT DATA Revenues from wholly-owned operations.............. $ 92,052 $ 100,424 $ 432,518 $801,080 $ $ Equity in earnings of unconsolidated affiliates.... 26,200 81,706 67,500 67,500 Operating income (loss)............................ 18,109 57,012 109,520 189,665 Other income (expense)(2).......................... 11,371 9,379 14,970 13,100 Interest expense................................... (30,989) (50,313) (93,376) (166,624) Income tax benefit(3).............................. 23,491 25,654 26,081 24,001 Net income (loss).................................. $ 21,982 $ 41,732 $ 57,195 $ 60,142 $ $ ---------- ---------- ---------- --------- -------- -------- Earnings per share -- basic........................ $ $ $ $ $ $ Earnings per share -- diluted...................... $ $ $ $ $ $ Weighted average shares outstanding -- basic....... Weighted average shares outstanding -- diluted..... AS OF AS OF DECEMBER 31, MARCH 31, ------------------------------------ --------- 1997 1998 1999 2000 ---------- ---------- ---------- --------- CONSOLIDATED BALANCE SHEET DATA Net property, plant and equipment................ $ 185,891 $ 204,729 $1,919,323 $ Total assets..................................... 1,168,102 1,293,426 3,431,684 Long-term recourse debt, including current maturities..................................... 499,982 504,781 915,000 Long-term non-recourse debt, including current maturities............................. 120,873 121,695 1,056,860 Stockholder's equity............................. 450,698 579,332 893,654 AS OF AS OF DECEMBER 31, MARCH 31, ------------------------------------ --------- 1997 1998 1999 2000 ---------- ---------- ---------- --------- OTHER GENERATION DATA Net power generation capacity (MW)............... 2,637 3,300 10,990 13,664 - --------------- (1) The pro forma financial information gives effect to our March 31, 2000 acquisition of the Cajun facilities as if that acquisition had occurred on January 1, 1999. We do not believe that the pro forma data is indicative of our future revenues and earnings, because the previous owner of the Cajun facilities sold energy and capacity and purchased coal upon terms substantially different from those under which we will operate these facilities. Thus, we believe the pro forma financial information is of limited use in making an investment decision. (2) These amounts include pretax charges of $9.0 million in 1997, $26.7 million in 1998 and $0 in 1999 to write-down the carrying value of certain energy projects. These amounts also include the pre-tax gain on sale of our interest in projects of $8.7 million in 1997, $30.0 million in 1998 and $15.5 million in 1999. (3) We have substantial tax credits that can be utilized by Northern States Power. Northern States Power pays us for these tax credits on a quarterly basis. 6

11 RISK FACTORS Before you invest in our common stock, you should be aware of the significant risks described below. You should carefully consider these risks, together with all of the other information included in this prospectus, before you decide whether to purchase shares of our common stock. Some of the information in this prospectus contains forward-looking statements that involve substantial risks and uncertainties. You can identify these statements by forward-looking words such as "may," "will," "expect," "anticipate," "believe," "estimate" and "continue" or similar words. You should read statements that contain these words carefully because they: (1) discuss our future expectations; (2) contain projections of our future results of operations or of our future financial condition; or (3) state other "forward-looking" information. We believe that it is important to communicate our future expectations to our investors. However, our future results and financial condition will be impacted by events or factors in the future that we have not been able to accurately predict or over which we have no control. The risk factors listed in this section, as well as any cautionary language in this prospectus, provide examples of risks, uncertainties and events that may cause our actual results to differ materially from the expectations we describe in our forward-looking statements. Before you invest in our common stock, you should be aware that the occurrence of the events described in these risk factors and elsewhere in this prospectus could have a material adverse effect on our business, financial condition and results of operations and on the price of our common stock. RISKS RELATING TO THE WHOLESALE POWER MARKETS OUR REVENUES ARE NOT PREDICTABLE BECAUSE MANY OF OUR POWER GENERATION FACILITIES OPERATE, WHOLLY OR PARTIALLY, WITHOUT LONG-TERM POWER PURCHASE AGREEMENTS. Historically, substantially all revenues from independent power generation facilities were derived under power purchase agreements having terms in excess of 15 years, pursuant to which all energy and capacity was generally sold to a single party at fixed prices. Because of changes in the industry, the percentage of facilities, including ours, with these types of long-term power purchase agreements has decreased, and it is likely that over time, most of our facilities will operate without these agreements. Without the benefit of these types of power purchase agreements, we cannot assure you that we will be able to sell the power generated by our facilities or that our facilities will be able to operate profitably. BECAUSE WHOLESALE POWER PRICES ARE SUBJECT TO EXTREME VOLATILITY, THE REVENUES THAT WE GENERATE ARE SUBJECT TO SIGNIFICANT FLUCTUATIONS. We must sell all or a portion of the energy, capacity and other products from many of our facilities into wholesale power markets. The prices of energy products in those markets are influenced by many factors outside of our control, including fuel prices, transmission constraints, supply and demand, weather, economic conditions, and the rules, regulations and actions of the system operators in those markets. The wholesale power markets are unpredictable and are subject to substantial price fluctuations over relatively short periods of time. WE HAVE A LIMITED HISTORY OF SELLING AND MARKETING PRODUCTS IN THE WHOLESALE POWER MARKETS AND MAY NOT BE ABLE TO SUCCESSFULLY MANAGE THE RISKS ASSOCIATED WITH THIS ASPECT OF OUR BUSINESS. We are exposed to market risks through our power marketing business, which involves the establishment of trading positions in the energy, fuel and emission allowance markets on a short-term basis. We sell forward contracts and options and establish positions, and sell on the spot market our energy, capacity and other energy products that are not otherwise committed under long-term contracts. In addition, we use these trading activities to procure fuel and emissions allowances for our facilities on the spot market. We have been managing risks associated with price volatility in this manner for only a limited amount of time. We may not be able to continue to effectively manage this price volatility, and may not 7

12 be able to successfully manage the other risks associated with trading in energy markets, including the risk that counterparties may not perform. RISKS RELATING TO OUR OPERATIONS WE HAVE MADE SUBSTANTIAL INVESTMENTS IN OUR RECENT ACQUISITIONS AND OUR SUCCESS DEPENDS ON THE APPROPRIATENESS OF THE PRICES WE PAID IN THESE ACQUISITIONS AS WELL AS ON OUR ABILITY TO SUCCESSFULLY INTEGRATE, OPERATE AND MANAGE THE ACQUIRED ASSETS. During the period from December 31, 1998 through March 31, 2000, we have more than quadrupled our net ownership interests in power generation facilities, expanding from 3,300 MW of net ownership interests in power generation facilities to approximately 13,664 MW of net ownership interests. During the rest of this year, if we complete the pending acquisition from Conectiv, we will increase our net ownership interests in power generation facilities by an additional 14%. The prices we paid in these acquisitions were based on our assumptions as to the economics of operating the acquired facilities and the prices at which we would be able to sell energy, capacity and other products from them. If any of the assumptions as to a given facility prove to be materially inaccurate, it could have a significant impact on the financial performance of that facility. In connection with these acquisitions, we have hired and will hire a substantial number of new employees. We may not be able to successfully integrate all of the newly hired employees, or profitably integrate, operate, maintain and manage our newly acquired power generation facilities in a competitive environment. In addition, operational issues may arise as a result of a lack of integration or our lack of familiarity with issues specific to a particular facility. OUR PROJECT DEVELOPMENT AND ACQUISITION ACTIVITIES MAY NOT BE SUCCESSFUL WHICH WOULD IMPAIR OUR ABILITY TO EXECUTE OUR GROWTH STRATEGY. We may not be able to identify attractive acquisition or development opportunities or to complete acquisitions or development projects that we undertake. If we are not able to identify and complete additional acquisitions and development projects, we will not be able to successfully execute our growth strategy. Factors that could cause our acquisition and development activities to be unsuccessful include the following: - competition, - inability to obtain additional capital on acceptable terms, - inability to obtain required governmental permits and approvals, - cost-overruns or delays in development that make continuation of a project impracticable, and - inability to negotiate acceptable acquisition, construction, fuel supply or other material agreements. WE INCUR SIGNIFICANT EXPENSES IN EVALUATING POTENTIAL PROJECTS, MOST OF WHICH ARE NOT ULTIMATELY ACQUIRED OR COMPLETED. In order to implement our growth strategy, we must continue to actively pursue acquisition and development opportunities. Substantial expenses are incurred in investigating and evaluating any potential opportunity before we can determine whether the opportunity is feasible or economically attractive. In addition, we expect to participate in many competitive bidding processes that require us to incur substantial expenses without any assurance that our bids will be accepted. As a result, we expect that our development expenses will increase in the future with no assurance that we will be successful in acquiring or completing additional new projects. 8

13 CONSTRUCTION, EXPANSION, REFURBISHMENT AND OPERATION OF POWER GENERATION FACILITIES INVOLVE SIGNIFICANT RISKS THAT CANNOT ALWAYS BE COVERED BY INSURANCE OR CONTRACTUAL PROTECTIONS. The construction, expansion and refurbishment of power generation, thermal energy production and transmission and resource recovery facilities involve many risks, including: - supply interruptions, - work stoppages, - labor disputes, - social unrest, - weather interferences, - unforeseen engineering, environmental and geological problems, and - unanticipated cost overruns. The ongoing operation of these facilities involves all of the risks described above, in addition to risks relating to the breakdown or failure of equipment or processes and performance below expected levels of output or efficiency. New plants may employ recently developed and technologically complex equipment, especially in the case of newer environmental emission control technology. While we maintain insurance, obtain warranties from vendors and obligate contractors to meet certain performance levels, the proceeds of such insurance, warranties or performance guarantees may not be adequate to cover lost revenues, increased expenses or liquidated damages payments. Any of these risks could cause us to operate below expected capacity levels, which in turn could result in lost revenues, increased expenses, higher maintenance costs and penalties. As a result, a project may operate at a loss or be unable to fund principal and interest payments under its project financing agreements, which may result in a default under that project's indebtedness. WE ARE EXPOSED TO THE RISK OF FUEL COST INCREASES AND INTERRUPTION IN FUEL SUPPLY BECAUSE WE GENERALLY DO NOT HAVE LONG-TERM FUEL SUPPLY AGREEMENTS. Most of our domestic merchant power generation facilities purchase fuel under short-term contracts or on the spot market. Even though we attempt to hedge some portion of our known fuel requirements, we still may face the risk of supply interruptions and fuel price volatility. The price we can obtain for the sale of energy may not rise at the same rate, or may not rise at all, to match a rise in fuel costs. This may have a material adverse effect on our financial performance. WE OFTEN RELY ON SINGLE SUPPLIERS AND AT TIMES WE RELY ON SINGLE CUSTOMERS AT OUR FACILITIES, EXPOSING US TO SIGNIFICANT FINANCIAL RISKS IF EITHER SHOULD FAIL TO PERFORM THEIR OBLIGATIONS. We often rely on a single supplier for the provision of fuel, water and other services required for operation of a facility, and at times, we rely on a single customer or a few customers to purchase all or a significant portion of a facility's output, in some cases under long-term agreements that provide the support for any project debt used to finance the facility. The failure of any one customer or supplier to fulfill its contractual obligations to the facility could have a material adverse effect on such facility's financial results. As a result, the financial performance of any such facility is dependent on the continued performance by customers and suppliers of their obligations under these long-term agreements and, in particular, on the credit quality of the project's customers and suppliers. OUR SIGNIFICANT BUSINESS OPERATIONS OUTSIDE THE UNITED STATES EXPOSE US TO LEGAL, TAX, CURRENCY, INFLATION, CONVERTIBILITY AND REPATRIATION RISKS, AS WELL AS POTENTIAL CONSTRAINTS ON THE DEVELOPMENT AND OPERATION OF OUR POTENTIAL BUSINESS, ANY OF WHICH CAN LIMIT THE BENEFITS TO US OF EVEN A SUCCESSFUL FOREIGN PROJECT. A key component of our business strategy is the development and acquisition of projects outside the United States in areas such as the United Kingdom, Australia, Central Europe and Latin America. The 9

14 economic and political conditions in many of the countries where we have interests or in which we are or may be exploring development or acquisition opportunities present risks of delays in permitting and licensing, construction delays and interruption of business, as well as risks of war, expropriation, nationalization, renegotiation or nullification of existing contracts and changes in law or tax policy, that are greater than similar risks in the United States. The uncertainty of the legal environment in certain foreign countries in which we may develop or acquire projects could make it more difficult to obtain non-recourse project financing on suitable terms and could impair our ability to enforce our rights under agreements relating to these projects. Operations in foreign countries also can present currency exchange, inflation, convertibility and repatriation risks. In countries in which we may develop or acquire projects in the future, economic and monetary conditions and other factors could affect our ability to convert our earnings to United States dollars or other acceptable currencies or to move funds offshore from such countries. Furthermore, the central bank of any foreign country may have the authority in certain circumstances to suspend, restrict or otherwise impose conditions on foreign exchange transactions or to approve distributions to foreign investors. Although we generally seek to structure our power purchase agreements and other project revenue agreements to provide for payments to be made in, or indexed to, United States dollars or a currency freely convertible into United States dollars, we can offer no assurance that we will be able to achieve this structure in all cases or that a power purchaser or other customer will be able to obtain acceptable currency to pay their obligations. As part of privatizations or other international acquisition opportunities, we may make investments in ancillary businesses not directly related to power generation, thermal energy production and transmission or resource recovery and in which our management may not have had prior experience. In such cases, our policy is to invest with partners having the necessary expertise. However, we can offer no assurance that such persons will be available as co-venturers in every case. In addition, as a condition to participating in privatizations and refurbishments of formerly state-owned businesses, we may be required to undertake transitional obligations relating to union contracts, employment levels and benefits obligations for employees, which could prevent or delay the achievement of desirable operating efficiencies and financial performance. THE LOY YANG FACILITY IN WHICH WE HAVE INVESTED IS EXPERIENCING FINANCIAL DIFFICULTIES BECAUSE OF LOWER THAN EXPECTED WHOLESALE POWER PRICES, WHICH COULD RESULT IN AN EVENT OF DEFAULT UNDER ITS LOAN AGREEMENTS. Energy prices in the Victoria, Australia wholesale power market into which our Loy Yang facility sells its power have been significantly lower than we had expected when we acquired our interest in the facility. As a result, the Loy Yang project company is currently prohibited by its loan agreements from making equity distributions to the project owners. Based on our current power price projections, we expect that the Loy Yang project company will fail to meet required coverage ratios under its loan agreements beginning in the third quarter of 2001, which constitutes an event of default. Moreover, if market prices in Victoria continue at current levels, which are below our current power price projections, we expect that the Loy Yang project company will be unable to service its long-term debt obligations beginning in the first quarter of 2002. In either case, absent a restructuring of the project company's debt, the project company's lenders would be allowed to accelerate the project company's indebtedness. We could be required to write-off all or a significant portion of our U.S.$250 million investment in this project as a result of such acceleration, a determination by the project company that a write-down of its assets is required or our determination that we would not be able to recover our investment in the project. RISKS RELATING TO OUR CORPORATE AND FINANCIAL STRUCTURE BECAUSE WE OWN LESS THAN 100% OF SOME OF OUR PROJECT INVESTMENTS, WE CANNOT EXERCISE COMPLETE CONTROL OVER THEIR OPERATIONS. We have limited control over the development, construction, acquisition or operation of some project investments and joint ventures because our investments are in projects where we beneficially own less than 50% of the ownership interests. A substantial portion of our future investments in international projects 10

15 may also take the form of minority interests. We seek to exert a degree of influence with respect to the management and operation of projects in which we own less than 50% of the ownership interests by negotiating to obtain positions on management committees or to receive certain limited governance rights such as rights to veto significant actions. However, we may not always succeed in such negotiations. We may be dependent on our co-venturers to construct and operate such projects. Our co-venturers may not have the level of experience, technical expertise, human resources management and other attributes necessary to construct and operate these projects. The approval of co-venturers also may be required for us to receive distributions of funds from projects or to transfer our interest in projects. WE REQUIRE SIGNIFICANT AMOUNTS OF CAPITAL TO GROW OUR BUSINESS AND OUR FUTURE ACCESS TO SUCH FUNDS IS UNCERTAIN. We will require continued access to debt and equity capital from outside sources on acceptable terms in order to assure the success of future projects and acquisitions, including the planned Conectiv acquisition. Our ability to arrange debt financing, either at the corporate-level or on a non-recourse project-level basis and the costs of such capital are dependent on numerous factors, including: - general economic and capital market conditions, - credit availability from banks and other financial institutions, - investor confidence in us, our partners and the regional wholesale power markets, - maintenance of acceptable credit ratings, - the success of current projects, - the perceived quality of new projects, and - provisions of tax and securities laws that may impact raising capital in this manner. In order to access capital on a substantially non-recourse basis in the future, we may have to make larger equity investments in, or provide more financial support for, our project subsidiaries. We also may not be successful in structuring future financing for our projects on a substantially non-recourse basis. To date, the equity capital for our projects has been provided by equity contributions from Northern States Power, internally-generated cash flow from our projects and other borrowings. We cannot assure you that Northern States Power will continue to provide additional equity capital to us or permit us to raise additional equity capital from others. Any inability to raise additional equity capital will restrict our ability to execute our growth strategy. WE HAVE SUBSTANTIAL INDEBTEDNESS, WHICH COULD LIMIT OUR ABILITY TO GROW AND OUR FLEXIBILITY IN OPERATING OUR PROJECTS. As of March 31, 2000, we had total recourse debt of $1,774 million, with an additional $2,325 million of non-recourse debt appearing on our balance sheet. The percentage of our total recourse debt to recourse debt and equity was 67.0% as of March 31, 2000. The substantial amount of debt that we have and the debt of our project subsidiaries and project affiliates presents the risk that we might not generate sufficient cash to service our indebtedness, and that our leveraged capital structure could limit our ability to finance the acquisition and development of additional projects, to compete effectively, to operate successfully under adverse economic conditions and to fully implement our strategy. In addition, our lenders may accelerate our credit facilities and public debt instruments upon the occurrence of events of default or if we undergo a change of control. Because Northern States Power will control % of the total voting power of the common stock and the class A common stock, we will have no ability to prevent a change of control. If our indebtedness is accelerated, we could be forced into bankruptcy, and you could lose your entire investment. Although we expect that the cash available from our domestic operations and the repayment of loans made to our foreign affiliates will be sufficient to service our corporate-level indebtedness, there can be no assurance that these funds will be sufficient to make corporate-level debt payments as and when due. If we 11

16 elect to repatriate cash from foreign subsidiaries or affiliates to make these payments in case of such a shortfall, then we may incur United States taxes, net of any available foreign tax credits, on the repatriation of such foreign cash. WE HAVE GUARANTEED OBLIGATIONS AND LIABILITIES OF OUR PROJECT SUBSIDIARIES AND AFFILIATES WHICH WOULD BE DIFFICULT FOR US TO SATISFY IF THEY ALL CAME DUE SIMULTANEOUSLY. In 20 of our projects, we have executed guarantees of the project affiliate's indebtedness, equity or operating obligations. In addition, in connection with the purchase and sale of fuel, emission allowances and power generation products to and from third parties with respect to the operation of some of our generation facilities, we are required to guarantee a portion of the obligations of certain of our subsidiaries. These guarantees totaled approximately $557 million as of March 31, 2000. We may not be able to satisfy all of these guarantees and other obligations if they were to come due at the same time, which would have a material adverse effect on us. OUR HOLDING COMPANY STRUCTURE LIMITS OUR ACCESS TO THE FUNDS OF PROJECT SUBSIDIARIES WHICH WE WILL NEED IN ORDER TO SERVICE OUR CORPORATE-LEVEL INDEBTEDNESS. Substantially all of our operations are conducted by our project subsidiaries and project affiliates. Our cash flow and our ability to service our corporate-level indebtedness when due is dependent upon our receipt of cash dividends and distributions or other transfers from our projects and other subsidiaries. The debt agreements of our subsidiaries and project affiliates generally restrict their ability to pay dividends, make distributions or otherwise transfer funds to us. In addition, a substantial amount of the assets of our project subsidiaries and project affiliates has been pledged as collateral under their debt agreements. Our subsidiaries and project affiliates are separate and distinct legal entities that have no obligation, contingent or otherwise, to pay any amounts due under our indebtedness or to make any funds available to us, whether by dividends, loans or other payments, and they do not guarantee the payment of our corporate-level indebtedness. We own less than 50% of the ownership interests in many of our foreign projects, and therefore we are unable to unilaterally cause dividends or distributions to be made from these operations. WE ARE CONTROLLED BY NORTHERN STATES POWER COMPANY. NORTHERN STATES POWER MAY NOT ALWAYS EXERCISE ITS CONTROL IN A WAY THAT BENEFITS OUR PUBLIC STOCKHOLDERS. Northern States Power will hold approximately % of the total voting power of the common stock and the class A common stock following this offering. Accordingly, without the approval of the holders of our common stock, Northern States Power will be able to control the vote on all matters submitted to a vote of the stockholders and in particular be able to elect all our directors, amend our certificate of incorporation or effect a merger, sale of assets, or other major corporate transaction, defeat any non-negotiated takeover attempt, determine the amount and timing of dividends paid on common stock, and otherwise control our management and operations and the outcome of all matters submitted for a stockholder vote. In circumstances involving a conflict of interest between Northern States Power, as the controlling stockholder, on the one hand, and our other stockholders on the other, we can offer no assurance that Northern States Power would not exercise its power to control us in a manner that would benefit Northern States Power to the detriment of our other stockholders. In addition, Northern States Power may enter into credit agreements, indentures or other contracts which limit the activities of its subsidiaries. While we would not likely be contractually bound by these limitations, Northern States Power would likely cause its representatives on our board to direct our business so as not to breach any of these agreements. 12

17 OUR CERTIFICATE OF INCORPORATION AND BYLAW PROVISIONS, AND SEVERAL OTHER FACTORS, COULD LIMIT ANOTHER PARTY'S ABILITY TO ACQUIRE US AND COULD DEPRIVE YOU OF THE OPPORTUNITY TO OBTAIN A TAKEOVER PREMIUM FOR YOUR SHARES OF COMMON STOCK. A number of provisions that are in our certificate of incorporation and bylaws will make it difficult for another company to acquire us and for you to receive any related takeover premium for your shares. For example, our certificate of incorporation allows our board of directors to issue up to preferred shares without a stockholder vote and provides that stockholders may not act by written consent and may not call a special meeting. In addition, our capital structure may deter a potential change in control, because our voting power will be concentrated in our class A common stock. Furthermore, we have adopted a "poison-pill" or investor rights plan designed to make certain that offers for the shares of our common stock can be thoroughly considered by all parties. POTENTIAL CONFLICTS OF INTEREST WITH OUR CONTROLLING STOCKHOLDER MAY BE RESOLVED IN A MANNER THAT IS ADVERSE TO US. Northern States Power, our controlling stockholder, and directors and officers of Northern States Power and its subsidiaries who may be our directors, are in positions involving the possibility of conflicts of interest with respect to transactions in which both we and Northern States Power have an interest. We can offer no assurance that any such conflict will be resolved in our favor. THE PENDING MERGER OF NORTHERN STATES POWER AND NEW CENTURY ENERGIES WILL CONSTRAIN THE CONDUCT OF OUR BUSINESS. It is expected that the pending merger of Northern States Power and New Century Energies will be accounted for as a "pooling of interest." In accordance with the "pooling of interest" rules, neither company can alter their equity interests or dispose of a material portion of their assets through the date of the merger and for a period of time thereafter. These constraints may limit our flexibility to conduct our business as we otherwise would absent such constraints. After the merger, the shares of our class A common stock that are owned by Northern States Power will be owned by a wholly-owned subsidiary of the surviving corporation in the merger, Xcel Energy. Xcel Energy will be subject to the provisions of various energy-related laws and regulations, including the Public Utility Holding Company Act of 1935 ("PUHCA"), and, in turn, we will be subject to constraints imposed by PUHCA. See "Business -- Energy Regulation in the United States". IF NORTHERN STATES POWER COULD NOT CONSOLIDATE US ON THEIR UNITED STATES FEDERAL INCOME TAX RETURNS, WE COULD LOSE THE REIMBURSEMENT WE RECEIVE FOR TAX BENEFITS. We are a member of Northern States Power's consolidated tax group for purposes of United States federal income taxes. We have generated significant tax assets in the past from which Northern States Power has been able to benefit. We received, subject to possible adjustment, $13.4 million for the year ended December 31, 1999 for the use of such benefits. If Northern States Power owns less than 80% of our voting power, or equity securities representing less than 80% of our value, or cannot generate substantial taxable income to utilize such tax benefits, we will no longer receive a cash reimbursement for these benefits on a dollar-for-dollar basis and we may not be able to use all of the benefits immediately. RISKS RELATING TO OUR INDUSTRY OUR BUSINESS IS SUBJECT TO SUBSTANTIAL GOVERNMENTAL REGULATION AND PERMITTING REQUIREMENTS AND MAY BE ADVERSELY AFFECTED BY ANY FUTURE INABILITY TO COMPLY WITH EXISTING OR FUTURE REGULATIONS OR REQUIREMENTS. In General. Our business is subject to extensive energy, environmental and other laws and regulations of federal, state and local authorities. We generally are required to obtain and comply with a wide variety of licenses, permits and other approvals in order to operate our facilities. We may incur 13

18 significant additional costs because of our compliance with these requirements. If we fail to comply with these requirements, we could be subject to civil or criminal liability and the imposition of liens or fines. In addition, existing regulations may be revised or reinterpreted, new laws and regulations may be adopted or become applicable to us or our facilities, and future changes in laws and regulation may have a detrimental effect on our business. Energy Regulation. PUHCA and the Federal Power Act ("FPA") regulate public utility holding companies and their subsidiaries and place certain constraints on the conduct of their business. The Public Utilities Regulatory Policies Act of 1978 ("PURPA") provides to qualifying facilities ("QFs") exemptions from federal and state laws and regulations, including PUHCA and the FPA. The Energy Policy Act in 1992 also provides relief from regulation under PUHCA to exempt wholesale generators ("EWGs") and foreign utility companies ("FUCOs"). Maintaining our status as a QF, EWG or FUCO is conditioned on our continuing to meet statutory criteria, and could be jeopardized, for example, by the making of retail sales by a project in violation of the requirements of the Energy Policy Act. Until the completion of the merger between Northern States Power and New Century Energies, we are not and will not be subject to regulation as a holding company under PUHCA as long as the domestic power plants we own are QFs under PURPA or are EWGs, and as long as our foreign utility operations are exempted as EWGs or foreign utility companies or are otherwise exempted under PUHCA; thereafter, we will be subject to the regulations described in "Business -- Energy Regulation in the United States." Environmental Regulation. In acquiring many of our facilities, we assumed on-site liabilities associated with the environmental condition of those facilities, regardless of when such liabilities arose and whether known or unknown, and in some cases agreed to indemnify the former owners of those facilities for on-site environmental liabilities. We may not at all times be in compliance with all applicable environmental laws and regulations. Steps to bring our facilities into compliance could be prohibitively expensive, and may cause us to be unable to pay our debts when due. Moreover, environmental laws and regulations can change. For example, on October 14, 1999, Governor Pataki of New York announced that he was ordering the New York Department of Environmental Conservation to require further reductions of sulphur dioxide and nitrogen oxides emissions from New York power plants, beyond that which is required under current federal and state law. These reductions would be phased in between January 1, 2003 and January 1, 2007. Compliance with these emissions reductions requirements, if they become effective, could have a material adverse impact on the operation of some of our facilities located in the State of New York. In addition, the Connecticut legislature has in the past considered, but rejected, legislation that would require older electrical generation stations to comply with more stringent pollution standards than are currently in effect in Connecticut for nitrogen oxides and sulphur dioxide emissions. Currently, legislation is being debated in the Connecticut legislature that could require our Connecticut facilities to rely on more expensive fuels or install additional air pollution control equipment. If such legislation were to become law without reflecting the benefit of critical elements of current federal emission reduction initiatives, such as market based emission trading between sources located across broad geographical regions, our Connecticut facilities may be placed at a significant competitive disadvantage. We are continually in the process of obtaining or renewing federal, state and local approvals required to operate our facilities. Additional regulatory approvals may be required in the future due to a change in laws and regulations, a change in our customers or other reasons. We may not always be able to obtain all required regulatory approvals, and we may not be able to obtain any necessary modifications to existing regulatory approvals or maintain all required regulatory approvals. If there is a delay in obtaining any required regulatory approvals or if we fail to obtain and comply with any required regulatory approvals, the operation of our facilities or the sale of electricity to third parties could be prevented or subject to additional costs. We are subject to environmental investigations and lawsuits both on the state and federal level. For instance, the Office of the Attorney General of the State of New York and the New York Department of Environmental Conservation are investigating physical changes made at the Huntley and Dunkirk facilities 14

19 prior to our assumption of ownership. The Attorney General has alleged that these changes represent major modifications undertaken without obtaining the required permits. Although we have a right to indemnification by the previous owner for penalties 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, we could be required, among other things, to install specified pollution control technology to further reduce pollutant emissions from the Dunkirk and Huntley facilities, and we could become subject to fines and penalties associated with the period of time we have operated the facilities. See "Business -- Legal Proceedings." In addition, on November 3, 1999, the United States Department of Justice filed suit against seven electric utilities for alleged violations of Title IV of the Federal Clean Air Act permit requirements at seventeen utility generation stations located in the southern and midwestern regions of the United States. The United States Environmental Protection Agency also issued administrative notices of violation alleging similar violations at eight other power plants owned by some of the electric utilities named as defendants in the lawsuit, and also issued an administrative order to the Tennessee Valley Authority for similar violations at seven of its power plants. To date, no lawsuits or administrative actions have been brought against us or any of our subsidiaries or affiliates or the former owners of our facilities alleging similar violations, although a subsidiary of Conectiv has received information requests from the EPA regarding the Deepwater and BL England facilities that we have agreed to purchase. However, lawsuits or administrative actions alleging similar violations at our facilities could be filed in the future and if successful, could have a material, adverse effect on our business. OUR COMPETITION IS INCREASING. 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 we do. Many of our competitors also are seeking attractive power generation opportunities, both in the United States and abroad. This competition may adversely affect our 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 our industry. WE FACE ONGOING CHANGES IN THE UNITED STATES UTILITY INDUSTRY THAT COULD AFFECT OUR COMPETITIVENESS. 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 our 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 15

20 competition, the 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. These price limitations and other mechanisms may adversely impact the profitability of our merchant plants. 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, we can offer no assurance that we will be able to operate profitably in all wholesale power markets. RISKS RELATING TO THE MARKET FOR OUR COMMON STOCK OUR COMMON STOCK WILL HAVE LIMITED VOTING POWER. Our common stock entitles its holders to one vote for each share, and our class A common stock entitles its holders to ten votes for each share. Upon completion of this offering, class A common stock will constitute % of our total outstanding common equity and about % of total voting power and thus will be able to exercise a controlling influence over our business. WE CAN OFFER NO ASSURANCE THAT AN ACTIVE PUBLIC MARKET FOR OUR COMMON STOCK WILL DEVELOP. Prior to the offering, Northern States Power held all of our outstanding common stock and therefore there is no public trading market for our common stock. We will apply to have our common stock approved for listing on the . We can offer no assurance that an active public market will develop or that, if a public market develops, the market price for our common stock will equal or exceed the public offering price set forth on the cover page of this prospectus. See "Underwriting." A SUBSTANTIAL NUMBER OF OUR SHARES WILL BE AVAILABLE FOR FUTURE SALE BY OUR STOCKHOLDERS, WHICH COULD DEPRESS THE MARKET PRICE OF OUR COMMON STOCK. Northern States Power owns shares of class A common stock. The class A common stock is convertible into common stock on a share-for-share basis and will be converted if sold by Northern States Power to a third party. We have agreed, if so requested by Northern States Power, to file registration statements and take other steps to enable Northern States Power to sell any shares of common stock held by it. Northern States Power has agreed with the underwriters, subject to certain exceptions, not to sell any shares of common stock for a period of 180 days following the date of this prospectus. Any sales of substantial amounts of common stock could adversely affect the prevailing market prices for the common stock. See "Shares Eligible for Future Sale", "Relationships and Related Transactions" and "Underwriting". 16

21 USE OF PROCEEDS The net proceeds from this offering are estimated to be approximately . Approximately $300 million of the net proceeds will be used to repay a loan from Citicorp USA, Inc., which matures on August 31, 2000 and bears interest at a floating rate, which at March 31, 2000 was 6.43%. The proceeds from the Citicorp USA loan were used to fund a portion of the purchase price of the Cajun facilities acquired by us in March 2000. The remaining net proceeds will be used for general corporate purposes, which may include funding of capital expenditures and potential acquisitions, such as the pending acquisition of generation assets from Conectiv, the development and construction of new facilities and additions to working capital. Funds not immediately required for such purposes may be used to temporarily reduce any outstanding balances under our revolving credit facility. The majority of the outstanding balance on our revolving credit facility was borrowed to fund the acquisition of assets from Connecticut Light & Power and bears interest at a floating rate, which was 7.20% at March 31, 2000. No proceeds of this offering will be distributed to Northern States Power. DIVIDEND POLICY We currently intend to retain future earnings, if any, to fund the development and growth of our business. Therefore, we do not currently anticipate paying any cash dividends in the foreseeable future. 17

22 CAPITALIZATION Capitalization is the amount invested in a company and is a common measurement of a company's size. The table below shows our capitalization as of December 31, 1999: - on an actual basis; - on a pro forma basis to reflect the acquisition of the Cajun facilities in March 2000; and - on a pro forma as adjusted basis to give effect to the acquisition of the Cajun facilities and the sale of the shares of our common stock offered by this prospectus at an assumed initial public offering price of $ per share and the application of the net proceeds from the sale, including the repayment of our $300 million loan from Citicorp USA, after deducting underwriting discounts and commissions and estimated offering expenses. The table below does not reflect options to purchase shares of our common stock under stock options granted to employees and non-employee directors under the NRG Long-Term Incentive Plan. You should read this table in conjunction with the consolidated financial statements and related notes that are included in this prospectus. DECEMBER 31, 1999 ------------------------------------- PRO FORMA ACTUAL PRO FORMA AS ADJUSTED ---------- ---------- ----------- (IN THOUSANDS EXCEPT PER SHARE DATA) Cash and cash equivalents................................ $ 31,483 $ 31,483 $ Current portion of long-term debt........................ 30,462 30,426 Short-term debt: Non-recourse (1)....................................... 35,766 35,766 Recourse(2)............................................ 340,000 628,000 Long-term debt Non-recourse (1)....................................... 1,026,398 1,826,398 Recourse (2)........................................... 915,000 915,000 Stockholders' equity: Preferred stock........................................ -- -- Common stock........................................... 1 1 Class A common stock................................... -- -- Additional paid-in capital............................. 781,913 781,913 Retained earnings...................................... 187,210 187,210 Accumulated other comprehensive income (loss)(3)....... (75,470) (75,470) ---------- ---------- ------- Total stockholders' equity............................. 893,654 893,654 ---------- ---------- ------- Total capitalization................................ $3,272,763 $4,360,727 $ ========== ========== ======= - --------------- (1) Non-recourse debt is indebtedness incurred by a subsidiary for which there is no recourse to NRG for repayment. (2) Recourse debt is a direct corporate-level obligation of NRG. (3) Represents cumulative currency translation adjustments related to various international projects. See Note 2 to our Financial Statements. 18

23 SELECTED CONSOLIDATED FINANCIAL AND OTHER DATA The selected consolidated financial data set forth below as of December 31, 1995, 1996, 1997, 1998 and 1999 and for the years then ended, have been derived from our audited consolidated financial statements. The financial data set forth below as of March 31, 1999 and March 31, 2000, and for the three-month periods then ended, have been derived from our unaudited financial statements, which were prepared on a basis consistent with our audited consolidated financial statements. We have supplied selected capacity and other data set forth below under the caption "Other Data." All dollar amounts are set forth in thousands, except per share amounts. CONSOLIDATED STATEMENTS OF INCOME DATA: THREE MONTHS ENDED YEAR ENDED DECEMBER 31, MARCH 31, ------------------------------------------------------------- ----------------------------- PRO FORMA PRO FORMA 1995 1996 1997 1998 1999 1999(1) 1999 2000 2000(1) ------- ------- ------- -------- -------- --------- ------- ------- --------- OPERATING REVENUES Revenues from wholly-owned operations...................... $64,180 $71,649 $92,052 $100,424 $432,518 $801,080 $37,847 $ $ Equity in earnings of unconsolidated affiliates....... 28,639 32,815 26,200 81,706 67,500 67,500 8,667 ------- ------- ------- -------- -------- -------- ------- ------- ------- Total operating revenues.......... 92,819 104,464 118,252 182,130 500,018 868,580 46,514 OPERATING COSTS AND EXPENSES Cost of wholly-owned operations... 32,535 36,562 46,717 52,413 269,900 513,944 27,940 Depreciation and amortization..... 8,283 8,378 10,310 16,320 37,026 64,595 4,734 General, administrative, and development..................... 34,647 39,248 43,116 56,385 83,572 100,376 15,985 ------- ------- ------- -------- -------- -------- ------- ------- ------- Total operating costs and expenses........................ 75,465 84,188 100,143 125,118 390,498 678,915 48,659 ------- ------- ------- -------- -------- -------- ------- ------- ------- OPERATING INCOME (LOSS)........... 17,354 20,276 18,109 57,012 109,520 189,665 (2,145) OTHER INCOME (EXPENSE) Minority interest................. -- -- (131) (2,251) (2,456) (2,456) (464) Other income, net(2).............. 29,746 9,477 11,502 11,630 17,426 15,556 734 Interest expense.................. (7,089) (15,430) (30,989) (50,313) (93,376) (166,624) (11,059) ------- ------- ------- -------- -------- -------- ------- ------- ------- Total other income (expense)...... 22,657 (5,953) (19,618) (40,934) (78,406) (153,524) (10,789) ------- ------- ------- -------- -------- -------- ------- ------- ------- INCOME (LOSS) BEFORE INCOME TAXES........................... 40,011 14,323 (1,509) 16,078 31,114 36,141 (12,934) INCOME TAX BENEFIT (EXPENSE)(3)... (8,810) 5,655 23,491 25,654 26,081 (24,001) 11,994 ------- ------- ------- -------- -------- -------- ------- ------- ------- NET INCOME (LOSS)................. $31,201 $19,978 $21,982 $ 41,732 $ 57,195 $ 60,142 (940) ======= ======= ======= ======== ======== ======== ======= ======= ======= Earnings per share -- basic....... $ $ $ $ $ $ Earnings per share -- diluted..... $ $ $ $ $ $ Weighted average shares outstanding -- basic............ Weighted average shares outstanding -- diluted.......... CONSOLIDATED BALANCE SHEET DATA: AS OF AS OF DECEMBER 31, MARCH 31, ---------------------------------------------------------- --------------------- 1995 1996 1997 1998 1999 1999 2000 -------- -------- ---------- ---------- ---------- ---------- -------- Net property, plant and equipment...................... $111,919 $129,649 $ 185,891 $ 204,729 $1,919,323 $ 207,473 Net equity investments in projects....................... 221,129 365,749 694,655 800,924 988,671 814,807 Total assets..................... 454,589 680,809 1,168,102 1,293,426 3,431,684 1,298,679 Long-term debt, including current maturities..................... 90,034 212,141 620,855 626,476 1,971,860 498,019 Stockholder's equity............. 319,764 421,914 450,698 579,332 893,654 680,017 19

24 OTHER DATA: AS OF AND FOR THE AS OF AND FOR THE YEAR ENDED THREE MONTHS DECEMBER 31, ENDED MARCH 31, ------------------------------------------- ----------------- 1995 1996 1997 1998 1999 2000 ------ ------ ------ ------ ------- ----------------- Consolidated EBITDA(4)..................................... 55,383 38,131 39,790 82,711 161,516 Total debt to total capitalization ratio................... 22.0% 33.5% 57.9% 52.0% 72.4% Ratio of recourse debt to recourse debt and equity......... 5.4% 30.9% 52.6% 46.6% 58.4% Consolidated interest expense coverage ratio(5)............ 7.81x 2.47x 1.28x 1.64x 1.72x Power generation capacity (MW), net........................ 999 1,326 2,637 3,300 10,990 13,664 Thermal energy generation capacity: mmBtus per hour, net..................................... 2,318 2,654 2,693 2,905 3,400 3,400 MW equivalent, net(6).................................... 812 917 950 1,012 1,204 1,204 - --------------- (1) The pro forma financial information gives effect to our March 31, 2000 acquisition of the Cajun facilities as if that acquisition had occurred on January 1, 1999. We do not believe that the pro forma data is indicative of our future revenues and earnings, because the previous owner of the Cajun facilities sold energy and capacity and purchased coal upon terms substantially different from those under which we will operate these facilities. Thus, we believe the pro forma financial information is of limited use in making an investment decision. (2) These amounts includes equity in gain from project termination settlements in 1995 of $29.9 million related to the settlement and termination of the San Joaquin Valley power purchase agreements with Pacific Gas & Electric, and include pretax charges of $5.0 million in 1995, $1.5 million in 1996, $9.0 million in 1997, $26.7 million in 1998 and $0 in 1999, to write-down the carrying value of certain energy projects. These amounts also include the gain on sale of interest in projects of $8.7 million in 1997, $30.0 million in 1998 and $15.5 million in 1999. (3) We are included in the consolidated federal income tax and state franchise tax returns of Northern States Power. We calculate our tax position on a separate company basis under a tax sharing agreement with Northern States Power and receive payment from Northern States Power for tax benefits and pay Northern States Power for tax liabilities. (4) EBITDA is the sum of income (loss) before income taxes, interest expense (net of capitalized interest) and depreciation and amortization expense. EBITDA is a measure of financial performance not defined under generally accepted accounting principles, which you should not consider in isolation or as a substitute for net income, cash flows from operations or other income or cash flow data prepared in accordance with generally accepted accounting principles or as a measure of a company's profitability or liquidity. In addition, EBITDA may not be comparable to similarly titled measures presented by other companies and could be misleading because all companies and analysts do not calculate it in the same fashion. (5) This coverage ratio equals the sum of funds from operations plus interest expense on recourse debt divided by interest expense on recourse debt. Funds from operations is calculated by subtracting working capital changes from cash provided (used) by operations. (6) Our conversion of thermal generation capacity to MW from British thermal units per hour is based upon the thermal constant of 3,412.14 British thermal units per hour per kilowatt hour. Our conversion of chilled water capacity to MW is based upon 12,000 British thermal units per hour per ton of chilled water capacity, as well as the thermal constant of 3,412.14 British thermal units per hour per kilowatt hour. 20

25 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS You should read the following in conjunction with our consolidated financial statements and notes thereto, "Risk Factors," and "Selected Consolidated Financial and Other Data," included elsewhere in this prospectus. A complete listing of our projects that are discussed in this section is set forth on the inside back cover of this prospectus. OVERVIEW We are a leading global energy company primarily engaged in the acquisition, development, ownership and operation of power generation facilities. We have grown significantly during the last three years. During this period, we have grown from a company deriving most of our revenues from our interests in power generation investments in which we owned less than 50% and from heating, cooling and thermal activities, to one of the largest independent power generation companies in the United States (measured by MW of net ownership interests in generation projects), deriving over 78% of our revenues from our wholly-owned power generation facilities in 1999. Since January 1, 1997, we have acquired 12,338 MW of net ownership interests in power generation facilities. During 1997, we acquired 1,311 MW of net ownership interests in power generation facilities, primarily as a result of our acquisition of interests in Crockett Cogeneration and other projects. In 1998, we acquired a 50% interest in 1,218 MW of generating capacity in Southern California. Since January 1, 1999, we have acquired an additional 6,980 MW of 100% owned generating capacity in the Northeast United States, 680 MW of 100% owned generating capacity in the United Kingdom and 1,708 MW of 100% owned generating capacity in Louisiana. We intend to continue growing through targeted acquisitions, repowering and the expansion of existing facilities and the development of new greenfield projects. Source of Revenues and Equity in Earnings of Unconsolidated Affiliates. Our operating revenues and expenses are primarily related to the operations of our controlled subsidiaries, which are consolidated for accounting purposes. Significant consolidated subsidiaries include NRG Northeast Generating LLC, NRG South Central Generating LLC, NEO Corporation, NRG Thermal, Inc., and Crockett Cogeneration. Investments in project companies over which we exercise significant influence, but do not control, are accounted for using the equity method of accounting. The operating results of these entities are reflected in total operating revenues in the form of equity in earnings of affiliates. Significant investments accounted for using the equity method include MIBRAG, Gladstone, Schkopau, Loy Yang, COBEE, West Coast Power LLC, Energy Developments Limited and ECK Generating. In 1999, we consolidated our Pittsburgh and San Francisco thermal operations and Crockett Cogeneration, which we previously accounted for using the equity method. Our operating revenues are derived primarily from the sale of electrical energy, capacity and other energy products from our 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 to 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. 21

26 The following charts illustrate the sources of our domestic power generation revenue (excluding thermal, resource recovery and NEO) and equity in earnings of international affiliates engaged in power generation for the year ended December 31, 1999: DOMESTIC LONG TERM SHORT TERM - --------- ---------- 73 27 INTERNATIONAL(1) LONG TERM SHORT TERM - --------- ---------- 96 4 - --------------- (1) Consists solely of equity in earnings of international affiliates. Operating Costs and Expenses. The principal costs and expenses of our operations are fuel used to generate energy, labor to operate and maintain our facilities, depreciation and amortization, general and administrative costs and development expenses. Seasonality. Demand for energy as well as energy and capacity prices tend to be higher in peak market periods, which are dictated by weather patterns. As a result of a portfolio consisting of assets predominantly located in the United States, we expect our revenues and profitability to be highest during the third quarter of the calendar year. RESULTS OF OPERATIONS FISCAL YEAR ENDED DECEMBER 31, 1999 COMPARED TO FISCAL YEAR ENDED DECEMBER 31, 1998 Revenues. For the year ended December 31, 1999, we had total revenues of $500.0 million, which includes operating revenues and equity in earnings of unconsolidated affiliates, compared to $182.1 million for the year ended December 31, 1998, an increase of $317.9 million or 174.5%. Our operating revenues from wholly-owned operations were $432.5 million, an increase of $332.1 million, or 330.7%, over the same period in 1998. Revenues from our Northeast assets that were acquired during 1999 accounted for approximately $303.6 million of this increase. In 1999, the acquisition of additional ownership interests in and resulting consolidation of our Pittsburgh and San Francisco thermal operations, together with the consolidation of Crockett Cogeneration, accounted for approximately $29.1 million of the increase in revenues. In 1999, operating revenues from wholly-owned operations consisted of revenue from electrical generation (78.3%), heating, cooling and thermal activities (17.6%) and technical services (4.1%), while in 1998, they consisted of operating revenue from electrical generation (46.2%), heating, cooling and thermal activities (46.0%) and technical services (7.8%). For 1999, our equity in earnings of unconsolidated affiliates was $67.5 million, compared to $81.7 million for 1998, a decrease of $14.2 million or 17.4%. This change was primarily the result of a cooler summer in the western region of the United States in 1999 and financing costs related to our El Segundo and Long Beach generation facilities, which accounted for a $12.8 million reduction in equity in earnings from these affiliates. Lower earnings at Mt. Poso, together with the consolidation of our Pittsburgh and San Francisco thermal operations and Crockett Cogeneration also contributed to the decrease in equity in earnings during 1999. These decreases were partially offset by increased earnings from MIBRAG and a favorable legal settlement at one of our affiliates. Operating Costs and Expenses. For 1999, our cost of wholly-owned operations was $269.9 million, compared to $52.4 million in 1998, an increase of $217.5 million or 415%. Costs associated with the 22

27 ownership and operation of our Northeast assets that were acquired during 1999 accounted for approximately $194.9 million. The remaining increase resulted from the consolidation of our Pittsburgh and San Francisco thermal operations and Crockett Cogeneration. Increases also resulted from the addition of new projects during 1999 by our NEO subsidiary. Our depreciation and amortization costs were $37.0 million for 1999, compared to $16.3 million for 1998, an increase of $20.7 million or 127%. This increase resulted primarily from the addition of our Northeast assets and the addition of new projects by our NEO subsidiary. The acquisition of additional ownership interests in and resulting consolidation of our Pittsburgh and San Francisco thermal operations, together with the consolidation of Crockett Cogeneration, also contributed to the increase in depreciation and amortization. Our general and administrative costs were $59.9 million for 1999, compared to $42.0 million for 1998, an increase of $17.9 million or 43%. Approximately $7.3 million of the increase was a direct result of the ownership and operation of our Northeast assets during 1999. The remaining increase was due primarily to the consolidation of certain affiliates described above, which were previously accounted for on the equity method, and an overall increase in legal, technical and accounting support resulting from expanded operations. Our development expenses were $23.7 million for 1999, compared to $14.4 million for 1998, an increase of $9.3 million or 65%. Our development expenses include development office costs, internal personnel costs, and fees paid to outside service providers in connection with the pursuit of new investment opportunities. The 1999 increase was due primarily to the pursuit of a greater number of potential opportunities during the year. Other Income (Expense). Minority interest in projects was $2.5 million for 1999 compared to $2.3 million for 1998. Minority interest relates to projects that were acquired in November 1997 and thermal operations in which we have a minority interest. Other income, net was $17.4 million in 1999 compared to $11.6 million in 1998, an increase of $5.8 million or 50%. This increase was primarily the result of the 1999 pretax gain of $11.0 million on the sell-down of our ownership interest in Cogeneration Corporation of America from approximately 45% to 20%. This increase was offset in part by a $2.0 million reclassification of management fees from income to equity in earnings of unconsolidated subsidiaries, compared to a 1998 $30.0 million gain from sale of interests in projects, offset in part by a $26.7 million write down of the carrying value of other projects. The 1998 charges included a $22.0 million write-off of our entire investment, which included development expenses as well as fees incurred in connection with the termination of an interest rate hedge, in a project we were pursuing in West Java, Indonesia. This write-off was due to uncertainties surrounding infrastructure projects in Indonesia. Interest expense was $93.4 million for 1999 compared with $50.3 million for 1998, an increase of $43.1 million or 86%. The increase in interest expense primarily resulted from the acquisition of our Northeast assets, which was primarily funded at the end of the second quarter, and the issuance of $300 million of senior notes in June 1999 and $240 million of senior notes in November 1999. In addition, a higher average outstanding balance on our revolving line of credit and the consolidation of Crockett Cogeneration and our Pittsburgh and San Francisco thermal operations contributed to higher interest expense. Income Tax. We generate substantial income tax benefits as a result of our operations. Because we are included in the consolidated federal income tax return of Northern States Power, we are paid by Northern States Power on a dollar-for-dollar basis for the reduction of Northern States Power's taxes attributable to the tax benefits we create. We have recorded an income tax benefit due to the recognition of Section 29 tax credits associated with our NEO subsidiary, foreign tax benefits related to the Loy Yang project and tax losses resulting from accelerated depreciation of certain fixed assets. The Section 29 credits comprised $20.4 million of our 1999 tax benefit compared with $15.9 million in 1998. The increase in Section 29 credits is due to the growth of NEO's portfolio of landfill gas projects. 23

28 Net Income. For 1999, we had net income of $57.2 million compared to $41.7 million in 1998, an increase of $15.5 million or 37.2%. This increase was due to the factors described above. FISCAL YEAR ENDED DECEMBER 31, 1998 COMPARED TO FISCAL YEAR ENDED DECEMBER 31, 1997 Revenues. For the year ended December 31, 1998, we had total revenues of $182.1 million, compared to $118.3 million for the year ended December 31, 1997, an increase of $63.8 million or 54%. Operating revenues from wholly-owned operations for 1998 were $100.4 million, compared to $92.0 million in 1997, an increase of $8.4 million, or 9.1%. The acquisition of new facilities, principally the Camas Power Boiler, accounted for this increase. Unusually mild weather in 1998 in the upper Midwest led to lower revenues in our heating and cooling operations, which partially offset the 1998 revenue increase. In 1998, operating revenues from wholly-owned operations consisted of revenue from electrical generation (46%), heating, cooling and thermal activities (46%), and technical services (8%), while in 1997, they consisted of operating revenues from heating, cooling and thermal activities (54%), electrical generation (32%), and technical services (14%). For 1998, our equity in earnings of unconsolidated affiliates was $81.7 million, compared to $26.2 million for 1997, an increase of $55.5 million or 212%. This increase primarily resulted from the acquisition of interests in new projects, including the El Segundo, Long Beach, Crockett Cogeneration and Mt. Poso projects, an increase in our holdings in Energy Developments Limited, and improved performance during a full-year of ownership from Loy Yang. Operating Costs and Expenses. For 1998, our cost of wholly-owned operations was $52.4 million, compared to $46.7 million in 1997, an increase of $5.7 million or 12%. The increase in cost of operations was due to new NEO projects and increased expenses in our heating, cooling and thermal operations. Our depreciation and amortization costs were $16.3 million for 1998, compared to $10.3 million for 1997, an increase of $6.0 million or 58%. The depreciation and amortization increase primarily resulted from increased amortization of intangible assets related to the acquisition of Crockett Cogeneration and other projects and additional depreciation due to the acquisition of additional projects by NEO. Our general and administrative costs were $42.0 million for 1998, compared to $32.2 million for 1997, an increase of $9.8 million or 30%. This increase was due primarily to increased legal, technical and accounting expenses resulting from expanded operations. Our development expenses were $14.4 million for 1998, compared to $10.9 million for 1997, an increase of $3.5 million or 32%. This increase was due primarily to increased business development activities. Other Income (Expense). Minority interest in projects was $2.3 million for 1998 compared to $0.1 million for 1997. Minority interest relates to projects that were acquired in November 1997. We recorded a total gain of $30.0 million in 1998 related to project sales. In October 1998, we sold our 110 MW Mid-Continent Power Company facility in Oklahoma to Cogeneration Corporation of America, our affiliate, for a $2.1 million gain. Also in October 1998, we sold 13.35% of our interest in ECK Generating for a gain of $1.6 million. We continue to own a 44.5% interest in the ECK Generating project. In December 1998, we sold half of our 50% interest in our Enfield project to an affiliate of El Paso International for a $26.2 million gain. For 1998, we recorded $26.7 million in total project write-downs compared to write-downs of $9.0 million in 1997. The 1998 write-down included a $22.0 million charge for our West Java, Indonesia project, a $1.9 million charge related to our investment in the Sunnyside project in Utah and $2.8 million of accumulated project development expenditures related to the Alto Cachopoal project in Chile. The 1997 charges consisted of a write-down of our investment in the Sunnyside project. At the end of 1998, no amounts remained on the balance sheet for these investments. Other income of $8.4 million in 1998 compared to $11.8 million in 1997 primarily reflected a reduction in interest income from loans to affiliates during 1998. 24

29 Interest expense was $50.3 million for 1998 compared with $31.0 million for 1997, an increase of $19.3 million or 62%. This increase was due primarily to the issuance of $250 million of senior notes in June 1997, interest on larger balances outstanding under our revolving line of credit incurred in connection with the purchase of Crockett Cogeneration and other projects and new debt obtained for certain NEO projects. Income Tax. The Section 29 credits comprised $15.9 million of our 1998 tax benefit compared with $9.8 million in 1997. The increase in Section 29 credits is due to the growth of NEO's portfolio of landfill gas projects. Net Income. For 1998, we had net income of $41.7 million compared to $22.0 million in 1997, an increase of $19.7 million or 90%. This increase was due to the factors described above. LIQUIDITY AND CAPITAL RESOURCES To date, we and our subsidiaries have obtained cash from operations, issuance of debt securities, borrowings under credit facilities, capital contributions from Northern States Power, the sale of tax benefits to Northern States Power and proceeds from non-recourse project financing. We have 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. From January 1, 1997, through December 31, 1999, our financing activities provided cash totaling approximately $2,260 million, including $430.9 million in capital contributions from Northern States Power. Financing activities for 1999 included $1,473 million in gross proceeds from the issuance of long and short term debt and $250.0 million of capital contributions from Northern States Power. These inflows were partially offset by $18.6 million in payments on long-term debt. In 1999, we used $11.4 million of cash in operating activities. Our use of cash in 1999 primarily related to ongoing working capital requirements for new operations. Financings at the NRG Level. Our objective is to maintain and improve our credit ratings, which are presently at "Baa3" from Moody's and "BBB-" from Standard & Poor's. We intend to do so by carefully leveraging our project subsidiary companies and by maintaining a corporate capital structure that is consistent with these credit rating objectives. Since January 1997, we have issued approximately $1,040 million of long-term corporate-level indebtedness. All of such debt is unsecured and ranks senior to all of our existing and future subordinated indebtedness. This amount includes $250 million of 7.5% senior notes due 2007 and $300 million of 7.5% senior notes due 2009. These senior notes were used primarily to support equity requirements for projects acquired and in development. Interest on all of these notes is paid semi-annually through their maturity dates. In November 1999, we issued $240 million of 8% remarketable or redeemable securities ("ROARS") due 2013. On November 1, 2003, Credit Suisse Financial Products may remarket the ROARS at a fixed rate of interest through 2013 or, at our option, at a floating rate of interest for up to one year and then at a fixed rate of interest through 2013. Interest is payable semi-annually beginning May 1, 2000 through November 1, 2003, and then at intervals and interest rates specified in the indenture. On November 1, 2003, the ROARS will either be mandatorily tendered to and purchased by Credit Suisse Financial Products or mandatorily redeemed by us at prices specified in the indenture. In March 2000, we issued L160 million (approximately $250 million at the time of issuance) of 7.97% reset senior notes due 2020, principally to finance our equity investment in 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 our option, 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. On March 15, 2005, these senior notes will either be mandatorily tendered to and purchased by Bank of America or mandatorily redeemed by us at prices specified in the indenture. 25

30 In addition, we have a $500 million revolving credit facility under a commitment fee arrangement that matures on March 9, 2001. This facility provides short-term financing in the form of bank loans. At March 31, 2000, we had $304 million outstanding under this facility. In March 2000, we borrowed $300 million under a short-term bridge facility with Citicorp USA, Inc., that expires on August 31, 2000 and bears interest at a floating rate, which was 6.43% at March 31, 2000. Proceeds from this loan, which were used to fund the acquisition of the Cajun facilities, will be repaid with a portion of the proceeds of this offering. In connection with the extension of this bridge facility, Northern States Power provided a support agreement on our behalf to Citicorp USA. In November 1999, we entered into a $125 million standby letter of credit facility with Australia and New Zealand Banking Group Limited as administrative agent. The facility provides for issuances of letters of credit for our account with respect to financial and performance guarantees that we or our project affiliates undertake. The facility terminates on November 31, 2002. Financings at the Project Level. We have generally financed the acquisition and development of our projects under financing arrangements to be repaid solely from each of our project's cash flows, which are typically secured by the plant's physical assets and equity interests in the project company. We have agreed, in some instances to undertake limited financial support for certain of our project affiliates in the form of certain limited obligations and contingent liabilities. As of March 31, 2000, our affiliates had approximately $2,325 million of indebtedness outstanding which is non-recourse to us. The most significant of these financings include the following: - $800 million of senior secured bonds issued by NRG South Central Generating LLC in March 2000 consisting of: - $500 million of 8.962% bonds due 2016; and - $300 million of 9.479% bonds due 2024. - $750 million of senior secured bonds issued by NRG Northeast Generating LLC in February 2000 consisting of: - $320 million of 8.065% bonds due 2004; - $130 million of 8.842% bonds due 2015; and - $300 million of 9.292% bonds due 2024. - In March 2000, three of our subsidiaries entered into a L325 million ($517 million) secured borrowing facility agreement with Bank of America International Limited, as arranger. Under this facility, the financial institutions party to the facility agreement have made available to our subsidiaries various term loans (L235 million) for purpose of financing the acquisition of the Killingholme facility and revolving credit and letter of credit facilities (collectively, L90 million) for the purpose of providing working capital for operating the Killingholme facility and for other purposes. 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 loan facility have been repaid or cancelled. - $255 million of 8.13% secured indebtedness due 2014 of Crockett Cogeneration that we recorded in 1999 when we consolidated this entity for accounting purposes as a result of an increase in our percentage interest in future distributions due to satisfaction of specified aggregate distribution levels by Crockett Cogeneration to its owners. We have used cash flows provided by our financing activities primarily to facilitate investments in our subsidiaries. From January 1, 1997, through December 31, 1999, we used approximately $2,286 million of cash for our investing activities. In 1999, we incurred $94.9 million in capital expenditures. Over the next several years, we intend to focus on the expansion or repowering of existing facilities and the development of greenfield projects as well as acquisitions of thermal energy production and 26

31 transmission facilities in the United States. Internationally, we intend to continue to pursue development and acquisition opportunities in selected countries. We expect to meet our cash and financing needs over the next several years through a combination of cash flows from operations and additional financing arrangements. We have committed to purchase the Conectiv assets for approximately $800 million in late 2000 and intend to finance this purchase with a combination of project-level and corporate-level debt. Additionally, we have contracted to purchase 16 turbine generators from General Electric at an acquisition cost of approximately $500 million payable over five years, as well as two turbines from Great River Energy for $43 million. In addition, we have ongoing annual expenditures of approximately $35 to $70 million for environmental and other investment at our existing projects. We expect to fund the turbine purchases and these levels of ongoing capital expenditures from internally generated cash flow. Our future growth strategy is dependent upon significant new capital investment, which we expect to finance with a combination of project-level debt, internally generated funds, corporate-level debt and additional equity. Our ability to arrange future financing is dependent on a number of factors. To the extent we were unable to raise additional capital on attractive terms either at the corporate level or on a non-recourse project level, it would have a material adverse effect on our ability to grow. IMPACT OF ENERGY PRICE CHANGES, INTEREST RATES AND FOREIGN CURRENCY FLUCTUATIONS We use derivative financial instruments to mitigate the impact of changes in electricity and fuel prices on our margins, the impact of changes in foreign currency exchange rates on our international project cash flows, and the impact of changes in interest rates on our cost of borrowing. Electricity and fuel prices tend to fluctuate significantly as they are influenced by many factors, including general economic conditions and changes in supply and demand. In particular, our power marketing subsidiary is exposed to the risk of changes in market prices of fuel oil, natural gas and electricity. To assist us in achieving our objective of maximizing net operating margins while minimizing our exposure to volatility in the electricity, fuel oil and natural gas markets, our power marketing subsidiary, NRG Power Marketing, uses a variety of instruments, including options, swaps and forward contracts. Contracts for the transmission and transportation of these commodities are also authorized, as necessary, in order to meet physical delivery requirements and obligations. NRG Power Marketing operates within strict risk management guidelines that have been approved by its board of directors. These guidelines: - generally prohibit speculative trading activities, meaning that we have to be able to produce from our assets, or accept and utilize the commodity being traded; - do not permit more than 50% of the uncommitted energy or capacity of any facility to be sold forward without the approval of the board of directors of NRG Power Marketing; and - require approval of all counter-parties and their trading limits by our Treasurer. As of December 31, 1999, a 10% increase in fuel oil, natural gas and electricity forward prices would have resulted in a gain on our outstanding forward contracts of approximately $11.9 million. Conversely, a 10% decrease in fuel oil, natural gas and electricity forward prices would have resulted in a loss on these contracts of approximately $11.9 million. These potential gains and losses on energy forward contracts may be offset by the gains and losses on the underlying commodities being hedged. For all derivative financial instruments, we and our subsidiaries are exposed to losses in the event of nonperformance by counterparties to such derivative financial instruments. We have established controls to determine and monitor the creditworthiness of counterparties in order to mitigate our exposure to counterparty credit risk. SFAS 52 requires foreign currency gains to be reflected in 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 27

32 is in non-local currencies, namely United States dollars and German deutsche marks. As of December 31, 1999, if the value of the Czech koruna had decreased by 10% in relation to the United States dollar and the German deutsche mark, we would have recorded a $5.0 million after tax loss on the currency transaction adjustment. If the value of the Czech koruna were to have increased by 10%, we would have recorded a $5.0 million after tax gain on the currency transaction adjustment. The potential impacts on our income statement of these currency fluctuations are a result of the debt structure of the project and are not indicative of the long-term earnings potential of the investment. Kladno is the only project we have at this time with this type of debt structure. We have historically used interest rate hedging contracts to mitigate the risks associated with movements in interest rates and, when deemed appropriate, have entered into swap agreements effectively converting fixed rate obligations into floating rate obligations. As of March 31, 2000, we had four interest rate swap agreements with notional amounts totaling approximately $692 million. If the swaps had been discontinued on March 31, 2000, we would have owed the counter-parties approximately $2 million. Based on the investment grade rating of the counter-parties, we believe that our exposure to credit risk due to nonperformance by the counter-parties to our hedging contracts is insignificant. - We entered into a swap agreement effectively converting the 7.5% fixed rate on $200 million of our Senior Notes due 2007 to a variable rate based on the London Interbank Offered Rate. The swap expires on June 1, 2009. - A second swap effectively converts a $16 million issue of 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 L188 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. NEW ACCOUNTING STANDARDS In June 1998, the Financial Accounting Standards Board issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." This statement requires that all derivatives be recognized at fair value in the balance sheet and that changes in fair value be recognized either currently in earnings or deferred as a component of Other Comprehensive Income, depending on the intended use of the derivative, its resulting designation and its effectiveness. We plan to adopt this standard in the first quarter of 2001, as required. We have not determined the potential impact of implementing this statement. 28

33 BUSINESS INTRODUCTION We are a leading global energy company primarily engaged in the acquisition, development, ownership and operation of power generation facilities. We believe we are the second largest independent power generation company in the United States and the seventh largest independent power generation company in the world measured by our net ownership interest in power generation facilities. We own all or a portion of 57 generation projects that have a total generating capacity of 23,660 MW; our net ownership interest in those projects is 13,664 MW. Upon the closing of our pending acquisition from Conectiv of interests in six power generation facilities, which we expect to occur later this year, we will have interests in projects having a total generating capacity of 28,722 MW; our net ownership interest in those projects will be 15,539 MW. In addition, we have an active acquisition and development program through which we are pursuing additional generation projects. As the following table illustrates, we have grown significantly during the last three years, primarily as a result of our success in acquiring domestic power generation facilities: YEAR ENDED DECEMBER 31, ------------------------------ 1997 1998 1999 ------- ------- -------- Net Generating Capacity (in MW at year end)(1)..... 2,637 3,300 10,990 Operating Income (in thousands).................... $18,109 $57,012 $109,520 - --------------- (1) All references to our MW ownership in this prospectus includes MW attributable to projects under construction, which totaled 383 MW as of March 31, 2000. We intend to continue our 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. To prepare for expansion, repowering and greenfield opportunities, we recently agreed to purchase 16 turbine generators from GE Power Systems and two turbine generators from Siemens Westinghouse over a six year period commencing in 2001. These new turbines, which we expect to install at domestic facilities, will have a combined capacity of approximately 3,300 MW. We believe that our operational skills and experience gives us a strong competitive position in the unregulated generation marketplace. We have organized our operations geographically such that inventories, maintenance, backup and other operational functions are pooled within a region. This approach enables us to realize cost savings and enhances our ability to meet our facility availability goals. Our availability goals are not driven by traditional benchmarks, such as daily or annual availability, but are focused on each facility's availability during periods when power prices are significantly above the variable cost of producing power at that facility -- what we call "in-market" availability. In addition to our power generation projects, we also have interests in district heating and cooling systems and steam generation and transmission operations. Our thermal and chilled water businesses have a steam and chilled water capacity equivalent to approximately 1,204 MW. We believe that, through our subsidiary NEO Corporation, we are also one of the top three landfill gas generation companies in the United States, extracting methane from landfills to generate electricity. NEO owns 30 landfill gas collection systems and has 55 MW of net ownership interests in related electric generation facilities. NEO also has 35 MW of net ownership interests in 18 small hydroelectric facilities. MARKET OPPORTUNITY The power industry is one of the largest industries in the world accounting for approximately $220 billion in annual revenues and approximately 730,000 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 upon cost of service pricing to a 29

34 non-regulated competitive market. We believe that the power industry will continue to undergo substantial restructuring over the next several years and will experience significant growth in the future. As of January 2000, 22 states had enacted legislation to restructure their electric utility industries, four additional state public utility commissions had issued comprehensive restructuring orders and 20 additional states had active legislative or regulatory processes underway to study restructuring and propose implementing legislation. As a result, from January 1, 1997 through December 31, 1999, approximately 70,000 MW of the power generating capacity, in the United States, had been sold or transferred by regulated electric utilities to independent power producers. We expect in excess of 70,000 additional MW to be sold to independent power producers by the end of 2002. We believe 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. In our view, these factors provide an attractive domestic environment for an independent power producer like us 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. We believe that these market trends will continue to create opportunities to acquire and develop power generation facilities globally. OUR HISTORY We have been acquiring and developing power generation facilities since 1989, when we were formed as a wholly-owned subsidiary of Northern States Power to take advantage of opportunities in the independent power market that had developed as a result of economic factors and legal and regulatory changes in the United States and throughout the world. During the early 1990s, we gained experience in acquiring interests in and operating smaller domestic generation facilities and established our landfill gas, resource recovery and district heating and cooling businesses. In 1993 we began focusing our development efforts outside the United States in response to the growing trend among foreign governments to privatize government-owned electric utility assets. We capitalized on our senior management's background and experience with our parent company, which has an excellent reputation as an owner and operator of coal-fired power plants; this, combined with Northern States Power's strong track record on environmental issues, was instrumental in our success in early global privatization initiatives in Germany and Australia. Since that time, we have gained experience in the development and operation of gas-fired power plants and have established an international reputation as a reliable and experienced owner and operator of power plants, which has allowed us to enjoy continued success in selected markets globally. In the mid-1990s, the international privatization trend was augmented by electric utility restructuring in the United States. As regulators began opening domestic markets to competition and electric utilities began selling their electric generation assets, we refocused a significant portion of our development efforts on independent power projects in the United States with a goal of becoming a significant owner of generation assets in certain core markets. Since January 1, 1997, we have acquired approximately 10,489 MW of power generation capacity in the United States: 7,025 MW in our Northeast region, 1,888 MW, in our South Central region, and 1,576 MW in our West Coast region. We continue to pursue targeted acquisition opportunities in our core United States markets. In January 2000 we agreed to purchase 1,875 MW of power generation assets in the Mid-Atlantic United States from Conectiv. We expect to complete this acquisition during the fourth quarter of 2000 subject to receipt of required regulatory approvals. 30

35 During the 1990s, we also expanded our landfill gas, resource recovery and district heating and cooling businesses. These businesses differentiate us as an independent power producer experienced in diverse fuels and alternative energy. We believe we are now the second largest district heating and cooling provider in the United States, with operations in Minnesota, California and Pennsylvania, and the third largest landfill gas operator in the United States. Our management team has substantial experience in the electric utility and independent power businesses gained at NRG, Northern States Power and, in the case of Keith G. Hilless, at Queensland Power Trading Corporation in Australia. YEARS OF EXPERIENCE IN ELECTRIC GENERATION NAME CURRENT POSITION YEARS WITH NRG INDUSTRY - ---- -------------------------------------- -------------- ------------- David H. Peterson.............. Chairman of the Board, President, Chief Executive Officer and Director 11 36 Leonard A. Bluhm............... Executive Vice President and Chief Financial Officer 9 28 Keith G. Hilless............... Senior Vice President, Asia Pacific 3 8 Craig A. Mataczynski........... Senior Vice President, North America 6 17 John A. Noer................... Senior Vice President 1 31 Ronald J. Will................. Senior Vice President, Europe 11 39 OUR INDEPENDENT POWER GENERATION BUSINESS DOMESTIC Our near-term domestic development plans are focused on core markets that are considered to have attractive business fundamentals and where we believe we have the ability to build the scale needed to enhance our long-term profitability. Our current core domestic markets are the Northeast, South Central and West Coast regions of the United States. The table that follows summarizes our domestic power generation operations in these core markets. TOTAL CAPACITY OUR NET UNITED STATES REGIONS STATES OF OPERATION PRIMARY FUELS (MW) INTEREST (MW) - --------------------- ------------------- -------------------- -------- ------------- Northeast...................... Connecticut, Maine, Gas, Coal, Jet Fuel, 7,602 7,099 Massachusetts, New and Oil Jersey, New York, and Pennsylvania South Central.................. Louisiana, Illinois, Gas and Coal 2,832 2,138 and Oklahoma West Coast..................... California Gas and Coal 3,151 1,603 ------ ------ Total Domestic............... 13,585 10,840 ====== ====== Upon completion of our acquisition of power generation assets from Conectiv, we intend to establish the Mid-Atlantic region as our fourth core domestic market. INTERNATIONAL In selected global markets, we have pursued development and acquisition opportunities in those countries in which we believe that the legal, political and economic environment is conducive to foreign investment. We are presently focusing our international development activities in the United Kingdom, Central Europe, Turkey, Australia and, to a lesser extent, Latin America. 31

36 The table that follows describes our existing international power generation operations. TOTAL CAPACITY OUR NET GLOBAL MARKETS COUNTRIES OF OPERATION PRIMARY FUELS (MW) EQUITY (MW) - -------------- ---------------------- ------------------ -------- ------------- Australia...................... Australia Coal, Landfill Gas 4,146 1,312 and Methane Europe......................... Czech Republic, Germany Coal and Gas 2,642 1,223 and United Kingdom Latin America.................. Bolivia, Colombia, Hydro, Gas, Coal, 1,078 186 Guatemala, Honduras, Oil and Geothermal Jamaica and Peru ------ ------ Total International.......... 7,866 2,721 ====== ====== STRATEGY Our 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 diversified in terms of geographic location, fuel type and dispatch level. Currently, 80% of our generation is located in the United States in three core markets: our Northeast, South Central and West Coast regions. With our diversified asset base, we seek 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 and periods of constrained availability of generating capacity, fuels and transmission. The following charts illustrate our diversity: GEOGRAPHIC LOCATION(1) U.S. EUROPE AUSTRALIA OTHER - ---- ------ --------- ----- 80 9.00 10.00 1.00 PRIMARY FUEL TYPE(1)(2) COAL OIL GAS OTHER - ---- --- --- ----- 35 26.00 37.00 2.00 DISPATCH LEVEL(3) PEAKING INTERMEDIATE BASELOAD - ------- ------------ -------- 41 19.00 40.00 - --------------- (1) Based upon MW of net ownership interests as of March 31, 2000 (2) Several of our generation facilities, constituting approximately 3,900 MW of capacity, are capable of utilizing more than one fuel, which can be switched as fuel prices fluctuate. (3) Estimated for 2000 based upon historic dispatch data. We define "baseload" as facilities that we expect to operate greater than 60% of the year, "intermediate" as facilities that we expect to operate between 20% and 60% of the year and "peaking" as facilities that we expect to operate less than 20% of the year, assuming utilization of primary fuel type. Our strategy is to capitalize on our acquisition, development and operating skills to build a balanced, global portfolio of power and thermal generation assets. We intend to implement this strategy by continuing an aggressive, but thoughtful, acquisition program and accelerating our development of existing expansion projects and greenfield projects. By leveraging the talents of our regional management teams, focusing on our regional market expertise and operating and utilizing our asset base on a regional rather than a project basis, we believe we can best position ourselves for long-term profitability. Achieving "critical mass" in core markets should allow us to capitalize on opportunities available in those markets. We neither own nor do we intend to own any interest in nuclear generation facilities. 32

37 DOMESTIC The domestic 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, we expect the evolution to continue as regulated utility generation assets are divested to non-regulated generators. In addition, we expect 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 independent power producers like us. In order to position ourselves for growth in this transitioning market, we have decided to focus our near-term domestic development plans on our existing three core markets, our Northeast, South Central, West Coast regions, and add the Mid-Atlantic region as our fourth core market to be established upon closing of the planned acquisition from Conectiv. In each of these markets, we believe that attractive business fundamentals and growth opportunities exist that will enable us to pursue a top three position in these markets. We will consider domestic projects outside of these markets if we believe that a future market opportunity exists to create a new core market or that the expected project returns warrant our investment. We have been active in acquiring assets from utility generation divestiture programs and have focused on the following factors and characteristics in evaluating potential acquisitions: - cost of competing generation in the relevant markets; - assets that provide diversity in terms of dispatch level, fuel source and access to wholesale power markets within a region; - assets in high priced or transmission constrained markets; - assets that allow for the sale of multiple generation products, including energy, capacity and ancillary services; - assets that can support our other regional assets or have the potential to sell into attractive adjacent markets; - assets that are being sold with initial transition power contracts to stabilize cash flows and earnings during our initial years of ownership; and - assets that provide opportunities for future capacity expansion or repowerings. Once we have acquired one or more power plants in a given market, we will then look to build additional capacity as appropriate, by building facilities at new sites within a market, also known as "greenfield development," or by expanding or repowering of facilities at existing sites. The 16 new turbines that we recently contracted to purchase from GE, representing approximately 3,000 MW of capacity, and the two 135 MW turbines being built by Siemens Westinghouse will be the foundation for our domestic development program. INTERNATIONAL Historically, the majority of power generation 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 33

38 awarding long-term contracts for energy and capacity to purchasers of generation to creating competitive wholesale markets for selling and trading energy, capacity and related products. We believe that there will be significant opportunities to invest in attractive projects in the international markets. Based upon our assessment of market opportunities and our portfolio risk management criteria, we intend to leverage our reputation, experience and expertise in order to acquire foreign assets in selected countries. As market opportunities develop, we expect that our international strategy will be consistent with our domestic core market strategy. We believe operating and asset diversity will allow us to reduce business and market risks, while positioning us 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 our international asset portfolio risks, we utilize 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 our board of directors, requires that we manage our entire portfolio of generation capacity to maintain a high quality, weighted average, equivalent country risk. Using this tool, we are able to monitor the exposure we are taking in emerging markets to ensure an appropriate balance of our asset portfolio. We are presently focusing our international development in the United Kingdom, Central Europe, Turkey, Australia and, to a lesser extent, Latin America. In the future, we will continue to focus on other areas that are consistent with our strategy. We expect to acquire or develop most international projects on a joint venture basis to enable us to share the risks associated with the acquisition and development of larger projects. Joint acquisition and development of future projects also should further reduce our financial risk by allowing us to build a more diversified portfolio of projects. Where appropriate, we will include a local or host country partner or a partner with substantial experience in the area. By doing so, we expect to gain a number of advantages, including technical expertise, greater knowledge of and experience with the political, economic, cultural and social conditions and commercial practices of the region or country where the project is being developed, and the ability to leverage our skilled personnel and financial resources. Among other things, a local partner may also assist in obtaining financing from local capital markets, building political and community support for the project and obtaining local regulatory approvals. HOW WE SELL OUR GENERATING CAPACITY AND ENERGY A facility's revenue under a power purchase agreement usually consists of two payments: energy and capacity. Energy payments, which are intended to cover the variable costs of electric generation, such as fuel costs and variable operation and maintenance expense, are normally based on a facility's net electrical output measured in kilowatt hours, with payment rates either fixed or indexed to fuel costs. Capacity payments, which are generally intended to provide funds for the fixed costs incurred by the project affiliate, such as debt service on the project financing and an equity return, are normally calculated based on the net electrical output or the declared capacity of a facility and its availability. Our operating revenues are derived primarily from the sale of electrical energy, capacity and other energy products from our 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 to 9 years); and - "transition" power purchase agreements with the former owners of acquired facilities (generally 3-5 years). 34

39 - 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. Our objective is to mitigate variability in our earnings by having approximately 40-70% of our capacity contracted for under contracts greater than one year, generally seeking to enter into contracts with lengths of 1-5 years, selling half of our remaining capacity in the forward market for 30-365 days, and selling the other half of our remaining capacity in the spot market to capture opportunities in the market when prices are higher. By following this strategy, we seek to achieve positive, stable returns while retaining the flexibility to capture premium returns when available. We derived approximately 36% of our 1999 revenues from two customers: Consolidated Edison Company of New York (17%) and Niagara Mohawk Power Corporation (19%). We sell energy and capacity to these customers under transition agreements expiring in 2002 and 2003, respectively. POWER MARKETING AND FUEL PROCUREMENT Our energy marketing subsidiary, NRG Power Marketing, Inc., was formed in 1997 to maximize the utilization of and return from our generation assets and to mitigate the risks associated with those assets. This group markets energy and energy related commodities, including electricity, natural gas, oil, coal and emissions allowances. By using internal resources to acquire fuel for and to market electricity generated by our domestic facilities, we believe we can secure the best pricing available in the markets in which we sell power and enhance our ability to compete. NRG Power Marketing provides a full range of energy management services for our wholly-owned generation facilities in our Northeast and South 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 sales of fuels and emissions allowances needed to operate these facilities. We operate within strict limits, selling only our available capacity and not engaging in any speculative activity by selling in excess of what we reasonably believe our facilities are capable of producing or will produce. The overall objective of our power marketing activities is to achieve an appropriate rate of return on our generation asset portfolio without taking on any undue risks. In order to achieve our objectives, we have assembled an experienced team. NRG Power Marketing managerial employees have an average of 6-7 years of power marketing or similar trading experience. In addition, we have taken steps to align the interest of the power marketing staff with the overall performance of our generation assets by basing their incentive compensation primarily upon the success and profitability of our generation facilities. In an effort to maximize our returns, we manage our power marketing for our 100% owned domestic assets centrally from our Minneapolis headquarters. We operate a trading floor, from which we monitor power and fuel prices and weather conditions and other factors affecting our business in each of our core markets. For example, we have a Northeast desk to manage power marketing for our Northeast assets. This desk is further divided by the three power pools in that region, namely, the Pennsylvania, New Jersey and Maryland power pool, the New England power pool, and the New York power pool. Although we have entered into a partnership with Dynegy for the marketing of power from our West Coast generation assets, our strategy and overall objectives remain the same. Accordingly, Dynegy is limited to sales that can be covered by the West Coast facilities and cannot enter into any speculative trades and sell more than the available capacity from these facilities. In addition, Dynegy cannot enter into an agreement for longer than a 30-day period without our approval. In Europe, our first project not covered by long-term agreements is Killingholme. Our strategy in Europe is similar to our strategy in the United States and a regional desk has been established in the United Kingdom and a central trading floor will be established as we continue to grow in Europe. 35

40 NRG Power Marketing handles fuel procurement and trading of emissions allowances in order to support our overall needs. Generally we seek to hedge prices for 50% to 70% of our expected fuel requirements during the succeeding 12 to 24 month period. This provides us with certainty as to a portion of our fuel costs while allowing us to maintain flexibility to address lower than expected dispatch rates and to take advantage of the dual fuel capabilities at many of our 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. The members of the NRG Power Marketing board of directors are our Chairman and Chief Executive Officer, Senior Vice President -- North America, and our General Counsel. The NRG Power Marketing board reports monthly to our Financial Risk Management Committee, which consists of our Chief Financial Officer, Treasurer, Controller, Senior Vice President -- North America and Northern States Power's Treasurer. The trading authority of each of our power marketing employees is determined by the position they hold. For example, contract administrators and fuel managers are limited to forward positions of up to one month, with a risk limit of $350,000. Transactions that would exceed these limits must receive varying levels of advance approvals. Transactions with a term of over one year and a risk greater than $1,250,000 need to be approved by the NRG Power Marketing board. Our risk management guidelines also require that our treasury department perform a credit review, and approve all counterparties, prior to the entering into transactions with such counterparties. Our risk management guidelines also require that our treasury department approves in advance credit limits for all counterparties. That is, all transactions are 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. PLANT OPERATIONS Our success depends on our ability to achieve operational efficiencies and high availability at our generation facilities. In the new merchant 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, and our operations and maintenance practices are designed to achieve these goals. Accordingly, we place a high level of importance on maximizing the operational performance and availability of our generation assets. Our availability goals are not driven by traditional benchmarks, such as daily or annual availability, but are focused on each facility's availability during periods when power prices are significantly above the variable cost of producing power at that facility -- what we call "in-market" availability. Our overall corporate strategy of establishing a top three presence in certain core markets is in part driven by our operational strategy. While our approach to plant management emphasizes the operational autonomy of our individual plant managers and staff to identify and resolve operations and maintenance issues at their respective facilities, we are also implementing a regional shared practices system in order to facilitate the exchange of information and best practices among the plants in our various regions. We have organized our operations geographically such that inventories, maintenance, backup and other operational functions are pooled within a region. This approach enables us to realize cost savings and enhances our ability to meet our facility availability goals. Plant supervisors and staff within core markets and across our 36

41 company typically participate in weekly conference calls in order to discuss operational issues and share best practices. We have a long track record of excellence in operating a diverse portfolio of generation assets. We currently operate and maintain approximately 17,600 MW of generating capacity, approximately 9,500 MW which we do not wholly own. We are establishing a compensation and incentive program to motivate our operations staff to realize operational efficiency and in-market availability goals. In the short time since we have closed our most recent acquisitions in the northeastern United States, we have been successful in increasing the efficiency and availability of most of these facilities while at the same time reducing the number of staff required to operate such facilities. An example of our successful operating performance is our Gladstone facility. Although we only own 37.5% of Gladstone, we are the sole operator of this facility and receive an annual operating fee and an operating performance bonus for achieving plant availability targets. We have earned performance bonuses for each year since the privatization of the Gladstone facility in March 1994. At facilities where we are an equity holder, but do not have operational responsibility, we typically require that we have a seat on a management committee or an operational committee. Through these positions, we are able to be kept abreast of plant status, pose questions and receive timely responses on pressing operations issues. At various times, we have used our technical personnel or we have contracted to use Northern States Power's personnel to provide consulting assistance for these projects. Finally, safety is a key area of concern to us. We believe that the most efficient and profitable performance of our facilities can only be accomplished within a safe working environment for our employees. Our compensation and incentive program includes safety as a key factor in evaluating our employees, and we have a well-developed reporting system to track safety and environmental incidents at our facilities. MANAGEMENT, ORGANIZATIONAL AND CORPORATE DEVELOPMENT STAFF STRUCTURE We have established three major corporate regions, North America, Europe and Australia, and have placed senior vice presidents in charge of each. Further, we have subdivided the North American and European generation business regions as follows: the North American business into Northeast, South Central and West Coast regions and the European business into the United Kingdom and Central Europe regions. The senior vice presidents and regional staff of each of these regions are responsible for the full spectrum of development activities as well as responsibility for asset optimization within each region. Our regional structure promotes market expertise and knowledge within our core markets. Each regional team carefully evaluates greenfield and acquisition opportunities against risk and return guidelines determined by management. Ten years of development experience have resulted in thorough and efficient due diligence procedures, whereby our cross-functional teams focus on the particular issues that are most critical to each project under consideration. If an opportunity meets the requirements of the regional management team and will strengthen our regional portfolio, our senior management must review the project before it is presented to our board of directors. INDEPENDENT POWER GENERATION PROJECTS -- DOMESTIC Most of our domestic projects are grouped under three regional holding companies corresponding to our domestic core markets. In order to better manage our domestic projects and to more effectively develop new projects in these regions, we have recently established regional offices in Pittsburgh, Pennsylvania (Northeast region), Baton Rouge, Louisiana (South Central region) and San Diego, California (West Coast region). Upon the completion of the Conectiv asset acquisition, it is expected that the assets will be grouped into a new Mid-Atlantic region. We intend our generation facilities within each region to be operated as a separate business. This regional portfolio structure will allow us to coordinate the operations of our assets to take advantage of 37

42 regional opportunities, reduce risks related to outages, whether planned or unplanned, and pursue expansion plans on a regional basis. NORTHEAST REGION We own approximately 7,100 MW of generation capacity in the Northeast United States in New York, New Jersey, Connecticut, Massachusetts and Pennsylvania. These generation facilities are well diversified in terms of dispatch level (baseload, intermediate and peaking), fuel source (coal, natural gas and oil) and customers. In addition, we believe certain of our facilities and facility sites in the Northeast provide opportunities for repowering or expansion of existing generating capacity. Our 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 and New England Power Pool. For example, the Arthur Kill and Astoria gas turbine facilities are located in the New York City in-city market and represent approximately 20% of the installed capacity inside this transmission constrained area. Load serving entities in the New York City in-city market must currently contract for 80% of their requirements from in-city resources. We believe there is presently limited potential to construct new in-city generation capacity or to gain transmission access to other generating capacity. We currently sell a portion of the energy and capacity generated by our assets in the Northeast region into the New York Power Pool. The independent system operator for the New York Power Pool has recently imposed price limitations on certain ancillary services sold in this market. We have joined several other independent power producers in New York in filing a claim with FERC challenging the independent system operator's actions. If this claim is unsuccessful, our revenues from ancillary services sold in the New York Power Pool could be substantially reduced. To achieve financing, cost and administrative advantages we have pooled our 100% owned Northeast generation assets into a regional holding company, NRG Northeast Generating LLC. Through NRG Northeast Generating, we financed a significant portion of the purchase prices for the separate acquisitions of these generation facilities by means of a $750 million debt financing, which was completed in February 2000. Through our ownership of 20% of Cogeneration Corporation of America, our Northeast assets also include several small, indirectly held, interests in facilities located in New York, New Jersey and Pennsylvania. 38

43 The following table summarizes our Northeast generation facilities: OUR OUR NET TOTAL OWNERSHIP INTEREST NAME AND LOCATION OF FACILITY PURCHASER/POWER MARKET MW INTEREST (MW) FUEL TYPE - ----------------------------- ---------------------- -------- --------- -------- --------- Oswego, New York...................... NIMO/NYISO 1,700 100.00% 1,700 Oil/Gas Huntley, New York..................... NIMO/NYISO 760 100.00% 760 Coal Dunkirk, New York..................... NIMO/NYISO 600 100.00% 600 Coal Arthur Kill, New York................. Con Ed/NYISO 842 100.00% 842 Gas Astoria Gas Turbines, New York........ Con Ed/NYISO 614 100.00% 614 Gas Somerset, Massachusetts(1)............ EUA/NEPOOL/ISO-NE 229 100.00% 229 Coal/Jet Fuel Middletown, Connecticut............... NEPOOL/NYPP/ISO-NE 856 100.00% 856 Oil/Gas/Jet Fuel Montville, Connecticut................ NEPOOL/NYPP/ISO-NE 498 100.00% 498 Gas/Oil Norwalk, Connecticut.................. NEPOOL/NYPP/ISO-NE 353 100.00% 353 Oil Devon, Connecticut.................... NEPOOL/NYPP/ISO-NE 401 100.00% 401 Gas/Jet Fuel Connecticut Jet Power, Connecticut.... NEPOOL/NYPP/ISO-NE 127 100.00% 127 Oil CogenAmerica (Grays Ferry), Penn...... PECO Energy 150 10.00% 15 Gas/Oil CogenAmerica (Parlin), New Jersey..... Jersey Central Power & Light 122 20.00% 24 Gas/Oil CogenAmerica (Newark), New Jersey..... Jersey Central Power & Light 54 20.00% 11 Gas/Oil Other(2).............................. Various 296 Various 69 Various ----- ----- Total............................... 7,602 7,099 ===== ===== - --------------- (1) Includes 69 MW of deactivated reserve. (2) Includes 69 MW of net equity interests in seven projects. The following generation facilities were purchased together in bundled transactions: - Astoria and Arthur Kill facilities for $505 million; - Huntley and Dunkirk facilities for $355 million; and - Middletown, Montville, Norwalk, Devon, and Connecticut jet facilities for $519 million. The purchase prices for each of the facilities set forth below, other than the Oswego and Somerset facilities, reflects an allocation of the purchase price paid in the bundled transaction in which it was acquired. Oswego Facility. The Oswego facility was acquired from Niagara Mohawk Power Corporation and Rochester Gas & Electric Company in October 1999 for a purchase price of $84.9 million. The Oswego facility, located in Oswego, New York, is a natural gas/oil-fired, peaking plant consisting of two units with a total capacity of 1,700 MW. The Oswego facility is currently a source of excess emission allowances that can be utilized at other facilities. We expect to operate this facility as a peaking facility. In connection with this acquisition, we entered into a four year transition power purchase agreement with Niagara Mohawk Power under which we agreed to sell to Niagara Mohawk Power 100% of the capacity of one unit, an option for up to 40% of the capacity of the second unit, and an option to purchase a nominal amount of energy from both units. Huntley Facility. The Huntley facility was acquired from Niagara Mohawk Power in June 1999 for a purchase price of $155.7 million. The Huntley facility, located near Buffalo, New York, is a coal-fired, base-load facility consisting of six units with a total capacity of 760 MW. The Huntley facility is among the lowest cost fossil fuel plants that sell into the New York Power Pool. We plan to operate it as a base-load facility. In connection with the acquisition of this facility, we entered into four-year transition power purchase agreements under which we agreed to sell to Niagara Mohawk Power 100% of the capacity of, and an option to purchase up to 45% of the annual energy output from, certain units of the Huntley facility. 39

44 Dunkirk Facility. The Dunkirk facility was acquired from Niagara Mohawk Power in June 1999 for a purchase price of $199.3 million. The Dunkirk facility, located in Dunkirk, New York, is a coal-fired, base-load facility consisting of four units with a total capacity of 600 MW. The Dunkirk facility is among the lowest variable cost fossil fuel plants that sell into the New York Power Pool. We plan to operate it as a base-load facility. In connection with the acquisition of this facility, we entered into four-year transition power purchase agreements under which we agreed to sell to Niagara Mohawk Power 100% of the capacity of, and an option to purchase up to 39% of the annual energy output from, the Dunkirk facility. Arthur Kill Facility. The Arthur Kill facility was acquired from Consolidated Edison Company of New York, Inc. in June 1999 for a purchase price of $395.6 million. The Arthur Kill facility, located in Staten Island, New York, is a natural gas/oil-fired, intermediate/peaking plant consisting of three units with a total capacity of 842 MW. Astoria Facility. The Astoria facility was acquired from Consolidated Edison in June 1999 for a purchase price of $109.5 million. The Astoria facility, located in Queens, New York, is a gas/liquid fuel-fired, peaking plant consisting of 11 units with a total capacity of 614 MW. In connection with the acquisition of the Arthur Kill and the Astoria facilities, we entered into transition capacity sales agreements under which we agreed to sell to Consolidated Edison at a fixed price, during certain periods, up to 100% of the capacity of each of the Arthur Kill and Astoria facilities for a transition period ending on the later of (a) the earlier of (i) December 31, 2002 or (ii) the date such facility receives notice from the independent system operator in New York State that none of the electric generation capacity of such facility is required for meeting the installed capacity requirements in New York City, or (b) the end of the capability period immediately preceding the capability period covered by the first auction for capacity sponsored by the independent system operator in New York State. Somerset Facility. The Somerset facility was acquired from Montaup Electric Company, an affiliate of Eastern Utilities Associates, in April 1999 for a purchase price of $55.2 million. The Somerset facility, located in Somerset, Massachusetts, is an oil/coal-fired, base-load/peaking facility consisting of three units with a total capacity of 229 MW (160 MW of which is currently operational). The Somerset facility provides low variable cost capacity, strategically positioned to sell power into the New England Power Pool. We intend to operate this facility as a peaking and base-load facility, depending on market conditions. In connection with this acquisition, we also entered into a wholesale standard offer service agreement under which we are obligated to provide approximately 30% of the energy and capacity requirements of certain affiliates of Eastern Utilities Associates, which we estimate to be approximately 275 MW at peak requirement, until December 31, 2009. The difference between this service requirement and our operational capacity at Somerset is made up by a combination of power supplied by our other Northeast facilities and purchased power. Connecticut Facilities In connection with the acquisition of the Middletown, Montville, Norwalk, Devon, and Connecticut Jet facilities from Connecticut Light & Power, we entered into a four-year standard offer service wholesale sales agreement with Connecticut Light & Power pursuant to which we will supply to Connecticut Light & Power at fixed prices a portion of Connecticut Light & Power's aggregate retail load. The quantity of power to be supplied is equal to 35% of Connecticut Light & Power's standard offer service load during calendar year 2000, 40% during calendar years 2001 and 2002, and 45% during calendar year 2003. We estimate that 45% of Connecticut Light & Power's standard offer service load in 2003 will be approximately 2,000 MW at peak requirement. The agreement terminates on December 31, 2003. We believe the Connecticut facilities are strategically positioned for sales into the New England Power Pool and have a competitive advantage on transmission charges; we will operate these facilities as peaking and intermediate facilities to take advantage of market volatility. Middletown Facility. The Middletown facility was acquired from Connecticut Light & Power Company in December 1999 for a purchase price of $92.5 million. The Middletown facility, located in 40

45 Middetown, Connecticut, is a natural gas/oil-fired intermediate/peaking plant consisting of four units with a total capacity of 856 MW. Montville Facility. The Montville facility was acquired from Connecticut Light & Power in December 1999 for a purchase price of $216.2 million. The Montville facility, located in Uncasville, Connecticut, is a natural gas/oil-fired intermediate/peaking load plant consisting of four units with a total capacity of 498 MW. Norwalk Facility. The Norwalk facility was acquired from Connecticut Light & Power in December 1999 for a purchase price of $75.0 million. The Norwalk facility, located in Norwalk, Connecticut, is an oil-fired, intermediate/peaking load plant consisting of three units with a total capacity of 353 MW. Devon Facility. The Devon facility was acquired from Connecticut Light & Power in December 1999 for a purchase price of $113.3 million. The Devon facility, located in Milford, Connecticut, is a natural gas/oil-fired, intermediate/peaking load facility consisting of seven units with a total capacity of 401 MW. Connecticut Jet Facilities. These six combustion turbine facilities were acquired from Connecticut Light & Power in December 1999 for a purchase price of $22.3 million. These facilities, located in Branford, Torrington Terminal, Franklin Drive and Cos Cob, Connecticut, are oil-fired, peaking units consisting of six units with a total capacity of 127 MW. SOUTH CENTRAL UNITED STATES REGION We own approximately 1,888 MW of generation capacity in the South Central United States, primarily in Louisiana. Our South Central generation assets consist primarily of our net ownership of 1,708 MW power generation facilities in New Roads, Louisiana that we acquired in March 2000 as a result of a competitive bidding process following a Chapter 11 bankruptcy. We refer to these facilities as the Cajun facilities. We believe that the Cajun facilities and infrastructure provide significant opportunities for expanding our generation capacity in the region. We intend to further augment our recent acquisition of the Cajun facilities in Louisiana with additional projects in the area. To achieve financing, cost and administrative advantages we formed a regional holding company, NRG South Central Generating LLC, to hold our ownership interest in Louisiana Generating LLC, the owner of the Cajun facilities. Through NRG South Central Generating, we financed a significant portion of the purchase price for the Cajun facilities by means of a $800 million debt financing completed in March 2000. Through our ownership of 20% of Cogeneration Corporation of America, our South Central assets also include two small, indirectly held, interests in facilities located in Oklahoma and Illinois. 41

46 The following table summarizes our South Central generation facilities: OUR OUR NET TOTAL OWNERSHIP INTEREST NAME AND LOCATION OF FACILITY PURCHASER/POWER MARKET MW INTEREST (MW) FUEL TYPE - ----------------------------- ---------------------- ----- --------- -------- --------- Big Cajun I, Louisiana Unit 1................................... Cooperatives/Municipals 110 100.00% 110 Gas Unit 2................................... Cooperatives/Municipals 110 100.00% 110 Gas Big Cajun II, Louisiana Unit 1................................... Cooperatives/Municipals 575 100.00% 575 Coal Unit 2................................... Cooperatives/Municipals 575 100.00% 575 Coal Unit 3................................... Cooperatives/Municipals 575 58.00% 338 Coal Sterlington, Louisiana(1).................. Various 200 100.00% 200 Gas Rocky Road Power, Illinois(2).............. ECAR/MAIN 350 50.00% 175 Gas Other(3)................................... Various 337 Various 55 Various ----- ----- Total.................................. 2,832 2,138 ===== ===== - --------------- (1) Under construction, expected to be phased into service between June and December 2000. (2) Includes 100 MW expected to be in service June 2000. (3) Includes 55 MW of net equity interests in three facilities. Cajun Facilities. The Cajun facilities were acquired in a competitive bidding process following a Chapter 11 bankruptcy filing by their former owner, Cajun Electric Power Cooperative, Inc. We paid approximately $1,026 million for these facilities. The Cajun facilities consist of 100% of two gas-fired, intermediate/peaking electric generation units with a total capacity of 220 MW, which we collectively refer to as "Big Cajun I," and two coal fired, baseload power generation units with a total capacity of 1,150 MW and a 58% interest in a third coal-fired, baseload unit with a total capacity of 575 MW, which we collectively refer to as "Big Cajun II." The Cajun facilities have benefited from an extensive maintenance program over their history and from capital expenditures in excess of $26 million from 1997 through 1999 while under the stewardship of Cajun Electric's bankruptcy trustee. We believe the bankruptcy resulted from Cajun Electric's inability to service approximately $4,200 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 I, a nuclear electric generating 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. We have no ownership interest in the River Bend nuclear facility or responsibility for any indebtedness of Cajun Electric to the Rural Utilities Service or otherwise. We sell 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 us, and four have entered into two to four year power purchase agreements. In addition, we sell power under contract to two municipal power authorities and one investor-owned utility that were former customers of Cajun Electric. We estimate that payments under the contracts with the 11 cooperatives will account for approximately 72% of the Cajun facility's projected 2001 revenues, and that payments under the contracts with the municipal power authorities and the investor-owned utility will account for approximately 7% of such revenues. Rocky Road Facility. We acquired a 50% interest in the Rocky Road facility from Dynegy in December 1999 for a purchase price of approximately $60.0 million. The Rocky Road facility, located in East Dundee, Illinois, is a gas-fired, peaking facility consisting of two units with a total capacity of 250 MW. The facility began commercial operations in June 1999 and received approval for the installation of an additional 100 MW natural gas combustion turbine in October 1999. The expansion is expected to be in service before the start of the peak summer 2000 season. This facility is a merchant facility that sells energy into the ECAR and MAIN markets. 42

47 Sterlington Facility. The Sterlington facility is a 200 MW simple cycle gas-fired peaking facility under construction in Sterlington, Louisiana. Commercial operations are expected to be phased in between June and December 2000. We anticipate that the facility will sell power into five nearby power pools. WEST COAST REGION We own approximately 1,603 MW of generating capacity on the West Coast of the United States. Our West Coast generation assets consist primarily of a 50% interest in West Coast Power LLC and a 58% interest in the Crockett Cogeneration facility. In May 1999, we and Dynegy formed West Coast Power to serve as the holding company for a portfolio of operating companies which own generation 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. We believe certain of our facilities and facility sites on the West Coast provide opportunities for repowering or expansion of generating capacity. We and Dynegy intend to utilize West Coast Power as a growth vehicle through which future investments in assets serving the California power market will be held. We believe that West Coast Power will benefit from synergies and economies of scale through a common management structure, and that it has an attractive mixture of revenue sources, including merchant and, as described below, "must-run" plants. In addition, West Coast Power has power marketing flexibility, in which a power shortage in one unit or plant can be compensated with excess power from another unit. Dynegy is providing power marketing services to West Coast Power. In June 1999, West Coast Power financed a significant portion of the purchase price for its assets with a 5-year, $362.5 million limited-recourse bank facility secured by the limited liability company interests and project assets of the El Segundo, Long Beach and Encina facilities and the San Diego combustion turbines. The Encina facility and the San Diego combustion turbines are currently subject to "Reliability Must-Run" agreements with the California independent system operator. These must-run agreements take the form of a call option contract under which the California independent system operator will pay a fixed capacity payment for the right to dispatch the unit, and variable costs are passed through at cost. We, however, retain the right to participate in any energy or ancillary services markets prior to being dispatched as a must-run unit. Must-run agreements with the California independent system operator are intended to mitigate regional market power and make up for inadequate power supplies in a specific area. The must-run agreements require us to provide power and ancillary services when requested by the California independent system operator. The must-run agreements have a one-year term, which the California independent system operator may extend indefinitely for additional one-year periods. We estimate that payment made under must-run contracts will account for approximately 17% to 21% of the revenues from projects owned by West Coast Power. The following table summarizes our West Coast generation facilities: OUR OUR NET TOTAL OWNERSHIP INTEREST NAME AND LOCATION OF FACILITY PURCHASER/POWER MARKET MW INTEREST (MW) FUEL TYPE - ----------------------------- ---------------------- ------ --------- -------- --------- El Segundo Power, California................. Cal PX 1,020 50.00% 510 Gas Encina, California........................... Cal PX/Must-run 965 50.00% 482 Gas Long Beach Generating, California............ Cal PX 530 50.00% 265 Gas San Diego Combustion Turbines, California.... Cal PX/Must-run 253 50.00% 127 Gas Crockett Cogeneration, California............ PG&E 240 57.67% 138 Gas Mt. Poso Cogeneration, California............ PG&E; 50 39.10% 19 Coal Other(1)..................................... Various 93 Various 62 Various ------ ----- Total........................................ 3,151 1,603 ====== ===== - --------------- (1) Includes our net equity interests in three small facilities. 43

48 El Segundo Generating Facility. The El Segundo facility was acquired from Southern California Edison Company in April 1998 for a purchase price of $87.7 million. The El Segundo facility, located in El Segundo, California, is a gas-fired, intermediate facility consisting of four units with a total capacity of 1,020 MW. The El Segundo facility sells electricity through the California power exchange. Encina Generating Facility. The Encina facility was acquired from San Diego Gas & Electric in May 1999 for a purchase price of $290.5 million. The Encina facility, located in Carlsbad, California, is a gas-fired, intermediate/peaking facility consisting of six units with a total capacity of 965 MW. The Encina facility sells electricity through the California power exchange and under must-run agreements. Long Beach Generating Facility. The Long Beach facility was acquired from Southern California Edison in March 1998 for a purchase price of $29.8 million. The Long Beach facility, located in Long Beach, California, is a gas-fired, peaking facility consisting of nine units with a total capacity of 530 MW. The Long Beach facility sells peak electricity and ancillary services through the California power exchange. San Diego Combustion Turbines. The San Diego combustion turbines were acquired from San Diego Gas & Electric in May 1999 for a purchase price of $69.1 million. The San Diego combustion turbines, located on seven different sites in San Diego County, California, consist of 17 combustion turbines with a total capacity of 253 MW. The combustion turbines have the ability to provide spinning reserve, black start capability, quick start capability, voltage support and quick load capability for the ancillary services market. The combustion turbines sell electricity through the California power exchange and under must-run agreements. Crockett Cogeneration Facility. We own a 58% interest in the Crockett cogeneration facility located in Crockett, California on the San Francisco Bay. We acquired our interest in November 1997 for $46.4 million. The Crockett facility is a gas-fired facility with a total capacity of 240 MW. This facility supplies all of the refinery steam needs of the adjacent C&H Sugar Company refinery and sells capacity and energy under a modified, interim standard offer power sales agreement to Pacific Gas & Electric Company, which expires in May 2026. Mt. Poso Cogeneration Facility. We own a 39% interest in the Mt. Poso cogeneration facility located near Bakersfield, California. We acquired an initial 22% interest in November 1997 for $14.3 million and our remaining interest in June 1998 for $4.7 million. The Mt. Poso facility is a coal-fired, facility with a total capacity of 50 MW. The facility sells steam to an adjacent oil field owned by the project company and the capacity and energy are sold under a long-term, interim standard offer power sales agreement to Pacific Gas & Electric, which expires in May 2019. PENDING MID-ATLANTIC ACQUISITIONS In January 2000, we executed purchase agreements with subsidiaries of Conectiv to acquire 1,875 MW of coal, gas and oil-fired electric generating capacity and other assets. We will pay approximately $800 million for the assets, a portion of which will be financed by project-level debt. The assets include the BL England and Deepwater facilities in New Jersey, the Indian River facility in Delaware and the Vienna facility in Maryland, and interests in the Conemaugh (7.6%) and Keystone (6.2%) facilities in Pennsylvania. The purchase also includes excess emissions allowances. Subject to receipt of required regulatory approvals, we expect the acquisition to close in the fourth quarter of 2000. 44

49 Subject to final documentation, we will sell 500 MW of capacity and associated energy to a subsidiary of Conectiv under a five-year power purchase agreement commencing upon the closing of the acquisition. OUR OUR NET TOTAL OWNERSHIP INTEREST NAME AND LOCATION OF FACILITY PURCHASER/POWER MARKET MW INTEREST (MW) FUEL TYPE - ----------------------------- ---------------------- ------ --------- -------- --------- BL England, New Jersey................... Conectiv/PJM 447 100.00% 447 Coal/Oil Deepwater, New Jersey.................... Conectiv/PJM 239 100.00% 239 Gas/Coal/Oil Indian River, Delaware................... Conectiv/PJM 784 100.00% 784 Coal Vienna, Maryland......................... Conectiv/PJM 170 100.00% 170 Oil Conemaugh, Pennsylvania.................. Conectiv/PJM 1,711 7.55% 129 Coal Keystone, Pennsylvania................... Conectiv/PJM 1,711 6.17% 106 Coal ----- ----- Total.................................. 5,062 1,875 ===== ===== DOMESTIC DEVELOPMENT We are currently pursuing a number of development projects in our core domestic markets. We have recently agreed to purchase 16 turbine generators from GE Power Systems and two turbine generators from Siemens Westinghouse over a six year period commencing in 2001. These new turbines, which we expect to install at domestic facilities, will have a combined capacity of approximately 3,300 MW. Our development activities in the United States also include greenfield opportunities. With our partners, Salt River Project and Dynegy, we announced plans to develop an 825 MW gas-fired, combined-cycle generation facility to serve the growing demand for electricity in the greater Phoenix area. Final negotiations on project agreements are in progress and site permitting has begun. INDEPENDENT POWER GENERATION PROJECTS- INTERNATIONAL AUSTRALIA We are the largest independent power producer in Australia with a net ownership interest of 1,312 MW. We intend to maintain our position in the market through additional acquisitions and development of new projects. We will also look for opportunities in selected countries in the Asia Pacific region to become established within the region. The following table summarizes our Australian assets: OUR OUR NET POWER MARKET/ TOTAL OWNERSHIP INTEREST NAME AND LOCATION OF FACILITY PURCHASER MW INTEREST (MW) FUEL TYPE - ----------------------------- ------------- ------ --------- -------- --------- Gladstone Power Station (Queensland), Australia............................... QPTC; Boyne Smelter 1,680 37.50% 630 Coal Loy Yang Power A (Victoria), Australia.... Victorian Pool 2,000 25.37% 507 Coal Collinsville (Collinsville), Australia.... QPTC 192 50.00% 96 Coal Energy Developments Limited (Various), Australia............................... Various 274 29.14% 79 LFG/Methane ----- ----- Total................................... 4,146 1,312 ===== ===== Gladstone Facility. The Gladstone facility is a 1,680 MW coal-fired power generation facility located in Gladstone, Australia. We acquired a 37.5% ownership interest in the Gladstone facility for $64.4 million when the facility was privatized in March 1994. We are responsible for 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. 45

50 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, the facility owners are paid both a capacity and an energy charge by Queensland Power. 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. A capacity bonus is also available if the equivalent availability factor exceeds 88% on a 24 month rolling average basis, and damages are payable by the project's owners if it is less than 82% on that same basis. As of December 31, 1999, the two-year average equivalent availability factor was 87.7%. The 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 owner 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 owner of Boyne Smelters is also obligated to pay an energy charge based on the fuel cost associated with the production of energy from the Gladstone facility. Expansion at Boyne Smelters resulted in an increase in capacity utilization from approximately 41% in 1994 to 60% in 1999. We anticipate that the capacity utilization will increase to approximately 64% in 2000. Recent reforms to the Queensland electricity industry arising from the introduction of the National Electricity Market have changed the regulatory framework in which the Gladstone facility operates. In particular, the existing arrangements relating to the commitment and dispatch of the facility and the supply of power to customers of the facility no longer accord with the mechanisms for buying and selling electricity in Queensland. As a result, Queensland Power and the other parties to the project agreements have entered into negotiations to alter the agreements to accomplish two goals: (1) compliance with the new framework arising from the introduction of the National Electricity Market, while ensuring that the actual operator of the power station is similar to that under the existing agreements and (2) preservation, to the extent possible, of the commercial positions of all parties. We expect amended agreements to be finalized and signed by the end of calendar year 2000 and we believe that any amended agreements will have no impact on the risk profile or financial performance of the Gladstone facility. Effective December 9, 1999, the Australian government reduced the corporate income tax rate. This reduction of Australian corporate income tax rates resulted in an increase in our net income related to this facility of $3.9 million for 1999. Loy Yang Facility. We have 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 AUS$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. 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 46

51 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. They establish a "strike price" for a certain volume of electricity purchased by the user during a specified period; differences between that "strike price" and the actual price set by the pool give rise to "difference payments" between the parties at the end of the period. Even if Loy Yang is producing less than its contracted quantity it will still be required to make and will be entitled to receive difference payments for the amounts set forth in its contracts for differences. Loy Yang also has contracts with the Victorian distribution companies in respect of regulated customer load. These contracts, called "vesting contracts," account for approximately 64% of Loy Yang's forecasted revenue from generation, and provide some stability in Loy Yang's revenues until all these contracts expire on December 31, 2000. Loy Yang's contracts for differences are generally for a term of one to two years, and the volume of load covered by these contracts will increase as vesting contracts expire. The combination of the contracts for differences and the vesting contracts covered approximately 90% of Loy Yang's load at March 31, 2000. Energy prices in the Victoria, Australia wholesale power market into which our Loy Yang facility sells its power have been significantly lower than we had expected when we acquired our interest in the facility. As a result, the Loy Yang project company is currently prohibited by its loan agreements from making equity distributions to the project owners. Based on our current power price projections, we expect that the Loy Yang project company will fail to meet required coverage ratios under its loan agreements beginning in the third quarter of 2001, which would constitute an event of default. Moreover, if market prices in Victoria continue at current levels (which are below our current power price projections) we expect that the Loy Yang project company will be unable to service its long-term debt obligations beginning in the first quarter of 2002. In either case, absent a restructuring of the project company's debt, the project company's lenders would be allowed to accelerate the project company's indebtedness. We could be required to write-off all or a significant portion of our $250 million investment in this project as a result of such acceleration, a determination by the project company that a write-down of its assets is required or our determination that we would not be able to recover our investment in this project. In February 2000, CMS Energy announced its intention to divest its 49.6% ownership in the Loy Yang project. 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. The remaining partners in the Loy Yang project have rights of first refusal with respect to CMS Energy's sale of its interest. The 1999 reduction of Australian corporate income tax rates described above resulted in a decrease in our net income related to this facility of $3.4 million for 1999. Collinsville Facility. The Collinsville Power Station is a 192 MW coal-fired power generation facility located in Collinsville, Australia. In March 1996, we acquired a 50% ownership interest in the idled Collinsville facility for US$11.9 million when it was privatized by the Queensland State government. The Collinsville facility was recommissioned and commenced operations on August 11, 1998. We and Transfield Holdings Pty Ltd, the project's other 50% owner, 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 Developments Limited. Energy Developments owns and operates approximately 274 MW of generation primarily in Australia. Between February 1997 and April 1998, we acquired a total of 14,609,670 common shares and 16,800,000 convertible, non-voting preference shares of Energy Developments Limited, a publicly traded company listed on the Australian Stock Exchange. We paid a total of approximately AUS$69.1 million (US$44.5 million at the time of acquisition), or AUS$2.20 (US$1.42 per share), for the shares, which represent approximately a 29% ownership interest in Energy Developments. We have agreed to restrictions on our ability to purchase more shares or to dispose of any existing shares of Energy Developments. The preference shares do not become convertible into common 47

52 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. The common shares of Energy Developments traded at AUS$12.35 (approximately US$7.50) per share on March 31, 2000. EUROPE We have been a significant participant in the independent power generation markets in Germany and the Czech Republic since our entry into those markets in 1993. Our growth in Europe was also augmented in early-2000 with the acquisition of the Killingholme facility and the expected mid-2000 commencement of commercial operations at the Enfield facility, both of which are located in the United Kingdom. We intend to continue our growth efforts in these countries and to develop projects in countries such as Poland Estonia and Turkey. The following table summarizes our European assets: OUR OUR NET TOTAL OWNERSHIP INTEREST NAME AND LOCATION OF FACILITY PURCHASER/POWER MARKET MW INTEREST (MW) FUEL TYPE - ----------------------------- ---------------------- ------ --------- -------- --------- Killingholme, UK............................ U.K. Electricity Grid 680 100.00% 680 Gas Enfield, UK................................. U.K. Electricity Grid 396 25.00% 99 Gas Schkopau Power Station, Germany............. VEAG 960 20.95% 200 Coal MIBRAG mbH, Germany......................... WESAG/MIBRAG 110 33.33% 37 Coal MIBRAG mbH, Germany......................... WESAG/MIBRAG 86 33.33% 29 Coal MIBRAG mbH, Germany......................... WESAG/MIBRAG 37 33.33% 12 Coal Kladno, Phase I, Czech Republic............. STE/Industrials 28 44.26% 12 Coal Kladno, Phase II, Czech Republic............ STE/Industrials 345 44.50% 154 Coal/Gas ----- ----- Total..................................... 2,642 1,223 ===== ===== Killingholme Facility. In March 2000, we acquired the 680 MW gas-fired Killingholme combined-cycle, baseload facility in North Lincolnshire, England from National Power plc. The purchase price was L390 million (approximately $615 million at the time of acquisition), subject to post-closing adjustments. We financed the acquisition with a 19-year non-recourse credit facility that provided for L235 million (approximately $370 million) for the costs of the acquisition and L90 million (approximately $142 million) for letters of credit and working capital needs. We are selling power from the facility into the wholesale electricity market of England and Wales, and we intend to enter into short and long term power contracts when we believe it to be advantageous to do so. 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, we entered into a tolling agreement with National Power pursuant to which we received revenues based on the prevailing market prices for electricity in exchange for payments to National Power based on the incremental operating cost of the power station. We anticipate that prices for power in the wholesale electricity market of England and Wales will decrease over the short term due to new trading rules which are expected to come into effect and increased competition in this market. This expected market trend was taken into account when we bid to acquire this facility. In the future, we intend to enter into short- and long-term agreements to sell a portion of the output from the Killingholme facility that will provide a degree of stability to our revenues from the facility. Enfield Facility. We hold a 25% interest in the Enfield Energy Center, a 396 MW gas-fired facility in the North London borough of Enfield, for which our net investment is expected to be approximately $11.2 million. This project was scheduled to commence commercial operation in November 1999, but due to problems in the design and manufacture of the rotors and gas turbines, has been delayed until June 2000. Although the construction contractor is contractually obligated to make certain payments to partially compensate the owners of the project for such delays, the obligation to make such payments in this situation and the amount of such payments are being disputed. Nevertheless, we expect that once the 48

53 project is completed it will function as anticipated, and we do not expect this delay to have a material adverse effect on the operations or financial results of the facility. Schkopau Facility. In 1993, we 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. 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. We receive 50% of the net profits from these VEAG payments through our ownership interest in Saale Energie. MIBRAG. We 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 is 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 1999 was approximately 50 million deutsche marks (approximately US$25 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 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. Kladno Facilities. The Energy Center Kladno project, located in Kladno, the Czech Republic, consists of two distinct phases. In 1994, we 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 a company called Energy Center Kladno, of which we own a 44.26% interest. The expansion project is held separately through ECK Generating, a Czech limited liability company, of which we own a 44.5% interest. 49

54 LATIN AMERICA We have pursued acquisition and development opportunities in Latin America since the early-1990s. Initially, we participated as one of four original sponsors of a private equity investment fund called Latin Power. More recently, we 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"). We plan to selectively target new opportunities in Argentina, Bolivia, Brazil, Chile and Peru, where we believe the more attractive acquisition and greenfield opportunities exist in Latin America. The following table summarizes our Latin American assets: OUR OUR NET TOTAL OWNERSHIP INTEREST NAME AND LOCATION OF FACILITY PURCHASER/POWER MARKET MW INTEREST (MW) FUEL TYPE - ----------------------------- ---------------------- ------ --------- -------- ---------------- COBEE, Bolivia.......................... Electropaz/ELF 219 49.10% 108 Hydro/Gas Bulo Bulo, Bolivia...................... Bolivian Grid 87 30.00% 26 Gas Latin Power Funds, Various.............. Various 772 Various 52 Gas/Coal/Oil/Geo ----- --- Total................................. 1,078 186 ===== === COBEE. In December 1996, we acquired for $81.8 million a 49% interest in COBEE, the second largest generator of electricity in Bolivia. COBEE has entered into an electricity supply contract with Electricidad de La Paz S.A., a Bolivian distribution company ("Electropaz"), which expires in 2008 with Empresa de Luz Fuerza Electrica de Oruro S.A. another Bolivian distribution company. 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. Bulo Bulo Facility. We own a 30% interest in a Bolivian company that will become the owner of the 87 MW gas-fired Bulo Bulo facility located in Carrasco, Bolivia. The Bulo Bulo facility is under construction and is scheduled to enter into commercial operations on May 1, 2000. The Bulo Bulo facility will operate under a 30-year generation license and will sell its power to various customers in Bolivia at market prices established under the rules of the Bolivian national grid. Latin Power Funds. The original Latin Power Fund was formed in 1993 as a vehicle for making equity investments in independent power projects in Latin America and the Caribbean. We invested $28 million in this original fund and have committed $7 million to a similar fund, both of which are managed by Scudder Kemper Investments. To date, these funds have committed a total of approximately $180 million in investments, of which our share is approximately $28 million. INTERNATIONAL DEVELOPMENT In 1999, we and our partners were selected as winning bidder for the 600 MW Seyitomer Power Station and lignite mine in Kuthya, Turkey. Seyitomer is our second successful bid in Turkey. In 1998, also with partners, we won a bid to acquire the 450 MW coal-fired Kangal plant and lignite mine in central Turkey. Our strategy is to build a long-term position in the high-growth energy market in Turkey. In August 1999, the Turkish Parliament amended the Turkish Constitution to allow international arbitration of disputes under concession agreements. The lack of international arbitration for such contracts had been a major stumbling block for many power projects in Turkey, including ours. The Parliament passed additional enabling legislation in January 2000. As a result, our projects, which were delayed 50

55 pending resolution of this issue, are now proceeding toward financial close, which may occur as early as the end of 2000. In December 1996, we signed a development and cooperation agreement with representatives of the Estonian Government and the state-owned utility. The development and cooperation agreement defines the terms under which the parties are to establish a plan to develop and refurbish the Balti and Eesti Power Plants. Pursuant to the development and cooperation agreement, we submitted a business plan to the Estonian government in which we have stated our willingness to invest up to $67.25 million of equity into the project and to assist the joint project in obtaining non-recourse debt to fund the required capital improvements to the Balti and Eesti Power Plants and we are continuing to negotiate a detailed agreement. Because we have a policy of expensing all development costs until there is a signed contract and board of directors' approval, all such costs with respect to Estonia have been expensed. We are currently evaluating additional development opportunities in Australia, Turkey, Europe, and Latin America. In Australia, we are specifically evaluating the privatization of South Australian power stations. In Europe, we and our partners are investigating two projects in Poland, one in Rybnik and the other in Pak. THERMAL ENERGY PRODUCTION AND TRANSMISSION FACILITIES; RESOURCE RECOVERY FACILITIES; LANDFILL GAS FACILITIES In the United States, our businesses in thermal heating and cooling, landfill gas collection related generation and resource recovery continue to be part of our diversified growth and operating strategies. These businesses give us experience in non-traditional energy sources and in environmentally sound energy alternatives. ACQUISITION OUR OWNERSHIP ENERGY PURCHASER/ NAME AND LOCATION OF FACILITY DATE CAPACITY(1) INTEREST MSW SUPPLIER - ----------------------------- ----------- ------------------------------- ------------- --------------------------- Thermal Energy Production and Transmission Facilities Minneapolis Energy Center, Minnesota................. 1993 Steam: 1,408 mmBtu/hr. (413 MW) 100.00% Approximately 90 commercial Chilled water: 40,750 tons/hr. steam customers and 35 (143 MW) commercial chilled water customers San Francisco Thermal LLC, California................ 1995 Steam; 490 mmBtu/hr. (143 MW) 100.00% Approximately 185 customers (Purchased remaining 51%).. 1999 San Diego Power & Cooling, California................ 1997 Chilled Water: 8,000 tons/hr. 100.00% Approximately 15 customers (28 MW) Pittsburgh Thermal LLC, Pennsylvania.............. 1995 Steam; 240 mmBtu/hr. (70 MW) 100.00% Approximately 25 steam customers and 25 chilled water customers (Purchased remaining 51%).................... 1999 Chilled Water; 10,180 tons/hr. (36 MW) Camas Power Boiler, Washington................ 1997 200 mmBtu/hr. (59 MW) 100.00% Fort James Corp. Grand Forks Air Force Base, North Dakota.............. 1992 105 mmBtu/hr. (31 MW) 100.00% Grand Forks Air Force Base Hennepin Co. Energy Center, Minnesota................. NA(2) 290 mmBtu/hr (85 MW) Leased MEC Customers Rock-Tenn, Minnesota........ 1992 Steam: 430 mmBtu/hr. (126 MW) 100.00% Rock-Tenn Company Washco, Minnesota........... 1992 160 mmBtu/hr. (47 MW) 100.00% Andersen Corporation Minnesota Correctional Facility 51

56 ACQUISITION OUR OWNERSHIP ENERGY PURCHASER/ NAME AND LOCATION OF FACILITY DATE CAPACITY(1) INTEREST MSW SUPPLIER - ----------------------------- ----------- ------------------------------- ------------- --------------------------- Energy Center Kladno, Czech Republic.................. 1994 512 mmBtu/hr. (150 MW) 44.26% City of Kladno Resource Recovery Facilities Newport, Minnesota.......... 1993 MSW: 1,500 tons/day 100.00% Ramsey and Washington Counties Elk River, Minnesota........ NA(2) MSW: 1,500 tons/day 0.00% Anoka, Hennepin, and Sherburne Counties; Tri-County Solid Waste Management Commission Penobscot Energy Recovery, Maine..................... 1997 MSW: 800 tons/day 28.71% Bangor Hydroelectric Company Maine Energy Recovery, Maine..................... 1997 MSW: 680 tons/day 16.25% Central Maine Power NEO Corporation............. Various MW: 175 51.43% Various - --------------- (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. Figures shown above are for 100% of each facility. (2) We operate these facilities on behalf of Northern States Power. Minneapolis Energy Center. Minneapolis Energy Center provides steam to approximately 90 customers and chilled water to approximately 35 customers in downtown Minneapolis, Minnesota. Minneapolis Energy Center provides steam and chilled water to its customers pursuant to energy supply agreements, which expire at varying dates from August 2000 to December 2019. Historically, Minneapolis Energy Center has renewed its energy supply agreements as they near expiration. With minor exceptions, these agreements are standard form contracts providing for a uniform rate structure consisting of three components: a demand charge designed to recover fixed capital costs, a consumption charge designed to provide a per unit margin, and an operating charge designed to pass through to customers all fuel, labor, maintenance, electricity and other operating costs. The demand and consumption charges are adjusted in accordance with the Consumer Price Index every five years. North American Thermal Systems. We own 100% of North American Thermal System, which holds the operating assets of the San Francisco, California and Pittsburgh, Pennsylvania district heating and cooling operations. The San Francisco thermal system has approximately 185 customers. The Pittsburgh thermal system has approximately 25 steam customers and 25 chilled water customers. Rock-Tenn Facility. The Rock-Tenn process steam operation consists of a five-mile closed-loop steam/condensate line that delivers steam to the Rock-Tenn Company, a paper manufacturer in St. Paul, Minnesota. Rock-Tenn has a peak steam capacity of 430 mmBtus per hour (126 MW equivalent). As a result of the settlement of a 1987 dispute between the Rock-Tenn Company and a previous owner of the steam operation, the Rock-Tenn Company prepaid revenues for future steam service. As of December 31, 1999, deferred revenues remaining were approximately $2.0 million. NEO Corporation. NEO Corporation is a wholly-owned subsidiary of ours 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 30 landfill gas collection systems and has 55 MW of net ownership interests in related electric generation facilities. As of March 31, 2000, NEO's investment in these projects totaled $70.7 million and loans to fund development, construction and start-up amounted to $26.9 million. NEO also has 35 MW of net ownership interests in 18 small hydroelectric facilities. NEO derives a substantial portion of its income as a result of the generation of Section 29 tax credits, which for 1999 totaled $20.4 million. The existing tax law authorizing these credits is scheduled to expire in 2007. Resource Recovery Facilities. Our 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 52

57 Red Wing and Mankato, Minnesota. This facility, which was originally constructed and operated by Northern States Power, was transferred to us in 1993. Pursuant to service agreements with Ramsey and Washington Counties, which expire in 2007, we process a minimum of 280,800 tons of municipal solid waste per year at the Newport facility and receive service fees based on the amount of waste processed, pass-through costs and certain other factors. We are also entitled to an operation and maintenance fee, which is designed to recover fixed costs and to provide us 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, we have 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. Northern States Power owns 85% of the Elk River facility and United Power Association owns the remaining 15%. We also manage and operate an ash storage and disposal facility for the Elk River facility at Northern States Power's Becker ash disposal facility, an approved ash deposit site near Becker, Minnesota. We operate the Becker facility on behalf of Northern States Power. Resource recovery projects, such as our Newport facility and Northern States Power's Elk River facility, historically were assured adequate supply of waste through state and local flow control legislation, which directed that waste be disposed of in certain facilities. In 1994, the United States Supreme Court held that such waste was a commodity in interstate commerce and, accordingly, that flow control legislation that prohibited shipment of waste out of state was unconstitutional. Since this ruling, resource recovery facilities have faced increased competition from landfills in surrounding states in obtaining municipal solid waste; however, this has not materially impacted our municipal solid waste volumes to date. 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 we do. Many of our competitors also are seeking attractive power generation opportunities, both in the United States and abroad. This competition may adversely affect our 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. The Energy Policy Act laid the ground work for a competitive wholesale market for electricity. Among other things, the Energy Policy Act expanded the FERC's authority to order wholesale transmission, thus allowing QFs, power marketers and EWGs to compete more effectively in the wholesale market. In May 1996, the FERC issued the first of the Open Access Rules, which requires utilities to offer eligible wholesale transmission customers non-discriminatory open access on utility transmission lines on a comparable basis to the utilities' own use of the lines. In addition, the Open Access Rules direct the regional power pools that control the major electric transmission networks to file uniform, non-discriminatory open access tariffs. The Open Access Rules have been the subject of rehearing at the FERC and are now undergoing judicial review. Over the past few years, Congress and the administration of President Clinton have considered various pieces of legislation to restructure the electric industry that would require, among other things, customer choice and/or repeal of PUHCA. The debate is likely to continue, and perhaps intensify. The effect of enacting such legislation cannot be predicted with any degree of certainty. Industry deregulation may encourage the disaggregation of vertically integrated utilities into separate generation, transmission and distribution businesses. As a result of these potential regulatory changes, significant additional competitors could become active in the generation segment of our industry. 53

58 FINANCING We fund our projects with a combination of non-recourse debt and equity contributions. Historically, equity contribution infused into a project consisted of cash from operations, corporate-level debt and capital. NON-RECOURSE FINANCING As with our existing facilities, we expect to finance most of our future projects with debt as well as equity. Leveraged financing permits the development of projects with a limited equity base, but also increases the risk that a reduction in revenues could adversely affect a particular project's ability to meet its debt or lease obligations. We have financed our principal power generation facilities primarily with non-recourse debt that is repaid solely from the project's revenues and generally is secured by the physical assets, major project contracts and agreements, cash accounts and, in certain cases, our ownership interest, in that project affiliate. This type of financing is referred to as "project financing." True project financing is not available for all projects, including some assets purchased out of bankruptcy, some merchant plants, some purchases of minority stock positions in publicly traded companies and plants in certain countries that lack a sufficiently well-developed legal system. Even in those instances, however, we may still be able to finance a smaller portion of the total project cost with project financing, with the remainder financed with debt that is either raised or supported at the corporate rather than the project level. Project financing transactions generally are structured so that all revenues of a project are deposited directly with a bank or other financial institution acting as escrow or security deposit agent. These funds then are payable in a specified order of priority set forth in the financing documents to ensure that, to the extent available, they are used first to pay operating expenses, senior debt service and taxes and to fund reserve accounts. Thereafter, subject to satisfying debt service coverage ratios and certain other conditions, available funds may be disbursed for management fees or dividends or, where there are subordinated lenders, to the payment of subordinated debt service. In the event of a foreclosure after a default, our project affiliate owning the facility would only retain an interest in the assets, if any, remaining after all debts and obligations were paid. In addition, the debt of each operating project may reduce the liquidity of our equity interest in that project because the interest is typically subject both to a pledge securing the project's debt and to transfer restrictions set forth in the relevant financing agreements. Also, our ability to transfer or sell our interest in certain projects is restricted by certain purchase options or rights of first refusal in favor of our partners or the project's power and steam purchasers and certain change of control restrictions in the project financing documents. These project financing structures are designed to prevent the lenders from looking to us or our other projects for repayment, that is, they are "non-recourse" to us and our other project affiliates not involved in the project, unless we or another project affiliate expressly agrees to undertake liability. We have agreed to undertake limited financial support for certain of our project subsidiaries in the form of certain limited obligations and contingent liabilities. These obligations and contingent liabilities take the form of guarantees of certain specified obligations, indemnities, capital infusions and agreements to pay certain debt service deficiencies. To the extent we become liable under such guarantees and other agreements in respect of a particular project, distributions received by us from other projects may be used by us to satisfy these obligations. To the extent of these obligations, creditors of a project financing may have recourse to us. See "Risk Factors -- We have guaranteed obligations and liabilities of our project subsidiaries and affiliates which would be difficult for us to satisfy if they all came due simultaneously." RECOURSE FINANCING Recourse financing through corporate-level debt is provided in many different forms. For instance, we have issued corporate-level debt and we periodically provide corporate-level guarantees to various subsidiary financings, mainly as an alternative to funding debt service reserve accounts with project cash. 54

59 Our goal is to have a recourse debt to recourse debt and equity capitalization ratio of 40-50%. Our credit ratings are "Baa3" on review for possible upgrade from Moody's Investors Service, Inc. and "BBB-" stable from Standard & Poor's Ratings Services. EXPOSURE TO CURRENCY FLUCTUATION We seek to manage our exposure to changes in currency exchange rates by matching the currency of revenues with the currency of expenses for each project to create a natural hedge against fluctuations in the currency markets. At the project level we typically sell power, buy fuel, and issue debt in the functional currency of the project. At the corporate level, when a significant source of operating cash is derived from a foreign investment, a portion of corporate debt may be issued in that currency. A recent example of this was our issuance in March 2000 of L160 million 7.97% Senior Reset Notes as a partial hedge of our purchase of the Killingholme project in the United Kingdom. After matching the currency of revenues and expenses, the remaining foreign currency risk is hedged under the guidelines set forth in our foreign exchange risk management policy. This policy requires us to hedge all known and highly probable cash flows over a twelve to eighteen month horizon through the use of forward, swap and option contracts with highly rated financial institutions as appropriate. We do not speculate on changes in foreign exchange rates. As part of our strategy, we hold assets and liabilities denominated in foreign currencies. We adjust the value of these holdings quarterly to reflect fluctuations in the values of their respective currencies. This can, and has, generated non-cash income and losses. REGULATION We are subject to a broad range of federal, state and local energy and environmental laws and regulations applicable to the development, ownership and operation of our United States and international projects. These laws and regulations generally require that a wide variety of permits and other approvals be obtained before construction or operation of a power plant commences and that, after completion, the facility operate in compliance with their requirements. We strive to comply with the terms of all such laws, regulations, permits and licenses and believe that all of our operating plants are in material compliance with all such applicable requirements. We cannot assure you, however, that in the future we will obtain all necessary permits and approvals and that we will comply with all applicable statutes and regulations. 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, we cannot assure you that existing regulations will not be revised or that new regulations will not be adopted or become applicable to us which could have an adverse impact on our operations. In particular, the independent power markets in the United States, United Kingdom, Australia and other countries are dependent on the existing regulatory and ownership structure, and while we strive to take advantage of the opportunities created by such changes, it is impossible to predict the impact of those changes on our operations. Further, we believe that the level of environmental awareness and enforcement is growing in most countries, including most of the countries in which we intend to develop and operate new projects. Therefore, based on current trends, we believe that the nature and level of environmental regulation to which we are subject will become increasingly stringent. Our policy is therefore to operate our projects in accordance with applicable local law or relevant environmental guidelines adopted by the World Bank, whichever reflects the more stringent level of control. ENERGY REGULATION -- UNITED STATES Federal Power Act. The Federal Power Act gives FERC exclusive rate-making jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce. Pursuant to the Federal Power Act, all public utilities subject to FERC's jurisdiction are required to file rate schedules 55

60 with FERC prior to commencement of wholesale sales or transmission of electricity. Public utilities with cost-based rate schedules are also subject to accounting, record-keeping and reporting requirements administered by FERC. PURPA and the Energy Policy Act. The enactment of PURPA in 1978 provided incentives for the development of Qualifying Facilities or "QFs", which were basically cogeneration facilities, and small power production facilities that utilized certain alternative or renewable fuels. QF status conveys two primary benefits. First, regulations under PURPA exempt Qualifying Facilities from PUHCA, most provisions of the Federal Power Act and the state laws concerning rates, and financial and organizational regulations of electric utilities. Second, FERC's regulations under PURPA require that (1) electric utilities purchase electricity generated by QFs at a price based on the purchasing utility's full avoided cost of producing power, (2) the electric utilities must sell back-up, interruptible, maintenance and supplemental power to the QF on a non-discriminatory basis, and (3) the electric utilities must interconnect with any QF in its service territory, and, if required, transmit power if they do not purchase it. We endeavor to acquire, develop and operate our QFs in a manner that minimizes the risk of those plants losing their QF status. However, if we were to lose QF status, we could attempt to avoid regulation under PUHCA by qualifying the project as an EWG. The passage of the Energy Policy Act in 1992 further encouraged independent power production by providing certain exemptions from regulation for EWGs and foreign utility companies ("FUCOs"). All of our subsidiaries that would otherwise be treated as public utilities are currently QFs, EWGs or FUCOs. An EWG is an entity that is exclusively engaged, directly or indirectly, in the business of owning or operating facilities that are exclusively engaged in generation and selling electric energy at wholesale. An EWG will not be regulated under PUHCA, but is subject to FERC and state public utility commission regulatory reviews, including rate approval. EWGs do not enjoy the same statutory and regulatory exemptions from state regulation as are granted to QFs. In fact, however, since EWGs are only allowed to sell power at wholesale, their rates must receive initial approval from FERC rather than the states. All of our EWGs to date that have sought rate approval from FERC have been granted market-based rate authority, which allows FERC to waive certain accounting, record-keeping and reporting requirements imposed on public utilities with cost-based rates. However, FERC customarily reserves the right to suspend, upon complaint, market-based rate authority on a prospective basis if it is subsequently determined that we or any of our EWGs exercised market power. If FERC were to suspend market-based rate authority, it would most likely be necessary to file, and obtain FERC acceptance of, cost-based rate schedules. In addition, the loss of market-based rate authority would subject the EWGs to the accounting, record-keeping and reporting requirements that are imposed on public utilities with cost-based rate schedules. In addition, if there occurs a "material change" in facts that might affect any of our subsidiaries' eligibility for EWG status, within 60 days of the material change, the relevant EWG must (i) file a written explanation of why the material change does not affect its EWG status, (ii) file a new application for EWG status, or (iii) notify FERC that it no longer wishes to maintain EWG status. If any of our subsidiaries were to lose EWG status, we, along with our affiliates, would be subject to regulation under PUHCA as a public utility company. Absent a substantial restructuring of our business, it would be difficult for us to comply with PUHCA without a material adverse effect on our business. FUCOs are companies owning or operating PUHCA jurisdictional facilities not located in the United States that derive no part of their income directly or indirectly from United States public utility activities. FUCOs are exempted from all provisions of PUHCA. After the merger of Northern States Power and New Century Energies we will be a subsidiary of the surviving entity, Xcel Energy. Xcel Energy will be subject to the provisions of various energy-related laws 56

61 and regulations, including regulation as a registered holding company under PUHCA, and, in turn, we will be subject to constraints imposed by PUHCA. These constraints include restrictions imposed upon aggregate investment by registered holding companies in EWGs and FUCOs, financed by contributions or guarantees by the parent holding company, pursuant to SEC regulation which limits registered holding company investment in EWGs/FUCOs without prior SEC approval to 50% of the registered holding company's consolidated retained earnings. The SEC has increased this "safe harbor" investment cap to 100% of retained earnings for a number of registered holding companies, and Xcel Energy has a pending request to raise its EWG/FUCO investment threshold to 100%. The existence of such investment cap and the potential need to request SEC waivers of or increases in the cap could delay any infusions of capital from Xcel Energy which we may need. This delay could be increased by the fact that to obtain a waiver from the Securities and Exchange Commission typically would require Xcel Energy to provide letters in support of such waiver from each state public service commission which regulates Xcel Energy's utility business, which could be time consuming and subject the waiver request to delays due to other matters in dispute between Xcel Energy and any one of the 12 public service commissions that are expected to regulate its utility business. Another constraint is that we could be delayed in creating subsidiaries that would not be involved in energy-related activities. We have created such subsidiaries in the past to enable certain of our project subsidiaries to acquire the status of an EWG, so any delay in this process could delay closings on future transactions, which could in turn have an adverse impact on us. Finally, transactions among us and our associate companies within the Xcel system (including Xcel Energy) would need to be "at cost" unless they fit within specified regulatory exceptions or were approved by the Securities and Exchange Commission. This constraint could delay our execution of contracts between our subsidiaries and other companies within the Xcel system, or limit terms to be contained in these contracts, which could have an adverse impact on us. State Energy Regulation. In areas outside of wholesale rate regulation (such as financial or organizational regulation), some state utility laws may give their public utility commissions broad jurisdiction over steam sales or EWGs that sell power in their service territories. The actual scope of that jurisdiction over steam or independent power projects varies significantly from state to state, depending on the law of that state. ENVIRONMENTAL REGULATION -- UNITED STATES 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 our facilities are not grandfathered, extensive modifications to project technologies and facilities could be required. General. Based on current trends, we expect that environmental and land use regulation will continue to be stringent. Accordingly, we plan to carefully monitor and provide input on (1) critical legislative initiatives which could impact operation of our facilities and (2) proposed construction projects which could subject us to stringent pollution controls imposed on "major modifications" as defined under the Clean Air Act and/or changes in discharge characteristics as defined under the Clean Water Act with the goal of achieving compliance with (1) applicable regulations, (2) administrative consent orders, and/or (3) variances from applicable air-quality-related regulations. Air pollution controls, inclusive of clean fuel use, utilized at our projects meets or exceeds emission limitations reflective of reasonably available control technology. Clean Air Act. Most of our steam electric generating plants in the United States are subject to Title IV of the Clean Air Act, which requires certain fossil-fuel-fired combustion devices to hold sulphur dioxide "allowances" for each ton of sulphur dioxide emitted. We plan to comply with the need for holding the appropriate number of allowances by reducing sulphur dioxide emissions through use of low sulphur fuels, installation of "back end" control technology, and/or purchase of allowances on the open market. The costs of obtaining the required number of allowances needed for future projects will be integrated into our overall financial analysis of such projects. 57

62 Our plants are subject to a variety of regulations governing emissions of oxides of nitrogen (NO(X)). We are installing pollution control equipment at our Somerset facility to implement the "Consumers First" Agreement between Montaup Electric Company and the Attorney General for the Commonwealth of Massachusetts that requires the Somerset facility to reduce NO(X) emissions at Unit 6 to .15 lb/mmBtu by the year 2003. At the Encina facility, we anticipate installing selective catalytic reduction (SCR) on at least two of the units at that facility in the next several years in order to meet mandated pollution control requirements. In addition to the above, our plants in the Northeast region are subject to NO(X) Budget Programs pursuant to which we are required to hold NO(X) "allowances" that equal, for each "ozone season" (May 1 - September 30), our NO(X) emissions from all of our facilities subject to the program. Our facilities in El Segundo and Long Beach are subject to the "RECLAIM" trading program, which is another emissions trading program designed to control NO(X). We currently intend to install SCR on one of the units at the El Segundo facility in order to assist with our compliance with the RECLAIM program. As for our East Coast plants other than Somerset, we intend to implement a strategic plan for the purchase of NO(X) allowances and/or reduction of NO(X) emissions through the installation of pollution control equipment which best meets our business objectives. Title V of the Clean Air Act imposes federal requirements which dictate that most of our fossil-fuel-fired generating facilities must obtain operating permits. All of our existing facilities subject to this requirement have submitted timely Title V permit applications. However, most facilities have not yet received final Title V permits. We do not anticipate that the costs of obtaining final operating permits will be material. In 1997, we were issued Administrative Orders and Notices of Civil Administrative Penalty Assessments by the New Jersey Department of Environmental Protection (NJDEP) as a result of the operations of two cogeneration facilities that we operated. The Administrative Orders and Notices of Civil Administrative Penalty Assessments resulted from alleged air emissions in excess of permit limits that occurred prior to our acquisition of these cogeneration facilities. Notwithstanding this fact, we have agreed to settle the outstanding Administrative Orders with the NJDEP and have executed an Administrative Consent Order (ACO) with the NJDEP in March 2000. The ACO requires us to pay a penalty in the amount of $102,500 within 60 days of the execution of the ACO by both parties. To our knowledge, the NJDEP has not yet executed the ACO. As a result of alleged violations of opacity, or visible emission, standards at the Huntley, Dunkirk and Oswego facilities, Niagara Mohawk (NiMo), the former owner and operator of these facilities, was in the process of negotiating a consent order with the NYDEC to resolve such violations at the time we acquired these facilities. Under the terms of our asset purchase agreements with NiMo, NiMo will be responsible for any and all exceedances which occurred prior to the closing of the transactions contemplated in the asset purchase agreements. We have agreed, in connection with our acquisition of these facilities, to enter into separate consent orders, for each of these facilities, to address on-going and potential future violations of opacity standards. We believe that almost all of the opacity exceedances at the Dunkirk and Oswego facilities are non-preventable events occurring as a result of startups and shutdowns at those facilities that should not be subject to penalties under the New York regulations. We are currently in discussions with the NYDEC regarding this issue. We are also currently in discussions with NYDEC regarding issues of alleged opacity exceedances at the Huntley facility. The hazardous air pollutant provisions of the 1990 Clean Air Act Amendments do not currently extend to the electric utility steam generating unit source category. Section (112)(n)(1)(A) of the Clean Air Act, as amended, requires the EPA to perform a study of the hazards to the public health reasonably anticipated to occur as a result of emissions by electric utility steam generating units of hazardous air pollutants after imposition of the requirements of the 1990 Amendments. The results of the study were presented in a Report to Congress on February 24, 1998. The regulatory determination is to be made by December 15, 2000. In their final report, EPA stated that mercury is the pollutant of greatest interest and the only pollutant for which additional information was to be gathered. The EPA is collecting additional 58

63 mercury-in-coal data from each coal-fired utility in the United States and additional speciated mercury emissions data from a subset of these coal-fired utilities. The data-gathering effort for the mercury-in-coal analyses commenced January 1, 1999 and continued until December 31, 1999. It is expected that the speciated stack testing will be completed by February 29, 2000. All final test reports are due to the EPA by May 31, 2000. Until studies of the emissions from such facilities are completed and Congress either amends the Clean Air Act further or the EPA promulgates regulations in connection therewith, the nature and extent to which federal hazardous air pollutants emissions restrictions will apply to our facilities and other electric utility steam generation units will remain uncertain. On October 14, 1999, Governor Pataki of New York announced that he was ordering the New York Department of Environmental Conservation to require further reductions of sulphur dioxide and nitrogen oxides emissions from New York power plants, beyond that which is required under current federal and state law. These reductions would be phased in between January 1, 2003 and January 1, 2007. Compliance with these emissions reductions requirements, if they become effective, could have a material adverse impact on the operation of some of our facilities located in the State of New York. In addition, the Connecticut legislature has in the past considered, but rejected, legislation that would require older electrical generation stations to comply with more stringent pollution standards than are currently in effect in Connecticut for nitrogen oxides and sulphur dioxide emissions. Currently, legislation is being debated in the Connecticut legislature that could require our Connecticut facilities to rely on more expensive fuels or install additional air pollution control equipment. If such legislation were to become law without reflecting the benefit of critical elements of current federal emission reduction initiatives (e.g. market based emission trading between sources located across broad geographical regions), our Connecticut facilities may be placed at a significant competitive disadvantage. The Office of the Attorney General of the State of New York and the New York Department of Environmental Conservation are investigating physical changes made at the Huntley and Dunkirk facilities prior to our assumption of ownership. The Attorney General has alleged that such changes represent major modifications undertaken without obtaining the required permits. If these facilities did not comply with the applicable permit programs, we could be required, among other things, to install best available control technology to further reduce criteria pollutant emissions from the Dunkirk and Huntley facilities, and we could become subject to fines and penalties associated with the period of time we have operated the facilities. In addition, on November 3, 1999, the United States Department of Justice filed suit against seven electric utilities for alleged violations of Title IV of the Federal Clean Air Act permit requirements at seventeen utility generation stations located in the southern and midwestern regions of the United States. The EPA also issued administrative notices of violation alleging similar violations at eight other power plants owned by some of the electric utilities named as defendants in the lawsuit, and also issued an administrative order to the Tennessee Valley Authority for similar violations at seven of its power plants. To date, no lawsuits or administrative actions have been brought against us or any of our subsidiaries or affiliates or the former owners of our facilities alleging similar violations, although Atlantic City Electric Company has received information requests from the EPA regarding the Deepwater and BL England facilities that we have agreed to purchase. However, lawsuits or administrative actions alleging similar violations at our facilities could be filed in the future and if successful, could have a material, adverse effect on our business. Clean Water Act. Our existing facilities are also subject to a variety of state and federal regulations governing existing and potential water/wastewater discharges therefrom. Generally, such regulations are promulgated under authority of the Clean Water Act and govern overall water/wastewater discharges, through National Pollutant Discharge Elimination System (NPDES) permits. Under current provisions of the Clean Water Act, existing NPDES permits must be renewed every five years, at which time permit limits are extensively reviewed and can be modified to account for changes in regulations or program initiatives. In addition, the permits have re-opener clauses which the federal government can use to modify a permit at any time. Many of our existing facilities have been operating under NPDES permits for a long 59

64 time and have gone through one or more NPDES permit renewal cycles and are currently in the process of renewing their existing NPDES permits again. In addition, some facilities are now lawfully operating under terms of an existing consent order. Costs related to renewal of the NPDES permits, e.g., conducting studies related to thermal discharges and/or the entrainment/impingement of fish, and/or, where applicable, costs related to complying with the terms of a consent order have generally been included as part of the project's pro forma. Where thermal discharges are known to be contentious, e.g., at Conectiv's Indian River Plant, we budgeted in our pro forma capital projects to address such concerns. Congress has not recently undertaken efforts to re-authorize the Clean Water Act. Even so, the conditions in NPDES permits have continued to tighten with increased focus on toxic pollutant discharges, receiving water body biological monitoring requirements, bioassay requirements, additional controls on stormwater runoff, and water quality standards and enforcement provisions. If the Clean Water Act is reauthorized and becomes more stringent, or the results of studies demonstrate significant issues related to effluent toxicity, thermal discharges and/or entrainment of impingment of fish, our facilities may be required to retrofit existing wastewater treatment facilities to accommodate removal of metals, install controls to reduce thermal discharges and/or to modify the water intake/discharge structures. Based on past operating experience and/or on the funds we have already budgeted to address known issues associated with effluent discharges, we do not expect the impact of these additional expenses to affect significantly the profitability of the facilities. We cannot assure you that existing laws and regulations will not be revised or that new regulations will not be adopted or become applicable to us which could have an adverse impact on our operations. ENERGY REGULATION -- INTERNATIONAL Most of the foreign countries in which we own 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 often particularly significant for independent power producers because they are still changing and evolving in many countries. Although the type and nature of these energy or electric laws vary widely from country to country, many of them address some or all of the following issues: - Establishment of an energy regulatory body; - Financial or technical qualifications for independent power producers; - Licensing requirements and procedures for independent power projects or producers; - Procedures for deciding whether the construction of new power plants should be allowed; - If existing generating facilities are to be sold or transferred to third parties, procedures for doing so; - Limitations on which customers may be served by independent power producers; - Price regulations; or - Incentives for independent power developers or developers of new power facilities. We retain appropriate advisors in foreign countries and seek to design our international development and acquisition strategy to comply with and take advantage of opportunities presented by each nation's energy laws and regulations. There can be no assurance, however, that changes in such laws or regulations could not adversely affect our international operations. ENVIRONMENTAL REGULATIONS -- INTERNATIONAL Although the type of environmental laws and regulations applicable to independent power producers and developers varies widely from country to country, many foreign countries have laws and regulations relating to the protection of the environment and land use which are similar to those found in the United States. Laws applicable to the construction and operation of electric power generation facilities in foreign countries generally regulate discharges and emissions into water and air, and also regulate noise levels. Air 60

65 pollution laws in foreign jurisdictions often limit the emissions of particles, dust, smoke, carbon monoxide, sulfur dioxide, nitrogen oxides and other pollutants. Water pollution laws in foreign countries generally limit wastewater discharges into municipal sewer systems and require treatment of wastewater so that it meets established standards. New projects and modifications to existing projects are also subject, in many cases, to land use and zoning restrictions imposed in the foreign country, in addition to the requirements currently imposed by a particular country, most lenders to international development projects may impose their own requirements relating to protection of the environment. We believe that the level of environmental awareness and enforcement is growing in most countries, including most of the countries in which we intend to develop and operate new projects. Therefore, based on current trends, we believe that the nature and level of environmental regulation to which we are subject will become increasingly stringent. Therefore, our policy is to operate our projects in accordance with environmental guidelines adopted by the World Bank or applicable local law, whichever reflects the more stringent level of control. OTHER PROPERTIES In addition to the other properties discussed in this prospectus, we lease our offices at 1221 Nicollet Mall, Suite 700, Minneapolis, Minnesota 55403, under a five-year lease that expires in June 2002. Our thermal division leases and operates the Hennepin County Energy Center. We also own interests in the following power generation facilities that have been idled: Madera, Chowchilla II and El Nido, San Joaquin Valley, California; Jackson Valley Energy Partners, Ione, California; Artesia, California; and Turners Falls, Massachusetts, which facilities represent an aggregate equity generation capacity of 63 MW and a book value of $8.4 million. EMPLOYEES At December 31, 1999, we had 1,809 employees, approximately 400 of whom are employed directly by us and approximately 1,409 of whom are employed by our wholly-owned subsidiaries. The majority of our domestic and international projects employ unionized employees whose conditions of employment are covered by collective bargaining agreements. We have experienced no significant labor stoppages or labor disputes at our facilities. LEGAL PROCEEDINGS On or about July 12, 1999, Fortistar Capital Inc., a Delaware Corporation, filed a complaint in the Fourth Judicial District, Hennepin County, Minnesota against us, asserting claims for injunctive relief and for damages as a result of our alleged breach of a confidentiality letter agreement with Fortistar relating to the Oswego facility. We disputed Fortistar's allegations and have asserted numerous counterclaims. We have counterclaimed against Fortistar for breach of contract, fraud and negligent misrepresentations and omissions, tortuous interference with contract, prospective business opportunities and prospective contractual relationships, unfair competition and breach of covenant of good faith and fair dealing. We seek, 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 our and Niagara Mohawk's intention to close on that date. On January 14, 2000, the court denied Fortistar's request for a temporary injunction. We intend to continue to vigorously defend the suit and believe Fortistar's complaint to be without merit. No trial date has been set. On October 12, 1999, we received a letter from the Office of the Attorney General of the State of New York alleging that based on a preliminary analysis, it believes that major modifications were made to our Huntley and Dunkirk facilities during prior ownership of those facilities without the required permits having been obtained. We believe that the Attorney General sent identical letters to the owners and 61

66 operators of all of the coal-fired utility plants in New York. On January 12, 2000, we received a formal request from the New York Department of Environmental Conservation seeking documents relating to the matters covered by the Attorney General's letter. We understand that this request supersedes the Attorney General's request. While we do not have knowledge at this time that the previous owner of the Huntley and Dunkirk facilities did not comply with the preconstruction permit requirement, we cannot predict the outcome of the state's investigation, as we have only owned these facilities since June 1999. Although we have a right to indemnification by the previous owner for penalties 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, we could be required, among other things, to install specified pollution control technology to further reduce pollutant emissions from the Dunkirk and Huntley facilities, and we could become subject to fines and penalties associated with the period of time we have operated the facilities. There are no other material legal proceedings pending, other than ordinary routine litigation incidental to our business, to which we are a party. There are no material legal proceedings to which an officer or director is a party or has a material interest adverse us or our subsidiaries. There are no material administrative or judicial proceedings arising under environmental quality or civil rights statutes pending or known to be contemplated by governmental agencies to which we are or would be a party. 62

67 MANAGEMENT The name, age and title of each of the directors and executive officers of NRG as of March 31, 2000 are as set forth below: NAME AGE TITLE - ---- --- ----- David H. Peterson.................... 58 Chairman of the Board, President, Chief Executive Officer and Director Gary R. Johnson...................... 53 Director Cynthia L. Lesher.................... 51 Director Edward J. McIntyre................... 49 Director Leonard A. Bluhm..................... 54 Executive Vice President and Chief Financial Officer Keith G. Hilless..................... 61 Senior Vice President, Asia Pacific Craig A. Mataczynski................. 39 Senior Vice President, North America John A. Noer......................... 53 Senior Vice President Ronald J. Will....................... 59 Senior Vice President, Europe James J. Bender...................... 43 Vice President, General Counsel and Corporate Secretary Brian B. Bird........................ 37 Vice President and Treasurer Roy R. Hewitt........................ 54 Vice President, Administrative Services Valorie A. Knudsen................... 43 Vice President, Corporate Strategy and Portfolio Assessment Louis P. Matis....................... 49 Vice President, Corporate Operating Services David E. Ripka....................... 51 Vice President and Controller David H. Peterson has been Chairman of the Board of NRG since January 1994, Chief Executive Officer since November 1993, President since 1989 and a Director since 1989. Mr. Peterson was also Chief Operating Officer of NRG from June 1992 to November 1993. Prior to joining NRG, 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. Mr. Peterson has also been a director of Northern States Power subsidiary Energy Masters International, Inc. since November 1993. Gary R. Johnson has been a Director of NRG since 1993 and Vice President and General Counsel of Northern States Power since November 1991. 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. Mr. Johnson has also been a director of Northern States Power's subsidiaries Seren Innovations, Inc. since November 1996 and Viking Gas Transmission Company since March 1997. Cynthia L. Lesher has been a Director of NRG since June 1996 and became President of Northern States Power-Gas in July 1997. Prior to July 1997, Ms. Lesher was Vice President-Human Resources of Northern States Power since March 1992 after serving as Director of Power Supply-Human Resources since 1991. Ms. Lesher became Area Manager, Electric Utility Operations, in 1990, and previously served as Manager, Metro Credit, and Manager, Occupational Health and Safety. Prior to joining Northern States Power, Ms. Lesher was a training and development consultant at the Center for Continuing Education in Minneapolis. From 1970 to 1977, she held a variety of positions with Multi Resource Centers, Inc., also in Minneapolis. Ms. Lesher has also been a director and Chairperson of Northern States Power subsidiaries Black Mountain Gas Company since July 1999, Natrogas, Incorporated since December 1999 and Viking Gas Transmission Company since July 1997, where she has served as Chairperson since June 1998. Edward J. McIntyre has been a Director of NRG since 1993 and Vice President and Chief Financial Officer of Northern States Power since January 1993. Mr. McIntyre has also been a director of Northern States Power subsidiaries Eloigne Company since April 1993 and Energy Masters International, Inc. since September 1994. 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 63

68 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. Leonard A. Bluhm has been Executive Vice President and Chief Financial Officer of NRG 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 from January 1993 through April 1996. Mr. Bluhm was Chief Financial Officer of Cypress Energy Partners, a wholly-owned project subsidiary of NRG, from April 1992 to January 1993, prior to which he was Director, International Operations and Manager, Acquisitions and Special Projects of NRG from 1991. Mr. Bluhm previously served for over 20 years in various financial positions with Northern States Power. Keith G. Hilless has been Senior Vice President, Asia Pacific of NRG since July 1998, prior to which he was a senior executive since August 1997. Prior to joining NRG, 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 of NRG, and President and Chief Executive Officer of NRG Energy 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's wholly-owned subsidiary that develops small electric generation projects within the United States. Prior to joining NRG, Mr. Mataczynski worked for NSP 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 since January 1, 2000. Immediately prior to that he served as President-NSP Combustion and 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, 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. Ronald J. Will has been Senior Vice President of NRG 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, 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. 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, 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 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. Roy R. Hewitt has been Vice President, Administrative Services at NRG since February 1999. He has nearly 30 years experience in the power industry including 24 years with NRG's parent company, Northern States Power and 6 years with NRG. Mr. Hewitt joined NRG in 1994 as a member of the 64

69 senior management team with NRG's Gladstone Power Station project in Queensland, Australia. In 1996, he returned to NRG'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's Asia-Pacific region headquartered in Brisbane, Australia. Valorie A. Knudsen has been Vice President, Corporate Strategy and Portfolio Assessment since February 2000. She has served as Vice President, Emerging Markets; Vice President, Finance and as Controller since joining NRG in August 1993. Prior to joining NRG, Ms. Knudsen served in various managerial accounting positions from November 1987 to July 1993 with Carlson Companies, Inc., where she was responsible for various types of accounting and reporting. Before joining Carlson Companies, Ms. Knudsen practiced as a Certified Public Accountant for seven years. Louis P. Matis has been Vice President, Corporate Operating Services of NRG since July 1998, prior to which he served in a variety of roles at Northern States Power. Mr. Matis joined Northern States Power in 1983 as a civil engineer and managed the construction and engineering of numerous projects. In 1990 he joined Fuel Resources as manager and then director, managing a portfolio of nuclear fuel, fossil fuel and transportation contracts as well as a nuclear fuel design group for Northern States Power. In 1996, he became General Manager of fossil fuel plants for Northern States Power. David E. Ripka has been Vice President and Controller of NRG since June 1999, and Controller since March 1997. Prior to joining NRG, Mr. Ripka held a variety of positions with Northern States Power for over 20 years, including Assistant Controller and General Manager of Accounting Operations and Director of Audit Services. BOARD OF DIRECTORS Upon completion of this offering, our board of directors will consist of nine directors, five of whom will be employees of Northern States Power and three of whom will be unaffiliated, independent directors. COMMITTEES OF THE BOARD OF DIRECTORS Our board of directors has a compensation committee and an audit committee. Compensation Committee. Following this offering, the members of our compensation committee will be , , and . The compensation committee reviews and makes recommendations to our board of directors concerning salaries and incentive compensation for our officers and employees. The compensation committee also will administer the NRG Long-Term Incentive Plan. Audit Committee. Following this offering, the members of our audit committee will be , and . Our board of directors has determined that each member of the audit committee is "independent," that each member is "financially literate," and that each member has "accounting or related financial management expertise." The audit committee reviews and monitors our financial statements and accounting practices, makes recommendations to our board of directors regarding the selection of independent auditors and reviews the results and scope of the audit and other services provided by our independent auditors. COMPENSATION OF DIRECTORS Directors who are also employees of NRG or Northern States Power do not receive any compensation for their services as directors. Directors who are not employees of NRG or Northern States Power will receive an annual fee of $30,000 and a fee of $1,000 per meeting plus reasonable travel expenses. Non-employee directors are also entitled to participate in the NRG Long-Term Incentive Plan, as described below. Prior to the offering we expect to issue options to purchase shares of our common stock to each of our non-employee directors. 65

70 Each of our directors has an indemnification agreement that entitles them to indemnification for claims asserted against them in their capacity as directors to the fullest extent permitted by Delaware law. COMPENSATION OF EXECUTIVE OFFICERS AND OTHER INFORMATION The following table shows the cash compensation paid or to be paid by us or any of our subsidiaries, as well as certain other compensation paid or accrued, during the fiscal years indicated to our Chief Executive Officer and our four next highest paid executive officers, which we refer to as our "Named Executives" in all capacities in which they serve: SUMMARY COMPENSATION TABLE LONG-TERM ANNUAL COMPENSATION COMPENSATION --------------------------------------------------- ------------ OTHER ANNUAL LTIP ALL OTHER NAME AND PRINCIPAL POSITION YEAR SALARY BONUS COMPENSATION(1) PAYOUTS COMPENSATION - --------------------------- ---- -------- --------------- --------------- ------------ ------------ David H. Peterson............................ 1999 $367,992 $192,970 $6,131 $155,995 $33,201(2) Chairman, President and Chief Executive 1998 345,826 290,220 4,922 7,724 17,777 Officer 1997 300,000 127,000 3,272 0 15,517 Craig A. Mataczynski......................... 1999 246,250 150,000 4,706 15,533 15,251(3) Senior Vice President, North America 1998 192,091 118,627 3,871 2,538 5,832 1997 163,336 60,804 1,347 0 39,962 Ronald J. Will............................... 1999 214,160 107,341 5,162 50,075 15,275(4) Senior Vice President, 1998 188,640 83,564 4,130 3,182 5,597 Europe 1997 163,507 38,667 1,627 0 4,870 James J. Bender.............................. 1999 213,746 100,000 6,528 19,729 6,172(5) Vice President, General Counsel and 1998 198,758 108,892 7,331 4,810 49,491 Corporate Secretary 1997 93,282 89,750(6) 6,239 0 42,391 Leonard A. Bluhm............................. 1999 194,590 72,150 5,265 50,489 12,814(7) Executive Vice President 1998 189,174 66,500 5,156 3,172 5,060 and CFO 1997 179,586 48,190 2,462 0 4,581 - --------------- (1) Amounts reimbursed during the fiscal year for the payment of taxes on fringe benefits. (2) Includes a $15,481 excess vacation payout; $8,707 of Incentive Pension Makeup Plan contributions; $7,000 of universal life insurance premiums; $1,114 of Employee Stock Ownership Plan contributions; and $900 of 401(k) Plan matching contributions. (3) Includes a $9,308 excess vacation payout; $3,559 of Incentive Pension Makeup Plan contributions; $1,114 of Employee Stock Ownership Plan contributions; $900 of 401(k) Plan matching contributions; and $370 of term life insurance premiums. (4) Includes a $9,288 excess vacation payout; $3,220 of Incentive Pension Makeup Plan contributions; $1,114 of Employee Stock Ownership Plan contributions; $900 of 401(k) Plan matching contributions; and $752 of term life insurance premiums. (5) Includes $3,267 of Incentive Pension Makeup Plan contributions; $1,114 of Employee Stock Ownership Plan contributions; $900 of 401(k) Plan matching contributions; and $1,406 of term life insurance premiums. (6) Includes $25,000 paid as a signing bonus. (7) Includes a $7,399 excess vacation payout; $1,995 of Incentive Pension Makeup Plan contributions; $1,114 of Employee Stock Ownership Plan contributions; $900 of 401(k) Plan matching contributions; and $752 of term life insurance premiums. 66

71 STOCK OPTION HOLDINGS The following table sets forth information concerning fiscal year-end value of unexercised options under the Northern States Power Executive Stock Option Program. Prior to the existence of the NRG Equity Plan, NRG executives participated in the Northern States Power Executive Stock Option Program. AGGREGATED OPTION/SAR FISCAL YEAR-END VALUES(1) NUMBER OF SECURITIES UNDERLYING VALUE OF UNEXERCISED IN-THE-MONEY UNEXERCISED OPTIONS/SARS AT FY-END OPTIONS/SARS AT FY-END(2) NAME EXERCISABLE/UNEXERCISABLE EXERCISABLE/UNEXERCISABLE - ---- ---------------------------------- --------------------------------- David H. Peterson................. 16,879/0 $29,583/$0 Leonard A. Bluhm.................. 6,593/0 $ 8,992/$0 Craig A. Mataczynski.............. 1,545/0 $ 959/$0 Ronald J. Will.................... 5,457/0 $ 8,846/$0 James J. Bender................... 0/0 $ 0/$0 - --------------- (1) These options to acquire Northern States Power Stock were granted to the Named Executives for services rendered to NRG and its subsidiaries. (2) Northern States Power's share price on December 31, 1999 was $19.50. PENSION PLAN TABLE As of January 1, 1999, pension benefits were changed. Prior to January 1, 1999, each nonbargaining employee was given an opportunity to choose between two retirement programs, the traditional program and the pension equity program. Under the traditional program, the pension benefit is computed by taking the highest average compensation multiplied by credited years of service with a 50% offset for social security benefits. The annual compensation used to calculate the average compensation uses base salary for the year and bonus compensation paid in that same year. After an employee has reached 30 years of service, no additional years of service are used in determining the pension benefit under the traditional program. The benefit amounts under the traditional program are computed in the form of a straight-line annuity. Under the pension equity program, the annual compensation used to calculate average compensation uses base salary for the year and bonus compensation paid in that same year, with no maximum on the number of years used to determine the pension benefit. The benefit amounts under the pension equity program are computed in the form of a lump sum. The formula for determining the lump sum is average compensation multiplied by credited years of service times 10% with a 50% offset for social security. The benefit amounts can be paid in a lump sump or in the form of a straight-line annuity, at the option of the employee. Both programs feature a cash balance side account, which credits $1,400 annually, plus interest each year. The opening balance as of January 1, 1999 is $1,400 times years of service. 67

72 The following table illustrates the approximate retirement benefits payable to employees retiring at the normal retirement age of 65 years under the traditional program: ESTIMATED ANNUAL BENEFITS FOR YEARS OF SERVICE INDICATED ------------------------------------------------------------ YEARS OF SERVICE ------------------------------------------------------------ AVERAGE COMPENSATION (LAST 4 YEARS) 5 10 15 20 25 30 - ----------------------------------- ------- ------- ------- -------- -------- -------- 50,000........................... $ 3,500 $ 7,000 $10,500 $ 14,000 $ 18,000 $ 21,500 100,000........................... 7,500 15,500 23,000 30,500 38,000 46,000 150,000........................... 11,500 23,500 35,000 47,000 58,500 70,500 200,000........................... 16,000 31,500 47,500 63,000 79,000 95,000 250,000........................... 20,000 40,000 59,500 79,500 99,500 119,500 300,000........................... 24,000 48,000 72,000 96,000 120,000 144,000 350,000........................... 28,000 56,000 84,000 112,500 140,500 168,500 400,000........................... 32,000 64,500 96,500 128,500 160,500 193,000 450,000........................... 36,000 72,500 108,500 144,500 181,000 217,000 500,000........................... 40,500 80,500 121,000 161,000 201,500 241,500 550,000........................... 44,500 88,500 133,000 177,500 221,500 266,000 600,000........................... 48,500 97,000 145,500 193,500 242,000 290,500 650,000........................... 52,500 105,000 157,500 210,000 262,500 315,000 700,000........................... 56,500 113,000 170,000 226,500 283,000 339,500 750,000........................... 60,500 121,500 182,000 242,500 303,500 364,000 The following table illustrates the approximate retirement benefits payable to employees retiring at the normal retirement age of 65 years under the pension equity program if paid in the form of a straight-line annuity: ESTIMATED ANNUAL BENEFITS FOR YEARS OF SERVICE INDICATED ------------------------------------------------------------ YEARS OF SERVICE ------------------------------------------------------------ AVERAGE COMPENSATION (LAST 4 YEARS) 5 10 15 20 25 30 - ----------------------------------- ------- ------- ------- -------- -------- -------- 50,000........................... $ 3,500 $ 7,000 $11,000 $ 15,500 $ 20,500 $ 26,500 100,000........................... 6,000 12,000 18,500 25,500 33,000 41,500 150,000........................... 8,500 17,000 26,000 35,500 46,000 57,000 200,000........................... 11,000 22,000 33,500 45,500 58,500 72,000 250,000........................... 13,500 27,000 41,500 56,000 71,000 87,000 300,000........................... 16,000 32,500 49,000 66,000 83,500 102,500 350,000........................... 18,500 37,500 56,500 76,000 96,500 117,500 400,000........................... 21,000 42,500 64,000 86,000 109,000 133,000 450,000........................... 23,500 47,500 71,500 96,500 121,500 148,000 500,000........................... 26,000 52,500 79,500 106,500 134,500 163,000 550,000........................... 28,500 57,500 87,000 116,500 147,000 178,500 600,000........................... 31,000 62,500 94,500 127,000 159,500 193,500 650,000........................... 33,500 67,500 102,000 137,000 172,500 208,500 700,000........................... 36,000 73,000 109,500 147,000 185,000 224,000 750,000........................... 39,000 78,000 117,000 157,000 197,500 239,000 As of March 31, 2000, each of the Named Executives had the following credited service: Mr. Peterson, 36 years, Mr. Bluhm, 29 years, Mr. Mataczynski, 18 years, Mr. Will, 40 years, and Mr. Bender, 5 years. Mr. Will and Mr. Bender have selected the pension equity program; all other Named Executives have selected the traditional program. 68

73 LONG-TERM INCENTIVE PLAN COMPENSATION The following table sets forth information concerning awards during fiscal 1999 to each of the Named Executives under the NRG Equity Plan, described below. LONG-TERM INCENTIVE PLAN AWARDS IN LAST FISCAL YEAR PERFORMANCE OR OTHER PERIOD UNTIL MATURATION NAME UNITS OR OTHER RIGHTS (#) OR PAYOUT - ---- ------------------------- --------------------------- David H. Peterson.............................. 41,080 8 years Leonard A. Bluhm............................... 9,070 8 years Craig A. Mataczynski........................... 12,100 8 years Ronald J. Will................................. 10,000 8 years James J. Bender................................ 10,000 8 years NRG EQUITY PLAN Prior to the offering, our officers and other selected employees participated in the NRG Equity Plan. This discretionary plan was established in 1993 to promote the achievement of long-term financial objectives by linking the long-term incentive compensation of our employees to the achievement of value creation; to attract and retain employees of outstanding competence; to encourage teamwork among employees; and to provide employees with an opportunity for long-term capital accumulation. The plan provided grants of "equity units" that were intended to simulate stock options. Grant size was based on the participant's position in the company and base salary. The Compensation Committee of the board of directors administered the plan for our officers. The Chief Executive Officer administered the plan for other employees. Equity grants were generally made annually at the discretion of the board of directors with the grant price consistent with the most recent valuation of equity units. Equity unit valuations were performed annually by a nationally recognized outside valuation firm selected by the board of directors. The value of an equity unit is the approximate value per share of our stockholder equity as of the valuation date, less the value of Northern States Power equity investments. The accrued value of each participant's award is equal to the current value of the equity unit minus the grant price. Equity units are paid out in cash over a five-year period (twenty percent per year) following a three-year vesting period. In the event of termination of employment by a participant due to death or disability, outstanding equity units become fully vested and are fully paid in the following year. In the event of termination of employment due to retirement, outstanding equity units become fully vested and are paid out pro rata over the five plan years following termination. Termination of a participant for any other reason results in forfeiture of all unvested equity units. Following the offering we do not plan to make any additional grants under this plan. Currently there are approximately 1,525,000 equity units outstanding. Of that amount, approximately 639,000 equity units are held by our officers. Approximately 886,000 equity units are held by other employees. No directors have participated in this plan. As part of the conversion to a stock appreciation rights plan, the stock price will be determined as the average closing price per share of our common stock for the last fifteen trading days of the plan year. NRG LONG-TERM INCENTIVE PLAN Prior to the completion of the offering, we expect to adopt a new incentive compensation plan that will replace the NRG Equity Plan. The board of directors or a committee as appointed by the board of directors will administer the incentive plan. The incentive plan will provide 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 will be eligible to participate in the incentive plan. The total number of shares of common stock 69

74 to be authorized for issuance under the incentive plan is expected to be approximately shares. As of the completion of the offering, we intend to make stock option grants under the incentive plan to our officers and other selected executives. These awards and subsequent awards under the incentive plan will be targeted to be competitive with equity-based awards in our industry. The initial options will have an exercise price equal to the initial public offering price. Subsequent awards, anticipated to be made annually, will have an option price at least equal to the market price of our common stock on the date of grant. Options generally will vest over a three-year period from date of grant. Each option granted will expire at such time as the board of directors determines at the time of grant; provided, however, that no option shall be exercisable later than the tenth anniversary date of its grant. The total number of shares covered by the initial awards is expected to be approximately shares. To the extent issuance of equity compensation under the incentive plan would cause Northern States Power to cease to own at least 80% of the value of our outstanding capital stock, Northern States Power may purchase shares of common stock in the open market to ensure that such minimum value is maintained. EMPLOYMENT CONTRACTS David H. Peterson. We have entered into an employment agreement with Mr. Peterson providing that Mr. Peterson will be employed as our highest level executive officer. The term of the agreement expires June 27, 2004. During the term of the agreement, Mr. Peterson's base salary will be reviewed at least annually by the Compensation Committee of the board of directors for possible increase. The agreement provides that Mr. Peterson will receive retirement and welfare benefits no less favorable than those provided to any of our other officers. In addition, the employment agreement provides for participation in a supplemental executive retirement plan such that the aggregate value of the retirement benefits that Mr. Peterson and his spouse will receive at the end of the term of the agreement under all of our defined benefit pension plans and those of our affiliates will not be less than the aggregate value of the benefits he would have received had he continued, through the end of the term of the agreement, to participate in the Northern States Power's Deferred Compensation Plan, the Northern States Power Excess Benefit Plan and the Northern States Power Pension Plan, including amounts to compensate Mr. Peterson for the monthly defined benefit payments he would have received during the term of the employment agreement and prior to the date of his termination of employment if monthly benefit payments had commenced following the month in which he first became eligible for early retirement under the Northern States Power Pension Plan. The employment agreement also provides for certain additional benefits to be paid upon Mr. Peterson's death. If Mr. Peterson's employment is terminated by us without cause or by Mr. Peterson with good reason, in each case as defined in the employment agreement, Mr. Peterson will continue to receive his salary, bonus at the greater of target bonus and actual bonus for the last plan year prior to termination, incentive compensation with cash replacing equity based awards and benefits under the agreement as if he had remained employed until the end of the term of the employment agreement and then retired, at which time he will be treated as eligible for retiree welfare benefits and other benefits provided to the retired senior executives. However, if the termination of employment is a result of a change of control, as defined in the NRG Equity Plan, the compensation and benefits will be continued for the longer of 30 months or through the end of the employment period. In accordance with the terms of the employment agreement, Mr. Peterson has agreed not to compete with our business during the period of his employment and for one year after his termination or resignation. Mr. Peterson has also agreed not to solicit any of our customers for any business purpose that competes with our business during the period of his employment or two years after his termination or resignation. Finally, during the period of his employment and for two years after his termination or resignation, Mr. Peterson has agreed not to disclose any of our confidential information to any person not authorized by us to receive it. 70

75 Leonard A. Bluhm, Craig A. Mataczynski; Ronald J. Will and James J. Bender. On April 15, 1998, we entered into employment agreements with each of Messrs. Bluhm, Mataczynski, Will and Bender. The term of each of these agreements is for a rolling three year period unless either party to the agreement notifies the other in advance of any annual anniversary date of the agreement that the agreement will expire two years from the annual anniversary date. These agreements expire on April 15, 2001. If the employment of any of Messrs. Bluhm, Mataczynski, Will and Bender is terminated due to his death, disability or for cause, or if any of them voluntarily resigns without good cause, he will receive his base salary excluding incentives and employee benefits through the date of termination or resignation. However, if any of the executives is terminated for any reason other than death, disability or cause, or if any of them voluntarily resigns for good cause, we will be obligated to continue to pay his then current total compensation, including base salary, anticipated incentives and all employee benefits for a period of three years following the date of termination or resignation. Under the terms of the employment agreements, each of the executives has agreed not to compete with our business during the course of his employment and for one year after his resignation or termination. In addition, each of the executives has agreed not to disclose any of our confidential information or trade secrets or use the information for his or a third party's benefit. The employment agreement with Mr. Will also provides that upon Mr. Will's termination of employment for any reason or his voluntary resignation with or without good cause, in addition to all other items of compensation, we will pay the sum of $100,000 as a retainer in exchange for Mr. Will's agreement to make himself available at our request to provide consulting services for one year following his termination or resignation. 71

76 OWNERSHIP OF CAPITAL STOCK Prior to the completion of this offering, Northern States Power Company, 414 Nicollet Mall, Minneapolis, Minnesota 55401, owned all of our outstanding capital stock. Upon completion of this offering, Northern States Power will own shares of class A common stock. Upon completion of this offering, class A common stock will constitute % of our total outstanding common equity and about % of our total voting power. Upon completion of this offering, common stock will constitute about % of our total outstanding stock and about % of our total voting power. 72

77 RELATIONSHIPS AND RELATED TRANSACTIONS The transactions described or referred to below were entered into between related parties prior to the offering of our common stock and were not the result of arms-length negotiations. Northern States Power has the power, and will continue to have the power following this offering, to control the election of the directors and all other matters submitted for stockholder approval and may be deemed to have control over our management and affairs. Northern States Power has policies in place, pursuant to applicable law, to ensure that its ratepayers are protected from affiliate transactions that may be adverse to the ratepayers' interests. Unless otherwise noted below, the agreements described below will continue in effect after this offering. OPERATING AGREEMENTS We have two agreements with Northern States Power for the purchase of thermal energy. Under the terms of the agreements, Northern States Power charges us for certain incremental costs, including fuel, labor, plant maintenance and auxiliary power, incurred by Northern States Power to produce the thermal energy. We paid Northern States Power $4.6 million in 1997, $5.1 million in 1998 and $4.4 million in 1999 under these agreements; we have paid $1.4 million under them in the first three months of 2000. One of the agreements expires on December 31, 2002 and the other one expires on December 31, 2006. We have a renewable 10-year agreement with Northern States Power, expiring on December 31, 2001, whereby Northern States Power agrees to purchase refuse-derived fuel for use in certain of its boilers and we agree to pay Northern States Power an incentive fee to use refuse-derived fuel. Under this agreement, we received from Northern States Power $1.3 million in 1997, $1.4 million in 1998 and $1.4 million in 1999; we paid to Northern States Power $2.8 million in 1997, $3.1 million in 1998 and $2.7 million in 1999 under this agreement. Through March 31, 2000, we received $0.6 million and paid $0.5 million. We have entered into an operation and maintenance agreement with Northern States Power with respect to the Elk River and Becker facilities, under which we receive a base management fee and are reimbursed for costs we have incurred. The operation and maintenance agreement also provides for a management incentive fee payable to us, based upon the financial performance of the facilities. We earned a total management fee of $1.1 million, in addition to reimbursed expenses, in 1997, $1.7 million in 1998 and $1.9 million in 1999. Management fees for the three months ended March 31, 2000, totaled $0.6 million. This agreement expires on December 31, 2003. ADMINISTRATIVE SERVICES AGREEMENT We have entered into an agreement with Northern States Power to provide for the reimbursement of actual administrative services provided to each other on an at-cost basis plus a 1% fee to cover handling costs, working capital requirements and other miscellaneous costs. Services provided by Northern States Power to us are principally for cash management, accounting, employee relations, governmental affairs and engineering. In addition, our employees participate in certain employee benefit plans of Northern States Power. We paid Northern States Power $0.7 million in 1997, $5.2 million in 1998 and $6.4 million in 1999, as reimbursement for the cost of services provided. Through March 31, 2000, we have paid $2.0 million. TAX SHARING AGREEMENT We are included in the consolidated federal income tax and state franchise tax returns of Northern States Power. We calculate our tax position on a separate company basis under a tax sharing agreement with Northern States Power and receive payment from Northern States Power for tax benefits they receive by our inclusion on their tax returns and pay Northern States Power for tax liabilities created by such inclusion. 73

78 LONG-TERM DEBT The construction cost of the Newport facilities was financed through tax exempt variable rate resource recovery revenue bonds issued by the two Minnesota counties served by the facilities, which have subsequently been converted to fixed rate resource recovery revenue bonds with an effective interest rate of 6.57% per annum and annual maturities each December through 2006. The proceeds of such bond issuance were loaned by the counties to Northern States Power, which agreed under a loan agreement to pay to the counties amounts sufficient to pay debt service on the bonds. We issued a separate note to Northern States Power in an original principal amount of approximately $10 million as part of the consideration for the purchase of the facility from Northern States Power. OPTION AGREEMENT Before this offering is completed, we will enter into an option agreement with Northern States Power under which we will grant to Northern States Power and its affiliates a continuing option to purchase additional shares of common stock. If we issue any additional equity securities after this offering, Northern States Power and its affiliates may exercise this option to purchase shares of common stock to the extent necessary for them to maintain their then-existing percentage of the total voting power. The purchase price of the shares of common stock will be the market price of the common stock. The stock option expires if Northern States Power and its affiliates beneficially own less than % of the outstanding common stock and class A common stock on a combined basis. REGISTRATION RIGHTS AGREEMENT On 2000, we entered into a registration rights agreement with Northern States Power, under which we have agreed to register the shares of common stock issuable upon conversion of shares of class A common stock held by Northern States Power under the following circumstances: - Demand Rights. Upon the written request of Northern States Power, we will register shares of common stock held by Northern States Power specified in its request for resale under an appropriate registration statement filed and declared effective by the Securities and Exchange Commission. Northern States Power may make a demand so long as: - it requests registration of shares with an anticipated aggregate offering price of at least $20 million; - it has made no more than four such previous requests; - we have not completed a registered offering of common stock within the last 180 days; and - our chief executive officer has not determined it advisable to delay the offering for a period of 180 days, which determination may only be made once every twelve months. - Piggyback Rights. If at any time we register newly issued shares of common stock, or register outstanding shares of common stock for resale on behalf of any holder of our common stock, Northern States Power may elect to include in such registration any shares of common stock it holds. If the offering is an underwritten offering, the managing underwriter may exclude all or a part of Northern States Power's shares if market factors dictate, but only if Northern States Power is not exercising a demand right, described above, and only if all other shares being sold by other stockholders are excluded first. - Lockup. In consideration for these registration rights, Northern States Power has agreed not to sell shares of common stock for a period of 180 days following the date of this prospectus. - Termination. The registration rights agreement will terminate upon the earlier of or the date on which all remaining shares of common stock held by Northern States Power, or issuable to Northern States Power upon conversion of class A common stock, may be sold in any 90-day period in compliance with Rule 144 under the Securities Act. 74

79 DESCRIPTION OF CAPITAL STOCK AUTHORIZED STOCK The authorized capital stock of NRG consists of shares of common stock, par value, shares of class A common stock, par value and shares of preferred stock, par value. All of the issued and outstanding capital stock is fully paid and nonassessable. The following summary of the shares of common stock, class A common stock and preferred stock is qualified by reference to our certificate of incorporation a copy of which we will provide to you upon your request, and a copy of which is filed as an exhibit to the registration statement to which this prospectus relates. COMPARISON OF OUR COMMON STOCK AND CLASS A COMMON STOCK The following table compares our common stock and class A common stock. COMMON SHARES CLASS A COMMON SHARES ------------- --------------------- Public Market................ Will be listed on the None. , subject to official notice of issuance. Voting Rights................ One vote per share on all Ten votes per share on all matters voted upon by our matters voted upon by our stockholders. stockholders. Transfer Restrictions........ None. None, but will convert to common stock on a share-for- share basis upon any transfer (including by way of merger, consolidation or reorganization) or if the number of outstanding shares of class A common stock drops below shares. Conversion................... Not convertible. Convertible at any time, in whole or in part, into shares of common stock on a share-for-share basis. Automatically converts into common stock on a share-for-share basis upon any transfer (including by way of merger, consolidation or reorganization) or if the number of outstanding shares of class A common stock drops below shares. Reissuance................... Additional shares may be No additional shares may be issued and redeemed shares issued, and shares redeemed may be reissued. or repurchased will be canceled and may not be reissued. PREFERRED STOCK Our board of directors has the authority to issue shares of preferred stock from time to time on terms that it may determine, to divide preferred stock into one or more classes or series, and to fix the designations, voting powers, preferences and relative participating, optional or other special rights of each 75

80 class or series, and the qualifications, limitations or restrictions of each class or series, to the fullest extent permitted by Delaware law. The issuance of preferred stock could have the effect of decreasing the market price of our common stock, impeding or delaying a possible takeover and adversely affecting the voting and other rights of the holders of common stock. Currently, there are no shares of preferred stock outstanding and there are no shares of preferred stock designated other than our series A redeemable preferred stock. See "-- Rights Plan." OTHER PROVISIONS RELATING TO COMMON STOCK AND CLASS A COMMON STOCK If we in any manner split, subdivide or combine the outstanding shares of common stock or class A common stock, the outstanding shares of the other class of common stock will be proportionally subdivided or combined in the same manner and on the same basis. In all other respects, whether as to dividends, upon liquidation, dissolution or winding up, or otherwise, the holders of record of common stock and the holders of record of class A common stock have identical rights and privileges on the basis of the number of shares held. ADVANCE NOTICE REQUIREMENTS FOR STOCKHOLDER PROPOSALS Our bylaws provide that stockholders seeking to bring business before an annual meeting of stockholders must provide timely notice of their proposal in writing to the corporate secretary. To be timely, a stockholder's notice must be delivered or mailed and received at our principal executive offices not less than 120 days in advance of the anniversary date of our proxy statement in connection with our previous year's annual meeting. Our bylaws also specify requirements as to the form and content of a stockholder's notice. These provisions may impede stockholders' ability to bring matters before an annual meeting of stockholders or make nominations for directors at an annual meeting of stockholders. So long as Northern States Power or its successors by way of merger or consolidation own at least shares of class A common stock, it will be exempt from these provisions. SPECIAL MEETINGS Holders of our common stock may not call a special meeting of stockholders; only our board of directors may call such a meeting. BUSINESS COMBINATIONS WITH INTERESTED STOCKHOLDERS We will not be subject to the business combination provisions of Section 203 of the Delaware General Corporation Law, but our certificate of incorporation will contain provisions substantially similar to Section 203. In general, these provisions will prohibit us from engaging in various business combination transactions with any interested stockholder for a period of three years after the date of the transaction in which the person became an interested stockholder unless: - the business combination transaction, or the transaction in which the interested stockholder became an interested stockholder, is approved by our board of directors prior to the date the interested stockholder obtained this status, - upon consummation of the transaction which resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% or our common stock outstanding at the time the transaction commenced, excluding for purposes of determining the number of shares outstanding those shares owned by: - persons who are directors and also officers; and - employee stock plans in which employee participants do not have the right to determine confidentially whether shares held subject to the plan will be tendered in a tender or exchange offer; or 76

81 - on or subsequent to this date the business combination is approved by our board of directors and authorized at an annual or special meeting of stockholders by the affirmative vote of at least 66 2/3% of our outstanding common stock which is not owned by the interested stockholder. Under our certificate of incorporation, a business combination is defined to include mergers, asset sales and other transactions resulting in financial benefit to a stockholder. In general, an interested stockholder is a person who, together with affiliates and associates, owns or, within three years, did own, 15% or more of our common stock. Northern States Power and its affiliates, including Xcel Energy upon the completion of Northern States Power's pending merger, will be exempt from these provisions. AMENDMENT Our certificate of incorporation also provides that, after the first date that Northern States Power or Xcel Energy, together with their respective affiliates, ceases to beneficially own at least % of the outstanding shares of common stock, the affirmative vote of the holders of at least 80% of the outstanding shares of common stock is required to amend the provisions of our certificate of incorporation described above under "-- Advance Notice Requirement for Stockholder Proposals," "-- Special Meetings," and "-- Business Combinations with Interested Stockholders." Under our certificate of incorporation and by-laws, our by-laws may only be amended: - at any time by the affirmative vote of directors constituting not less than a majority of the entire board of directors; - prior to the first date that Northern States Power or Xcel Energy, together with their respective affiliates, cease to beneficially own at least 49% of the outstanding shares of common stock, by the affirmative vote of the holders of a majority of the outstanding shares of common stock; or - after that date, by the affirmative vote of the holders of a least 80% of the outstanding shares of common stock. RIGHTS PLAN We have declared a dividend on shares of common stock and class A common stock for holders of record as of the closing date of this offering consisting of the right to purchase shares of our series A redeemable preferred stock for a purchase price equal to $ per share upon the occurrence of a "triggering event." The triggering event is the acquisition by a person or entity of shares of common stock, the result of which is that such person or entity has beneficial ownership of % of more of the voting power of the outstanding common stock, unless such acquisition was approved in advance by our board of directors. The series A redeemable preferred stock, when issued, will entitle the holder thereof to purchase shares of our common stock. The rights may be redeemed by us at a price of $ per right. Our rights plan makes it highly unlikely that any third party could acquire us without the approval of our board of directors. REGISTRATION RIGHTS We have agreed to register shares of our common stock on behalf of Northern States Power as described in "Relationships and Related Transactions -- Registration Rights Agreement." LIMITATIONS ON LIABILITY AND INDEMNIFICATION OF OFFICERS AND DIRECTORS The Delaware General Corporation Law authorizes corporations to limit or eliminate the personal liability of directors to corporations and their stockholders for monetary damages for breaches of directors' fiduciary duties. Our certificate of incorporation includes a provision that eliminates the personal liability of directors for monetary damages for actions taken as a director, except for liability: - for breach of duty of loyalty; 77

82 - for acts or omissions not in good faith or involving intentional misconduct or knowing violation of law; - under Section 174 of the Delaware General Corporation Law (unlawful dividends); and - for transactions from which the director derived improper personal benefit. Our bylaws provide that we must indemnify our directors and officers to the fullest extent authorized by the Delaware General Corporation Law, subject to very limited exceptions. We are also expressly authorized to carry directors' and officers' insurance providing indemnification for our directors, officers and certain employees for some liabilities. We believe that these indemnification provisions and insurance are necessary to attract and retain qualified directors and executive officers. The limitation of liability and indemnification provisions in our certificate of incorporation, bylaws and indemnification agreements may discourage stockholders from bringing a lawsuit against directors for breach of their fiduciary duty. These provisions may also have the effect of reducing the likelihood of derivative litigation against directors and officers, even though such an action, if successful, might otherwise benefit us and our stockholders. In addition, your investment may be adversely affected to the extent we pay the costs of settlement and damage awards against directors and officers pursuant to these indemnification provisions. There is currently no pending litigation or proceeding involving any of our directors, officers or employees for which indemnification is sought. Except for an action recently brought by one of our stockholders against us and each of our directors, we are unaware of any pending or threatened litigation that may result in claims for indemnification. TRANSFER AGENT Norwest Bank, N.A. will act as the transfer agent for the common stock. 78

83 DESCRIPTION OF INDEBTEDNESS $125 MILLION 7.625% SENIOR NOTES DUE 2006; $250 MILLION 7.5% SENIOR NOTES DUE 2007; AND $300 MILLION 7.5% SENIOR NOTES DUE 2009 In January 1996, we sold $125 million of 7.625% Senior Notes due 2006 in a transaction exempt from registration under the Securities Act. All of the 7.625% Senior Notes due 2006 are still outstanding. In June 1997, we sold $250 million of 7.5% Senior Notes due 2007 in a transaction exempt from registration under the Securities Act. On January 20, 1998, we issued in an offering registered under the Securities Act an aggregate principal amount of $250 million of 7.5% Senior Notes due 2007 in exchange for all the unregistered 7.5% Senior Notes due 2007 issued on June 17, 1997. All of the 7.5% Senior Notes due 2007 are still outstanding. In May 1999, we sold $300 million of 7.5% Senior Notes due 2009 in an offering registered under the Securities Act. All of the 7.5% Senior Notes due 2009 are still outstanding. Each of the 7.625% Senior Notes due 2006, the 7.5% Senior Notes due 2007 and the 7.5% Senior Notes due 2009 are governed by the terms of an indenture. The material terms of the indentures are described below. As a summary, the following discussion necessarily omits many of the details of the indentures. A copy of the indentures have been filed as an exhibit to the registration statement of which this prospectus is a part. Interest on the 7.625% Senior Notes due 2006 is payable semiannually in arrears on each February 1 and August 1. Interest on the 7.5% Senior Notes due 2007 is payable semiannually in arrears on each June 15 and December 15. Interest on the 7.5% Senior Notes due 2009 is payable semiannually in arrears on each June 1 and December 1. OPTIONAL REDEMPTION The 7.625% Senior Notes due 2006 are redeemable, in whole or in part, at any time after February 1, 2001, and the 7.5% Senior Notes due 2007 and the 7.5% Senior Notes due 2009 are redeemable, in whole or in part, at any time. In each case, the redemption price to be repaid is the greater of: - 100% of principal amount of the senior notes, plus accrued interest on the principal amount, if any, to the redemption date; or - a discounted sum of the present values of all of the remaining scheduled payments of principal and interest from the redemption date to maturity on the senior notes. CHANGE OF CONTROL If a change of control occurs, we must make an offer to purchase all outstanding 7.625% Senior Notes due 2006, 7.5% Senior Notes due 2007 and 7.5% Senior Notes due 2009 at a purchase price equal to 101% of their principal amount plus accrued and unpaid interest. This requirement could deter a change of control transaction in which stockholders could receive a premium. However, no change of control will be deemed to have occurred if the rating remains investment grade. COVENANTS RESTRICTING OUR ACTIONS Each of the indentures contain covenants which generally prohibit or restrict our ability to pledge, mortgage, hypothecate or permit to exist any lien upon our property to secure any indebtedness for borrowed money unless the senior notes are equally and ratably secured. In addition, the indenture for the 7.625% Senior Notes due 2006 requires us to maintain a tangible net worth of greater than the sum of $175 million plus 25% of our consolidated net income for the period from and including April 1, 1996 to the determination date of such income. 79

84 EVENTS OF DEFAULT The following are "events of default" under each of the indentures: - our failure to pay any interest on the senior notes when due, which failure continues for 30 days; - our failure to pay principal or premium (including in connection with a change of control) on the senior notes when due; - our failure to perform any other covenant relating to the senior notes for a period of 30 days after the trustee gives us written notice or we receive written notice by the holders of at least 25% in aggregate principal amount of the senior notes; - an event of default occurring under any of our instruments under which there may be issued, or by which there may be secured or evidenced, any indebtedness for money borrowed that has resulted in the acceleration of the indebtedness, or any default occurring in payment of any indebtedness at final maturity and after the expiration of any applicable grace periods, other than: - indebtedness that is payable solely out of the property or assets of a partnership, joint venture or similar entity of which we or any of our subsidiaries or affiliates is a participant, or that is secured by a lien on the property or assets owned or held by that entity without further recourse to us; or - indebtedness not exceeding $20 million; - one or more final judgments, decrees or orders for the payment of money aggregating $20 million or more, either individually or in the aggregate, shall be entered against us and shall remain undischarged, unvacated and unstayed for more than 90 days, except while being contested in good faith by appropriate proceedings; and - a bankruptcy, insolvency, reorganization or receivership or similar proceedings with respect to us. $240 MILLION 8% REMARKETABLE OR REDEEMABLE SECURITIES ("ROARS") DUE 2013 (REMARKETING DATE NOVEMBER 1, 2003) In November 1999, we sold $240 million of 8% ROARS due 2013 in an offering registered under the Securities Act. All of the 8% ROARS due 2013 are still outstanding and interest on them is payable semiannually in arrears on each November 1 and May 1. The ROARS are governed by the terms of an indenture. The material terms of the indenture are described below. As a summary, the following discussion necessarily omits many of the details of the indenture. A copy of the indenture has been filed as an exhibit to the registration statement of which this prospectus is a part. CHANGE OF CONTROL If a change of control (as defined in the indenture) occurs, we must make an offer to purchase all outstanding ROARS then outstanding at a purchase price equal to 101% of their principal amount plus accrued and unpaid interest. This requirement could deter a change of control transaction in which stockholders could receive a premium. However, no change of control will be deemed to have occurred if the rating remains investment grade. COVENANTS RESTRICTING OUR ACTIONS The indenture for the ROARS contains covenants which generally prohibit or restrict our ability to pledge, mortgage, hypothecate or permit to exist any lien upon our property to secure any indebtedness for borrowed money unless the senior notes are equally and ratably secured. 80

85 EVENTS OF DEFAULT The "events of default" under the indenture governing the ROARS are substantially equivalent to those previously described with respect to the senior notes. MANDATORY TENDER We have entered into a Remarketing Agreement with Credit Suisse Financial Products pursuant to which Credit Suisse has the option to purchase all of the ROARS on November 1, 2003 at a purchase price equal to 100% of the aggregate principal amount outstanding. The ROARS will be remarketed at a fixed rate of interest unless we have redeemed the ROARS or have exercised our option to have the ROARS remarketed at a floating rate of interest for up to twelve months following November 1, 2003. If we have elected to have the ROARS remarketed at a floating rate of interest for up to twelve months, Credit Suisse will have the option to purchase all of the ROARS at the end of the applicable floating rate period at a discounted sum of the present values of all of the remaining scheduled payments of principal and interest from the redemption date to maturity on the ROARS. OPTIONAL REDEMPTION If Credit Suisse exercises its purchase option on November 1, 2003 or at the end of the applicable floating rate period, if any, we have the option of redeeming all of the ROARS at a discounted sum of the present values of all of the remaining scheduled payments of principal and interest from the redemption date to maturity on the ROARS. MANDATORY REDEMPTION We will be required to redeem the ROARS in whole on November 1, 2003 or at the end any floating rate period in the event that Credit Suisse elects not to exercise its option to purchase the ROARS. If we are required to redeem the ROARS, we will redeem them at a purchase price equal to: - if redeemed on November 1, 2003, 100% of the aggregate principal amount outstanding; or - if redeemed at the end of any floating rate period, a discounted sum of the present values of all of the remaining scheduled payments of principal and interest from the redemption date to maturity on the ROARS. L160 MILLION 7.97% RESET SENIOR NOTES DUE 2020 In March 2000, we sold L160 million (approximately $250 million) of 7.97% Reset Senior Notes due 2020 in a transaction exempt from registration under the Securities Act. All of the 7.97% Reset Senior Notes were sold to the NRG Energy Pass-Through Trust 2000-1, a trust formed pursuant to a trust agreement between us and The Bank of New York, as trustee. The trust issued $250 million aggregate principal amount of certificates that represented an undivided beneficial interest in the assets of the trust, which assets consist principally of the 7.97% Reset Senior Notes. Interest on the 7.97% Reset Senior Notes is payable semiannually in arrears on each September 15 and March 15. The 7.97% Reset Senior Notes are governed by the terms of an indenture. The material terms of the indenture are described below. As a summary, the following discussion necessarily omits many of the details of the indenture. A copy of the indenture has been filed as an exhibit to the registration statement of which this prospectus is a part. CHANGE OF CONTROL If a change of control (as defined in the indenture) occurs on or before March 15, 2005 in L, we must make an offer to purchase all 7.97% Reset Senior Notes then outstanding at a purchase price equal to 100% of their principal amount plus accrued and unpaid interest plus a payment in U.S. dollars equal to 1% of the principal amount of trust certificates to be redeemed by the trust pursuant to a similar change of 81

86 control offer under the trust agreement. If a change of control occurs prior to March 15, 2005, but after an event of default that results in the principal amount of the 7.97% Reset Senior Notes being due and payable immediately, we may be required to purchase all or a part of the notes at a price in U.S.$ equal to 101% of the principal amount plus accrued and unpaid interest. If a change of control occurs after March 15, 2005, we must make an offer to purchase all 7.97% Reset Senior Notes then outstanding at a purchase price in L equal to 101% of their principal amount plus accrued and unpaid interest. This requirement could deter a change of control transaction in which stockholders could receive a premium. However, no change of control will be deemed to have occurred if the rating remains investment grade. COVENANTS RESTRICTING OUR ACTIONS The indenture for our 7.97% Reset Senior Notes contains covenants which generally prohibit or restrict our ability to pledge, mortgage, hypothecate or permit to exist any lien upon our property to secure any indebtedness for borrowed money unless the senior notes are equally and ratably secured. EVENTS OF DEFAULT The "events of default" under the indenture governing the 7.97% Reset Senior Notes are substantially equivalent to those previously described with respect to the senior notes. MANDATORY TENDER We have entered into a Remarketing Agreement and a Call Agreement with Bank of America, N.A. pursuant to which Bank of America has the option to purchase all of the 7.97% Reset Senior Notes on March 15, 2005 at a purchase price equal to 100% of the aggregate principal amount outstanding. The 7.97% Reset Senior Notes will be remarketed at a fixed rate of interest unless we have redeemed the 7.97% Reset Senior Notes or have exercised our option to have the 7.97% Reset Senior Notes remarketed at a floating rate of interest for up to twelve months following March 15, 2005. If we have elected to have the 7.97% Reset Senior Notes remarketed at a floating rate of interest for up to twelve months, Bank of America will have the option to purchase all of the 7.97% Reset Senior Notes at the end of the applicable floating rate period at a discounted sum of the present values of all of the remaining scheduled payments of principal and interest from the redemption date to maturity on the 7.97% Reset Senior Notes. OPTIONAL REDEMPTION If Bank of America exercises its purchase option on March 15, 2005 or at the end of the applicable floating rate period, if any, we have the option of redeeming all of the 7.97% Reset Senior Notes at a discounted sum of the present values of all of the remaining scheduled payments of principal and interest from the redemption date to maturity on the 7.97% Reset Senior Notes. MANDATORY REDEMPTION We will be required to redeem the 7.97% Reset Senior Notes in whole on March 15, 2005 or at the end any floating rate period in the event that Bank of America elects not to exercise its option to purchase the 7.97% Reset Senior Notes. If we are required to redeem the 7.97% Reset Senior Notes, we will redeem them at a purchase price equal to: - if redeemed on March 15, 2005, 100% of the aggregate principal amount outstanding; or - if redeemed at the end of any floating rate period, a discounted sum of the present values of all of the remaining scheduled payments of principal and interest from the redemption date to maturity on the 7.97% Reset Senior Notes. ABN AMRO REVOLVING CREDIT FACILITY In March 2000, we entered into a $500 million revolving credit facility with ABN AMRO Bank, N.V., as agent, and various lenders. The facility is unsecured and provides for borrowings of "Base Rate 82

87 Loans" and "Eurocurrency Loans." The Base Rate Loans bear interest at the greater of ABN AMRO's prime rate or the sum of the prevailing per annum rates for overnight funds plus 0.5% per annum plus an additional 0.125% if we draw upon greater than one-third of the facility amount and an additional 0.25% if we draw upon greater than two-thirds of the facility amount. The Eurocurrency loans bear interest at an adjusted rate based on LIBOR plus an adjustment percentage of from between 0.4% to 1.8% per annum, depending on NRG's senior debt credit rating and the amount outstanding under the facility. The facility terminates on March 9, 2001. The facility contains covenants that restrict the incurrence of liens and require us to maintain a net worth of at least $700 million plus 25% of our net income from January 1, 2000 through the determination date. In addition, we must maintain a debt to capitalization ratio of not more than 0.68 to 1.0 or not more than 0.72 to 1.0 for any consecutive two months in a six month period. An event of default under the standby Letter of Credit Facility (described below) is also an event of default under this facility. STANDBY LETTER OF CREDIT FACILITY In November 1999, we entered into a $125 million standby letter of credit facility with Australia and New Zealand Banking Group Limited, as administrative agent. The facility is unsecured and provides for the issuances of letters of credit for our account with respect to financial and performance guarantees that we undertake. The facility terminates on November 30, 2002 unless extended in accordance with the terms of the facility. The facility contains covenants that restrict the incurrence of liens and require us to maintain a net worth to capitalization ratio of 0.32 to 1.0 for each fiscal quarter. In addition, the facility requires us to maintain a minimum net worth of at least $500 million plus 25% of our net income for each fiscal quarter beginning with the fiscal quarter ending September 30, 1999 for which net income is positive through the fiscal quarter ending on or ending last prior to the determination date. 83

88 SHARES ELIGIBLE FOR FUTURE SALE Prior to this offering, there has been no public market for the common stock. We cannot provide any assurance that a significant public market for the common stock will develop or be sustained after this offering. Future sales of substantial amounts of common stock in the public market, or the possibility of such sales occurring, could adversely affect prevailing market prices for the common stock or our future ability to raise capital through an offering of equity securities. After this offering, we will have outstanding shares of common stock or shares if the underwriters' over-allotment option is exercised in full. All of these shares will be freely tradable in the public market without restrictions under the Securities Act, except for any such shares acquired by an "affiliate" of NRG as that term is defined in Rule 144 under the Securities Act, which shares will remain subject to resale limitations of Rule 144. Northern States Power owns shares of class A common stock, which represent % of the total number of both common stock and class A common stock outstanding and which are immediately convertible into an equal number of shares of common stock upon the election of Northern States Power or upon a sale of shares of class A common stock to a third party. We have agreed, if so requested by Northern States Power, to file registration statements and take other steps to enable Northern States Power to sell shares of common stock held by it, including but not limited to shares of common stock acquired by conversion of shares of class A common stock. In addition, beginning 90 days after the date of this prospectus, Northern States Power will be entitled to make sales under Rule 144 of limited quantities of common stock. However, we and Northern States Power have agreed with the underwriters, subject to certain exceptions, not to sell any shares of common stock for a period of 180 days following the date of this prospectus. Generally, Rule 144 provides that an affiliate may sell on the open market in brokers' transactions within any three month period a number of shares that does not exceed the greater of: - 1% of the then outstanding shares of common stock; and - the average weekly trading volume in the common stock on the open market during the four calendar weeks preceding the sale. Sales under Rule 144 will also be subject to post-sale notice requirements and the availability of current public information about NRG. Shares properly sold in reliance upon Rule 144 to persons who are not affiliates are freely tradable without restriction after the sale. 84

89 MATERIAL UNITED STATES TAX CONSEQUENCES TO NON-UNITED STATES HOLDERS The following discussion is a summary of the material United States federal income and estate tax consequences of the ownership and disposition of our common stock to beneficial owners that are Non-United States persons. This discussion does not deal with all aspects of United States income and estate taxation and does not deal with foreign, state and local tax consequences that may be relevant to Non-United States persons in light of their personal circumstances. Furthermore, this discussion is based on the Internal Revenue Code of 1986, as amended, Treasury Department regulations, published positions of the Internal Revenue Service and court decisions now in effect, all of which are subject to change. YOU SHOULD CONSULT YOUR OWN TAX ADVISOR WITH REGARD TO THE APPLICATION OF THE FEDERAL INCOME TAX LAWS, AS WELL AS TO THE APPLICABILITY AND EFFECT OF ANY STATE, LOCAL OR FOREIGN TAX LAWS TO WHICH YOU MAY BE SUBJECT. Under the Code, a "Non-United States person" means a person that is not any of the following: - a citizen or resident of the United States; - a corporation or partnership created or organized in or under the laws of the United States or any political subdivision of the United States; - an estate the income of which is subject to United States federal income taxation regardless of its source; or - a trust that: - is subject to the supervision of a court within the United States and the control of one or more United States persons; or - has a valid election in effect under applicable United States Treasury regulations to be treated as a United States person. DIVIDENDS Generally, any dividend paid to a Non-United States person will be subject to United States withholding tax either at a rate of 30% of the gross amount of the dividend or at a lesser applicable treaty rate. However, dividends that are effectively connected with the conduct of a trade or business within the United States and, where a tax treaty applies, that are attributable to a United States permanent establishment are not subject to the withholding tax but instead are subject to United States federal income tax on a net income basis at applicable graduated individual or corporate rates. Certain certification and disclosure requirements must be complied with in order to be exempt from withholding under the effectively connected income exemption. Any effectively connected dividends received by a foreign corporation may, under certain circumstances, be subject to an additional "branch profits tax" at a 30% rate or a lesser applicable treaty rate. Until January 1, 2001, dividends paid to an address outside the United States are presumed to be paid to a resident of that country, unless the payer has knowledge to the contrary, for purposes of the withholding tax discussed above and, under the current interpretation of the United States Treasury regulations, for purposes of determining the applicability of a tax treaty rate. However, under United States Treasury regulations, if you wish to claim the benefit of an applicable treaty rate and avoid backup withholding, as discussed below, for dividends paid after December 31, 2000, you will be required to satisfy applicable certification and other requirements. If you are eligible for a reduced treaty rate of United States withholding tax pursuant to an income tax treaty, you may obtain a refund of any excess amounts withheld by filing an appropriate claim for refund with the Internal Revenue Service. 85

90 GAIN ON DISPOSITION OF COMMON STOCK If you are a Non-United States person, you will generally not be subject to United States federal income tax with respect to gain recognized on a sale or other disposition of our common stock unless: - the gain is effectively connected with a trade or business in the United States and, where a tax treaty provides, the gain is attributable to a United States permanent establishment; - if you are an individual and hold our common stock as a capital asset, you are present in the United States for 183 or more days in the taxable year of the sale or other disposition and certain other conditions are met; - you are subject to tax pursuant to the provisions of the Code regarding taxation of certain U.S. expatriates; or - we are or have been a "United States real property holding corporation" for United States federal income tax purposes. We believe that we are not, and do not anticipate becoming, a "United States real property holding corporation" for United States federal income tax purposes. If we were to become a United States real property holding corporation, so long as our common stock continues to be regularly traded on an established securities market, you would be subject to federal income tax on any gain from the sale or other disposition of the stock only if you actually or constructively owned, during the five-year period preceding the disposition, more than 5% of our common stock. Special rules may apply to certain Non-United States persons, such as "controlled foreign corporations," "passive foreign investment companies," "foreign personal holding companies" and corporations that accumulate earnings to avoid federal income tax, that are subject to special treatment under the Code. These entities should consult their own tax advisors to determine the United States federal, state, local and other tax consequences that may be relevant to them. BACKUP WITHHOLDING AND INFORMATION REPORTING We must report annually to the Internal Revenue Service and to you the amount of dividends paid to you and the tax withheld with respect to these dividends, regardless of whether withholding was required. Copies of the information returns reporting the dividends and withholding may also be made available to the tax authorities in the country in which you reside under the provisions of an applicable income tax treaty. Under current law, backup withholding at the rate of 31% generally will not apply to dividends paid to you at an address outside the United States, unless the payer has knowledge that you are a United States person. Under the final regulations effective December 31, 2000, however, you will be subject to backup withholding unless applicable certification requirements are met. Payment of the proceeds of a sale of our common stock within the United States or conducted through certain U.S. related financial intermediaries is subject to both backup withholding and information reporting unless you certify under penalties of perjury that you are a Non-United States person, and the payer does not have actual knowledge that you are a United States person, or you otherwise establish an exemption. Any amounts withheld under the backup withholding rules may be allowed as a refund or a credit against your United States federal income tax liability provided the required information is furnished to the Internal Revenue Service. ESTATE TAX Common stock held by an individual Non-United States person at the time of death will be included in that holder's gross estate for United States federal estate tax purposes, unless an applicable estate tax treaty provides otherwise. 86

91 UNDERWRITING Subject to the terms and conditions stated in the underwriting agreement dated the date hereof, each underwriter named below has severally agreed to purchase, and NRG Energy, Inc. has agreed to sell to such underwriter, the number of shares set forth opposite the name of such underwriter. NUMBER NAME OF SHARES ---- --------- Salomon Smith Barney Inc.................................... Credit Suisse First Boston Corporation...................... ABN AMRO Incorporated....................................... Banc of America Securities LLC.............................. Goldman, Sachs & Co......................................... Lehman Brothers Inc......................................... Merrill Lynch, Pierce, Fenner & Smith Incorporated................................... Morgan Stanley & Co. Incorporated........................... ------- Total..................................................... ======= The underwriting agreement provides that the obligations of the several underwriters to purchase the shares included in this offering are subject to approval of certain legal matters by counsel and to certain other conditions. The underwriters are obligated to purchase all the shares (other than those covered by the over-allotment option described below) if they purchase any of the shares. The underwriters, for whom Salomon Smith Barney Inc. and Credit Suisse First Boston Corporation, ABN AMRO Incorporated, Banc of America Securities LLC, Goldman, Sachs & Co., Lehman Brothers Inc., Merrill Lynch, Pierce Fenner & Smith Incorporated and Morgan Stanley & Co. Incorporated are acting as representatives, propose to offer some of the shares directly to the public at the public offering price set forth on the cover page of this prospectus and some of the shares to certain dealers at the public offering price less a concession not in excess of $ per share. The underwriters may allow, and such dealers may reallow, a concession not in excess of $ per share on sales to certain other dealers. If all of the shares are not sold at the initial offering price, the representatives may change the public offering price and the other selling terms. We have granted to the underwriters an option, exercisable for 30 days from the date of this prospectus, to purchase up to additional shares of common stock at the public offering price less the underwriting discount. The underwriters may exercise such option solely for the purpose of covering over-allotments, if any, in connection with this offering. To the extent such option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase a number of additional shares approximately proportionate to such underwriter's initial purchase commitment. We, our officers and directors, and Northern States Power have agreed that, for a period of 180 days from the date of this prospectus, they will not, without the prior written consent of Salomon Smith Barney Inc., dispose of or hedge any shares of our common stock or any securities convertible into or exchangeable for common stock. Salomon Smith Barney Inc. in its sole discretion may release any of the securities subject to these lock-up agreements at any time without notice. Prior to this offering, there has been no public market for the common stock. Consequently, the initial public offering price for the shares was determined by negotiations among us and the representatives. Among the factors considered in determining the initial public offering price were our record of operations, our current financial condition, our future prospects, our markets, the economic conditions in and future prospects for the industry in which we compete, our management, and currently prevailing general conditions in the equity securities markets, including current market valuations of publicly traded companies considered comparable to us. There can be no assurance, however, that the prices at which the shares will sell in the public market after this offering will not be lower than the price at which they are 87

92 sold by the underwriters or that an active trading market in the common stock will develop and continue after this offering. We will apply to have the common stock listed on the under the symbol " ". The following table shows the underwriting discounts and commissions to be paid to the underwriters by us in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters' option to purchase additional shares of common stock. PAID BY NRG ---------------------------- NO EXERCISE FULL EXERCISE ----------- ------------- Per share................................................... $ $ Total....................................................... $ $ In connection with the offering, Salomon Smith Barney Inc., on behalf of the underwriters, may purchase and sell shares of common stock in the open market. These transactions may include over-allotment, syndicate covering transactions and stabilizing transactions. Over-allotment involves syndicate sales of common stock in excess of the number of shares to be purchased by the underwriters in the offering, which creates a syndicate short position. Syndicate covering transactions involve purchases of the common stock in the open market after the distribution has been completed in order to cover syndicate short positions. Stabilizing transactions consist of certain bids or purchases of common stock made for the purpose of preventing or retarding a decline in the market price of the common stock while the offering is in progress. The underwriters also may impose a penalty bid. Penalty bids permit the underwriters to reclaim a selling concession from a syndicate member when Salomon Smith Barney Inc., in covering syndicate short positions or making stabilizing purchases, repurchases shares originally sold by that syndicate member. Any of these activities may cause the price of the common stock to be higher than the price that otherwise would exist in the open market in the absence of such transactions. These transactions may be effected on the or in the over-the-counter market, or otherwise and, if commenced, may be discontinued at any time. We estimate that the total expenses of this offering will be $ . The representatives have performed certain investment banking and advisory services for us from time to time for which they have received customary fees and expenses. The representatives may, from time to time, engage in transactions with and perform services for us in the ordinary course of their business. We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933, or to contribute to payments the underwriters may be required to make in respect of any of those liabilities. Because an affiliate of Salomon Smith Barney Inc. is a party to the $300 million Citicorp USA loan with us, which will be repaid with the proceeds of this offering, this offering is being conducted in accordance with Rule 2720 of the National Association of Securities Dealers, Inc. That rule requires that the initial public offering price may be no higher than that recommended by a "qualified independent underwriter", as defined by the NASD. is serving in that capacity and has conducted due diligence and participated in the preparation of the registration statement of which this prospectus forms a part. The initial public offering price will be no higher than that recommended by . At our request, the underwriters have reserved for sale, at the initial public offering price, up to 5% of the shares offered hereby to be sold to some of our employees, management and directors. The number of shares of our common stock available for sale to the general public will be reduced to the extent that those persons purchase the reserved shares. Any reserved shares not so purchased will be offered to the general public on the same terms as the other shares. 88

93 LEGAL MATTERS The validity of the shares of common stock being offered will be passed on for NRG by Gibson Dunn & Crutcher LLP. Certain legal matters will be passed on for the underwriters by Skadden, Arps, Slate, Meagher & Flom LLP. Skadden, Arps, Slate, Meagher & Flom LLP has from time to time represented us and may in the future, from time to time, represent us in connection with various matters. EXPERTS The consolidated financial statements of NRG Energy, Inc. and the carve-out financial statements of Cajun Electric as of December 31, 1999 and 1998 and for each of the three years in the period ended December 31, 1999 included in this prospectus have been so included in reliance on the reports of PricewaterhouseCoopers LLP, independent accountants, given on the authority of said firm as experts in auditing and accounting. AVAILABLE INFORMATION We have filed with the United States Securities and Exchange Commission a registration statement on Form S-1 under the Securities Act about the common stock that we are offering. This prospectus does not contain all of the information set forth in the registration statement and the exhibits and schedules to it. In addition, we currently file, and after the offering we will continue to file, annual, quarterly and special reports, proxy statements and other information with the Commission. For further information with respect to us, please refer to these documents on file, including registration statement, and the exhibits and schedules thereto, which may be inspected without charge and copied at prescribed rates at the Public Reference Section of the Commission at Room 1024, 450 Fifth Street, N.W., Washington, D.C. 20549 and at the Commission's regional offices at 7 World Trade Center, Suite 1300, New York, New York 10048, and Northwestern Atrium Center, 500 West Madison Street, Suite 140, Chicago, Illinois 60661. The Commission maintains a website that contains reports, proxy and information statements and other information filed electronically with the Commission at http://www.sec.gov. 89

94 INDEX TO NRG ENERGY, INC. FINANCIAL STATEMENTS PAGE NO. -------- Independent Accountant's Report............................. F-2 Consolidated Statement of Income............................ F-3 Consolidated Statement of Cash Flows........................ F-4 Consolidated Balance Sheet.................................. F-5 Consolidated Statement of Stockholders' Equity.............. F-6 Notes to Consolidated Financial Statements.................. F-7 INDEX TO PRO-FORMA FINANCIAL STATEMENTS Introduction to Pro Forma Financial Statements.............. F-33 Pro Forma Balance Sheet..................................... F-34 Pro Forma Income Statement.................................. F-36 CAJUN ELECTRIC (CAJUN FACILITIES) INDEX TO CARVE-OUT FINANCIAL STATEMENTS PAGE NO. -------- Independent Accountant's Report............................. F-37 Carve-Out Statement of Net Assets........................... F-38 Carve-Out Statement of Certain Revenue and Expenses......... F-39 Notes to Financial Statements............................... F-40 F-1

95 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Stockholder of NRG Energy, Inc.: In our opinion, the accompanying consolidated balance sheet and the related consolidated statement of income, of stockholder's equity and of cash flows present fairly, in all material respects, the financial position of NRG Energy, Inc. (a wholly-owned subsidiary of Northern States Power Company) and its subsidiaries at December 31, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. /s/ PRICEWATERHOUSECOOPERS LLP March 17, 2000 F-2

96 NRG ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF INCOME YEAR ENDED DECEMBER 31, -------------------------------- 1999 1998 1997 ---- ---- ---- (THOUSANDS OF DOLLARS EXCEPT PER SHARE AMOUNTS) OPERATING REVENUES Revenues from wholly-owned operations..................... $432,518 $100,424 $ 92,052 Equity in earnings of unconsolidated affiliates........... 67,500 81,706 26,200 -------- -------- -------- Total operating revenues and equity earnings........... 500,018 182,130 118,252 -------- -------- -------- OPERATING COSTS AND EXPENSES Cost of wholly-owned operations........................... 269,900 52,413 46,717 Depreciation and amortization............................. 37,026 16,320 10,310 General, administrative and development................... 83,572 56,385 43,116 -------- -------- -------- Total operating costs and expenses..................... 390,498 125,118 100,143 -------- -------- -------- OPERATING INCOME............................................ 109,520 57,012 18,109 -------- -------- -------- OTHER INCOME (EXPENSE) Minority interest in earnings of consolidated subsidiary............................................. (2,456) (2,251) (131) Gain on sale of interest in projects...................... 10,994 29,950 8,702 Write-off of project investments.......................... -- (26,740) (8,964) Other income, net......................................... 6,432 8,420 11,764 Interest expense.......................................... (93,376) (50,313) (30,989) -------- -------- -------- Total other expense.................................... (78,406) (40,934) (19,618) -------- -------- -------- INCOME (LOSS) BEFORE INCOME TAXES........................... 31,114 16,078 (1,509) INCOME TAX BENEFIT.......................................... (26,081) (25,654) (23,491) -------- -------- -------- NET INCOME.................................................. $ 57,195 $ 41,732 $ 21,982 ======== ======== ======== EARNINGS PER SHARE-BASIC AND DILUTED........................ $ 57,195 $ 41,732 $ 21,982 ======== ======== ======== WEIGHTED AVERAGE SHARES OUTSTANDING-BASIC AND DILUTED....... 1,000 1,000 1,000 ======== ======== ======== See notes to consolidated financial statements. F-3

97 NRG ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF CASH FLOWS YEAR ENDED DECEMBER 31, ----------------------------------- 1999 1998 1997 ---- ---- ---- (THOUSANDS OF DOLLARS) CASH FLOWS FROM OPERATING ACTIVITIES Net income............................................... $ 57,195 $ 41,732 $ 21,982 Adjustments to reconcile net income to net cash provided by operating activities Undistributed equity in earnings of unconsolidated affiliates.......................................... (27,181) (23,391) 6,481 Depreciation and amortization......................... 37,026 16,320 10,310 Deferred income taxes and investment tax credits...... (3,401) 7,618 3,107 Minority interest..................................... 857 (5,019) -- Investment write-downs................................ -- 26,740 8,964 Gain on sale of investments........................... (10,994) (29,950) (8,702) Cash provided (used) by changes in certain working capital items, net of effects from acquisitions and dispositions Accounts receivable................................. (99,608) 297 (2,859) Accounts receivable-affiliates...................... 9,964 21,657 (19,963) Accrued income taxes................................ 25,834 (24,861) 1,762 Inventory........................................... (17,287) (28) (307) Other current assets................................ (13,433) 469 305 Accrued property and sales taxes.................... 1,740 (553) 1,645 Accounts payable.................................... 40,616 (8,082) 7,791 Accrued salaries, benefits, and related costs....... 1,955 4,735 3,826 Accrued interest.................................... 5,192 1,050 1,215 Other current liabilities........................... (3,533) (2,219) 6,084 Cash used by changes in other assets and liabilities...................................... (16,322) (4,517) (7,155) ----------- --------- --------- NET CASH (USED) PROVIDED BY OPERATING ACTIVITIES........... (11,380) 21,998 34,486 ----------- --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES Investments in projects............................... (163,340) (132,379) (318,149) Acquisition, net of liabilities assumed............... (1,519,365) -- (148,830) Consolidation of equity subsidiaries.................. 20,181 -- -- Cash from sale of project investment.................. 43,500 18,053 19,158 Decrease (increase) in notes receivable............... 58,331 16,858 (37,431) Capital expenditures.................................. (94,853) (31,719) (26,936) (Increase) decrease in restricted cash................ (13,067) (2,433) 16,100 Other, net............................................ -- -- 10,114 ----------- --------- --------- NET CASH USED BY INVESTING ACTIVITIES...................... (1,668,613) (131,620) (485,974) ----------- --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES Net borrowings under line of credit agreement......... 216,000 2,000 122,000 Capital contributions from parent..................... 250,000 100,000 80,900 Proceeds from issuance of long-term debt.............. 575,633 23,169 254,061 Proceeds from issuance of note........................ 682,096 -- -- Principal payments on long-term debt.................. (18,634) (21,152) (5,925) ----------- --------- --------- NET CASH PROVIDED BY FINANCING ACTIVITIES.................. 1,705,095 104,017 451,036 ----------- --------- --------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS....... 25,102 (5,605) (452) CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR............. 6,381 11,986 12,438 =========== ========= ========= CASH AND CASH EQUIVALENTS AT END OF YEAR................... $ 31,483 $ 6,381 $ 11,986 =========== ========= ========= SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION Interest paid (net of amount capitalized)............. $ 82,891 $ 49,089 $ 30,890 Income taxes paid (benefits received), net............ (54,384) (6,797) (24,577) See notes to consolidated financial statements. F-4

98 NRG ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET DECEMBER 31, ----------------------- 1999 1998 ---- ---- (THOUSANDS OF DOLLARS) ASSETS CURRENT ASSETS Cash and cash equivalents................................. $ 31,483 $ 6,381 Restricted cash........................................... 17,441 4,021 Accounts receivable-trade, less allowance for doubtful accounts of $186 and $100............................... 126,376 15,223 Accounts receivable-affiliates............................ -- 7,324 Taxes Receivable.......................................... -- 21,169 Current portion of notes receivable -- affiliates......... 287 4,460 Current portion of notes receivable....................... -- 26,200 Inventory................................................. 119,181 2,647 Prepayments and other current assets...................... 29,202 4,533 ---------- ---------- Total current assets.................................... 323,970 91,958 ---------- ---------- PROPERTY, PLANT AND EQUIPMENT, AT ORIGINAL COST In service................................................ 2,022,724 291,558 Under construction........................................ 53,448 5,352 ---------- ---------- Total property, plant and equipment..................... 2,076,172 296,910 Less accumulated depreciation............................. (156,849) (92,181) ---------- ---------- Net property, plant and equipment....................... 1,919,323 204,729 ---------- ---------- OTHER ASSETS Investments in projects................................... 988,671 800,924 Capitalized project costs................................. 2,592 13,685 Notes receivable, less current portion -- affiliates...... 65,494 101,887 Notes receivable, less current portion.................... 5,787 3,744 Intangible assets, net of accumulated amortization of $4,308 and $2,984....................................... 55,586 22,507 Debt issuance costs, net of accumulated amortization of $6,640 and $1,675....................................... 20,081 7,276 Other assets, net of accumulated amortization of $8,909 and $7,350.............................................. 50,180 46,716 ---------- ---------- Total other assets...................................... 1,188,391 996,739 ---------- ---------- TOTAL ASSETS................................................ $3,431,684 $1,293,426 ---------- ---------- LIABILITIES AND STOCKHOLDER'S EQUITY CURRENT LIABILITIES Current portion of project level long-term debt........... $ 30,462 $ 8,258 Revolving line of credit.................................. 340,000 -- Consolidated project level, non-recourse debt............. 35,766 -- Accounts payable-trade.................................... 61,211 7,371 Accounts payable-affiliate................................ 6,404 -- Accrued income taxes...................................... 4,730 -- Accrued property and sales taxes.......................... 4,998 3,251 Accrued salaries, benefits and related costs.............. 9,648 7,551 Accrued interest.......................................... 13,479 7,648 Other current liabilities................................. 17,657 8,289 ---------- ---------- Total current liabilities............................... 524,355 42,368 OTHER LIABILITIES: Minority interest......................................... 14,373 13,516 Consolidated project-level, long-term, non-recourse debt.................................................... 1,026,398 113,437 Corporate level long-term debt, less current portion...... 915,000 504,781 Deferred Income Taxes..................................... 16,940 19,841 Deferred Investment Tax Credits........................... 1,088 1,343 Postretirement and other benefit obligations.............. 24,613 11,060 Other long-term obligations and deferred income........... 15,263 7,748 ---------- ---------- Total liabilities....................................... 2,538,030 714,094 ---------- ---------- STOCKHOLDER'S EQUITY Common stock; $1 par value; 1,000 shares authorized; 1,000 shares issued and outstanding........................... 1 1 Additional paid-in capital................................ 781,913 531,913 Retained earnings......................................... 187,210 130,015 Accumulated other comprehensive income.................... (75,470) (82,597) ---------- ---------- Total Stockholder's Equity.............................. 893,654 579,332 ---------- ---------- TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY.................. $3,431,684 $1,293,426 ========== ========== See notes to consolidated financial statements. F-5

99 NRG ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF STOCKHOLDER'S EQUITY ACCUMULATED ADDITIONAL OTHER TOTAL COMMON PAID-IN RETAINED COMPREHENSIVE STOCKHOLDER'S STOCK CAPITAL EARNINGS INCOME EQUITY ------ ---------- -------- ------------- ------------- (THOUSANDS OF DOLLARS) BALANCES AT DECEMBER 31, 1996.......... $1 $351,013 $ 66,301 $ 4,599 $421,914 == ======== ======== ======== ======== Net Income............................. 21,982 21,982 Currency translation adjustments....... (74,098) (74,098) -------- Comprehensive income for 1997.......... (52,116) Capital contributions from parent...... 80,900 80,900 -- -------- -------- -------- -------- BALANCES AT DECEMBER 31, 1997.......... $1 $431,913 $ 88,283 $(69,499) $450,698 == ======== ======== ======== ======== Net Income............................. 41,732 41,732 Currency translation adjustments....... (13,098) (13,098) -------- Comprehensive income for 1998.......... 28,634 Capital contributions from parent...... 100,000 100,000 -- -------- -------- -------- -------- BALANCES AT DECEMBER 31, 1998.......... $1 $531,913 $130,015 $(82,597) $579,332 == ======== ======== ======== ======== Net Income............................. 57,195 57,195 Currency translation adjustments....... 7,127 7,127 -------- Comprehensive income for 1999.......... 64,322 Capital contributions from parent...... 250,000 250,000 -- -------- -------- -------- -------- BALANCES AT DECEMBER 31, 1999.......... $1 $781,913 $187,210 $(75,470) $893,654 == ======== ======== ======== ======== Other comprehensive income is shown net of tax expenses (benefits) which were $0 during both 1999 and 1998 and $5.9 million in 1997. See notes to consolidated financial statements. F-6

100 NOTE 1 -- ORGANIZATION NRG Energy, Inc. (the Company), a Delaware Corporation, was incorporated on May 29, 1992, as a wholly owned subsidiary of Northern States Power Company (NSP). Beginning in 1989, the Company was doing business through its predecessor companies, NRG Energy, Inc. and NRG Group, Inc., Minnesota corporations, which were merged into the Company subsequent to its incorporation. The Company and its subsidiaries and affiliates develop, build, acquire, own and operate non-regulated energy-related businesses. NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES PRINCIPLES OF CONSOLIDATION AND BASIS OF PRESENTATION The consolidated financial statements include the accounts of the Company and its subsidiaries (referred to collectively herein as the Company). All significant intercompany transactions and balances have been eliminated in consolidation. Accounting policies for all of the Company's operations are in accordance with accounting principles generally accepted in the United States. As discussed in Note 5, the Company has investments in partnerships, joint ventures and projects for which the equity method of accounting is applied. Earnings from equity in international investments are recorded net of foreign income taxes. CASH EQUIVALENTS Cash equivalents include highly liquid investments (primarily commercial paper) with a remaining maturity of three months or less at the time of purchase. RESTRICTED CASH Restricted cash consists primarily of cash collateral for letters of credit issued in relation to project development activities and funds held in trust accounts to satisfy the requirements of certain debt agreements. INVENTORY Inventory is valued at the lower of average cost or market and consists principally of fuel oil, coal, spare parts and raw materials used to generate steam. PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment are capitalized at original cost. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance are charged to expense as incurred. Depreciation is computed using the straight-line method over the following estimated useful lives: Facilities and improvements................................. 10-45 years Machinery and equipment..................................... 7-30 years Office furnishings and equipment............................ 3-5 years CAPITALIZED INTEREST Interest incurred on funds borrowed to finance projects expected to require more than three months to complete is capitalized. Capitalization of interest is discontinued when the project is completed and considered operational. Capitalized interest is amortized using the straight line method over the useful life of the related project. Capitalized interest was $287,000 and $172,000 in 1999 and 1998, respectively. F-7

101 DEVELOPMENT COSTS AND CAPITALIZED PROJECT COSTS These costs include professional services, dedicated employee salaries, permits, and other costs which are incurred incidental to a particular project. Such costs are expensed as incurred until a sales agreement or letter of intent is signed, and the project has been approved by the Company's Board of Directors. Additional costs incurred after this point are capitalized. When project operations begin, previously capitalized project costs are reclassified to investment in projects and amortized on a straight-line basis over the lesser of the life of the project's related assets or revenue contract period. DEBT ISSUANCE COSTS Costs to issue long-term debt have been capitalized and are being amortized over the terms of the related debt. INTANGIBLES Intangibles consist principally of the excess of the cost of investment in subsidiaries over the underlying fair value of the net assets acquired and are being amortized using the straight-line method over 20 to 30 years. The Company periodically evaluates the recovery of goodwill and other intangibles based on an analysis of estimated undiscounted future cash flows. OTHER LONG TERM ASSETS Other long-term assets consist primarily of service agreements and operating contracts. These assets are being amortized over the remaining terms of the individual contracts, which range from seven to twenty-eight years. INCOME TAXES The Company is included in the consolidated tax returns of NSP. The Company calculates its income tax provision on a separate return basis under a tax sharing agreement with NSP as discussed in Note 9. Current federal and state income taxes are payable to or receivable from NSP. The Company records income taxes using the liability method. Income taxes are deferred on all temporary differences between pretax financial and taxable income and between the book and tax bases of assets and liabilities. Deferred taxes are recorded using the tax rates scheduled by law to be in effect when the temporary differences reverse. The Company's policy for income taxes related to international operations is discussed in Note 9. REVENUE RECOGNITION Under fixed-price contracts, revenues are recognized as products or services are delivered. Revenues and related costs under cost reimbursable contract provisions are recorded as costs are incurred. Anticipated future losses on contracts are charged against income when identified. FOREIGN CURRENCY TRANSLATION The local currencies are generally the functional currency of the Company's foreign operations. Foreign currency denominated assets and liabilities are translated at end-of-period rates of exchange. The resulting currency adjustments are accumulated and reported as a separate component of stockholder's equity. Income, expense, and cash flows are translated at weighted-average rates of exchange for the period. DERIVATIVE FINANCIAL INSTRUMENTS To preserve the U.S. dollar value of projected foreign currency cash flows, the Company hedges, or protects, those cash flows if appropriate foreign hedging instruments are available. The gains and losses on those agreements offset the effect of exchange rate fluctuations on the Company's known and anticipated cash flows. The Company defers gains on agreements that hedge firm commitments of cash flows, and F-8

102 accounts for them as part of the relevant foreign currency transaction when the transaction occurs. The Company defers expected losses on these agreements, unless it appears that the deferral would result in recognizing a loss later. While the Company is not currently hedging investments involving foreign currency, the Company will hedge such investments when it believes that preserving the U.S. dollar value of the investment is appropriate. The Company is not hedging currency translation adjustments related to future operating results. The Company does not speculate in foreign currencies. From time to time the Company also uses interest rate hedging instruments to protect it from an increase in the cost of borrowing. Gains and losses on interest rate hedging instruments are reported as part of the asset for Investments In Projects when the hedging instrument relates to a project that has financial statements that are not consolidated into the Company's financial statements. Otherwise, they are reported as part of debt. USE OF ESTIMATES The preparation of financial statements in conformity with Generally Accepted Accounting Principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. In recording transactions and balances resulting from business operations, the Company uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, tax provisions, uncollectible accounts and actuarially determined benefit costs, among others. As better information becomes available (or actual amounts are determinable), the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates. NEW ACCOUNTING PRONOUNCEMENTS In June 1998, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standard (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities,". This statement requires that all derivatives be recognized at fair value in the balance sheet and that changes in fair value be recognized either currently in earnings or deferred as a component of Other Comprehensive Income, depending on the intended use of the derivative, its resulting designation and its effectiveness. The Company plans to adopt this standard in the first quarter of 2001, as required. The Company has not determined the potential impact of implementing this statement. RECLASSIFICATIONS Certain prior-year amounts have been reclassified for comparative purposes. These reclassifications had no effect on net income or stockholder's equity as previously reported. NOTE 3 -- ASSET ACQUISITIONS AND DIVESTITURES In February 1999, the Company purchased from Thermal Ventures, Inc. (TVI) the remaining 50.1% limited partnership interests held by TVI in San Francisco Thermal Limited Partnership and Pittsburgh Thermal Limited Partnership for $12.3 million. In April 1999, NRG acquired TVI's 50% member interest in North American Thermal Systems LLC (the entity holding the general partnership interest in the San Francisco and Pittsburgh partnerships) for $500,000. In 1994, the Company, through a wholly-owned subsidiary, purchased a 50% ownership interest in Sunnyside Cogeneration Associates, a Utah joint venture, which owns and operates a 58 MW waste coal plant in Utah. The waste coal plant is currently being operated by a partnership that is 50% owned by a Company affiliate. In March 1999, the Company and its partner executed an agreement to sell the Sunnyside project to an affiliate of Baltimore Gas & Electric for a purchase price of $2.0 million. There was no gain or loss on the sale which closed during the second quarter of 1999. F-9

103 In April 1999, the Company completed the acquisition of the Somerset power station for approximately $55 million from the Eastern Utilities Association (EUA). The Somerset station, located in Somerset, Massachusetts, includes two coal-fired generating facilities and two aeroderivative combustion turbine peaking units with a capacity rating of 229 MW, of which 69 MW is on deactivated reserve. In connection with this acquisition, the Company entered into a Wholesale Standard Offer Service Agreement pursuant to which the Company is obligated to provide approximately 30% of the energy and capacity requirements of certain EUA affiliates (which is estimated to be approximately 275 MW at peak requirement) until December 31, 2009. In May 1999, the Company and Dynegy Power Corporation (Dynegy), through West Coast Power LLC, completed the acquisition of the Encina generating station and 17 combustion turbines for approximately $356 million from San Diego Gas & Electric Company. The facilities, which have a combined capacity rating of 1,218 MW, are located near Carlsbad and San Diego, California. The Company and Dynegy each own a 50% interest in these facilities. In June 1999, the Company completed its acquisition of the Huntley and Dunkirk generating stations from Niagara Mohawk Power Corporation (NIMO) for approximately $355 million. The two coal-fired power generation facilities are located near Buffalo, New York, and have a combined summer capacity rating of 1,360 MW. In connection with this acquisition, the Company entered into several Transition Power Purchase Agreements and a related swap agreement with NIMO pursuant to which NIMO purchases certain energy and capacity from these facilities for a term of four years. In June 1999, the Company completed its acquisition of the Arthur Kill generating station and the Astoria gas turbine site from Consolidated Edison Company of New York, Inc. (ConEd) for approximately $505 million. These facilities, which are located in the New York City Area, have a combined capacity rating of 1,456 MW. In connection with the acquisition of each facility, the Company entered into (i) Transition Energy Sales Agreements pursuant to which energy from each facility is sold to ConEd for a transition period ending on the date on which the independent system operator in New York State (NYISO) commences operation (which commencement date was November 18, 1999) of a spot market for energy and certain ancillary services, and (ii) Transition Capacity Sales Agreements pursuant to which capacity from each facility is sold to ConEd for a transition period ending on the later of (a) the earlier of (i) December 31, 2002 or (ii) the date such facility receives notice from the NYISO that none of the electric generating capacity of such facility is required for meeting the installed capacity requirements in New York City, or (b) the date the NYISO commences an auction for system capacity. Pursuant to the Transition Energy Sales Agreements, the Company agreed to sell to ConEd at a fixed price varying amounts of energy from the Arthur Kill generating facility and the Astoria gas turbine generating facility, in each case in amounts to be specified by ConEd, up to the full capability of each facility. Pursuant to the Transition Capacity Sales Agreements, the Company agreed to sell to ConEd at a fixed price, during certain periods, up to 100% of the capacity of the Arthur Kill generating facility and up to 100% of the capacity of the Astoria gas turbines facility. In August, the Company agreed to sell all but a 20 percent ownership interest in Cogeneration Corporation of America (CogenAmerica) to Calpine Corporation in connection with Calpine's acquisition of the remaining shares of CogenAmerica. Prior to December 1999, the Company owned approximately 45% of CogenAmerica. Upon closing of the transaction, all outstanding shares of CogenAmerica common stock (other than those retained by the Company) were acquired by Calpine for a cash purchase price of $25.00 per share. The transaction closed during the fourth quarter of 1999 and the Company retained a 20% ownership interest in CogenAmerica. In October 1999, the Company completed its acquisition of the Oswego generating station from NIMO and Rochester Gas and Electric for approximately $85 million. The oil and gas-fired power generating facility which has a capacity rating of 1,700 MW, is located on a 93-acre site in Oswego, New York. This facility consists of two units each having a capacity rating of 850 MW. In connection with this acquisition, the Company entered into a Transition Power Purchase Agreement with NIMO similar to those entered into in connection with the acquisitions of the Dunkirk and Huntley facilities. Pursuant to F-10

104 this agreement, the Company has agreed to sell 100% of the capacity of one unit, an option for up to 40% of the capacity of the other unit. The Company has agreed to sell NIMO an option to purchase a nominal amount of energy for a term of four years. In December 1999, the Company acquired four fossil fuel generating stations and six remote gas turbines from CL&P for approximately $460 million, plus adjustments for working capital. These facilities are located throughout Connecticut and have a combined nominal capacity rating of 2,235 MW. The Company entered into a Standard Offer Service Wholesale Sales Agreement with CL&P pursuant to which the Company will supply CL&P with 35% of its standard offer service load during 2000, 40% during 2001 and 2002, and 45% during 2003. The Company estimates that 45% of CL&P's standard offer service load in 2003 will be approximately 2,070 MW at peak requirement. The Agreement terminates on December 31, 2003. In December 1999, the Company purchased a 50% interest in the Rocky Road Power Plant, a 250 MW natural gas fired simple-cycle peaking facility in East Dundee, IL from Dynegy Inc., for approximately $60 million. The power plant began commercial operations on June 30, 1999 and received approval for the installation of an additional 100 MW natural gas combustion turbine in October 1999, increasing the facilities generating capacity to a nominal 350 MW. The expansion is expected to be in service before the start of the peak summer 2000 season. Pro forma information has not been presented for the assets acquired in 1999 due to the fact that the assets acquired do not constitute businesses under Rule 11-01(d) of Regulation S-X. Accordingly, historical financial information does not exist for the assets acquired. NOTE 4 -- PROPERTY, PLANT AND EQUIPMENT The major classes of property, plant and equipment at December 31 were as follows: 1999 1998 ---- ---- (THOUSANDS OF DOLLARS) Facilities and equipment, including construction work in progress of $53,448 and $5,352................... $2,000,541 $280,876 Land and improvements................................. 64,330 10,397 Office furnishings and equipment...................... 11,301 5,637 ---------- -------- Total property, plant and equipment.............. 2,076,172 296,910 Accumulated depreciation.............................. (156,849) (92,181) ---------- -------- Net property, plant and equipment..................... $1,919,323 $204,729 ========== ======== NOTE 5 -- INVESTMENTS ACCOUNTED FOR BY THE EQUITY METHOD The Company has investments in various international and domestic energy projects. The equity method of accounting is applied to such investments in affiliates, which include joint ventures and partnerships, because the ownership structure prevents the Company from exercising a controlling influence over operating and financial policies of the projects. Under this method, equity in pretax income or losses of domestic partnerships and, generally, in the net income or losses of international projects are reflected as equity in earnings of unconsolidated affiliates. F-11

105 A summary of the Company's significant equity-method investments which were in operation at December 31, 1999 is as follows: ECONOMIC PURCHASED OR NAME GEOGRAPHIC AREA INTEREST PLACED IN SERVICE ---- --------------- -------- ----------------- Loy Yang A................................... Australia 25.37% May 1997 Energy Developments Limited.................. Australia 29.14% February 1997 ECK Generating............................... Czech Republic 44.50% December 1994 MIBRAG mbH................................... Germany 33.33% January 1994 Gladstone Power Station...................... Australia 37.50% March 1994 Schkopau Power Station....................... Germany 20.95% January and July 1996 Scudder Latin American Projects.............. Latin America 6.63% June 1993 Long Beach Generating........................ USA 50.00% April 1998 El Segundo Power............................. USA 50.00% April 1998 Bolivian Power Company (Cobee)............... Bolivia 49.10% December 1996 Cogeneration Corp. of America................ USA 20.00% April 1996 Encina....................................... USA 50.00% May 1999 San Diego Combustion Turbines................ USA 50.00% May 1999 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: 1999 1998 1997 ---- ---- ---- (THOUSANDS OF DOLLARS) Operating revenues....................................... $1,732,521 $1,491,197 $1,612,897 Costs and expenses....................................... 1,531,958 1,346,569 1,522,727 ---------- ---------- ---------- Net income.......................................... $ 200,563 $ 144,628 $ 90,170 ---------- ---------- ---------- Current assets........................................... $ 742,674 $ 710,159 $ 713,390 Noncurrent assets........................................ 7,322,219 7,938,841 7,733,886 ---------- ---------- ---------- Total assets........................................ $8,064,893 $8,649,000 $8,447,276 ---------- ---------- ---------- Current liabilities...................................... $ 708,114 $ 527,196 $ 472,980 Noncurrent liabilities................................... 5,168,893 5,854,284 6,042,102 Equity................................................... 2,187,886 2,267,520 1,932,194 ---------- ---------- ---------- Total liabilities and equity........................ $8,064,893 $8,649,000 $8,447,276 NRG's share of equity.................................... $ 988,671 $ 800,924 $ 694,655 NRG's share of income.................................... $ 67,500 $ 81,706 $ 26,200 In accordance with FASB No. 121 "Accounting for Impairment of Long-lived Assets to be Disposed of," the Company reviews long lived assets, investments and certain intangibles for impairment whenever events or circumstances indicate the carrying amounts of an asset may not be recoverable. During 1998, the Company wrote down accumulated project development expenditures of $26.7 million. The Company's West Java, Indonesia, project totaling $22.0 million was written off due to the uncertainties surrounding infrastructure projects in Indonesia. Also during 1998, the Company wrote off its $1.9 million investment in the Sunnyside project and its $2.8 million investment in Alto Cachopoal. The charge represents the difference between the carrying amount of the investment and the fair value of the asset, determined using a cash flow model. In December 1997, the Company reviewed the carrying amount of the Sunnyside project that failed to restructure its debt and recorded a charge of $8.9 million. The charge represents the difference between the carrying amount of the investment and the fair value of the asset, determined using a discounted cash flow model. F-12

106 NOTE 6 -- RELATED PARTY TRANSACTIONS SALE TO AFFILIATE During October 1998, the Company sold its interest in the Mid-Continent Power Corporation (MCPC) facility to CogenAmerica for a $2.1 million gain after elimination of affiliate interest. The MCPC facility is a 110 MW, gas-fired generation station located near Pryor, Oklahoma. The Company owns 20 percent of the outstanding stock of CogenAmerica. OPERATING AGREEMENTS The Company has two agreements with NSP for the purchase of thermal energy. Under the terms of the agreements, NSP charges the Company for certain costs (fuel, labor, plant maintenance, and auxiliary power) incurred by NSP to produce the thermal energy. The Company paid NSP $4.4 million in 1999 and $5.1 million in 1998 under these agreements. The Company has a renewable 10-year agreement with NSP, expiring on December 31, 2001, whereby NSP agrees to purchase refuse-derived fuel for use in certain of its boilers and the Company agrees to pay NSP a burn incentive. Under this agreement, the Company received $1.4 million and $1.4 million from NSP, and paid $2.7 million and $3.1 million to NSP in 1999 and 1998, respectively. ADMINISTRATIVE SERVICES AND OTHER COSTS The Company and NSP have entered into an agreement to provide for the reimbursement of actual administrative services provided to each other, an allocation of NSP administrative costs and a working capital fee. Services provided by NSP to the Company are principally cash management, legal, accounting, employee relations, benefits administration and engineering support. In addition, the Company employees participate in certain employee benefit plans of NSP as discussed in Note 10. During 1999 and 1998, the Company paid NSP $6.4 million and $5.2 million, respectively, as reimbursement under this agreement. In 1996, the Company and NSP entered into an agreement for the Company to provide operations and maintenance services for NSP's Elk River resource recovery facility and Becker ash landfill. During 1999 and 1998, NSP paid the Company $1.9 million and $1.7 million, respectively, as compensation under this agreement. F-13

107 NOTE 7 -- NOTES RECEIVABLE Notes receivable consists primarily of fixed and variable rate notes secured by equity interests in partnerships and joint ventures. The notes receivable at December 31, are as follows: 1999 1998 ---- ---- (THOUSANDS OF DOLLARS) COGENERATION CORPORATION OF AMERICA: Note due 2001, 9.5%....................................... $ -- $ 2,539 Grays Ferry note due 2005, LIBOR plus 4.0% (9.31%@12/98).......................................... -- 1,900 Morris note due 2004, prime +3.5% (11.25%@12/98).......... -- 12,027 MCPC note due 2004, prime +3.5% (11.25%@12/98)............ -- 23,947 El Paso note, due January 1999, non interest bearing........ -- 26,200 Thermal Ventures, Inc. note due 1999, 11%................... -- 1,500 TOSLI, various notes due 2000, LIBOR plus 4.0% (10.0%@12/99)............................................. 207 132 Various secured notes due 2000 and later, non-interest and interest bearing.......................................... 224 723 NEO notes to various affiliates due primarily 2012, prime +2% to 12.5%.............................................. 26,850 27,445 Southern MN Praireland Solid Waste, note due 2003, 7%....... 44 1,441 Pacific Generation, various notes, prime +2% to 12%......... 3,368 4,203 NRGenerating International BV notes to various affiliates, non-interest bearing...................................... 40,410 34,234 O'Brien Cogen II note, due 2008, non interest bearing....... 465 -- ------- -------- Total................................................ $71,568 $136,291 ======= ======== F-14

108 NOTE 8 -- LONG-TERM DEBT Long-term debt consists of the following at December 31: 1999 1998 ---- ---- (THOUSANDS OF DOLLARS) NEO Landfill Gas, Inc. term loan, due October 30, 2007, 9.35%..................................................... $ -- $ 9,847 NEO Landfill Gas Inc. construction loan due October 30, 2007 LIBOR +1% (6.31% @ 12/98)................................. -- 6,550 NEO Landfill Gas, Inc. City of L.A. term loan, due December 2019 non-interest bearing................................. -- 1,395 Revolving Line of Credit, due March 17, 2000, 5.85%......... 124,000 COBEE, due April 21, 2000, 0%............................... 5,761 -- O'Brien Cogen II due August 31, 2000, 9.5%.................. 2,893 -- NRG San Diego, Inc. promissory note, due June 25, 2003, 8.0%...................................................... 1,729 2,141 Pittsburgh Thermal LP -- Credit Line, due 2004, LIBOR +4.25%.................................................... 1,100 -- San Francisco Thermal LP -- Credit Line, due 2004, LIBOR +4.25%.................................................... 900 -- Pittsburgh Thermal LP, due 2002-2004, 10.61%-10.73%......... 6,800 -- San Francisco Thermal LP, October 5, 2004, 10.61%........... 5,905 -- NRG Energy senior notes, due February 1, 2006, 7.625%....... 125,000 125,000 Note payable to NSP, due December 1, 1995-2006, 5.40%-6.75%............................................... 6,495 7,174 NRG Energy senior notes, due June 15, 2007, 7.50%........... 250,000 250,000 Camas Power Boiler LP, unsecured term loan, due June 30, 2007, 7.65%............................................... 17,087 17,576 Camas Power Boiler LP, revenue bonds, due August 1, 2007, 4.65%..................................................... 9,130 11,010 Various NEO debt due 2005-2008, 9.35%....................... 28,615 -- NRG Energy senior notes, due June 1, 2009, 7.50%............ 300,000 -- NRG Energy Center, Inc. senior secured notes due June 15, 2013, 7.31%............................................... 68,881 71,783 NRG Energy senior notes, due Nov. 1, 2013, 8.00%............ 240,000 -- Crockett Corp. LLP, due Dec. 31, 2014, 8.13%................ 255,000 -- NRG Northeast Generating debt............................... 646,564 -- ---------- -------- 1,971,860 626,476 Less current maturities..................................... (30,462) (8,258) ---------- -------- Total................................................ $1,941,398 $618,218 ========== ======== The NRG Energy Center, Inc. notes are secured principally by long-term assets of the Minneapolis Energy Center (MEC). In accordance with the terms of the note agreement, MEC is required to maintain compliance with certain financial covenants primarily related to incurring debt, disposing of MEC assets, and affiliate transactions. MEC was in compliance with these covenants at December 31, 1999. The note payable to NSP relates to long-term debt assumed by the Company in connection with the transfer of ownership of a Refuse Derived Fuel processing plant by NSP to the Company in 1993. The NRG Energy $125 million, $250 million, $300 million and $240 million senior notes are unsecured and are used to support equity requirements for projects acquired and in development. The interest is paid semi-annually and the ten-year senior notes mature in February 2006, June 2007, and 2009. The fourteen year notes mature in November 2013. The $240 million of NRG Energy Senior notes due November 1, 2013 are remarketable or redeemable Security (ROARS). November 1, 2003 is the first remarketing date for these notes. Interest is payable semi-annually beginning May 1, 2000 through November 1, 2003, and then at intervals and interest rates as discussed in the indenture. On the remarketing date, the notes will either be mandatorily tendered to and purchased by Credit Suisse Financial Products or mandatorily redeemed by the Company at prices discussed in the indenture. The notes are unsecured debt that rank senior to all of the Company's existing and future subordinated indebtedness. F-15

109 The NRG San Diego, Inc. promissory note is secured principally by long-term assets of the San Diego Power & Cooling Company. The various NEO notes are term loans. The loans are secured principally by long-term assets of NEO Landfill Gas collection system. NEO Landfill Gas is required to maintain compliance with certain covenants primarily related to incurring debt, disposing of the NEO Landfill Gas assets, and affiliate transactions. The Camas Power Boiler LP notes are secured principally by long-term assets. In accordance with the terms of the note agreements, Camas Power Boiler LP is required to maintain compliance with certain financial covenants primarily related to incurring debt, disposing of assets, and affiliate transactions. Camas Power Boiler was in compliance with these covenants at December 31, 1999. The Crockett Corporation term loan is secured by primarily the long-term assets of the Crockett Cogeneration project. The O'Brien Cogen II promissory note is payable on the earlier of the first anniversary of the effective date (August 31, 1999) or upon the sale of the assets at the O'Brien Cogen II facility. Full payment of the note is guaranteed by the Company. Annual maturities of long-term debt for the years ending after December 31, 1999 are as follows: (THOUSANDS OF DOLLARS) ---------------------- 2000...................................................... $ 30,462 2001...................................................... 23,637 2002...................................................... 26,104 2003...................................................... 27,610 2004...................................................... 31,594 Thereafter................................................ 1,832,453 ---------- Total................................................ $1,971,860 ========== The Company has $550 million in revolving credit facilities under a commitment fee arrangement. These facilities provide short-term financing in the form of bank loans and letters of credit. At December 31, 1999, the Company has $340 million outstanding under its revolving credit agreements. The Company had $116 million and $33.6 million in outstanding letters of credit as of December 31, 1999 and 1998, respectively. In December 1999, the Company filed a shelf registration with the SEC to issue up to $500 million of unsecured debt securities. The Company expects to issue debt under this shelf during 2000 for general corporate purposes, which may include financing, development and construction of new facilities, additions to working capital and financing capital expenditures and pending or potential acquisitions. On February 22, 2000, NRG Northeast Generating issued $750 million of senior secured bonds to refinance short-term project borrowings and for certain other purposes. The bond offering included three tranches: $320 million with an interest rate of 8.065 percent due in 2004, $130 million with an interest rate of 8.842 percent due in 2015 and $300 million with an interest rate of 9.292 percent due in 2024. The Company used $647 million of the proceeds to repay short-term borrowings outstanding at December 31, 1999; accordingly, $646.6 million of short term debt has been re-classified as long-term debt, based on this refinancing. In March 2000, the Company issued $250 million of 8.70 percent 20-year remarketable or redeemable securities through an unconsolidated grantor trust. The funds were subsequently converted to 160 million pound sterling and will be used to finance the Company's investment in the Killingholme Power Station in England. In March 2000, NRG South Central Generating LLC, a subsidiary of the Company, issued $800 million of senior secured bonds in a two-part offering. The first tranche was for $500 million with a coupon of 8.962 percent and a maturity of 2016. The second tranche was for $300 million with a coupon F-16

110 of 9.479 percent and a maturity of 2024. The proceeds will be used to finance the Company's investment in the Cajun generating facilities. GUARANTEES The Company may be directly liable for the obligations of certain of its project affiliates and other subsidiaries pursuant to guarantees relating to certain of their indebtedness, equity and operating obligations. One example is the Company's guarantee of the obligations of its project subsidiary that operates the Gladstone facility for up to AU$25 million, indexed to the Australian consumer price index, under the project subsidiary's operating and maintenance agreement with the owners of the facility. In addition, in connection with the purchase and sale of fuel, emission credits and power generation products to and from third parties with respect to the operation of some of the Company's generation facilities in the United States, the Company may be required to guarantee a portion of the obligations of certain of its subsidiaries. As of December 31, 1999, the Company's obligations pursuant to its guarantees of the performance, equity and indebtedness obligations of its subsidiaries totaled approximately $416.4 million. NOTE 9 -- INCOME TAXES The Company and its parent, NSP, have entered into a federal and state income tax sharing agreement relative to the filing of consolidated federal and state income tax returns. The agreement provides, among other things, that (1) if the Company, along with its subsidiaries, is in a taxable income position, the Company will be currently charged with an amount equivalent to its federal and state income tax computed as if the group had actually filed separate federal and state returns, and (2) if the Company, along with its subsidiaries, is in a tax loss position, the Company will be currently reimbursed to the extent its combined losses are utilized in a consolidated return, and (3) if the Company, along with its subsidiaries, generates tax credits, the Company will be currently reimbursed to the extent its tax credits are utilized in a consolidated return. The provision for income taxes consists of the following: 1999 1998 1997 ---- ---- ---- (THOUSANDS OF DOLLARS) Current Federal................................................ $ 3,620 $(10,773) $ (8,516) State.................................................. 1,041 (3,940) (1,274) Foreign................................................ 4,040 2,358 236 -------- -------- -------- 8,701 (12,355) (9,554) Deferred Foreign................................................ (7,668) (7,736) (2,703) Federal................................................ (2,792) 8,828 (958) State.................................................. (3,901) 1,541 (439) -------- -------- -------- (14,361) 2,633 (4,100) Tax credits recognized................................... (20,421) (15,932) (9,837) -------- -------- -------- Total income tax (benefit).......................... $(26,081) $(25,654) $(23,491) ======== ======== ======== Effective tax rate....................................... (84)% (160)% (1,557)% F-17

111 The components of the net deferred income tax liability at December 31 were: 1999 1998 ---- ---- (THOUSANDS OF DOLLARS) Deferred tax liabilities Differences between book and tax basis of property........ $37,713 $29,712 Investments in projects................................... 17,308 14,911 Goodwill.................................................. 1,117 978 Other..................................................... 5,544 6,212 ------- ------- Total deferred tax liabilities............................ 61,682 51,813 Deferred tax assets Deferred revenue.......................................... 841 1,402 Deferred compensation, accrued vacation and other reserves............................................... 10,996 6,514 Development costs......................................... 6,768 9,241 Deferred investment tax credits........................... 450 661 Steam capacity rights..................................... 844 910 Foreign tax benefit....................................... 20,919 12,425 Other..................................................... 3,924 819 ------- ------- Total deferred tax assets................................. 44,742 31,972 ------- ------- Net deferred tax liability................................ $16,940 $19,841 ======= ======= The effective income tax rate for the years 1999, 1998 and 1997 differs from the statutory federal income tax rate of 35% primarily due to state tax, foreign tax, and tax credits as shown above, income and expenses from foreign operations not subject to U.S. taxes (as discussed below). The Company intends to reinvest the earnings of foreign operations except to the extent the earnings are subject to current U.S. income taxes. Accordingly, U.S. income taxes and foreign withholding taxes have not been provided on a cumulative amount of unremitted earnings of foreign subsidiaries of approximately $195 million and $158 million at December 31, 1999 and 1998. The additional U.S. income tax and foreign withholding tax on the unremitted foreign earnings, if repatriated, would be offset in whole or in part by foreign tax credits. Thus, it is not practicable to estimate the amount of tax that might be payable. NOTE 10 -- BENEFIT PLANS AND OTHER POSTRETIREMENT BENEFITS PENSION BENEFITS The Company participates in NSP's noncontributory, defined benefit pension plan that covers substantially all employees, other then those employed as a result of the NE Generating asset acquisitions. Benefits are based on a combination of years of service, the employee's highest average pay for 48 consecutive months, and Social Security benefits. Plan assets principally consist of the common stock of F-18

112 public companies, corporate bonds and U.S. government securities. The Company's net annual periodic pension cost includes the following components: COMPONENTS OF NET PERIODIC BENEFIT COST 1999 1998 1997 ---- ---- ---- (THOUSANDS OF DOLLARS) Service cost benefits earned................................ $ 1,602 $ 1,303 $ 1,127 Interest cost on benefit obligation......................... 1,739 1,417 1,187 Expected return on plan assets.............................. (2,866) (2,226) (1,029) Amortization of prior service cost.......................... 393 172 5 Recognized actuarial (gain) loss............................ (2,053) (1,878) (3) ------- ------- ------- Net periodic (benefit) cost............................... $(1,185) $(1,212) $ 1,287 ======= ======= ======= The Company discontinued funding its pension costs in 1998 due to the effects of funding limitations from employee benefit and tax laws on NSP's plan. Plan assets consist principally of common stock of public companies, corporate bonds and U.S. government securities. The funded status of the pension plan in which the Company employees participate is as follows at December 31: RECONCILIATION OF FUNDED STATUS 1999 1998 -------------------------- ------------------------- NSP PLAN NRG PORTION NSP PLAN NRG PORTION -------- ----------- -------- ----------- (THOUSANDS OF DOLLARS) Benefit obligation at Jan. 1................. $ 1,143,464 $ 20,112 $1,048,251 $17,410 Service cost................................. 36,421 1,602 31,643 1,303 Interest cost................................ 86,429 1,739 78,839 1,417 Plan amendments.............................. 184,255 2,214 102,315 3,045 Actuarial gain............................... (105,634) (178) (41,635) (2,278) Benefit payments............................. (97,086) (1,200) (75,949) (785) ----------- -------- ---------- ------- Benefit obligation at Dec. 31.............. $ 1,247,849 $ 24,289 $1,143,464 $20,112 =========== ======== ========== ======= Fair value of plan assets at Jan. 1.......... $ 2,221,819 39,079 $1,978,538 $18,795 Actual return on plan assets................. 293,904 9,199 319,230 21,069 Benefit payments............................. (97,086) (1,200) (75,949) (785) ----------- -------- ---------- ------- Fair value of plan assets at Dec. 31....... $ 2,418,637 $ 47,078 $2,221,819 $39,079 =========== ======== ========== ======= Funded status at Dec. 31 -- excess of assets over obligation............................ $ 1,170,788 $ 22,789 $1,078,355 $18,967 Unrecognized transition (asset) obligation... (311) -- (387) -- Unrecognized prior service cost.............. 277,350 4,775 114,305 2,954 Unrecognized net gain........................ (1,381,889) (26,944) (1,167,340) (22,486) ----------- -------- ---------- ------- Accrued (prepaid) benefit obligation at Dec. 31......................................... $ 65,938 $ 620 $ 24,933 $ (565) =========== ======== ========== ======= AMOUNT RECOGNIZED IN THE BALANCE SHEET 1999 1998 ----------------------- ----------------------- NSP PLAN NRG PORTION NSP PLAN NRG PORTION -------- ----------- -------- ----------- (THOUSANDS OF DOLLARS) Prepaid benefit cost............................. $65,938 $ 868 $24,933 $ -- Accrued benefit liability........................ -- (248) -- (565) ------- ----- ------- ----- Net amount recognized -- asset (liability)............................... $65,938 $ 620 $24,933 $(565) ======= ===== ======= ===== F-19

113 The weighted average discount rate used in determining the actuarial present value of the projected benefit obligation was 7.5% for December 31, 1999 and 6.5% for December 31, 1998. The rate of increase in future compensation levels used in determining the actuarial present value of the projected obligation was 4.5% in 1999 and 4.5% in 1998. The assumed long-term rate of return on assets used for cost determinations was 8.5% for 1999 and 1998 and 9.0% for 1997. Effective Jan. 1, 1998, NSP changed its method of accounting for subsidiary pension costs under SFAS No. 87. The new method, which now allocates plan assets based on subsidiary benefit obligations, was adopted to better match earnings on total plan assets with the corresponding subsidiary benefit obligations. The effect of this change decreased periodic pension costs by $2.9 million in 1998 from 1997 levels, including $1.3 million related to periods prior to the change. The effects of this change have not been reported separately on the income statement and prior periods have not been restated due to immateriality. NRG EQUITY PLAN Employees are eligible to participate in the Company's Equity Plan (the Plan). The Plan grants phantom equity units to employees based upon performance and job grade. The Company's equity units are valued based upon the Company's growth and financial performance. The primary financial measures used in determining the equity units' value are revenue growth, return on investment and cash flow from operations. The units are awarded to employees annually at the respective year's calculated share price (grant price). The Plan provides employees with a cash pay out for the unit's appreciation in value over the vesting period. The Plan has a seven year vesting schedule with actual payments beginning after the end of the third year and continuing at 20% each year for the subsequent five years. During 1999 and 1998, the Company recorded approximately $13 million and $2.6 million, respectively for the Plan. The Plan includes a change of control provision, which allow all shares to vest if the ownership of the Company were to change. POSTRETIREMENT HEALTH CARE The Company participates in NSP's contributory health and welfare benefit plan that provides health care and death benefits to substantially all employees after their retirement. The plan, was terminated for nonbargaining employees retiring after 1998 and for bargaining employees retiring after 1999. is intended to provide for sharing of costs of retiree health care between the Company and retirees. For covered retirees, the plan enables the Company to share the cost of retiree health costs. Nonbargaining retirees pay 40 percent of total health care costs. Cost-sharing for bargaining employees is governed by the terms of the collective bargaining agreement. Postretirement health care benefits for the Company are determined and recorded under the provisions of SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." SFAS No. 106 requires the actuarially determined obligation for postretirement health care and death benefits to be fully accrued by the date employees attain full eligibility for such benefits, which is generally when they reach retirement age. F-20

114 The Company's net annual periodic benefit cost under SFAS No. 106 includes the following components: COMPONENTS OF NET PERIODIC BENEFIT COST 1999 1998 1997 ---- ---- ---- (THOUSANDS OF DOLLARS) Service cost benefits earned................................ $ 9 $165 $223 Interest cost on benefit obligation......................... 24 145 246 Amortization of transition asset............................ -- 17 70 Amortization of prior service cost.......................... (104) (40) -- Recognized actuarial (gain) loss............................ (34) 2 -- ----- ---- ---- Net periodic (benefit) cost............................ $(105) $289 $539 ===== ==== ==== Plan assets as of December 31, 1999 consisted of investments in equity mutual funds and cash equivalents. The Company's funding policy is to contribute to NSP benefits actually paid under the plan. The following table sets forth the funded status of the health care plan in which the Company employees participate at December 31: RECONCILIATION OF FUNDED STATUS 1999 1998 ------------------------ ------------------------ NSP PLAN NRG PORTION NSP PLAN NRG PORTION -------- ----------- -------- ----------- (THOUSANDS OF DOLLARS) Benefit obligation at Jan. 1................... $ 219,762 $ 1,517 $ 279,230 $ 3,893 Service cost................................... 196 9 3,247 165 Interest cost.................................. 9,184 24 15,896 145 Plan amendments................................ (80,840) (770) (51,456) (1,872) Actuarial gain loss............................ 8,269 (359) (9,732) (814) Benefit payments............................... (16,637) -- (17,423) -- --------- ------- --------- ------- Benefit obligation at Dec. 31............. $ 139,934 $ 421 $ 219,762 $ 1,517 ========= ======= ========= ======= Fair Value of plan assets at Jan. 1............ $ 34,514 $ -- $ 19,783 $ -- Actual return on plan assets................... 3,982 -- 2,471 -- Employer contributions......................... 13,339 -- 29,683 -- Benefit payments............................... (16,637) -- (17,423) -- --------- ------- --------- ------- Fair value of plan assets at Dec. 31...... $ 35,198 $ -- $ 34,514 $ -- ========= ======= ========= ======= Funded status at Dec. 31 -- unfunded obligation................................... $(104,736) $ (421) $ 185,248 $ 1,517 Unrecognized transition obligation............. 22,073 -- (104,482) -- Unrecognized prior service cost................ (2,926) (1,452) 2,399 786 Unrecognized net gain (loss)................... 10,580 (562) (3,790) 237 --------- ------- --------- ------- Accrued (liability) benefit recorded at Dec. 31........................................... $ (75,009) $(2,435) $ 79,375 $ 2,540 ========= ======= ========= ======= The assumed health care cost trend rates used in measuring the accumulated projected benefit obligation (APBO) at both December 31, 1999 and 1998, were 8.1% for those under age 65, and 6.1 % for those over age 65. The assumed cost trends are expected to decrease each year until they reach 5.0% for both age groups in the year 2004, after which they are assumed to remain constant. A one percent increase in the assumed health care cost trend rate would increase the APBO by approximately $36 thousand as of December 31, 1999. Service and interest cost components of the net periodic postretirement cost would increase by approximately $2 thousand with a similar one percent increase in the assumed health care cost trend rate. The assumed discount rate used in determining the APBO was 6.5% for both December 31, F-21

115 1999 and 1998, compounded annually. The assumed long-term rate of return on assets used for cost determinations under SFAS No. 106 was 8% for 1999, 1998 and 1997 PENSION BENEFITS -- 1999 ACQUISITIONS During 1999, the Company acquired several generating assets and assumed benefit obligations for a number of employees associated with those acquisitions. The plans assumed included noncontributory defined benefit pension formulas, matched 401(k) savings plans, and contributory post-retirement welfare plans. Approximately, 56 percent of the Company's benefit employees are represented by eight local labor unions under collective bargaining agreements, which expire between 2000 and 2003. The Company sponsors one noncontributory, defined benefit pension plan that covers most of the employees associated with the 1999 acquisitions. Generally, the benefits are based on a combination of years of service, the final average pay and Social Security benefits. COMPONENTS OF NET PERIODIC BENEFIT COST 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 ======= RECONCILIATION OF FUNDED STATUS 1999 ---- (THOUSANDS OF DOLLARS) Benefit obligation at beginning of period................... $ 24,954 Additional Acquisitions during the Year..................... 27,330 Service cost................................................ 968 Interest cost............................................... 1,115 Plan amendments............................................. -- Actuarial gain.............................................. (1,098) Benefit payments............................................ (403) -------- Benefit obligation at Dec. 31.......................... $ 52,866 ======== Fair value of plan assets at beginning of period............ $ 24,905 Additional assets transferred............................... 10,070 Actual return on plan assets................................ 3,091 Benefit payments............................................ (403) -------- Fair value of plan assets at Dec. 31................... $ 37,663 ======== Funded status at Dec. 31 -- excess of assets over obligation................................................ $(15,203) Unrecognized transition (asset) obligation.................. -- Unrecognized prior service cost............................. -- Unrecognized net gain....................................... (2,996) -------- (Accrued) Prepaid benefit obligation at Dec. 31............. $(18,199) ======== F-22

116 AMOUNT RECOGNIZED IN THE BALANCE SHEET 1999 ---------------------- (THOUSANDS OF DOLLARS) Prepaid benefit cost....................................... -- Accrued benefit liability.................................. $(18,199) -------- Net amount recognized -- (liability)..................... $(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 The Company has also assumed post retirement health care benefits for some of the Company's employees associated with the 1999 acquisitions. The plan enables the Company and the retirees to share the costs of retiree health care. The cost sharing varies by acquisition group and collective bargaining agreements. There are no existing Company retirees under these plans as of December 31, 1999. Complete valuation data is not available for some of these groups. The estimated net periodic postretirement benefit cost for 1999 is $0.85 million. The estimated accumulated post-retirement benefit obligation is $12 million at December 31,1999. 401(K) PLANS The Company also assumed several contributory, defined contribution employee savings plans as a result of its 1999 acquisition activity. These plans comply with Section 401(k) of the Internal Revenue Code and cover substantially all of the Company's employees who are not covered by NSP's 401(k) Plan. The Company matches specified amounts of employee contributions to the plan. Employer contributions made to the Company's plans were approximately $0.31 million in 1999. NOTE 11 -- SALES TO SIGNIFICANT CUSTOMERS During 1999, the Company's electric power generation operations located in the northeastern part of the United States, NRG Northeastern Generating LLC, accounted for approximately 60% of the Company's total revenues from wholly owned operations. Sales to three customers accounted for 10.5%, 21.0% and 19.7% of total revenues from wholly owned operations in 1999. During 1999, the Company entered into transition agreements with these customers providing for the sale of energy and other ancillary services generated from certain electric generating facilities recently acquired from these customers and others. These agreements generally range from four to ten years in duration. The Company and the Ramsey/Washington Resource Recovery Project have a service agreement for waste disposal, which expires in 2006. Approximately 26.5% in 1998 of the Company's operating revenues were recognized under this contract. In addition, sales to one thermal customer amounted to 10.3% of operating revenues in 1998. F-23

117 NOTE 12 -- FINANCIAL INSTRUMENTS The estimated December 31 fair values of the Company's recorded financial instruments are as follows: 1999 1998 ----------------------- ------------------- CARRYING FAIR CARRYING FAIR AMOUNT VALUE AMOUNT VALUE -------- ----- -------- ----- (THOUSANDS OF DOLLARS) Cash and cash equivalents.......................... $ 31,483 $ 31,483 $ 6,381 $ 6,381 Restricted cash.................................... 17,441 17,441 4,021 4,021 Notes receivable, including current portion........ 71,568 71,568 136,291 136,291 Long-term debt, including current portion.......... 1,971,860 1,931,969 502,476 519,418 For cash, cash equivalents and restricted cash, the carrying amount approximates fair value because of the short-term maturity of those instruments. The fair value of notes receivable is based on expected future cash flows discounted at market interest rates. The fair value of long-term debt is estimated based on the quoted market prices for the same or similar issues. DERIVATIVE FINANCIAL INSTRUMENTS As of December 31, 1999, the Company had no contracts to hedge or protect foreign currency denominated future cash flows. One contract that was executed during 1999 had no material effect on earnings. During the third quarter of 1999, NRG Northeast, a wholly owned subsidiary of the Company entered into $600 million of "treasury locks," at various interest rates, which expired in February 2000. These treasury locks were an interest rate hedge for an NRG Northeast bond offering that was completed on February 22, 2000. The proceeds of this bond offering were used to pay down borrowings under a NRG Northeast's existing short-term credit facility. As of December 31, 1999, the Company had three interest rate swap agreements with notional amounts totaling approximately $393 million. The contracts are used to manage the Company's exposure to changes in interest rates. If the swaps had been discontinued on December 31, 1999, the Company would have owed the counterparties approximately $3 million. Management believes that the Company's exposure to credit risk due to nonperformance by the counterparties to its hedging contracts is insignificant, based on the investment grade rating of the counterparties. - In September 1999, the Company entered into a $200 million swap agreement effectively converting the 7.5 percent fixed rate on its senior notes to a variable rate based on the London Interbank Offered Rate. The swap expires on June 1, 2009. - A second swap effectively converts a $16 million issue of variable rate debt into a fixed rate debt. The swap expires on September 30, 2002. - A third swap converts $177 million of variable rate debt into fixed rate debt. The swap expires on December 17, 2014. The Company's Power Marketing subsidiary uses energy forward contracts along with physical supply, to hedge market risk in the energy market. At December 31, 1999, the notional amount of energy forward contracts was approximately $207 million. If the contracts had been terminated at December 31, 1999, the Company would have received approximately $12.0 million based on price fluctuations to date. Management believes the risk of counterparty nonperformance with regard to any of the Company's hedging transactions is not significant. F-24

118 NOTE 13 -- COMMITMENTS AND CONTINGENCIES OPERATING LEASE COMMITMENTS The Company leases certain of its facilities and equipment under operating leases, some of which include escalation clauses, expiring on various dates through 2010. Rental expense under these operating leases was $5.4 million in 1999 and $1.7 million in 1998. Future minimum lease commitments under these leases for the years ending after December 31, 1999 are as follows: (THOUSANDS OF DOLLARS) ------------- 2000........................................................ $ 5,518 2001........................................................ 5,223 2002........................................................ 4,614 2003........................................................ 4,161 2004........................................................ 4,094 Thereafter.................................................. 35,293 ------- Total..................................................... $58,903 ======= The Company expects to invest approximately $2.7 billion in 2000 and approximately $4.7 billion for the five-year period 2000 - 2004 for nonregulated projects and property, which include acquisitions and projects investments. The Company's capital requirements for 2000 reflect expected acquisitions of existing generation facilities, including Cajun, Killingholme A and the Conectiv fossil assets. CAPITAL COMMITMENTS -- INTERNATIONAL In November 1999, the Company agreed to purchase the 665 MW Killingholme A station from National Power plc. Killingholme A was commissioned in 1994 and is a combined-cycle, gas-turbine power station located in England. The purchase price for the station will be approximately 410 million pounds sterling (approximately $662 million U.S. at end of year exchange rates), subject to commercial adjustments. The purchase price includes 20 million pounds sterling (approximately $32 million U.S. at end of year exchange rates) that is contingent upon the successful completion of negotiations regarding NRG's purchase of National Power's Blyth generating facilities. The Blyth assets consist of two coal-fired stations totaling 1,140 MW of generation capacity located in England. CAPITAL COMMITMENTS -- DOMESTIC The Company, together with its partner and the creditors's committee filed a plan with the United States Bankruptcy Court for the Middle District of Louisiana to acquire 1,708 MW of fossil generating assets from Cajun Electric Power Cooperative of Baton Rouge, Louisiana (Cajun) for approximately $1.0 billion The consortium has the support of the Chapter 11 trustee and Cajun's secured creditors. During the third quarter of 1999, the U.S. Bankruptcy Judge confirmed the creditors plan of reorganization and the Company exercised an option to purchase its partner's 50 percent interest in the project. The Company expects to close the acquisition of the Cajun assets during the first quarter of 2000. In January 2000, the Company agreed to purchase 1,875 MW of fossil-fueled electric generating capacity and other assets from Conectiv of Wilmington, Delaware for $800 million. The fossil-fueled generating facilities consist of Conectiv's wholly owned BL England, Deepwater, Indian River and Vienna steam stations plus Conectiv's interest in the Conemaugh and Keystone steam stations. Other assets in the purchase are the 241-acre Dorchester site located in Dorchester County, Maryland, certain Merrill Creek Reservoir entitlements in Harmony Township, New Jersey and certain excess emission allowances. In January 2000, the Company executed a memorandum of understanding with GE Power Systems, a division of General Electric Company, to purchase 11 gas turbine generators and five steam turbine generators. The purchase will take place over the next five years and is valued at approximately $500 million with an option to purchase additional units. The 16 turbines have an equivalent generation output of 3,000 MW and will be installed at the Company's existing North American plant sites. F-25

119 The Company has contractually agreed to the monetization of certain tax credits generated from landfill gas sales through the year 2007. Future capital commitments related to projects are as follows: (MILLIONS OF DOLLARS) ------------ 2000........................................................ $2,700 2001........................................................ 500 2002........................................................ 500 2003........................................................ 500 2004........................................................ 500 ------ Total..................................................... $4,700 ====== SOURCE OF CAPITAL The Company anticipates funding its ongoing capital commitments through the issuance of debt, additional equity from NSP, and operating cash flows. In addition, the Company may issue a limited amount of equity financing to third parties for funding a portion of the capital requirements. CONTINGENT REVENUES During 1999, the first year of deregulation in the state of New York power industry, the Company has claims related to certain revenues earned during the period April 27, 1999 to December 31, 1999. The Company is actively pursuing resolution and/or collection of these amounts, which totaled approximately $8.9 million as of December 31, 1999. These amounts have not been recorded in the financial statements and will not be recognized as income until disputes are resolved and collection is assured. The contingent revenues relate to interpretation of certain transition power sales agreements and to sales to the NYPP and NEPOOL, conflicting meter readings, pricing of firm sales and other power pool reporting issues. CONTRACTUAL COMMITMENTS Arthur Kill Power and Astoria Power have entered into agreements with ConEd that obligate them to maintain the electric generating capability and availability of their respective facilities at specified levels for the terms of these agreements, and whereby during certain periods, ConEd will purchase specified amounts of capacity, as long as the capacity is counted in the installed capacity requirement for New York City. The capacity must satisfy all criteria, standards and requirements applicable to providers of installed capacity established by the New York State Reliability Counsel ("NYSRC"), the Northwest Power Coordinating Council ("NPCC"), the North American Electric Reliability Council ("NERC"), the New York Power Pool (NYPP) or the NYISO. Should the capacity of the facility drop below the minimum level required, the subsidiary owning the facility will pay to ConEd a deficiency charge. The sellers may use electric capacity other than that generated by their own plants to satisfy ConEd's demands. The respective subsidiary will bill ConEd for the electricity capacity sold and ConEd will bill that subsidiary for any capacity deficiency payments on a monthly basis. Any amount unpaid after it is due will accrue interest. Any dispute on the amount payable will first be settled by good faith negotiation among the parties. For the next four years, the Company estimates that a significant portion of the total revenues from the Dunkirk and Huntley facilities will be derived from four-year transition contracts for capacity and energy. All forward capacity is sold to NIMO during the transition period, with the remainder of energy sold to the NYISO. Each of the following agreements was executed on June 11, 1999 and extends for a term of four years. To hedge its transition to market rates, NIMO has required NRG Power Marketing to enter into an International Swap Dealers Association (ISDA) Master Agreement (together with the Schedule, the Confirmation and the Guarantee Agreement, the "Swap Agreement"). Under the Swap Agreement, NIMO will pay to NRG Power Marketing a fixed monthly price for the Dunkirk (units 1, 2, 3 and 4) and Huntley (units 67 and 68 only) facilities' capacity and ancillary services and NRG Power Marketing will F-26

120 pay to NIMO the market rates for the related capacity and ancillary services. The swap is only a financial contract and it incorporates the terms of the ISDA Master Agreement. NIMO will have the right from time to time to exercise a call option for an additional swap pursuant to which, within a certain limit consistent with outages and availability requirements, NIMO will nominate certain amounts of energy from the Dunkirk and Huntley facilities and will pay to NRG Power Marketing an amount for such energy determined in accordance with the heat rate curve representing the nominated unit. NRG Power Marketing will pay to NIMO the market rates for such energy at the time that the energy was nominated. However, NRG Power Marketing may refuse the call option for either of the facilities if a facility is unexpectedly forced off-line or derated sufficiently to be unable to fulfill the portion of the specified quantity of power in the option. Any such refusal of the call option will be limited to the Decline Quantity Cap, which is calculated based upon the capacity of the relevant facility for the prior six months. NIMO will be entitled to make up for any refused call option in the future by delivering reasonable notice to NRG Power Marketing. In addition to the Swap Agreement, Huntley Power has entered into an agreement with NIMO that gives NIMO the option to purchase from the Huntley facility certain quantities of electricity generated by Huntley units 65 and 66, during the summer and winter months, up to a specified maximum limit for the term of this agreement. If Huntley Power is selling the electrical output generated by units 65 and 66 to a third party, Huntley Power may refuse to deliver such output to NIMO. Furthermore, if unit 65 or 66 is generating for NIMO, Huntley Power has the right to "recall" the unit(s) in order to facilitate a sale to a third party. If Huntley Power fails to meet NIMO's quantity request for electricity output, it will compensate NIMO. NIMO will pay Huntley Power according to the amount of electricity output delivered to NIMO, on a monthly basis. Control and title pass at the point of delivery of the energy and each party agrees to indemnify the other against any claims arising out of any act or incident occurring during the period when control and title of the electricity is vested in the indemnifying party. Huntley Power has also entered into an agreement with NIMO that gives NIMO the option to purchase from Huntley Power certain quantities of electricity generated by Huntley units 67 or 68 (during peak and off-peak summer hours), within a specified range of MW per hour, not to exceed 189 MW for any one hour during the peak hours, for the term of the agreement. If Huntley Power fails to meet NIMO's quantity request for electricity, Huntley Power will compensate NIMO for quantities not provided. NIMO will pay Huntley Power according to the amount of power delivered to NIMO, on a monthly basis. Control and title passes at the point of delivery of the energy and each party shall indemnify the other party from any claims arising out of any act or incident occurring during the period when control and title of the electricity is vested in the indemnifying party. Oswego Power has entered into a four-year transition power sales contract with NIMO in order to hedge its transition to market rates. Under the agreement, NIMO will pay to Oswego Power a fixed monthly price plus start up fees for the right, but not the obligation, to claim, at a specified delivery point or points, the installed capacity of unit 5 of the Oswego facility, and for the right to exercise, at a specified price, an option for an additional 350 MW of installed capacity. The total amount of energy which Oswego Power must supply under the call option is limited to a nominal amount of energy per year. Oswego Power may refuse such option if the facility is unexpectedly unavailable or derated sufficiently to be unable to fulfill the option, as long as Oswego Power uses "good utility practice" to maintain the power stations. Oswego Power may also choose to supply the energy required from another source as long as adjustment is made for any difference in value between the agreed upon delivery point and the actual point of delivery. In the event that Oswego Power is unable to provide from its own sources installed capacity of unit 5 in the amount claimed by NIMO, Oswego Power must procure the capacity from the market and provide it to NIMO at no additional cost or else suffer a penalty. NRG Power Marketing has entered into a Wholesale Standard Offer Service Agreement, dated October 13, 1998 and amended as of January 15, 1999 (the "WSO Agreement"), with Blackstone Valley Electric Company, Eastern Edison Company, and Newport Electric Corporation (collectively the "EUA Companies"), which obligates NRG Power Marketing to provide each of the EUA Companies with firm all-requirements electric service, including capacity, energy, reserves, losses and related services necessary F-27

121 to serve a specified share of the EUA Companies' aggregate load attributable to retail customers taking standard offer service. NRG Power Marketing assumes all expenses, liabilities and losses, regulatory or economical, related to such service. NRG Power Marketing may supply the power to the EUA Companies at any point on the New England Power Pool transmission facilities system or on the EUA Companies' system. The price for each unit of electricity is a combination of a fixed price plus a fuel adjustment factor. The EUA Companies will calculate the estimated power supplied each month and pay to NRG Power Marketing the price for such electricity before the end of the next month. Any amounts unpaid by the due date will accrue interest. The EUA Companies may make retroactive adjustments to the bills for up to one year after the date of the original billing. NRG Power Marketing must meet certain creditworthiness criteria for the term of the agreement, or must provide a guaranty from an entity which meets the creditworthiness criteria. The term extends from April 26, 1999, the closing date of the asset purchase agreement until December 31, 2009. The agreement may also be terminated in the case of an event of default or if the facility's electric service requirement is less than 1 MW/hr for two consecutive months. In 1999, the Company entered into a Standard Offer Service Wholesale Sales Agreement with CL&P. The Company will supply CL&P with 35 percent of its standard offer service load during 2000, 40 percent during 2001 and 2002, and 45 percent during 2003. The four year contract is valued at $1.7 billion. The Company will serve the load with a combination of existing generation and power purchases. ENVIRONMENTAL REGULATIONS Environmental controls at the federal, state, regional and local levels have a substantial impact on the Company's operations due to the cost of installation and operation of equipment required for compliance. AIR On October 12, 1999, the Company received a letter from the Office of the Attorney General of the State of New York speculating that based on a preliminary analysis, it believes that significant modifications were made to the Huntley and Dunkirk facilities during NIMO's ownership of these facilities without obtaining Prevention of Significant Deterioration (PSD) and/or New Source Review (NSR) permits. The letter requested documents related to historic maintenance, repair, and replacement work at the facilities, as well as other data related to operations and emissions from these facilities. On January 12, 2000, the Company received a formal request from the New York Department of Environmental Conservation (NYDEC) seeking essentially the same documents covered by the Attorney General's letter. The Company understands that the NYDEC request supercedes the Attorney General's request. Although, the Company does not have knowledge that NIMO failed to comply with the preconstruction permit requirements at the Huntley and Dunkirk facilities, the Company has only recently initiated steps to investigate more fully allegations to the contrary. If it is determined that these facilities did not comply with the PSD or NSR permit programs, the Company could be required among other things, to install pollution control technology to further control the emissions of nitrogen oxide (NO(X)) and sulfur dioxide (SO(2)) from the Huntley and Dunkirk facilities. By virtue of conditions imposed under the asset sale agreement between the Company and NIMO (the Company's rights and obligations under the asset sale agreement were substantially assigned to Huntley Power LLC and Dunkirk Power LLC), NIMO remains responsible for "any fines, penalties and assessments imposed by a governmental entity with respect to violation or alleged violation of Environmental Law which occurred prior to the Closing Date." Even so, the Company could become subject to fines and/or penalties associated with the period of time it has operated the facilities. On October 14, 1999, Governor Pataki of New York directed the Commissioner of the NYDEC to require further reductions of SO(2) emissions and NO(X) emissions from New York power plants, beyond that which is required under current federal and state law. Under Governor Pataki's directive NO(X) emissions during the "non-ozone" season would be reduced to levels consistent with those currently mandated for the F-28

122 "ozone" season under the Ozone Transport Commission's Memorandum of Understanding. This additional reduction requirement would be phased in between January 1, 2003 and January 2, 2007. In addition, Governor Pataki announced that he is ordering a reduction of S02 emissions by 50% beyond the requirements of the Federal Acid Rain Program. These reductions would also be phased in between January 1, 2003 and January 1, 2007. Compliance with these emission reduction requirements, if they become effective, could have a material impact on the operation of the Company's facilities located in the State of New York. On November 3, 1999, in the southern and mid-western regions of the United States, the United States Department of Justice (DOJ) filed suit against seven electric utilities for alleged violations of the Federal Clean Air Act (the Clean Air Act) NSR and PSD permit requirements at seventeen utility generating stations located in the southern and mid-western regions of the United States. In addition, the United States Environmental Protection Agency (U.S. EPA) issued administrative notices of violation alleging similar violations at eight other power plants owned by certain of the electric utilities named as defendants in the DOJ lawsuit, and also issued an administrative order to the Tennessee Valley Authority for similar violations at seven of its power plants. The DOJ lawsuit alleges that the defendants, over a period of twenty years, undertook modifications at their generating stations that resulted in increased air emissions without complying with stringent regulatory requirements governing such modifications. Subsequent to the DOJ lawsuit, New York, Connecticut and New Jersey have brought their own lawsuits against American Electric Power, an Ohio based utility holding company, and have sought to intervene in the DOJ lawsuit. To date, no lawsuits or administrative actions have been brought against the Company or the former owners of the facilities alleging violations of the NSR or PSD requirements. However, there is a likelihood that future lawsuits alleging similar violations may be filed against additional electric utility generating stations. The Company can provide no assurance that lawsuits or administrative actions alleging violations of PSD and NSR requirements will not be filed in the future. The State of Connecticut has in the past considered legislation that would require older electrical generating stations to comply with more stringent pollution standards for NO(X) and SO(2) emissions. During the 1999 legislative session, the Connecticut House of Representatives voted in favor of such legislation. The House bill was referred to the Energy Technology Committee where no action was taken. Similar legislation has been introduced as part of the 2000 legislative session. SITE CONTAMINATION/REMEDIATION With the acquisition of the NRG Northeast assets, the Company assumed certain liabilities for existing environmental conditions at the sites with the exception of off-site liabilities associated with the disposal of hazardous materials and certain other environmental liabilities. The Company has not assumed responsibility for any contamination resulting from the September 7, 1998 explosion and subsequent fire involving a transformer containing PCBs at the Arthur Kill Station. The transformer explosion, fire and subsequent oil spill resulted in the release of PCB's to the environment. Consolidated Edison Company of New York, Inc. maintains responsibility for the remediation of the PCB and other contamination associated with this event. Environmental site assessments have been prepared for all of the recently acquired NRG Northeast assets. The remediation activities at the Arthur Kill, Astoria Gas Turbine and Somerset facilities are still in the study phase. As such, the remediation cost estimates are based on approaches that have not been approved yet by the regulatory agencies involved. Data from additional investigations performed at the Astoria Gas Turbines and the approach being taken at the Somerset Station may result in less costly remediation efforts than originally estimated. For the Connecticut facilities, the Company is planning to conduct additional studies to better quantify remedial need. Such studies include the preparation of risk assessments to justify remedial actions proposed by the Company to the Connecticut Department of Environmental Protection and U.S. EPA. F-29

123 COSTS The Company has recorded approximately $5.8 million for expected environmental costs related to site remediation issues at the Arthur Kill, Astoria facilities and Somerset facilities. These amounts are based on the environmental assessments for these sites. The Company has budgeted approximately $44 million for capital expenditures between 2000 and 2004 for environmental compliance, which includes the above remedial investigations, the installation of NO(X) control technology at the Somerset facility, intake screens at the Dunkirk facility, the resolution of consent orders for remediation at the Arthur Kill and Astoria facilities and the resolution of a consent order for water intake at the Arthur Kill facility. CLAIMS AND LITIGATION On or about July 12, 1999, Fortistar Capital Inc., a Delaware Corporation (Fortistar), filed a complaint in District Court (Fourth Judicial District, Hennepin County) in Minnesota against the Company, asserting claims for injunctive relief and for damages as a result of the Company's alleged breach of a confidentiality letter agreement with Fortistar relating to the Oswego facility (Letter Agreement). The Company disputes Fortistar's allegations and has asserted numerous counterclaims. A temporary injunction hearing was held on September 27, 1999. The acquisition of the Oswego facility was closed on October 22, 1999, following notification to the Court of Oswego Power's intention to close on that date. On January 14, 2000, the court denied Fortistar's request for a temporary injunction. The Company intends to continue to vigorously defend the suit and believes Fortistar's complaint to be without merit. No trial date has been set. The Company is involved in various other litigation matters. The Company is actively defending these matters and does not feel the outcome of such matters would materially impact the Company's results of operations. NOTE 14 -- SEGMENT REPORTING The Company conducts its business within three segments: Independent Power Generation, Alternative Energy (Resource Recovery and Landfill Gas) and Thermal projects. These segments are distinct components of the Company with separate operating results and management structures in place. F-30

124 The "Other" category includes operations that do not meet the threshold for separate disclosure and corporate charges that have not been allocated to the operating segments. INDEPENDENT POWER ALTERNATIVE GENERATION ENERGY THERMAL OTHER TOTAL ----------- ----------- ------- ----- ----- (THOUSANDS OF DOLLARS) 1999 OPERATING REVENUES Revenues from wholly-owned operations(a).......... $322,943 $ 26,934 $76,277 $ 5,401 $431,555 Intersegment revenues............................. -- 963 -- -- 963 Equity in earnings of unconsolidated affiliates(b)................................... 69,686 (2,205) 19 -- 67,500 -------- -------- ------- -------- -------- Total operating revenues................... 392,629 25,692 76,296 5,401 500,018 -------- -------- ------- -------- -------- OPERATING COSTS AND EXPENSES Cost of wholly-owned operations................... 207,081 24,977 42,401 (4,559) 269,900 Depreciation and amortization..................... 17,153 6,126 6,280 7,467 37,026 General, administrative, and development.......... 33,783 7,876 8,869 33,044 83,572 -------- -------- ------- -------- -------- Total operating costs and expenses......... 258,017 38,979 57,550 35,952 390,498 -------- -------- ------- -------- -------- OPERATING INCOME.................................... 134,612 (13,287) 18,746 (30,551) 109,520 -------- -------- ------- -------- -------- OTHER INCOME (EXPENSE) Minority interest in earnings of consolidated Subsidiary...................................... (2,322) -- (134) -- (2,456) Write-off of investment........................... -- -- -- -- -- Gain on sale of interest in projects.............. -- -- -- 10,994 10,994 Other income, net................................. 2,328 (4,281) 10 8,375 6,432 Interest expense.................................. (25,918) 169 (8,152) (59,475) (93,376) -------- -------- ------- -------- -------- Total other income (expense)............... (25,912) (4,112) (8,276) (40,106) (78,406) -------- -------- ------- -------- -------- INCOME (LOSS) BEFORE INCOME TAXES................... 108,700 (17,399) 10,470 (70,657) 31,114 INCOME TAX (BENEFIT)................................ 8,812 (27,642) 3,963 (11,214) (26,081) -------- -------- ------- -------- -------- NET INCOME.......................................... $ 99,888 $ 10,243 $ 6,507 $(59,443) $ 57,195 1998 OPERATING REVENUES Revenues from wholly-owned operations(a).......... $ 8,185 $ 30,143 $52,699 $ 7,660 $ 98,687 Intersegment revenues............................. -- 1,737 -- -- 1,737 Equity in earnings of unconsolidated affiliates(b)................................... 81,948 (1,314) 1,215 (143) 81,706 -------- -------- ------- -------- -------- Total operating revenues................... 90,133 30,566 53,914 7,517 182,130 -------- -------- ------- -------- -------- OPERATING COSTS AND EXPENSES Cost of wholly-owned operations................... 7,097 20,980 24,665 (329) 52,413 Depreciation and amortization..................... 980 5,590 9,258 492 16,320 General, administrative, and development.......... (7,099) 7,776 3,298 52,410 56,385 -------- -------- ------- -------- -------- Total operating costs and expenses......... 978 34,346 37,221 52,573 125,118 -------- -------- ------- -------- -------- OPERATING INCOME.................................... 89,155 (3,780) 16,693 (45,056) 57,012 -------- -------- ------- -------- -------- OTHER INCOME (EXPENSE) Minority interest in earnings of consolidated Subsidiary........................................ (2,251) -- -- -- (2,251) Write-off of investment........................... (26,740) -- -- -- (26,740) Gain on sale of interest in projects.............. 29,950 -- -- -- 29,950 Other income, net................................. 2,482 2,683 118 3,137 8,420 Interest expense.................................. (586) (1,921) (7,359) (40,447) (50,313) -------- -------- ------- -------- -------- Total other income (expense)............... 2,855 762 (7,241) (37,310) (40,934) -------- -------- ------- -------- -------- INCOME (LOSS) BEFORE INCOME TAXES................... 92,010 (3,018) 9,452 (82,366) 16,078 INCOME TAX (BENEFIT)................................ 18,605 (16,445) 2,852 (30,666) (25,654) -------- -------- ------- -------- -------- NET INCOME.......................................... $ 73,405 $ 13,427 $ 6,600 $(51,700) $ 41,732 F-31

125 INDEPENDENT POWER ALTERNATIVE GENERATION ENERGY THERMAL OTHER TOTAL ----------- ----------- ------- ----- ----- (THOUSANDS OF DOLLARS) 1997 OPERATING REVENUES Revenues from wholly-owned operations(a).......... $ 5,339 $ 27,257 $48,604 $ 9,926 $ 91,126 Intersegment revenues............................. -- 926 -- -- 926 Equity in earnings of unconsolidated affiliates(b)................................... 26,206 (192) 186 -- 26,200 -------- -------- ------- -------- -------- Total operating revenues................... 31,545 27,991 48,790 9,926 118,252 -------- -------- ------- -------- -------- OPERATING COSTS AND EXPENSES Cost of wholly-owned operations................... 1,693 17,730 24,902 2,392 46,717 Depreciation and amortization..................... 483 2,842 6,623 362 10,310 General, administrative, and development.......... 8,186 6,111 2,403 26,416 43,116 -------- -------- ------- -------- -------- Total operating costs and expenses......... 10,362 26,683 33,928 29,170 100,143 -------- -------- ------- -------- -------- OPERATING INCOME.................................... 21,183 1,308 14,862 (19,244) 18,109 -------- -------- ------- -------- -------- OTHER INCOME (EXPENSE) Minority interest in earnings of consolidated Subsidiary...................................... (131) (131) Write-off of investment........................... (8,964) (8,964) Gain on sale of interest in projects.............. 1,559 7,143 8,702 Other income, net................................. 5,888 2,618 (14) 3,272 11,764 Interest expense.................................. (653) (529) (5,958) (23,849) (30,989) -------- -------- ------- -------- -------- Total other income (expense)............... (2,301) 2,089 (5,972) (13,434) (19,618) -------- -------- ------- -------- -------- INCOME (LOSS) BEFORE INCOME TAXES................... 18,882 3,397 8,890 (32,678) (1,509) INCOME TAX (BENEFIT)................................ (6,502) (4,888) 3,165 (15,266) (23,491) -------- -------- ------- -------- -------- NET INCOME.......................................... $ 25,384 $ 8,285 $ 5,725 $(17,412) $ 21,982 - --------------- (a) Revenues from wholly-owned operations are from external customers located in the United States. (b) The Company has significant equity investments for non-regulated projects outside of the United States. Equity earnings of unconsolidated affiliates, primarily independent power projects, includes $33.5 million in 1999, $29.3 million in 1998 and $27.1 million in 1997 from non-regulated projects located outside of the United States. The Company's equity investments in projects outside of the United States were $602.4 million in 1999, $591 million in 1998 and $517 million in 1997. F-32

126 NRG ENERGY, INC. INTRODUCTION TO PRO FORMA FINANCIAL STATEMENTS On March 31, 2000, Louisiana Generating LLC (Louisiana Generating), a wholly-owned subsidiary of NRG Energy, Inc. (NRG) completed the purchase of 1,708 megawatts (MW) of fossil fuel generating assets from Cajun Electric Power Cooperative, Inc. (Cajun) for approximately $1.026 billion. The purchase price was funded through an $800 million bond offering and an equity contribution from NRG. The Cajun assets consist of two plants near New Roads, Louisiana, a two-unit, 220 MW gas-turbine generating station and a three-unit 1,488 MW coal fired generating station. Louisiana Generating was formed for the purpose of facilitating the acquisition of the Cajun facilities and will own, operate and maintain the Cajun facilities. The purchase price of $1.026 billion has been preliminarily allocated to tangible assets, identifiable assets and intangible assets of Louisiana Generating based on estimates of their respective values and an initial review of an appraisal recently completed. This appraisal needs to be carefully evaluated and will most likely be adjusted for other valuations and studies currently underway. These evaluations and studies will be completed over the next several months and, as such, final values may differ substantially from those shown. The pro forma combined financial statements should be read in conjunction with NRG's and the Cajun Electric (carve-out) historical financial statements. The following pro forma income statement presents the combination of NRG and the Cajun Electric facilities as if the acquisition occurred on January 1, 1999. The pro forma balance sheet presents the combination of NRG and the Cajun Electric facilities as if the acquisition occurred on December 31, 1999. The 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 Electric facilities been consummated at the beginning of the respective periods or as of the date for which pro forma financial information is presented. F-33

127 NRG ENERGY, INC. PRO FORMA BALANCE SHEET DECEMBER 31, 1999 (THOUSANDS OF DOLLARS) (UNAUDITED) CAJUN ELECTRIC PRO FORMA ADJUSTMENTS NRG NRG (CAJUN ------------------------ ENERGY, INC. ENERGY, INC. FACILITIES) DEBIT CREDIT PRO FORMA ------------ -------------- ---------- ---------- ------------ ASSETS CURRENT ASSETS Cash and cash equivalents...... $ 31,483 $ -- $ -- $ -- $ 31,483 Restricted cash................ 17,441 17,441 Accounts receivable-trade, less allowance for doubtful accounts of $186............ 126,376 33,842 160,218 Accounts receivable-affiliates....... -- -- Taxes receivable............... -- -- Current portion of notes receivable-affiliates....... 287 287 Current portion of notes receivable.................. -- -- Inventory...................... 119,181 34,234 153,415 Prepayments and other current assets...................... 29,202 1,600 30,802 ---------- ---------- ---------- ---------- ---------- Total current assets........ 323,970 69,676 -- -- 393,646 ---------- ---------- ---------- ---------- ---------- PROPERTY PLANT AND EQUIPMENT, AT ORIGINAL COST In service..................... 2,022,724 1,208,832 451,647(A) 3,683,203 Under construction............. 53,448 3,996 57,444 ---------- ---------- ---------- ---------- ---------- Total property, plant and equipment................. 2,076,172 1,212,828 451,647 -- 3,740,647 Less accumulated depreciation................ (156,849) (632,899) (789,748) ---------- ---------- ---------- ---------- ---------- Net property, plant and equipment................. 1,919,323 579,929 451,647 -- 2,950,899 ---------- ---------- ---------- ---------- ---------- OTHER ASSETS Investments in projects........ 988,671 988,671 Capitalized project costs...... 2,592 2,592 Notes receivable, less current portion-affiliates.......... 65,494 65,494 Notes receivable, less current portion..................... 5,787 5,787 Intangible assets, net of accumulated amortization of $4,308...................... 55,586 55,586 Debt issuance costs, net of accumulated amortization of $6,640...................... 20,081 20,081 Other assets, net of accumulated amortization of $8,909...................... 50,180 4,188 54,368 ---------- ---------- ---------- ---------- ---------- Total other assets.......... 1,188,391 4,188 -- -- 1,192,579 ---------- ---------- ---------- ---------- ---------- TOTAL ASSETS..................... $3,431,684 $ 653,793 $ 451,647 $ -- $4,537,124 ========== ========== ========== ========== ========== F-34

128 CAJUN ELECTRIC PRO FORMA ADJUSTMENTS NRG NRG (CAJUN ------------------------ ENERGY, INC. ENERGY, INC. FACILITIES) DEBIT CREDIT PRO FORMA ------------ -------------- ---------- ---------- ------------ LIABILITIES AND STOCKHOLDERS EQUITY CURRENT LIABILITIES Current portion of project level long-term debt........ $ 30,462 $ -- $ -- $ -- $ 30,462 Revolving line of credit and other short term debt....... 340,000 288,000(D) 628,000 Consolidated project level, non recourse debt............... 35,766 35,766 Accounts payable-trade......... 61,211 4,806 66,017 Accounts payable-affiliate..... 6,404 6,404 Accrued income taxes........... 4,730 4,730 Accrued property and sales taxes....................... 4,998 150 5,148 Accrued salaries, benefits and related costs............... 9,648 9,648 Accrued interest............... 13,479 13,479 Other current liabilities...... 17,657 8,966 26,623 ---------- ---------- ---------- ---------- ---------- Total current liabilities... 524,355 13,922 -- 288,000 826,277 OTHER LIABILITIES Minority Interest.............. 14,373 14,373 Consolidated project level, long-term, non recourse debt........................ 1,026,398 800,000(B) 1,826,398 Corporate level long-term debt, less current portion........ 915,000 915,000 Deferred income taxes.......... 16,940 16,940 Deferred investment tax credits..................... 1,088 1,088 Postretirement and other benefit obligations......... 24,613 24,613 Other long-term obligations and deferred income............. 15,263 3,518 18,781 ---------- ---------- ---------- ---------- ---------- Total liabilities.............. 2,538,030 17,440 -- 1,088,000 3,643,470 ---------- ---------- ---------- ---------- ---------- STOCKHOLDER'S EQUITY Common stock; $1 par value; 1,000 shares authorized; 1,000 shares issued and outstanding................. 1 1 Additional paid-in capital..... 781,913 636,353 636,353(C) 781,913 Retained earnings.............. 187,210 187,210 Accumulated other comprehensive income...................... (75,470) (75,470) ---------- ---------- ---------- ---------- ---------- Total Stockholder's equity.................... 893,654 636,353 636,353 -- 893,654 ---------- ---------- ---------- ---------- ---------- TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY........... $3,431,684 653,793 $1,088,000 $1,088,000 $4,537,124 ========== ========== ========== ========== ========== FOOTNOTES (A) Reflects increase in overall fixed asset balances resulting from purchase accounting adjustments net of depreciation expense. (B) Reflects $800 million debt from issuance of bonds. (C) Reflects elimination of Cajun Electric equity. (D) Reflects short-term borrowings used to fund the acquisition of the Cajun facilities. F-35

129 NRG ENERGY, INC. PRO FORMA INCOME STATEMENT DECEMBER 31, 1999 (THOUSANDS OF DOLLARS) (UNAUDITED) CAJUN ELECTRIC PRO FORMA ADJUSTMENTS NRG NRG (CAJUN ---------------------- ENERGY, INC. ENERGY, INC. FACILITIES) DEBIT CREDIT PRO FORMA ------------ -------------- --------- --------- ------------ OPERATING REVENUES Revenues from wholly-owned operations........................ $432,518 $368,562 $ -- $ -- $ 801,080 Equity in earnings of unconsolidated affiliates........................ 67,500 67,500 -------- -------- ------- ------- --------- Total operating revenues.......... 500,018 368,562 -- -- 868,580 -------- -------- ------- ------- --------- OPERATING COSTS AND EXPENSES Cost of wholly-owned operations...... 269,900 244,044 513,944 Depreciation and amortization........ 37,026 37,930 10,361(1) 64,595 General, administrative and development....................... 83,572 16,804 100,376 -------- -------- ------- ------- --------- Total Operating costs and expenses........................ 390,498 298,778 -- 10,361 678,915 -------- -------- ------- ------- --------- OPERATING INCOME....................... 109,520 69,784 -- 10,361 189,665 -------- -------- ------- ------- --------- OTHER INCOME (EXPENSE) Minority interest in earnings of consolidated subsidiary........... (2,456) (2,456) Gain on sale of interest in projects.......................... 10,994 10,994 Write-off of project investments..... -- (2,878) (2,878) Other income, net.................... 6,432 1,008 7,440 Interest expense..................... (93,376) 73,248(2) (166,624) -------- -------- ------- ------- --------- Total other expense............... (78,406) (1,870) 73,248 -- (153,524) -------- -------- ------- ------- --------- INCOME (LOSS) BEFORE INCOME TAXES...... 31,114 67,914 73,248 10,361 36,141 INCOME TAX BENEFIT..................... (26,081) -- 2,080(3) (24,001) -------- -------- ------- ------- --------- NET INCOME............................. $ 57,195 $ 67,914 $75,328 $10,361 $ 60,142 ======== ======== ======= ======= ========= FOOTNOTES (1) Reflects lower net depreciation/amortization resulting from assets and capitalized costs being depreciated over a longer estimated useful life based on engineering studies. (2) Reflects accrued interest on $800 million principal amount for 12 months at a rate of 9.156% per annum. (3) Incremental tax expense due to increased taxable income computed at 41.37%. F-36

130 REPORT OF INDEPENDENT ACCOUNTANTS To the Management of NRG South Central Generating LLC: In our opinion, the accompanying carve-out statement of net assets and the related carve-out statement of certain revenue and expenses present fairly, in all material respects, the net assets of the Cajun Electric (Cajun Facilities) business to be acquired by Louisiana Generating LLC at December 31, 1999 and 1998, and certain revenue and expenses of its operations for each of the three years in the period ended December 31, 1999 in conformity with accounting principles generally accepted in the United States. These financial statements are the responsibility of NRG South Central Generating LLC's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. Our audit included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. As described in Note 3, the accompanying carve-out financial statements were prepared to present the net assets of the Cajun Electric (Cajun Facilities) business to be acquired by Louisiana Generating LLC and the certain revenue and expenses related to such business and are not intended to be a complete presentation of the assets, liabilities, revenue, expenses and cash flows of Cajun Electric Power Cooperative, Inc. PricewaterhouseCoopers LLP Minneapolis, Minnesota March 7, 2000 F-37

131 CAJUN ELECTRIC (CAJUN FACILITIES) CARVE-OUT STATEMENT OF NET ASSETS DECEMBER 31, ------------------------ 1999 1998 ---------- ---------- (IN THOUSANDS) ASSETS Utility plant Electric plant in service................................. $1,198,928 $1,191,375 Less: Accumulated depreciation and amortization........... 632,899 594,539 ---------- ---------- 566,029 596,836 Construction work in progress............................. 3,996 1,455 Electric plant held for future use........................ 9,904 9,904 ---------- ---------- 579,929 608,195 ---------- ---------- Other property and investments Non-utility property...................................... 670 670 Decommissioning reserve fund.............................. 3,518 3,225 ---------- ---------- 4,188 3,895 ---------- ---------- Current assets Accounts receivable -- electric customers Members................................................ 25,944 23,504 Nonmembers............................................. 6,220 4,725 Accounts receivable -- other.............................. 1,678 2,043 Fuel and supplies inventories............................. 34,234 40,578 Prepaids.................................................. 1,600 1,316 ---------- ---------- 69,676 72,166 ---------- ---------- Total assets...................................... 653,793 684,256 ---------- ---------- LIABILITIES Current liabilities Accounts payable.......................................... 4,806 2,114 Taxes other than income tax............................... 150 215 Other accrued expenses.................................... 8,966 13,904 ---------- ---------- 13,922 16,233 ---------- ---------- Decommissioning............................................. 3,518 3,225 ---------- ---------- Total liabilities...................................... 17,440 19,458 ---------- ---------- Net assets........................................ $ 636,353 $ 664,798 ========== ========== See accompanying notes to financial statements. F-38

132 CAJUN ELECTRIC (CAJUN FACILITIES) CARVE-OUT STATEMENT OF CERTAIN REVENUE AND EXPENSES YEAR ENDED DECEMBER 31, -------------------------------- 1999 1998 1997 -------- -------- -------- (IN THOUSANDS) Operating revenue Sales of electric energy Members............................................... $292,090 $289,856 $280,109 Nonmembers............................................ 75,258 66,341 65,715 Other.................................................... 1,214 1,379 958 -------- -------- -------- 368,562 357,576 346,782 -------- -------- -------- Operating expenses Power production Fuel.................................................. 165,597 154,964 154,257 Operations and maintenance............................ 36,673 37,405 37,236 Purchased power.......................................... 10,951 11,645 12,681 Other power supply expenses.............................. 577 592 578 Transmission............................................. 30,246 29,882 41,687 Administrative and general............................... 9,711 9,122 9,437 Depreciation and amortization............................ 37,930 38,117 39,537 Taxes, other than income................................. 7,093 7,629 8,575 -------- -------- -------- 298,778 289,356 303,988 -------- -------- -------- Operating income........................................... 69,784 68,220 42,794 -------- -------- -------- Other income and expenses Interest, rents and leases............................... 463 456 695 Other income............................................. 545 787 730 Loss on asset dispositions............................... (2,878) (5,900) (481) -------- -------- -------- (1,870) (4,657) 944 -------- -------- -------- Revenues in excess of expenses............................. $ 67,914 $ 63,563 $ 43,738 ======== ======== ======== See accompanying notes to financial statements. F-39

133 CAJUN ELECTRIC (CAJUN FACILITIES) NOTES TO CARVE-OUT FINANCIAL STATEMENTS 1. BUSINESS DESCRIPTION The accompanying "carve-out" financial statements present the net assets and certain revenue and expenses of the non-nuclear electric power generating business (herein named "Cajun Electric (Cajun Facilities)") of Cajun Electric Power Cooperative, Inc. (the "Cooperative"). The Cooperative is a rural electric generation and transmission cooperative wholly owned by 11 distribution cooperatives (the "Members"). Pursuant to a competitive bidding process following the Cooperative's Chapter 11 bankruptcy proceeding, Louisiana Generating LLC has agreed to acquire the Cooperative's non-nuclear electric power generating facilities (see Notes 2 and 3). Louisiana Generating LLC is a wholly owned subsidiary of NRG South Central Generating LLC, which in turn is an indirect wholly owned subsidiary of NRG Energy, Inc. NRG Energy, Inc. is a wholly owned subsidiary of Northern States Power Company. 2. BANKRUPTCY PROCEEDING Bankruptcy Filing On December 21, 1994 (the "Petition Date"), the Cooperative filed a Petition for Reorganization under Chapter 11 of the United States Bankruptcy Code and began operating as debtor-in-possession under the supervision of the United States Bankruptcy Court for the Middle District of Louisiana (the "Bankruptcy Court"). In August 1995, the United States District Court for the Middle District of Louisiana (the "Court") ordered the appointment of a trustee (the "Trustee") to oversee the Cooperative's operations for the benefit of claim holders and interest holders. All debts of the Cooperative as of the Petition Date were stayed by the bankruptcy petition and subject to compromise pursuant to such proceedings. The Cooperative operated its business and managed its assets in the ordinary course as debtor-in-possession, and was required to obtain Trustee approval for transactions outside the ordinary course of business. Plan of Reorganization and Acquisition On January 22, 1996, the Court approved the Trustee's motion to establish procedures for submission of proposals to purchase the Cooperative's assets. The Trustee ultimately selected a bid by NRG Energy, Inc. to create a new limited liability company (Louisiana Generating LLC) to purchase certain non-nuclear assets of the Cooperative. In September 1999, the Bankruptcy Court approved the Plan of Reorganization (the "Plan"), which incorporates the Acquisition Agreement (see Note 3). The purchase price of the assets to be acquired by Louisiana Generating LLC is $1,026 million, subject to adjustment for interest rate fluctuations beyond specific levels. In addition, Louisiana Generating LLC has agreed to reimburse the Members for up $14 million of the expenses that the Members incurred in connection with the bankruptcy of the Cooperative. The transaction is scheduled to close on March 31, 2000, subject to various conditions. The assets to be acquired by Louisiana Generating LLC include all non-nuclear assets owned by the Cooperative, other than enumerated excluded assets defined in the Acquisition Agreement. Generally, the assets to be acquired consist of: - Big Cajun I and Big Cajun II, Units 1 and 2; - the Cooperative's 58% interest in Big Cajun II, Unit 3; - an energy control center and headquarters building; - approximately 4,200 acres of agricultural land near Coushatta, Louisiana; - a 540 MW General Electric steam turbine generator; F-40

134 CAJUN ELECTRIC (CAJUN FACILITIES) NOTES TO CARVE-OUT FINANCIAL STATEMENTS -- (CONTINUED) - a 17.5 mile gas pipeline system; - 848 steel rotary dump railcars; - approximately 38,000 annual sulfur dioxide allowances; - all coal inventory, oil in storage, materials and supplies; - the Big Cajun II solid waste closure investment fund; and - certain transmission assets and all other substations. Louisiana Generating LLC will not assume any liabilities of the Cooperative, other than (i) obligations under any of the contracts that Louisiana Generating LLC assumes in connection with the acquisition and which arise on or after the closing date of the acquisition, (ii) contingent liabilities related to certain tax benefit transfer agreements to which the Cooperative was a party and (iii) environmental liabilities that may exist related to the transferred property, including the obligation to rehabilitate the Big Cajun II ash and wastewater impoundment areas (see Note 8). 3. BASIS OF PRESENTATION The accompanying carve-out financial statements have been presented in accordance with generally accepted accounting principles and were derived from the historical accounting records of the Cooperative. The statements are intended to present the net assets and certain revenue and expenses of the Cajun Electric (Cajun Facilities) business to be acquired by Louisiana Generating LLC pursuant to the Fifth Amended and Restated Asset Purchase and Reorganization Agreement among Louisiana Generating LLC, Ralph R. Mabey, as Chapter 11 Trustee of Cajun Electric Power Cooperative, Inc., and NRG Energy, Inc. (as to Sections 7.4, 9.13 and 9.14 of the agreement only) (the "Acquisition Agreement") and the Cooperative's bankruptcy proceedings (see Note 2). Louisiana Generating LLC has agreed to purchase substantially all of the Cooperative's non-nuclear electric power generating facilities and related transmission assets, inventory and other real and personal property. Louisiana Generating LLC will not acquire the "Excluded Assets", as defined in the Acquisition Agreement, which generally consist of the Cooperative's cash, receivables and investments, nor will it assume any liabilities of the Cooperative, except as described in Note 2. Accordingly, the carve-out financial statements do not include all assets, liabilities, revenue and costs and expenses of the Cooperative as of and for the periods presented. Generally, the statements of net assets exclude the Cooperative's cash, investments (except decommissioning trust fund investments), employee post-retirement benefit obligation, liabilities subject to compromise in the bankruptcy proceeding, income taxes and equity and margin accounts. The statements of certain revenue and expenses exclude the Cooperative's investment earnings (except earnings from the decommissioning trust fund investments), bankruptcy reorganization costs, income taxes, and revenue, expenses and losses related to the ownership, operation and disposal of its 30% interest in the River Bend Nuclear Station in 1997. All long-term debt of the Cooperative is subject to compromise in the bankruptcy proceeding and during the three years ended December 31, 1999 the Cooperative did not record any interest expense thereon in accordance with American Institute of Certified Public Accountants Statement of Position No. 90-7, "Financial Reporting by Entities in Reorganization Under the Bankruptcy Code." Therefore, the carve-out financial statements do not include any long-term debt of the Cooperative or interest expense thereon. Although Louisiana Generating LLC will not purchase any receivables or assume any liabilities of the Cooperative, except as described in Note 2, the statements of net assets include receivables, accounts payable and accrued expenses in order to present the historical net assets of the business operation that will be acquired. F-41

135 CAJUN ELECTRIC (CAJUN FACILITIES) NOTES TO CARVE-OUT FINANCIAL STATEMENTS -- (CONTINUED) The carve-out financial statements do not include a statement of cash flows due to exclusion of cash from the statements of net assets. However, see Note 4 for a summary of cash provided by and used in Cajun Electric's (Cajun Facilities) operating and investing activities. 4. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates. Significant Customers and Concentrations of Credit Risk During 1999 sales to two customers totaled 16.7% and 18.9%, respectively, of total operating revenue (1998: 16.7% and 19.2%, respectively; 1997: 16.2% and 19.0%, respectively). No other customer accounted for more than 10% of total operating revenue during the years ended December 31, 1999, 1998 and 1997. Electric Plant in Service and Construction Work in Progress Electric plant in service and construction work in progress are stated on the basis of cost. Depreciation is computed using the straight-line method over the expected useful lives of the related component assets. The net book value of units of property replaced or retired, including costs of removal net of any salvage value, is charged to operations. Fuel and Supplies Inventories Fuel and supplies inventories are stated on the basis of cost utilizing the weighted-average cost method of inventory valuation. Fair Values of Financial Instruments Investments held in the decommissioning reserve fund are comprised of U.S. government debt securities carried at amortized cost, which approximates fair value. F-42

136 CAJUN ELECTRIC (CAJUN FACILITIES) NOTES TO CARVE-OUT FINANCIAL STATEMENTS -- (CONTINUED) Summary of Cash Flows Summarized cash flows from operating and investing activities were as follows (in thousands): 1999 1998 1997 -------- -------- -------- Cash flows from operating activities: Revenues in excess of expenses........................... $ 67,914 $ 63,563 $ 43,738 Adjustments to reconcile net margins to net cash: Depreciation and amortization......................... 37,930 38,117 39,537 Asset dispositions.................................... 2,878 5,900 481 Changes in accounts receivable........................ (4,939) 5,988 (2,838) Changes in fuel and prepayments....................... 6,060 (8,184) 5,315 Changes in accounts payable and accrued expenses...... (2,313) (4,333) (254) -------- -------- -------- Net cash provided by operating activities........ 107,530 101,051 85,979 -------- -------- -------- Cash flows from (for) investing activities: Capital expenditures..................................... (11,631) (9,999) (7,074) -------- -------- -------- $ 95,899 $ 91,052 $ 78,905 ======== ======== ======== 5. UTILITY PLANT Electric plant in service is comprised of the following generating facilities: CAPABLE LOUISIANA GENERATING GENERATING ------------------------- GENERATING UNIT CAPACITY PERCENTAGE MEGAWATTS - --------------- ----------- ---------- ----------- (UNAUDITED) (UNAUDITED) Big Cajun II, Unit 1..................................... 575 100% 575 Big Cajun II, Unit 2..................................... 575 100% 575 Big Cajun II, Unit 3..................................... 575 58% 338 Big Cajun I, Unit 1...................................... 110 100% 110 Big Cajun I, Unit 2...................................... 110 100% 110 ----- --- ----- 1,945 1,708 ===== ===== Big Cajun II, Unit 3 is jointly owned by the Cooperative (58%) and Gulf States Utilities (42%). The unit is operated by the Cooperative pursuant to a Joint Ownership Participation and Operating Agreement, which governs the rights and obligations to the ownership of the facility. Each owner is entitled to their ownership percentage of the hourly net electrical output of the unit. All fixed costs of operating the unit are shared in proportion to the respective ownership interests and all variable costs are borne in proportion to the energy delivered to either co-owner. The statements of certain revenue and expenses include the Cooperative's share of all fixed and variable costs of operating the unit. The Cooperative's 58% share of the original cost included in electric plant in service at December 31, 1999 was $291.1 million ($290.9 million at December 31, 1998). The corresponding accumulated depreciation and amortization was $151.1 million ($141.9 million at December 31, 1998). The Cooperative will assign the Joint Ownership Participation and Operating Agreement to Louisiana Generating LLC upon closing of the acquisition. F-43

137 CAJUN ELECTRIC (CAJUN FACILITIES) NOTES TO CARVE-OUT FINANCIAL STATEMENTS -- (CONTINUED) Electric plant in service balances at December 31 consisted of the following (in thousands): 1999 1998 ---------- ---------- Production: Coal...................................................... $1,048,012 $1,041,741 Gas....................................................... 35,368 34,749 Transmission................................................ 94,393 94,320 General..................................................... 21,155 20,565 ---------- ---------- $1,198,928 $1,191,375 ========== ========== Construction work in progress consists of improvements and additions to existing plants. The estimated cost to complete these projects at December 31, 1999 was approximately $10.8 million. Electric plant held for future use of approximately $9.9 million at December 31, 1999 and 1998 consists primarily of land, carried at its original cost of $9.5 million, related to an abandoned lignite project that has been retained as a possible site for a future generating facility. The net change in accumulated depreciation and amortization for the years ended December 31 was (in thousands): 1999 1998 ---------- ---------- Charged to operating expenses............................... $ 37,930 $ 38,117 Charged to fuel inventories and other assets................ 1,192 1,197 ---------- ---------- $ 39,122 $ 39,314 Less: Disposals and other adjustments....................... 762 1,435 ---------- ---------- $ 38,360 $ 37,879 ========== ========== Substantially all of the assets included in the carve-out statements of net assets are pledged as collateral to the Cooperative's long-term debt payable to the Rural Utilities Service. In addition, certain office facilities have been separately pledged as collateral to the Cooperative's industrial revenue bonds. These obligations are included in the Cooperative's pre-petition liabilities subject to compromise, which have been excluded from the carve-out statement of net assets. Upon execution of the Plan and closing of the acquisition, Louisiana Generating LLC will acquire the assets free of such encumbrances. 6. EMPLOYEE BENEFIT PLANS All of the Cooperative's employees participate in the National Rural Electric Cooperatives Association (NRECA) Retirement and Security Program once they have met minimum service requirements. The Cooperative makes annual contributions to the plan equal to the amounts accrued for pension expense. In this master multiple-employer defined benefit plan, which is available to all member cooperatives of the NRECA, the accumulated benefits and plan assets are not determined or allocated separately by individual employer. The Cooperative's contributions to the plan and amounts included in the accompanying statements of certain revenue and expenses of Cajun Electric (Cajun Facilities) totaled approximately $1.7 million, $1.7 million and $1.3 million in 1999, 1998 and 1997, respectively. The Cooperative also maintains a defined contribution pension plan, which constitutes a cash or deferred arrangement under section 401(k) of the Internal Revenue Code of 1986 (as amended). Once minimum service requirements are met, all of the employees of the Cooperative are eligible to participate in the plan. Under the terms of the plan, which is administered by the NRECA, the Cooperative matches 50% of employee contributions up to a maximum of 4% of each participating employee's base F-44

138 CAJUN ELECTRIC (CAJUN FACILITIES) NOTES TO CARVE-OUT FINANCIAL STATEMENTS -- (CONTINUED) compensation. The Cooperative's contributions to the plan and amounts included in the accompanying statement of certain revenue and expenses of Cajun Electric (Cajun Facilities) totaled approximately $0.4 million, $0.3 million and $0.4 million in 1999, 1998 and 1997, respectively. The Cooperative also makes medical benefits available to all retirees. For those nonbargaining employees who retire at age 62 or thereafter and who have at least 10 years of service, the Cooperative will pay a portion of the cost. All other retirees are required to pay the full cost of benefits. Net periodic postretirement benefit expense of approximately $0.8 million, $0.8 million and $0.8 million in 1999, 1998 and 1997, respectively, is included in the accompanying statement of certain revenue and expenses. Upon the closing of the acquisition, all of the Cooperative's employee benefit plans will be terminated, including the defined benefit pension plan, the defined contribution (401(k)) pension plan and the post-retirement healthcare plan and no liabilities related thereto will be assumed by Louisiana Generating LLC. 7. RATES AND REGULATION The electric rates charged by the Cooperative to its Members have been subject to the jurisdiction of the Louisiana Public Service Commission ("LPSC"). For the three years ended December 31, 1999, the Cooperative provided capacity and energy to its 11 Members pursuant to "all requirements" power supply agreements. Generally, the all requirements power supply agreements obligated the Cooperative to supply and required the Members to purchase all of the energy and capacity required by the Members for service to its retail customers, with limited exceptions. The Cooperative also provided capacity and energy to three other customers under long-term power agreements and sold excess capacity and energy on a merchant basis to other power suppliers and marketers. Pursuant to the Acquisition Agreement and the Plan, all 11 Members have elected to terminate, effective on the closing date, their existing all requirements supply agreements with the Cooperative. Each of the 11 Members has selected one of three alternative supply options offered by Louisiana Generating LLC, to be effective immediately after the acquisition closes. Seven of the Members have agreed to purchase power from Louisiana Generating LLC under long-term "all requirements" power supply agreements with terms of 25 years commencing on the acquisition closing. After the initial term, each agreement will continue on a year to year basis unless either party gives the other five years' notice of its intent to terminate the agreement. The remaining four Members have agreed to purchase power from Louisiana Generating LLC under short-term four-year transition power supply agreements. A Member may terminate a short-term agreement upon two years advance notice. The underlying terms and provisions of the long- and short-term power supply agreements offered by Louisiana Generating LLC and selected by the Members have been approved by the LPSC, which has regulatory authority over the Members. Although the form of the agreements have been approved by the LPSC, each Member must obtain approval from the LPSC of the supply alternative selected. Such approval has been obtained by three of the Members that have elected the long-term agreement. The remaining eight Members are expected to request and receive LPSC approval of their decisions prior to the closing of the acquisition. Electric Utility Deregulation On December 17, 1997, the LPSC accepted a staff report finding that deregulation, or retail wheeling, may be in the public interest contingent upon numerous issues being individually and adequately researched. During January 1998, the LPSC investigated the issues of tax implications; unbundling; market structure; market power, reliability, Independent System Operators; stranded costs and benefits; consumer protection, public policy programs and environmental issues; and future regulatory structure and affiliate relationships. In February of 1999, LPSC staff issued a report finding that restructuring is not in the public F-45

139 CAJUN ELECTRIC (CAJUN FACILITIES) NOTES TO CARVE-OUT FINANCIAL STATEMENTS -- (CONTINUED) interest and recommending that the LPSC defer making a final determination. At its March 1999 Open Session, the LPSC adopted a new procedural schedule to continue its investigation of competitive implications through August of 2000. The effect of deregulation upon Cajun Electric (Cajun Facilities) cannot be determined at this time. 8. OTHER COMMITMENTS AND CONTINGENCIES Coal Supply and Transportation Agreements Purchases under the terms of contracts for the acquisition and related transportation of coal during 1999, 1998 and 1997 were approximately $129 million, $136 million and $127 million, respectively. Louisiana Generating LLC will not assume any liabilities incurred by the Cooperative prior to the closing of the acquisition related to the existing coal supply and transportation agreements. Louisiana Generating LLC has entered into a five-year coal supply agreement under which Triton Coal Company will sell to Louisiana Generating LLC sufficient quantities of coal to satisfy the full coal requirements of the Cajun facilities. Louisiana Generating LLC has entered into a five-year coal transportation agreement with Burlington Northern and Santa Fe Railway Company and American Commercial Terminal LLC which agreement will be effective on the closing date of the acquisition. Pursuant to the agreement, the railroad will transport the coal from the Triton mines in Wyoming to St. Louis, Missouri, and American Commercial Terminal will transport the coal down the Mississippi River from St. Louis to the Cajun facilities. Decommissioning The Cooperative is required by the State of Louisiana Department of Environmental Quality ("DEQ") to rehabilitate its Big Cajun II ash and wastewater impoundment areas upon removal from service of the Big Cajun II facilities. On July 1, 1989, the Cooperative established a guarantor trust (the "Solid Waste Disposal Trust Fund") to accumulate the estimated funds necessary for such purpose. The Cooperative deposited $1.06 million in the Solid Waste Disposal Trust Fund in 1989, and has funded $116,000 annually thereafter, based upon the Cooperative's 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 liability. At December 31, 1999 the carrying value of the trust fund investments and the related accrued decommissioning liability was approximately $3.5 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. The Solid Waste Trust Fund is included in assets to be acquired by Louisiana Generating LLC, which will also assume the obligation to rehabilitate the Big Cajun II ash and wastewater impoundment areas. Letters of Credit The Cooperative has outstanding two letters of credit in the aggregate amount of approximately $15 million as of December 31, 1999 supporting potential indemnity payments related to certain tax benefit transfer agreements to which the Cooperative was a party. The letters of credit will be terminated upon the closing of the acquisition. However, as of the closing date, Louisiana Generating LLC will assume the contingent liability related to the potential indemnity payments. F-46

140 CAJUN ELECTRIC (CAJUN FACILITIES) NOTES TO CARVE-OUT FINANCIAL STATEMENTS -- (CONTINUED) Member Class Action Rate Litigation On September 20, 1989, a class action petition was filed in the Tenth Judicial District State Court in Natchitoches Parish, Louisiana, naming the Cooperative's Members as defendants. The plaintiffs in this action seek a refund of all rate increases enacted by the Cooperative's Members from 1978 until the respective Member voted to be subject to the jurisdiction of the LPSC or was placed under the jurisdiction of the LPSC by action of the State Supreme Court. On October 17, 1989, the case was moved to the federal courts. On August 28, 1992, the District Court abstained from this matter in favor of proceedings at the LPSC. The LPSC currently has an open docket associated with this matter. On August 19, 1994, the LPSC adopted the standards recommended by its Special Counsel. Based on those standards, Special Counsel issued a report in August 1996 recommending that 23 of the 29 rate increases implemented during the period of nonregulation be found presumptively not unreasonable and be eliminated from further review. Special Counsel recommended that the remaining six rate increases be further reviewed for reasonableness. On November 18, 1997, the LPSC issued Order U-19943-B dismissing two more rate increases, finding all but the four remaining increases presumptively not unreasonable. On August 19, 1998, the LPSC dismissed two rate increases for Southwest Louisiana Electric Membership Corporation leaving the final two rate increases to be reviewed for reasonableness. A hearing was held on October 12, 1999, on the last two rate increases. The LPSC staff is expected to issue a final report in time for the LPSC to vote on the matter at its March 2000 Open Session. The timing or outcome of this matter is uncertain and no provision for any liability that may result has been made in the financial statements. However, each Member has entered into a stipulation with the Trustee which releases the Bankruptcy Estate from claims by the Members that might arise as a result of any refunds which the LPSC may order. Further, Louisiana Generating LLC will not assume any liability that may result from the outcome of this matter. F-47

141 INSIDE BACK COVER PAGE NRG ENERGY, INC. PROJECT LIST CAPACITY OWNERSHIP PROJECT LOCATION (MW) (NET MW) - ------- -------------------------------------------- -------- --------- NORTHEAST REGION Osweg, Oswego, NY.................................. 1,700.0 1,700.0 Middletown, Middletown, CT.............................. 856.2 856.2 Arthur Kill, Staten Island, NY........................... 842.0 842.0 Huntley, Tonawanda, NY............................... 760.0 760.0 Astoria Gas Turbines, Queens, NY.................................. 614.0 614.0 Dunkirk, Dunkirk, NY................................. 600.0 600.0 Montville, Uncasville, CT.............................. 497.6 497.6 Devon, Milford, CT................................. 400.5 400.5 Norwalk Harbor, So. Norwalk, CT............................. 353.0 353.0 Somerset Power, Somerset, MA*............................... 229.0 229.0 Connecticut remote jets, Connecticut................................. 127.4 127.4 Kingston Cogeneration, Kingston, Ontario, Canada............................. 110.0 27.5 Parlin Cogen, Parlin, NJ.................................. 122.0 24.4 Cadillac, Cadillac, MI................................ 39.0 19.5 Grays Ferry Cogen, Grays Ferry, PA............................. 150.0 15.0 Newark Cogen, Newark, NJ.................................. 54.0 10.8 Penobscot Energy Recovery, Orrington, ME............................... 25.3 7.3 Curtis-Palmer Hydroelectric, Corinth, NY................................. 58.3 5.0 Philadelphia Cogen, Philadelphia, PA............................ 22.0 3.7 Maine Energy Recovery, Biddeford, ME............................... 22.0 3.6 Turners Falls, Turners Falls, MA**......................... 20.1 1.8 7,602.0 7,099.0 NEO, Various Locations........................... 175.0 90.0 Other Investors Fund - Domestic, Various.......... 999.0 10.0 Total North America............................... 14,759.0 10,940.0 Total Worldwide, Existing and Under Construction................................ 23,660.0 13,664.0 SOUTH CENTRAL REGION Louisiana Generating LLC, Baton Rouge, LA............................. 1,945.0 1,708.5 Sterlington, Sterlington, LA ***......................... 200.0 200.0 Rocky Road, East Dundee, IL............................. 250.0 125.0 Rocky Road (Expansion), East Dundee, IL ***......................... 100.0 50.0 Morris Cogen, Morris, IL.................................. 117.0 23.4 Pryor Cogen, Pryor, OK................................... 110.0 22.0 Power Smith Cogeneration Oklahoma City, OK........................... 110.0 9.6

142 CAPACITY OWNERSHIP PROJECT LOCATION (MW) (NET MW) - ------- --------------------------------------------- -------- --------- WESTERN REGION El Segundo Power, El Segundo, CA............................... 1,020.0 510.0 Encina Power Station, Carlsbad, CA................................. 965.0 482.5 Long Beach Generating, Long Beach, CA............................... 530.0 265.0 Crockett Cogeneration, Crockett, CA................................. 240.0 138.4 San Diego Turbines, San Diego, CA................................ 253.0 126.5 Artesia (Calif. Cogen), Artesia, CA.................................. 34.0 34.0 Mt. Poso, Bakersfield, CA.............................. 49.5 19.5 San Joaquin Valley Energy, Chowchilla, CA**............................. 43.0 19.4 Jackson Valley Energy, Ione, CA**................................... 16.0 8.0 3,151.0 1,603.0 2,832.0 2,138.0 CAPACITY OWNERSHIP PROJECT LOCATION (MW) (NET MW) - ------- --------------------------------------------- -------- --------- EUROPE Killingholme, North Lincolnshire, England.................. 680.0 680.0 Schkopau, Halle, Germany............................... 960.0 200.0 ECK Generating, Kladno, Czech Republic....................... 345.0 153.5 Enfield Energy Centre, London, England, UK ***...................... 396.0 99.0 MIBRAG, Thiessen, Germany............................ 233.0 77.7 Energy Center Kladno, Kladno, Czech Republic....................... 28.0 12.4 -------- -------- 2,642.0 1,223.0 International Asia-Pacific Gladstone Power Station, Gladstone, Qld., Australia................... 1,680.0 630.0 Loy Yang Power A, Traralgon, Vic., Australia................... 2,000.0 507.4 Collinsville, Collinsville, Qld., Australia................ 192.0 96.0 Energy Developments, Ltd., Various Locations............................ 274.0 79.1 -------- -------- 4,146.0 1,312.0 Latin America Bolivian Power Company, Bolivia...................................... 219.2 108.4 Scudder Latin American Power, Various Locations............................ 772.0 51.2 Bulo Bulo, Bolivia ***.................................. 87.0 26.1 1,078.0 186.0 Energy Investors Fund - Various Locations............................ 1,035.0 3.0 Total International, Total........................................ 8,901.0 2,724.0 ======== ======== - --------------- * Includes 69 megawatts on deactivated reserve ** Operations are suspended *** Facilities under construction

143 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- SHARES NRG ENERGY, INC. COMMON STOCK NRG LOGO ------------------ PROSPECTUS , 2000 ------------------ SALOMON SMITH BARNEY ------------------ CREDIT SUISSE FIRST BOSTON ABN AMRO ROTHSCHILD A DIVISION OF ABN AMRO INCORPORATED BANC OF AMERICA SECURITIES LLC GOLDMAN, SACHS & CO. LEHMAN BROTHERS MERRILL LYNCH & CO. MORGAN STANLEY DEAN WITTER - -------------------------------------------------------------------------------- - --------------------------------------------------------------------------------

144 PART II INFORMATION NOT REQUIRED IN PROSPECTUS ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION The registrant's expenses in connection with the Offering described in this registration statement are set forth below. All amounts except the Securities and Exchange Commission registration fee, the NASD filing fee and the listing fee are estimated. Securities and Exchange Commission registration fee......... 158,400 NASD filing fee............................................. 30,500 Printing and engraving expenses............................. 300,000 Accounting fees and expenses................................ 50,000 Legal fees and expenses..................................... 500,000 Fees and expenses (including legal fees) for qualification under state securities laws............................... 1,000 Transfer agent's fees and expenses.......................... 10,000 Miscellaneous............................................... 25,100 --------- Total..................................................... 1,075,000 ========= ITEM 14. INDEMNIFICATION OF DIRECTORS AND OFFICERS Section 145(a) of the General Corporation Law of the State of Delaware (the "DGCL") provides that a Delaware corporation may indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (other than an action by or in the right of the corporation) by reason of the fact that such person is or was a director, officer, employee or agent of the corporation or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation or enterprise, against expenses, judgments, fines and amounts paid in settlement actually and reasonably incurred by such person in connection with such action, suit or proceeding if he or she acted in good faith and in a manner he or she reasonably believed to be in or not opposed to the best interests of the corporation, and, with respect to any criminal action or proceeding, had no cause to believe his or her conduct was unlawful. Section 145(b) of the DGCL provides that a Delaware corporation may indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action or suit by or in the right of corporation to procure a judgment in its favor by reason of the fact that such person acted in any of the capacities set forth above, against expenses actually and reasonably incurred by such person in connection with the defense or settlement of such action or suit if he or she acted under similar standards to those set forth above, except that no indemnification may be made in respect to any claim, issue or matter as to which such person shall have been adjudged to be liable to the corporation unless and only to the extent that the court in which such action or suit was brought shall determine that despite the adjudication of liability, but in view of all the circumstances of the case, such person is fairly and reasonably entitled to be indemnified for such expenses which the court shall deem proper. Section 145 of the DGCL further provides that to the extent a director or officer of a corporation has been successful in the defense of any action, suit or proceeding referred to in subsection (a) and (b) of Section 145 or in the defense of any claim, issue or matter therein, he or she shall be indemnified against expenses actually and reasonably incurred by him or her in connection therewith; that indemnification provided for by Section 145 shall not be deemed exclusive of any other rights to which the indemnified party may be entitled; and that the corporation may purchase and maintain insurance on behalf of a director or officer of the corporation against any liability asserted against such officer or director and incurred by him or her in any such capacity or arising out of his or her status as such, whether or not the corporation would have the power to indemnify him or her against such liabilities under Section 145.

145 As authorized by Section 145 of the DGCL, each director and officer of NRG may be indemnified by NRG against expenses (including attorney's fees, judgments, fines and amounts paid in settlement) actually and reasonably incurred in connection with the defense or settlement of any threatened, pending or completed legal proceedings in which he is involved by reason of the fact that he is or was a director or officer of NRG if he acted in good faith and in a manner that he reasonably believed to be in or not opposed to the best interest of NRG and, with respect to any criminal action or proceeding, if he had no reasonable cause to believe that his conduct was unlawful. However, if the legal proceeding is by or in the right of NRG, the director or officer may not be indemnified in respect of any claim, issue or matter as to which he shall have been adjudged to be liable for negligence or misconduct in the performance of his duty to NRG unless a court determines otherwise. In addition, Article VI of NRG's By-Laws provides that NRG shall indemnify and hold harmless, to the fullest extent permitted by applicable law, any person who was or is made or is threatened to be made a party or is otherwise involved in any action, suit or proceeding, whether civil, criminal, administrative or investigative (a "Proceeding") by reason of the fact that he or she, or a person for whom he or she is the legal representative, is or was a director, officer, employee or agent of NRG or is or was serving at the request of NRG as a director, officer, employee or agent of another company or of a partnership, joint venture, trust, enterprise or non-profit entity, including service with respect to employee benefit plans, against all liability and loss suffered and expenses reasonably incurred by such person. NRG shall be required to indemnify a person in connection with a Proceeding initiated by such person only if the Proceeding was authorized by the Board of Directors of NRG. All of NRG's directors will enter into indemnity agreements that obligate NRG to indemnify such directors to the fullest extent permitted by the DGCL. ITEM 15. RECENT SALES OF UNREGISTERED SECURITIES The following tables summarize securities issued or sold by us within the past three years that were not sold pursuant to registered offerings: UNDERWRITER OR SECURITY AND DATE SOLD CLASS OF PURCHASERS AMOUNT SOLD EXEMPTION RELIED UPON - ---------------------- ----------------------- ----------------- --------------------- 7.5% Senior Notes Due 2007 issued June 17, 1997.... Accredited investors: $ 250,000,000 Rule 144A; Regulation S Salomon Brothers Inc. 0.650% discount ABN AMRO Chicago Corporation Chase Securities Inc. 7.97% Reset Notes Due 2020 (Remarketing Date March 15, 2005) issued March 20, 2000................ NRG Energy Pass-Through L160,000,000 Section 4(2) Trust 2000-1 /no discount ITEM 16. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES EXHIBIT NO. DESCRIPTION - ----------- ----------- 1.1* Underwriting Agreement. 3.1 Certificate of Incorporation.(a) 3.2 By-Laws.(a) 4.1 Indenture, dated as of June 1, 1997, between the Company and Norwest Bank Minnesota, National Association.(a)

146 EXHIBIT NO. DESCRIPTION - ----------- ----------- 4.2 Loan Agreement, dated June 4, 1999 between Northeast Generating LLC, Chase Manhattan Bank and Citibank, N.A.(b) 4.3 Indenture between the Company and Norwest Bank Minnesota, National Association, as Trustee dated as of May 25, 1999.(c) 4.4 Indenture between the Company and NRG Northeast Generating LLC and The Chase Manhattan Bank, as Trustee dated as of February 22, 2000.(b) 4.5 NRG Energy Pass-Through Trust 2000-1, $250,000,000 8.70% Remarketable or Redeemable Securities ("ROARS") due March 15, 2005.(b) 4.6 Trust Agreement between NRG Energy Inc. and The Bank of New York, as Trustee, dated March 20, 2000.(b) 4.7 Indenture between NRG Energy Inc. and the Bank of New York, as Trustee dated March 20, 2000, 160,000,000 pounds sterling Reset Senior Notes due March 15, 2000.(b) 4.8 Indenture between the Company and Norwest Bank Minnesota, National Association as Trustee dated as of November 8, 1999.(d) 4.9 Indenture, dated as of January 31, 1996, between the Company and Norwest Bank Minnesota, National Association, As Trustee.(a) 5.1* Opinion and Consent of Gibson, Dunn & Crutcher LLP, regarding validity of Common Stock. 10.1 Employment Contract, dated as of June 28, 1995, between the Company and David H. Peterson.(a) 10.2 Note Agreement, dated August 20, 1993, among the Company Energy Center, Inc. and each of the purchasers named therein.(a) 10.3 Master Shelf and Revolving Credit Agreement, dated August 20, 1993 among the Company Energy Center, Inc., The Prudential Insurance Registrants of America and each Prudential Affiliate which becomes party thereto.(a) 10.4 Energy Agreement, dated February 12, 1988 between the Company formerly known as Norenco Corporation) and Waldorf Corporation (the "Energy Agreement").(a) 10.5 First Amendment to the Energy Agreement, dated August 27, 1993.(a) 10.6 Second Amendment to the Energy Agreement, dated August 27, 1993.(a) 10.7 Third Amendment to the Energy Agreement, dated August 27, 1993.(a) 10.8 Construction, Acquisition, and Term Loan Agreement, dated September 2, 1997 by the among NEO Landfill Gas, Inc., as Borrower, the lenders named on the signature pages, Credit Lyonnais New York Branch, as Construction/Acquisition Agent and Lyon Credit Corporation as Term Agent.(a) 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.(a) 10.10 Construction, Acquisition, and Term Loan Agreement, dated September 2, 1997 by and among Minnesota Methane LLC, as Borrower, the lenders named on the signature pages, Credit Lyonnais New York Branch, as Construction/Acquisition Agent and Lyon Credit Corporation as Term Agent.(a) 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.(a) 10.12 Non Operating Interest Acquisition Agreement dated as of September 12, 1997, by and among the Company and NEO Corporation.(a) 10.13 Employment Agreements between the Company and certain officers dated as of April 15, 1998.(e)

147 EXHIBIT NO. DESCRIPTION - ----------- ----------- 10.14 Wholesale Standard Offer Service Agreement between Blackstone Valley Electric Company, Eastern Edison Company, Newport Electric Corporation and NRG Power Marketing, Inc., dated October 13, 1998.(b) 10.15 Asset Sales Agreement by and between Niagara Mohawk Power Corporation and NRG Energy, Inc., dated December 23, 1998.(b) 10.16 First Amendment to Wholesale Standard Offer Service Agreement between Blackstone Valley Electric Company, Eastern Edison Company, Newport Electric Corporation and NRG Power Marketing, Inc., dated January 15, 1999.(b) 10.17 Generating Plant and Gas Turbine Asset Purchase and Sale Agreement for the Arthur Kill generating plants and Astoria gas turbines by and between Consolidated Edison Company of New York, Inc., and NRG Energy, Inc., dated January 27, 1999.(b) 10.18 Transition Energy Sales Agreement between Arthur Kill Power LLC and Consolidated Edison Company of New York, Inc., dated June 1, 1999.(b) 10.19 Transition Power Purchase Agreement between Astoria Gas Turbine Power LlC and Consolidated Edison Company of New York, Inc., dated June 1, 1999.(b) 10.20 Transition Power Purchase Agreement between Niagara Mohawk Power Corporation and Huntley Power LLC, dated June 11, 1999.(b) 10.21 Transition Power Purchase Agreement between Niagara Mohawk Power Company and Dunkirk Power LLC, dated June 11, 1999.(b) 10.22 Power Purchase Agreement between Niagara Mohawk Power Corporation and Dunkirk Power LLC, dated June 11, 1999.(b) 10.23 Power Purchase Agreement between Niagara Mohawk Power Corporation and Huntley Power LLC, dated June 11, 1999.(b) 10.24 Amendment to the Asset Sales Agreement by and between Niagara Mohawk Power Corporation and NRG Energy, Inc., dated June 11, 1999.(b) 10.25 Transition Capacity Agreement between Astoria Gas Turbine Power LLC and Consolidated Edison Company of New York, Inc., dated June 25, 1999.(b) 10.26 Transition Capacity Agreement between Arthur Kill Power LLC and Consolidated Edison Company of New York, Inc., dated June 25, 1999.(b) 10.27 First Amendment to the Employment Agreement of David H. Peterson, dated June 27, 1999.(b) 10.28 Second Amendment to the Employment Agreement of David H. Peterson, dated August 26, 1999.(b) 10.29 Third Amendment to the Employment Agreement of David H. Peterson, dated October 20, 1999.(b) 10.30 Swap Master Agreement between Niagara Mohawk Power Corporation and NRG Power Marketing, Inc., dated June 11, 1999.(b) 10.31 Standard Offer Service Wholesale Sales Agreement between the Connecticut Light and Power Company and NRG Power Marketing, Inc., dated October 29, 1999.(b) 10.32 364-day Revolving Credit Agreement among the Company and The Financial Institutions party thereto, and ABN-AMRO Bank, N.V., as Agent, dated as of March 10, 2000.(b) 10.33 Amended Agreement for the Sale of Thermal Energy between Northern States Power and Norenco Corporation, dated January 1, 1983. 10.34 Operations and Maintenance Agreement between Northern States Power and NRG, dated November 1, 1996.

148 EXHIBIT NO. DESCRIPTION - ----------- ----------- 10.35 Agreement for the Sale of Thermal Energy and Wood Byproduct between Northern States Power and Norenco Corporation, dated December 1, 1986. 10.36 Federal and State Income Tax Sharing Agreement between Northern States Power Company and NRG Group, Inc., dated April 4, 1991. 10.37 Support Agreement between Northern State Power Company and CitiCorp USA Inc., dated March 27, 2000. 10.38 Administrative Services Agreement between Northern States Power Company and NRG Thermal Corporation, dated January 1, 1992. 21.1 Subsidiaries of NRG. 23.1 Consent of PricewaterhouseCoopers LLP. 23.2 Consent of Gibson, Dunn & Crutcher LLP (included in Exhibit 5.1) 24.1 Power of Attorney (included on signature page). 27.1 Financial Data Schedule. - --------------- (a) Incorporated herein by reference to the Registrant's Registration Statement on Form S-1, as amended, File No. 333-33397. (b) Incorporated herein by reference to the Company's current report on Form 10-K for the year ended December 31, 1999. (c) Incorporated herein by reference to the Company's current report on Form 8-K dated May 25, 1999. (d) Incorporated herein by reference to Exhibit 4.1 to the Company's current report on Form 8-K dated November 16, 1999. (e) Incorporated herein by reference to Exhibit 10.17 on Form 10-Q for the quarter ended March 31, 1998. * To be filed by amendment ITEM 17. (a) Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities begin registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue. (b) For purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 242(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective. (C) For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

149 SIGNATURES Pursuant to the requirements of the Securities Act, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Minneapolis, State of Minnesota, on April, 18, 2000. NRG ENERGY, INC. /s/ JAMES J. BENDER By: -------------------------------------- Vice President, General Counsel and Secretary POWER OF ATTORNEY KNOW BY ALL MEN THESE PRESENTS, that each person whose signature appears below constitutes and appoints Leonard A. Bluhm and James J. Bender, and each of them, his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution for him and in his name, place and stead, in any and all capacities to sign any and all amendments (including post-effective amendments) to this Registration Statement, and to file the same, with all exhibits thereto, and other documents in connection therewith, including, without limitation, any registration statement filed pursuant to Rule 462 under the Securities Act of 1933, as amended, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite or necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that each of said attorneys-in-fact and agents or any of them or their or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof. Pursuant to the requirements of the Securities Act, this registration statement has been signed on April 18, 2000 by the following persons in the respective capacities indicated opposite their names. SIGNATURE TITLE DATE --------- ----- ---- /s/ DAVID H. PETERSON Chairman of the Board, President April 18, 2000 - --------------------------------------------- and Chief Executive Officer David H. Peterson (Principal Executive Officer) /s/ LEONARD A. BLUHM Executive Vice President and Chief April 18, 2000 - --------------------------------------------- Financial Officer (Principal Leonard A. Bluhm Financial Officer) /s/ DAVID E. RIPKA Controller (Principal Accounting April 18, 2000 - --------------------------------------------- Officer) David E. Ripka /s/ GARY R. JOHNSON Director April 18, 2000 - --------------------------------------------- Gary R. Johnson

150 SIGNATURE TITLE DATE --------- ----- ---- /s/ CYNTHIA L. LESHER Director April 18, 2000 - --------------------------------------------- Cynthia L. Lesher /s/ EDWARD J. MCINTYRE Director April 18, 2000 - --------------------------------------------- Edward J. McIntyre

151 EXHIBIT INDEX EXHIBIT NO. DESCRIPTION - ----------- ----------- 1.1* Underwriting Agreement. 3.1 Certificate of Incorporation.(a) 3.2 By-Laws.(a) 4.1 Indenture, dated as of June 1, 1997, between the Company and Norwest Bank Minnesota, National Association.(a) 4.2 Loan Agreement, dated June 4, 1999 between Northeast Generating LLC, Chase Manhattan Bank and Citibank, N.A.(b) 4.3 Indenture between the Company and Norwest Bank Minnesota, National Association, as Trustee dated as of May 25, 1999.(c) 4.4 Indenture between the Company and NRG Northeast Generating LLC and The Chase Manhattan Bank, as Trustee dated as of February 22, 2000.(b) 4.5 NRG Energy Pass-Through Trust 2000-1, $250,000,000 8.70% Remarketable or Redeemable Securities ("ROARS") due March 15, 2005.(b) 4.6 Trust Agreement between NRG Energy Inc. and The Bank of New York, as Trustee, dated March 20, 2000.(b) 4.7 Indenture between NRG Energy Inc. and the Bank of New York, as Trustee dated March 20, 2000, 160,000,000 pounds sterling Reset Senior Notes due March 15, 2000.(b) 4.8 Indenture between the Company and Norwest Bank Minnesota, National Association as Trustee dated as of November 8, 1999.(d) 5.1* Opinion and Consent of Gibson, Dunn & Crutcher LLP, regarding validity of Common Stock. 10.1 Employment Contract, dated as of June 28, 1995, between the Company and David H. Peterson.(a) 10.2 Indenture, dated as of January 31, 1996, between the Company and Norwest Bank Minnesota, National Association, As Trustee.(a) 10.3 Note Agreement, dated August 20, 1993, among the Company Energy Center, Inc. and each of the purchasers named therein.(a) 10.4 Master Shelf and Revolving Credit Agreement, dated August 20, 1993 among the Company Energy Center, Inc., The Prudential Insurance Registrants of America and each Prudential Affiliate which becomes party thereto.(a) 10.5 Energy Agreement, dated February 12, 1988 between the Company formerly known as Norenco Corporation) and Waldorf Corporation (the "Energy Agreement").(a) 10.6 First Amendment to the Energy Agreement, dated August 27, 1993.(a) 10.7 Second Amendment to the Energy Agreement, dated August 27, 1993.(a) 10.8 Third Amendment to the Energy Agreement, dated August 27, 1993.(a) 10.9 Construction, Acquisition, and Term Loan Agreement, dated September 2, 1997 by the among NEO Landfill Gas, Inc., as Borrower, the lenders named on the signature pages, Credit Lyonnais New York Branch, as Construction/Acquisition Agent and Lyon Credit Corporation as Term Agent.(a) 10.10 Guaranty, dated September 12, 1997 by the Company in favor of Credit Lyonnais New York Branch as agent for the Construction/Acquisition Lenders.(a) 10.11 Construction, Acquisition, and Term Loan Agreement, dated September 2, 1997 by and among Minnesota Methane LLC, as Borrower, the lenders named on the signature pages, Credit Lyonnais New York Branch, as Construction/Acquisition Agent and Lyon Credit Corporation as Term Agent.(a)

152 EXHIBIT NO. DESCRIPTION - ----------- ----------- 10.12 Guaranty, dated September 12, 1997 by the Company in favor of Credit Lyonnais New York Branch as agent for the Construction/Acquisition Lenders.(a) 10.13 Non Operating Interest Acquisition Agreement dated as of September 12, 1997, by and among the Company and NEO Corporation.(a) 10.14 Employment Agreements between the Company and certain officers dated as of April 15, 1998.(e) 10.15 Wholesale Standard Offer Service Agreement between Blackstone Valley Electric Company, Eastern Edison Company, Newport Electric Corporation and NRG Power Marketing, Inc., dated October 13, 1998.(b) 10.16 Asset Sales Agreement by and between Niagara Mohawk Power Corporation and NRG Energy, Inc., dated December 23, 1998.(b) 10.17 First Amendment to Wholesale Standard Offer Service Agreement between Blackstone Valley Electric Company, Eastern Edison Company, Newport Electric Corporation and NRG Power Marketing, Inc., dated January 15, 1999.(b) 10.18 Generating Plant and Gas Turbine Asset Purchase and Sale Agreement for the Arthur Kill generating plants and Astoria gas turbines by and between Consolidated Edison Company of New York, Inc., and NRG Energy, Inc., dated January 27, 1999.(b) 10.19 Transition Energy Sales Agreement between Arthur Kill Power LLC and Consolidated Edison Company of New York, Inc., dated June 1, 1999.(b) 10.20 Transition Power Purchase Agreement between Astoria Gas Turbine Power LlC and Consolidated Edison Company of New York, Inc., dated June 1, 1999.(b) 10.21 Transition Power Purchase Agreement between Niagara Mohawk Power Corporation and Huntley Power LLC, dated June 11, 1999.(b) 10.22 Transition Power Purchase Agreement between Niagara Mohawk Power Company and Dunkirk Power LLC, dated June 11, 1999.(b) 10.23 Power Purchase Agreement between Niagara Mohawk Power Corporation and Dunkirk Power LLC, dated June 11, 1999.(b) 10.24 Power Purchase Agreement between Niagara Mohawk Power Corporation and Huntley Power LLC, dated June 11, 1999.(b) 10.25 Amendment to the Asset Sales Agreement by and between Niagara Mohawk Power Corporation and NRG Energy, Inc., dated June 11, 1999.(b) 10.26 Transition Capacity Agreement between Astoria Gas Turbine Power LLC and Consolidated Edison Company of New York, Inc., dated June 25, 1999.(b) 10.27 Transition Capacity Agreement between Arthur Kill Power LLC and Consolidated Edison Company of New York, Inc., dated June 25, 1999.(b) 10.28 First Amendment to the Employment Agreement of David H. Peterson, dated June 27, 1999.(b) 10.29 Second Amendment to the Employment Agreement of David H. Peterson, dated August 26, 1999.(b) 10.30 Third Amendment to the Employment Agreement of David H. Peterson, dated October 20, 1999.(b) 10.31 Swap Master Agreement between Niagara Mohawk Power Corporation and NRG Power Marketing, Inc., dated June 11, 1999.(b) 10.32 Standard Offer Service Wholesale Sales Agreement between the Connecticut Light and Power Company and NRG Power Marketing, Inc., dated October 29, 1999.(b)

153 EXHIBIT NO. DESCRIPTION - ----------- ----------- 10.33 364-day Revolving Credit Agreement among the Company and The Financial Institutions party thereto, and ABN-AMRO Bank, N.V., as Agent, dated as of March 10, 2000.(b) 10.34 Amended Agreement for the Sale of Thermal Energy between Northern States Power and Norenco Corporation, dated January 1, 1983. 10.35 Operations and Maintenance Agreement between Northern States Power and NRG, dated November 1, 1996. 10.36 Agreement for the Sale of Thermal Energy and Wood Byproduct between Northern States Power and Norenco Corporation, dated December 1, 1986. 10.37 Federal and State Income Tax Sharing Agreement between Northern States Power Company and NRG Group, Inc. dated April 4, 1991. 10.38 Support Agreement between Northern State Power Company and CitiCorp USA Inc., dated March 27, 2000. 10.39 Administrative Services Agreement between Northern States Power Company and NRG Thermal Corporation, dated January 1, 1992. 21.1 Subsidiaries of NRG. 23.1 Consent of PricewaterhouseCoopers LLP. 23.2 Consent of Gibson, Dunn & Crutcher LLP (included in Exhibit 5.1) 24.1 Power of Attorney (included on signature page). 27.1 Financial Data Schedule. - --------------- (a) Incorporated herein by reference to the Registrant's Registration Statement on Form S-1, as amended, File No. 333-33397. (b) Incorporated herein by reference to the Company's current report on Form 10-K for the year ended December 31, 1999. (c) Incorporated herein by reference to the Company's current report on Form 8-K dated May 25, 1999. (d) Incorporated herein by reference to Exhibit 4.1 to the Company's current report on Form 8-K dated November 16, 1999. (e) Incorporated herein by reference to Exhibit 10.17 on Form 10-Q for the quarter ended March 31, 1998. * To be filed by amendment

1 EXHIBIT 10.34 AMENDED AGREEMENT FOR THE SALE OF THERMAL ENERGY BETWEEN NORTHERN STATES POWER COMPANY AND NORENCO CORPORATION This Agreement, effective as of the first day of January, 1983, between Northern States Power Company, a Minnesota corporation (hereinafter referred to as "NSP") and Norenco Corporation, a Minnesota corporation (hereinafter referred to as "NORENCO"), a wholly owned subsidiary of NSP, such parties hereinafter referred to individually as "party" or collectively as "parties", supersedes and replaces the original agreement between the parties which was executed on February 8, 1983. WITNESSETH Whereas, NSP owns and operates the High Bridge Steam-Electric Generatinq Plant located in St. Paul, Minnesota comprising boilers B9, B10, B11 and B12 which supply steam to turbine-generators T3, T4, T5 and T6, respectively. Boiler B9 or B10 can serve either turbine T3 or T4; and WHEREAS, NSP desires to sell steam to NORENCO from boilers B9 and B10, and NORENCO desires to purchase such steam from NSP to resell to Champion International Corporation (hereinafter "Champion") which owns and operates a paper mill in Saint Paul, Minnesota, pursuant to a steam supply agreement dated August 30, 1982; and WHEREAS, it is the intention of NSP and NORENCO that NORENCO reimburse NSP for all of NSP's incremental costs associated with the sale of steam to NORENCO.

2 NOW THEREFORE, in consideration of the mutual covenants, stipulations and agreements herein contained, the parties hereby covenant, stipulate and agree as follows: I. Term-Effective Date 1.1 This Agreement shall be effective on January 1, 1983, and shall extend through December 31, 2002. II. Conditions of Service 2.1 Steam sales from NSP's High Bridge Plant to NORENCO normally will be interrupted within two hours after any oil-fired peaking is required on NSP's system to meet system capacity requirements. Under system emergencies as determined by NSP System Operations, boilers B9 and B10 will be released immediately for electric generation. 2.2 At NSP's option, NORENCO may purchase steam from NSP after any such oil-fired peaking is required. NORENCO will then reimburse NSP for the incremental cost associated with replacement energy. 2.3 NORENCO shall make all modifications, adjustments, and additions to NSP's existing boilers, pipes, valves, meters, controls, coal handling and storage systems, buildings, yards, tracks and all other equipment and machinery (collectively called Generating Equipment) at the High Bridge Plant necessary to produce steam of the quality specified and in the quantity required by this Agreement, (herein sometimes referred to as Useable Steam). 2.4 NORENCO shall obtain all necessary franchises, licenses, permits, rights of way or easements and purchase, 2

3 construct and install a transmission system which will connect boilers B9 and B10 to the Champion paper mill. The transmission system (herein called the Supply Line) shall include all pipes, pumps, valves, meters, controls, wires, insulation and other equipment necessary to: (a) transport Useable Steam from the High Bridge Plant to the Champion paper mill. (b) transport condensate and make-up water of the quality and in the quantity required by this Agreement from the paper mill to the High Bridge Plant; and (c) provide for control of steam and communications between the High Bridge Plant and the paper mill. 2.5 Throughout the Term of this Agreement NORENCO shall obtain, renew, and maintain all licenses, permits and other governmental authorizations necessary to furnish steam through the Supply Line. NSP shall use its best efforts to change rules, regulations, laws or ordinances which would prevent NSP from furnishing steam hereunder. 2.6 Throughout the Term of this Agreement NSP shall own, operate, maintain, repair, and adjust the Generating Equipment. NSP will not purchase any equipment not required for electric generation. 2.7 Throughout the Term of this Agreement, NORENCO shall own and pay for the incremental cost of the operation, maintenance, repair and adjustment of NORENCO-purchased equipment installed on NSP property. At NORENCO's cost, NSP 3

4 shall, throughout the Term of this Agreement, operate, maintain and repair NORENCO-purchased equipment installed on NSP property. 2.8 NORENCO shall not, by reason of this Agreement or the termination of this Agreement or the payments made pursuant to this Agreement, acquire title or ownership in or to the generating equipment of the High Bridge Plant. 2.9 NSP shall use its best efforts to produce and deliver to NORENCO and NORENCO shall use its best efforts to purchase and accept from NSP all of NORENCO's steam requirements at the Champion paper mill during the Term; provided, however: (a) NSP shall not be required to produce and deliver nor shall NORENCO be required to purchase and accept more than 4,000,000 Million BTU's of Useable Steam during any fiscal year; (b) NSP shall use its best efforts to produce and deliver and NORENCO shall use its best efforts to purchase and accept the Annual minimum quantity of Useable Steam each fiscal year. The Annual Minimum quantity is expected to be 2,640,000 million BTU's; and (c) NSP shall use its best efforts to produce and deliver steam for at least 347 days per year. NSP and NORENCO shall use their best efforts to coordinate inspections, maintenance and repairs to their respective facilities. 2.10 All steam produced and delivered from boiler B9 or B10 shall meet the following specifications when 4

5 measured at the delivery point: (a) Temperature: 790 degrees F with variations required for load control. (b) Pressure: 850 pounds per square inch gauge (PSIG) with variations required for load control. (c) Steam flow rate shall be from 250,000 pounds per hour to 430,000 pounds per hour. 2.11 Delivery point as used in Article II of this Agreement shall be the point where the steam exits the steam conditioning valve and enters the Supply Line at High Bridge. 2.12 During each fiscal year of the Term of this Agreement, NORENCO shall provide 100% of the water necessary to produce steam for NORENCO at the High Bridge Plant by delivering to NSP the condensate return water. (NORENCO shall pay for the water to initiate steam production.) NORENCO shall return the condensate in a condition acceptable for 850 PSIG boilers. III. Billing 3.1 NSP will bill NORENCO by the 20th of the month following the month in which the costs were incurred. Each month's bill shall be increased by 1% to cover handling costs, working capital and miscellaneous costs. 3.2 NORENCO will pay NSP no later than 10 days following the date of NSP's bill. Interest shall accrue on payments which are overdue at the daily commercial prime rate in effect at the Northwestern National Bank of Minneapolis from the date that interest first accrues. 5

6 3.3 NSP will provide NORENCO with a cost component schedule along with its bill similar to that shown in Table 1. 3.4 The total monthly cost billed shall be calculated pursuant to Article IV of this Agreement. IV. Cost of Service For any steam delivered to NORENCO by NSP, the following costs shall be recovered by NSP from NORENCO. The calculation of these costs includes the use of coefficients which are to be updated at least annually by NSP. The costs recovered by NSP are to be reviewed annually by NSP to ensure that the provisions of this Agreement recover all appropriate costs. Corrections to billings will be made if it can be demonstrated by either party to the other party's satisfaction that the monthly payments made by NORENCO to NSP are in error by at least plus or minus 1%. Any corrections to billings will be consistent with the incremental cost approach. 4.1 Fuel Cost 4.1.1 NORENCO will provide NSP with a monthly estimate of steam to be produced and delivered from the NSP High Bridge Plant to satisfy NORENCO thermal energy requirements. The nature and timing of these estimates will be specified in writing by NSP. 4.1.2 NSP will determine the amount of coal required to produce the quantities of steam identified in paragraph 4.1.1. The quantities of coal so calculated and schedules proposed to deliver such quantities will be provided to NORENCO. 6

7 4.1.3 Any quantities of coal identified in Section 4.1 will not decrease the quantities of coal available for NSP electric generation from long term coal supply agreements executed for the purpose of supplying coal for electric generation. 4.1.4 The coal required to produce steam for the benefit of NORENCO may be stored in the NSP High Bridge coal storage area. 4.1.5 NSP will provide to NORENCO monthly fuel inventory reports for fuel used to produce steam for sale to NORENCO. These reports will include beginning of month coal on hand for NORENCO, coal delivered during the month for NORENCO, coal consumed during the month for NORENCO and coal on hand at the end of the month for NORENCO. These reports will be in a format shown in Table 2. 4.1.6 NORENCO will pay NSP for the actual cost per MMBTU of coal (including retroactive adjustment) as delivered to High Bridge for NORENCO. The cost per MMBTU will be determined from the delivered cost per ton and the heat value of the coal as determined by NSP's Fuel Supply Department and NSP's Coal Testing Laboratory. NORENCO will reimburse NSP for any adjustments charged to NSP for fuel quality and for High Bridge coal handling charges for NORENCO coal. 4.2 Incremental Maintenance Cost Each month, NORENCO shall pay NSP for the cost 7

8 of incremental maintenance as calculated using NSP Power Production's incremental maintenance coefficient. 4.3 Incremental Auxiliary Cost Each month, NORENCO shall pay NSP for the cost of incremental auxiliary electrical power useage at High Bridge as calculated using the average incremental system generation cost for that month. 4.4 Incremental No Load Maintenance Cost 4.4.1. Each month, for those hours that boiler B9 is in thermal only service by NORENCO, NORENCO shall pay NSP the incremental cost of no load maintenance as calculated using NSP Power Production's no load operation and maintenance coefficient. 4.4.2 Each month, for those hours that boiler B10 is in thermal only service by NORENCO, NORENCO shall pay NSP the incremental cost of no load maintenance as calculated using NSP Power Production's no load operation and maintenance coefficient. 4.5 Incremental No Load Auxiliaries 4.5.1 Each month, for those hours boiler B9 is in thermal only service for NORENCO, NORENCO shall pay NSP an amount equal to that month's average system incremental generation cost times that month's no load electrical consumption by boiler B9. 4.5.2 Each month, for those hours boiler B10 is in thermal only service for NORENCO, NORENCO shall pay NSP an amount equal to that month's average system incremental 8

9 generation cost times that month's no load electrical consumption by boiler B10. 4.6 Ash Disposal 4.6.1 Ash disposal costs for High Bridge are accumulated in FERC Account 152 (NSP Account 61.01.36). 4.6.2 The monthly charges to account 61.01.36 will be prorated between NORENCO and NSP on the basis of monthly coal burned for NORENCO and coal burned for electric generation at High Bridge as reported per Table 2. This charge shall also include an incremental ash disposal site development cost for NORENCO ash. 4.7 Energy Management System Costs 4.7.1 Replacement Energy 4.7.1.1 The cost of replacement energy is calculated as the difference in the cost of NSP generation and purchases to supply NSP native requirements with and without the supply of steam to NORENCO. The change in NSP generation cost will include the changes in fuel and maintenance for startup and hours of operation, and the incremental ash disposal cost. The change in billing cost for purchases with and without the supply of steam to NORENCO will also be used in the calculation. 4.7.1.2. Without NORENCO's thermal requirements, less efficient units may be dispatched prior to the use of Units 3 and 4 at High Bridge. With NORENCO's thermal requirements, when NSP interrupts thermal service for electrical production on Units 3 and 4, energy costs may be avoided by NSP because these units are available immediately. 9

10 This credit will be reflected appropriately in determining replacement energy costs. 4.7.1.3 The cost of replacement energy shall be calculated using NSP System Operation's computer program. The capacity effect on either turbine T3 or T4 shall be considered hourly by that program. The capacity effect of turbines T3 and T4 shall reflect actual plant conditions as evaluated by NSP Power Production. 4.7.2 Sales of Electricity for Resale NORENCO will be charged monthly for incremental costs associated with the loss of the opportunity to sell electricity for resale due to NORENCO's thermal requirements. This incremental cost is the estimated lost revenues from sales for resale from High Bridge Units 3 and 4 minus the estimated avoided electrical production costs, had this energy been generated at High Bridge Units 3 and 4. 4.8 Flame Stabilization 4.8.1 NORENCO will be charged for any incremental flame stabilization due to thermal operations. For oil flame stabilization the cost will be calculated as follows: Cost = Gallons of oil used for x Oil cost per NORENCO flame stabilization gallon 4.8.2 For gas flame stabilization, the cost will be calculated as follows: Cost = Millions of Btu of gas x Gas cost per used for NORENCO flame million Btu stabilization. 10

11 4.8.3 The High Bridge Plant will report monthly the gallons of oil and the millions of Btu's of gas used for flame stabilization for thermal only service on boilers B9 and B10. 4.9 Incremental Operating Cost Any additional overtime or operating personnel shall be reported and charged to NORENCO. 4.10 Thermal Equipment Operation and Maintenance Any operation or maintenance of thermal only equipment (equipment installed for thermal use only) will be charged on separate work orders to NORENCO. 4.11 Standby No Loads If NORENCO desires an additional boiler on line for backup, the no load costs specified in 4.4 and 4.5 will be charged to NORENCO for those hours that the backup boiler is used for thermal only service. 4.12 Supply of Gas or Oil If NSP supplies any oil or natural gas to NORENCO, NORENCO shall reimburse NSP for replacement cost of that oil or natural gas including appropriate carrying and handling charges. 4.13 Cold Start Credits and Costs Since NORENCO's use of boilers B9 and B10 for thermal service to Champion will result in considerably fewer boiler cold starts than otherwise would be the case, the cost credit associated with such reduction in cold starts will be assumed to offset any startup costs of boilers B9 and B10 11

12 caused by NORENCO. 4.14 Administrative and General Costs Administrative and general costs are covered by the Administrative Services Agreement dated January 1, 1983, and any amendments thereto, between NSP and NORENCO. V. LIABILITY 5.1 NORENCO shall hold harmless and indemnify NSP from any and all claims, loss, damage or liability, including injury to and death of persons, caused directly or indirectly by the steam or the use of NORENCO's facilities after the delivery of steam to NORENCO other than those resulting solely from the negligence of NSP or its agents or employees (excluding persons assigned to NORENCO on a full-time basis). NSP likewise shall hold harmless and indemnify NORENCO from any and all claims, loss, damage or liability, including injury to and death of persons, caused directly or indirectly by steam or the use of NSP's facilities before the delivery of steam to NORENCO other than those resulting solely from the negligence of NORENCO or its agents or employees (including those persons assigned to NORENCO on a full-time basis). 5.2 Notwithstanding any other provision of this Agreement, neither NSP nor NORENCO in any event shall be liable to the other, whether arising under contract, tort (including negligence), or otherwise, for claims of customers or any other third parties, or for loss of use of capital or revenue, or for loss of anticipated profits, or for 12

13 any other special, indirect, incidental or consequential loss or damage of any nature arising at any time or from any cause whatsoever 5.3 No provision of this Agreement shall in any way inure to the benefit of any third person including the public at large) so as to constitute any such person a third party beneficiary of this Agreement or of any one or more of the terms hereof, or otherwise give rise to any cause of action in any person not a party hereto. 5.4 The provisions of this section shall apply notwithstanding any other provisions of this Agreement or of any other agreement. 5.5 The provisions of this section and of any other sections of this Agreement providing for limitation of or protection against liability shall apply to the full extent permitted by law and regardless of fault and shall survive the expiration or termination of this Agreement. VI. CONTINUITY OF SERVICE 6.1 NSP shall not be liable to NORENCO for its failure to deliver steam, and NORENCO shall not be liable to NSP for its failure to receive steam, when such failure on the part of either party shall be due to accident to or breakage of pipelines or equipment, fires, floods, storms, weather conditions, strikes, lockouts or other industrial disturbances, riots, legal interference, acts of God or public enemy, shutdowns for necessary repairs and maintenance, or, without limitation by enumeration, any other 13

14 cause beyond the reasonable control of the party failing to deliver or receive steam provided such party shall promptly and diligently take such action as may be necessary and practicable under the then existing circumstances to remove the cause of failure and resume the delivery or receipt of steam. Furthermore, NSP shall not be liable for its failure to deliver steam provided that such failure is (i) due to any scheduled or unscheduled maintenance shutdown of boilers B9 and/or B10 or (ii) due to operating conditions on boiler B9 or B10 and turbine T3 or T4 that warrant curtailment of the delivery of steam to NORENCO. NSP shall have the sole right to determine when those conditions exist. NSP and NORENCO shall cooperate with each other regarding maintenance and steam service curtailment, and shall use their best efforts to coordinate inspections, maintenance and repairs to their respective facilities. NSP shall provide NORENCO with as much advance notice as possible of scheduled interruption or curtailment of steam service. VII MISCELLANEOUS 7.1 This Agreement shall bind and inure to the benefit of the respective successors and assigns of the parties hereto, and any reference to any of the parties hereto shall be deemed to include all successors and assigns. Notwithstanding the foregoing, no assignment shall relieve a party of its duties and obligations to the other party under 14

15 this Agreement if the assignee defaults in such duty or obligation, unless such other party consents to the novation in writing. 7.2 Unless designated otherwise in writing, all notices from NORENCO to NSP shall be delivered to: D. E. Gilberts Senior Vice President-Power Supply Northern States Power Company 414 Nicollet Mall Minneapolis, MN 55401 Unless designated otherwise in writing, all notices from NSP to NORENCO shall be delivered to: H.S. Wick, Jr. Vice President Norenco Corporation 414 Nicollet Mall P.O. Box 1396 Minneapolis, MN 55440 7.3 All payments and reimbursements required to be made by NORENCO to NSP pursuant to this Agreement shall be directed to: Manager, General Accounting Northern States Power Company 414 Nicollet Mall Minneapolis, MN 55401 7.4 The costs and charges provided for herein are exclusive of any present or future federal, state, municipal or other sales or use tax with respect to the personnel covered hereby, or any other present or future excise tax upon or measured by the gross receipts from this transaction or any allocated portion thereof or by the gross value of the personnel covered hereby. If NSP is required by applicable law or regulations to pay or collect any such tax or 15

16 taxes on account of this transaction or the personnel covered hereby, then such amount shall be paid by NORENCO in addition to the costs or charges provided for herein. 7.5 This Agreement shall be construed in accordance with and be governed by the laws of the State of Minnesota. IN WITNESSETH WHEREOF, the parties hereto have caused this instrument to be executed by their respective officers thereunto duly authorized as of the day and year below written. NORENCO CORPORATION NORTHERN STATES POWER COMPANY By /s/ H. S. Wick By /s/ D.E. Gilberts -------------------------- -------------------------------- Its V.P. and Gen. Mgr. Its Sr. Vice President Power Supply ------------------------- ------------------------------- Date 5/18/83 Date 5/18/83 ------------------------ ------------------------------ 16

17 Table 1 _________ Month _____ Year 4.1) FUEL Fuel Delivered in Month = $ _________ 4.2) Incremental Maintenance ______ MMBtu ________ $/MWHO = $ _________ 4.3) Incremental Auxiliaries ______ MMBtu ________ $/MWH = $ _________ 4.4) No Load Maintenance ______ Hours ________ $/MWCAPO = $ _________ 4.5) No Load Auxiliaries ______ Hours ________ $/MWH = $ _________ 4.6) Ash Disposal = $ _________ 4.7) Energy Management System Costs -- 4.7.1) Replacement Energy = $ _________ 4.7.1.1 Costs Fuel $ ___________ Maintenance $ ___________ Startup $ ___________ Fuel & Ash Handling $ ___________ Other $ ___________ 4.7.1.2 Boiler Availability Credits $ ___________ 4.7.2) Sales of Electricity for Resale = $ _________ 4.8) Flame Stabilization _____ MMBtu gas ______ gas cost = $ _________ _____ Gallons oil ______ oil cost = $ _________ 4.9) Incremental Operations from time sheets = $ _________ 4.10) Thermal Equipment O & M from work orders = $ _________ 4.11) Standby No Loads _______ hours = $ _________ 4.12) Supply of Gas and Oil = $ _________

18 Table 2 ____________ Month __________ Year HIGH BRIDGE FUEL INVENTORY --------- NSP Electric NORENCO ------------ ------- Tons MMBtu Tons MMBtu Fuel beginning of month Fuel delivered during month Fuel consumed during month* Fuel onsite end of month * For boilers B9 and Bl0, fuel consumed will be prorated between NSP Electric and NORENCO on the basis of measured integrated readings of steam flow to NORENCO and the turbine generators T3 and T4. Total coal consumption by boilers B9 and B10 will be measured using existing plant procedures and instrumentation. Differences in measured and estimated pile inventory on annual pile true-up will be prorated between NSP Electric and NORENCO on the basis of the recorded NORENCO and Electric inventory at the time of true-up. HIGH BRIDGE STEAM PRODUCTION ---------------------------- NSP Electric NORENCO ------------ ------- T3 T4 Steam integrator beginning of month Steam integrator end of month Steam consumption

19 DEFINITIONS Thermal Only Service At any point in time High Bridge Boilers B9 and B10 are either in a shutdown mode, a hot standby mode, a startup mode, or an operating mode. When those boilers would otherwise be in the shutdown mode with respect to system electric generation requirements, such boilers shall be deemed to be in thermal only service. No Load Operation and A coefficient calculated periodically by NSP Maintenance Coefficient Power Production which relates the annual maintenance cost of a generating unit to the energy output of the unit. Average System Incremental Each month, NSP Power Production calculates Generation Cost its average incremental cost to generate electricity to meet NSP's native load requirements.

1 Exhibit 10.35 OPERATIONS AND MAINTENANCE AGREEMENT FOR ELK RIVER RESOURCE RECOVERY FACILITY AND BECKER ASH LANDFILL THIS OPERATIONS AND MAINTENANCE AGREEMENT (the "Agreement") is made as of this 1st day of November, 1996 by and between Northern States Power Company, a Minnesota corporation ("Owner") and NRG Energy, Inc., a Delaware corporation ("Operator"). RECITALS: WHEREAS, Owner is a public utility which serves retail customers in Minnesota, South Dakota and North Dakota, and which is subject to regulation by the Minnesota Public Utilities Commission ("MPUC"), among other agencies; WHEREAS, Operator is a wholly-owned subsidiary of Owner engaged in the business of owning and operating electric generating facilities and facilities for the transportation and processing of municipal solid waste into refuse-derived fuel ("RDF"); WHEREAS, Owner owns an undivided 85% interest in the fixed assets and 100% interest in the mobile assets of a facility located in Elk River, Minnesota for the receipt and processing of municipal solid waste into RDF as more particularly described on Exhibit A (the "Facility"); WHEREAS, Owner owns an ash landfill facility in Becker, Minnesota, as more particularly described on Exhibit B (the "Ash Landfill"); WHEREAS, the County of Anoka ("Anoka County") and Owner entered into a Loan Agreement, as defined herein (the "Loan Agreement"), pursuant to which Anoka County agreed to loan to Owner the proceeds of its Floating/Fixed Rate Resource Recovery Revenue Bonds (Northern States Power Company Project), Series 1985 (the "Series 1985 Bonds") for the purpose of financing costs of the Facility to be acquired, constructed and equipped and thereafter owned and operated by Owner; WHEREAS, Anoka County and Owner entered into a service agreement dated November 26, 1985 as amended and restated on March 10, 1987 ("Anoka Service Agreement"); WHEREAS, the County of Hennepin and Owner entered into a service agreement dated December 30, 1987 ("Hennepin Service Agreement"); WHEREAS, the County of Sherburne and Owner entered into a service agreement in March, 1987 ("Sherburne Service Agreement"); 1

2 WHEREAS, The Tri-County Solid Waste Management Commission ("Tri-County Commission") and Owner entered into a service agreement in March, 1987 ("Tri-County Service Agreement); WHEREAS, Hennepin County, Anoka County, Sherburne County, the Tri-County Commission and Owner entered into an Ash Management Services Agreement dated June 15, 1989 ("Ash Management Service Agreement") pursuant to which Owner agreed to transport, dispose of and store various ash; WHEREAS, Anoka County and Owner entered into a design and construction agreement dated November 26, 1985, as amended and restated on March 10, 1987 ("Construction Agreement"); WHEREAS, Owner and United Power Association ("UPA") entered into an agreement dated February 10, 1987 as amended on March 15, 1991 ("UPA Agreement"), pursuant to which UPA and Owner defined their respective rights and obligations with respect to management, administration, ownership, revenues and responsibilities with respect to the Facility; WHEREAS, Owner and Operator have entered into an Administrative Services Agreement dated February 24, 1992 (the "Administrative Agreement") approved by the MPUC under which either entity may provide services to the other and setting forth the means by which compensation for any such services is to be computed; and WHEREAS, Owner desires that Operator continue to operate and maintain the Facility and Ash Landfill, pursuant to an agreement independent of the Administrative Agreement; NOW THEREFORE, in consideration of the premises and the mutual promises and agreements of the parties, the parties agree as follows: 1. DEFINITIONS The following terms shall have the meaning set forth herein: 1.1 Agreement: This contract, including all appendices, exhibits and schedules attached or incorporated, as it may be amended, supplemented or modified by the Parties from time to time in accordance with this Agreement. 1.2 Annual Operating Budget: The budget materials and information prepared by Operator each year of the Term as set forth in Section 5.1. 1.3 Ash Landfill: The real property, fixtures, equipment, personal property, improvements and other items described on Exhibit B. 2

3 1.4 Ash Landfill Equipment: All equipment, fixtures and machinery used in the operation or maintenance of the Ash Landfill. 1.5 Base Management Fee: The amount Owner is to pay Operator as provided in Section 6.5. 1.6 Commencement Date: The date on which Operator commenced the provision of operation and maintenance services for the Facility and Ash Landfill, which is agreed to be January 1, 1994. 1.7 Contract Year: From January 1 to December 31 of any given calendar year. 1.8 Effective Date: The date on which this Agreement takes effect, as set forth in Section 9.1. 1.9 Emergency: Any condition, situation or event relating to or affecting the Facility, the Ash Landfill, or any part thereof which (i) imminently endangers or might endanger the life or safety of persons or result in damage to property; or (ii) adversely affects or might adversely affect the ability of the Facility or Ash Landfill to meet any material obligation of the Loan Agreement or might create an Event of Default under the Loan Agreement or any RDF Facility Agreement; or (iii) creates, or might create, a material violation of any Law or Permit. 1.10 Event of Default: Any occurrence defined in Section 14.1. 1.11 Facility: The real property, fixtures, improvements, equipment, personal property and other items located on Exhibit A. 1.12 Facility Equipment: All equipment, fixtures and machinery used in the operation or maintenance of the Facility. 1.13 Final Non-appealable Order: An order from the MPUC or from any other judicial, quasi-judicial, administrative or legislative body from which all rights to seek reconsideration and appeal have been exhausted or from which the time limits applicable to seeking reconsideration and appeal have expired. 1.14 Force Majeure: An event or events as defined in Article XII. 1.15 Governmental Authority: The United States of America, the State of Minnesota, or any state or other political subdivision thereof, including, without limitation, any municipality, township, or county, and any entity exercising executive, legislative, judicial, regulatory or administrative functions 3

4 of or pertaining to government, including, but not limited to, any corporation or other entity owned or controlled by any of the foregoing. 1.16 Law(s): Any constitution, charter, act, statute, ordinance, code, rule, regulation, order, permit, condition, specified standards or objective criteria contained in any applicable permit, approval, order, decision, determination or ruling of any Governmental Authority having jurisdiction, all as in effect from time to time, including without limitation, environmental laws pertaining to air and water emissions relating to the Facility and Ash Landfill, and the operation thereof, which standards or criteria must be met in order for the Facility or Ash Landfill to be operated lawfully, or other legislative, administrative or judicial action, decree, judgment or Final Non-appealable Order of any Governmental Authority having jurisdiction relating to the Facility or Ash Landfill. 1.17 Lien: Any security interest, mortgage, pledge, lien (statutory or otherwise), claim, hypothecation, assignment, preference, priority, charge, encumbrance, title, retention agreement, or Lessor's interest under a capital lease or analogous instrument, or any other agreement of any kind or nature which has substantially the effect of constituting a security interest in, of, against or on any portion of the Facility, Ash Landfill, Facility Equipment or Ash Landfill Equipment. 1.18 Materials: All supplies, spare parts, materials, tools, consumables, chemicals and equipment necessary for the operation and maintenance of the Facility or Ash Landfill. 1.19 MPUC: The Minnesota Public Utilities Commission and any successor agency. 1.20 Operation and Maintenance Manuals: The operating manuals for the Facility and Ash Landfill, including the operating data and parameters, design drawings, specifications, vendor manuals, manufacturer manuals or warranties and similar materials for the Facility, Ash Landfill, Facility Equipment and Ash Landfill Equipment. 1.21 Operator: NRG Energy, Inc. and its successors and assignees. 1.22 Owner: Northern States Power Company and its successors and assignees. 1.23 Parties: Owner and Operator and their respective successors and assignees. 1.24 Party: Owner or Operator and any successor or assignee of either Owner or Operator, respectively. 4

5 1.25 Permits: All federal, state and local authorizations, certificates, licenses, permits, consents, rights, exemptions, orders, concessions, determinations, franchises, and approvals required by any Governmental Authority for the construction, operation or maintenance of the Facility, the Ash Landfill, the Facility Equipment, or the Ash Landfill Equipment or otherwise applicable. 1.26 Person: Any individual, partnership, corporation, business trust, limited liability company, joint stock company, trust, unincorporated association, joint venture, Governmental Authority or other entity. 1.27 Potential Event of Default: An event which, but for the passage of time or the giving of notice or both, would constitute an Event of Default. 1.28 Prudent Operating Practice: Those practices, designs, means, techniques, equipment, methods, specifications and standards of safety and performance, as the same may change from time to time, as would be used by experienced, knowledgeable and professional firms performing operation and maintenance services on facilities of the type and size similar to the Facility or Ash Landfill, which, in the exercise of reasonable judgment and in the light of the facts known or which reasonably should have been known, are considered to be sound, safe and prudent practice in connection with the operation and maintenance of RDF processing facilities and ash landfill facilities, and similar facilities, at the time a decision is made or an action taken or not taken, and which are consistent with all applicable laws, permits, the RDF Facility Agreements, the Loan Agreement, the UPA Agreement and relevant standards for reliability, safety, environmental protection, efficiency and economy. 1.29 RDF Facility Agreements: Collectively the Anoka Service Agreement, Hennepin Service Agreement, Tri-County Service Agreement, Ash Management Service Agreement, Construction Agreement, and UPA Agreement. 1.30 Reimbursable Costs: The costs and expenses set forth in Section 6.2. 1.31 Requests for Payment: The periodic written invoices and requests from Operator to Owner prepared in accordance with Section 6.7(a) for payment of the Management Fee, Reimbursable Costs and other amounts due from Owner to Operator. 1.32 Standards of Performance: The standards for Operator's performance of the services to be provided as set forth in Section 3.2. 5

6 1.33 Supplies: Lubricants, hand tools, office and laboratory supplies, protective clothing and any other consumable items required for operation and maintenance of the Facility, Facility Equipment, Ash Landfill and Ash Landfill Equipment. 1.34 Term: The Period of time during which this Agreement is in effect. ARTICLE 11 SCOPE OF WORK 2.1 Scope of Work: Operator will operate and maintain the Facility, Ash Landfill, Facility Equipment and Ash Landfill Equipment (collectively the "RDF Facilities") and perform certain other duties as set forth in this Agreement, including, but not limited to, all operation and maintenance services defined in Section 3.1 (the "Contract Services"). Operator shall operate and maintain the RDF Facilities in a clean, safe, efficient and environmentally responsible manner. The Contract Services shall be performed in accordance with the Standards of Performance set forth in Section 3.2. 2.2 RDF Facility Agreements and Permits: Prior to execution of this Agreement, Owner has provided Operator with copies of the RDF Facility Agreements and Permits. Upon execution or receipt by Owner of any new RDF Facility Agreements, Permits, or any amendments to RDF Facility Agreements or Permits previously transmitted to Operator, Owner shall provide Operator with executed copies. The Parties recognize and agree that this Agreement is intended, in part, to fulfill Owner's operation and maintenance obligations under the RDF Facility Agreements and, after compliance with the Permits, Standards of Performance, Prudent Operating Practice, and Laws, to optimize the operation of the RDF Facilities consistent with Owner's objective to achieve its expected return. 2.3 Compliance with RDF Facility Agreements and Permits: Operator shall abide by all terms and conditions of the RDF Facility Agreements and Permits applicable to the operation and maintenance of the RDF Facilities in performing any part of the Contract Services. If Operator's compliance with this Agreement would cause Owner to be in default or otherwise in breach or violation of any of its obligations under any RDF Facility Agreement, the Loan Agreement, or any Permit, the requirements of such agreements or permits shall control Operator's performance hereunder to the extent necessary to avoid such default, breach or violation, subject to Operator's obligation to comply with all Laws. Each Party shall notify the other as soon as it knows or believes that compliance with this Agreement may result in such a default, breach or violation. 6

7 ARTICLE III OPERATOR RESPONSIBILITIES 3.1 On and after the Commencement Date and subject to approval by Owner of the Annual Operating Budget and any other expenses Operator shall be responsible for the operation and maintenance of the Ash Landfill, Ash Landfill Equipment, Facility and Facility Equipment, including, but not limited to, the following: A. Performance of all operation and maintenance of the Ash Landfill, Ash Landfill Equipment, Facility and Facility Equipment, including the procurement of all Ash Landfill Equipment, Facility Equipment, Materials, Supplies and related services required to ensure operation and maintenance in accordance with the provisions of this Agreement and industry standards and to accomplish the objectives of maximizing useful life and minimizing damage to the RDF Facilities and outages or unavailability due to lack of maintenance. B. Performance of all preventive maintenance, in accordance with applicable Operation and Maintenance Manuals and manufacturers' and vendors' warranties and recommendations; the performance of routine maintenance such as lubrication, oil changes, adjustments, and scheduled replacements; and the performance of corrective maintenance such as repairs after the occurrence of a problem, breakdown or failure. C. Performance of all services required by the UPA Agreement, Ash Management Services Agreement, Tri-County Service Agreement, Anoka Service Agreement, Hennepin Service Agreement, and Sherburne Service Agreement to operate and maintain the RDF Facilities, including, but not limited to, all necessary communication with the respective parties to such agreements, and preparation of notices, reports and supporting data for Owner's review and submittal under such agreements, and all necessary administration of such agreements. D. Applying for and maintaining all Permits necessary for the operation of the RDF Facilities. E. Administration and coordination of all municipal solid waste supplies received at the Facility, including, but not limited to, management of 7

8 contract trucking services and landfill operator's contracts and operations. F. Preparing and revising site procedures, budgets, logs, records and technical and administrative reports as may be required or advisable. G. Identifying the need for the procurement of subcontractors for performance of portions of the Contract Services subject to Owner approval, and scheduling, coordinating and supervising any such subcontractors. H. Preparing the Annual Operating Budget required in accordance with Section 5.1. I. Preparing and submitting, or providing to Owner for submittal, with the appropriate Person or Governmental Authority, all reports, data and other information required by the Permits and RDF Facility Agreements. J. Responding in a timely manner to written requests from Owner for information about the Contract Services. K. Performing all other responsibilities assigned to Operator pursuant to this Agreement. 3.2 Standards of Performance: Operator shall perform each item of the Contract Services in a careful, professional, prudent and efficient manner at a level of care consistent with that expected from similarly situated professional operation and maintenance providers, and in accordance with the following requirements (collectively "Standards of Performance"): (a) Prudent Operating Practice; (b) the terms of the Operation and Maintenance Manuals and other operating instructions provided by Anoka County or its agents pursuant to the Construction Agreement or provided by any other vendors, suppliers or contractors (and, with regard to any Facility Equipment acquired subsequent to the Commencement Date, in accordance with the operating instructions provided by the respective equipment suppliers, vendors or manufacturers) or other appropriate practices, whichever are more stringent; (c) all operational and maintenance obligations imposed on the Owner pursuant to any RDF Facility Agreement; 8

9 (d) the requirements of the providers of insurance described in Article VII, and any and all insurance coverage documents maintained by Owner for the protection of the RDF Facilities and their revenues, copies of which are provided to Operator; (e) any and all warranties received from Anoka County or its agents or any manufacturer of the Facility Equipment or Materials, which are not part of any RDF Facility Agreements, copies of which have been provided to Operator; (f) the Permits and all applicable Laws; (g) the site procedures, and all other procedures devised by Operator for operation and maintenance of the RDF Facilities; (h) after compliance with all relevant Laws, Permits, RDF Facility Agreements and Standards of Performance, operation of the RDF Facilities consistent with Owner's objective to achieve its expected return from the operation of the Facility. In the case of any conflict between any such standards, the most stringent applicable standard shall govern. 3.3 Procurement of equipment, materials, services and supplies: (a) Subject to the limitations set forth in Section 5.2, Operator shall identify, select, schedule, procure and receive all equipment, materials, supplies and services necessary to perform the Contract Services. Operator shall identify all such items needed, establish technical and commercial requirements, develop qualified bid lists, request bids or proposals from prospective vendors and subcontractors, evaluate bids or proposals received and select appropriate vendors and subcontractors. Operator shall use its best efforts to procure all equipment, services and supplies at competitive rates, and to make all purchases at the lowest evaluated price available for the appropriate type and quality of equipment, services and supplies. Operator shall use its professional judgment to determine when competitive bidding is appropriate. (b) Operator shall receive, inspect and inventory all Equipment, Materials and Supplies delivered and identify and resolve any defects or deficiencies, and shall sign all invoices, bills of lading or other documents indicating acceptance when the Equipment, Materials and 9

10 Supplies meet Operator's purchase order or other specifications. Operator shall be responsible for resolving defects or deficiencies identified, including arrangement for obtaining replacements, modifying or withholding payment, or otherwise processing any claim or dispute arising under a purchase order. (c) In no event shall Operator take title to any Equipment, Materials or Supplies received for the RDF Facilities. All purchase orders, bills of lading and other title and shipping documents with respect to the Equipment, Materials and Supplies shall specify that Owner is to take title directly from the manufacturer, vendor or supplier. Title to all Equipment, Materials and Supplies or other services or items purchased by Operator in connection with the Contract Services shall pass directly to Owner from the manufacturer, vendor or supplier free of all liens of Operator. (d) Operator shall be responsible for supervising, coordinating and administering the work of all subcontractors providing services. 3.4 Inventory. Operator shall maintain an inventory of Materials adequate to support the continuous and successful operation of the RDF Facilities. The procurement of such inventory, including replacement Materials, shall be made in accordance with the provisions of Section 3.3. Operator shall provide necessary security for such inventory, and establish and manage an inventory control system. 3.5 Personnel. (a) Operator shall employ at the Facility and the Ash Landfill the appropriate number of properly qualified and trained personnel to perform the Operator's obligations under this Agreement as approved under the Annual Operating Budget. Operator shall be solely responsible for the development of a staffing plan and the selection and training of all personnel employed by Operator at the Facility and the Ash Landfill following the Commencement Date. (b) All personnel shall be qualified (including holding all appropriate valid licenses required by Law) and fully trained for their respective positions. All individuals utilized by Operator to perform Contract Services shall be employees of the Operator or workers or independent contractors under Operator's direction. Working hours, rates of compensation, and all other matters relating to such personnel shall be determined by Operator (subject to Owner's approval with respect to budget items.) 10

11 (c) Operator shall retain sole responsibility and control of labor matters pertaining to its personnel. Operator shall provide Owner with such information regarding the selection of its personnel as Owner may reasonably request. With respect to hiring of personnel and its employment policies, Operator shall comply with all applicable federal and state labor and employment Laws and shall exercise control over labor relations in a reasonable manner consistent with the intent and purpose of this Agreement, including the laws and policies set forth in Exhibit C. (d) Operator acknowledges and agrees that it does not have the authority to enter into any contracts or collective bargaining agreements which bind or purport to bind or obligate Owner. 3.6 Training. (a) Operator shall insure that its personnel are trained in a satisfactory manner so as to enable each of the personnel to perform their assigned functions and as required to enable Operator to comply with its obligations under this Agreement. Operator shall establish and maintain a regular ongoing training program for the personnel. This training program shall be designed to train new personnel, keep existing personnel familiar with all existing site procedures and informed of all new revisions. Owner may at any time, upon reasonable notice, review Operator's regular training program in order to assess its adequacy and compliance with this Section 3.6. (b) If this Agreement is scheduled to terminate for any reason, Operator will cooperate with Owner and any replacement operator, at Owner's expense, in training replacement personnel for the RDF Facilities, including permitting such replacement personnel to participate in the training program described in Section 3.6(a). 3.7 Taxes. Operator shall pay all federal, state and local taxes which it is obligated to pay with respect to wages, salaries and benefits paid or provided by it to its employees, including, but not limited to: (i) all payroll-related or consumer taxes of its employees, federal, state and local tax withholdings, Federal Insurance Contribution Act taxes, and federal and state unemployment taxes and; (ii) all federal, state and local corporate income taxes on income earned by Operator. Owner shall pay real and tangible real estate and personal property taxes for property owned, leased, or rented by Owner. Operator shall forward to Owner any tax bills for which Owner is responsible immediately upon receipt by Operator. Operator shall maintain 11

12 all appropriate records reflecting its tax obligations, withholdings and payments. 3.8 Safety. Operator shall take all necessary and advisable precautions for the safety and security of its personnel and other persons at the Facility and the Ash Landfill and in connection with the performance of the Contract Services, and shall comply with all applicable safety laws and requirements, necessary to prevent accidents or injury to persons or damage to property at the Facility or the Ash Landfill. Operator shall promptly and continuously update its safety and security procedures to ensure safe, secure and efficient operation of the Facility and Ash Landfill. 3.9 Administration. Operator shall administer and be responsible for all cost accounting, purchasing, personnel, insurance and payroll functions relating to the performance of the Contract Services. All accounting shall be in accordance with generally accepted accounting principles. Operator shall pay all bills related to the Contract Services in a timely manner so as to take advantage of any available discounts and to avoid any penalties, except for those bills which are the obligation of Owner to pay. 3.10 Licenses and Permits. (a) Operator shall cause each of its personnel to procure and maintain their respective licenses as required to perform the Contract Services. (b) Operator shall maintain each of the Permits and procure any renewals, revisions, waivers or new Permits necessary or desirable for the operation and maintenance of the RDF Facilities. Operator shall retain all original Permits received or obtained by Operator for the Facility and Ash Landfill from time to time as such Permits are received or obtained during the term of this Agreement, including any renewals, revisions, waivers, or amendments and deliver copies of all such Permits to Owner. (c) Operator shall perform Owner's obligations under the Permits and any renewals thereof and shall give all notices required by, and otherwise comply with, all applicable Permit terms and shall keep the Permits in full force and effect. In the event any Permit shall be violated by the operation or maintenance of the Facility or Ash Landfill by Operator or otherwise, Operator shall promptly notify Owner and all other applicable Persons and take all necessary action required to place the Facility and Ash Landfill into compliance with the Permit as soon as practicable. The provisions of this section shall apply to any Permit 12

13 required in connection with the transportation, handling, processing, storage or disposition of any Hazardous Materials. 3.11 Compliance with Laws. Operator shall at all times operate and maintain the RDF Facilities in a manner which complies in every material respect with all applicable Laws and Permits, as amended from time to time. In the event any of the RDF Facilities, Contract Services, or Operator shall violate any Law, Operator shall promptly notify Owner and all other applicable Persons and take all necessary action to place the RDF Facilities into compliance with the applicable Laws. 3.12 Emergencies In the case of an Emergency, Operator shall, as soon as reasonably practicable, notify Owner of the nature of such Emergency, the proposed remedial measures and its probable duration. Operator shall act immediately as required to prevent or overcome any risk of injury to Persons or material damage to property and to otherwise minimize the likelihood and degree of adverse consequences from the Emergency. 3.13 Improvements. Operator shall identify any alterations, additions, modifications or other changes to the RDF Facilities ("Improvements") which would improve the overall operation, output, safety or efficiency of the RDF Facilities, and advise Owner in writing of such proposed Improvements. Upon the written approval of Owner, the Operator shall arrange for the procurement and integration of all such equipment, materials and other resources necessary to implement such Improvements at the RDF Facilities. Except as set forth in the Annual Operating Budget, the Operator shall make no Improvements other than Improvements made in accordance with this Section 3.13. 3.14 Books and Record. (a) Operator shall maintain operating logs, records and reports documenting the operation of the RDF Facilities, including those logs, records and reports required by any RDF Facility Agreement or MPUC, maintain current revisions of Facility and Ash Landfill drawings, equipment manuals, instruction books, and the Operation and Maintenance Manuals; and maintain accurate cost ledgers and accounting records regarding the Contract Services in accordance with generally accepted accounting principles for review by Owner. Operator shall also prepare all reports required for Governmental Authorities, or by the Permits, and provide same to Owner for its review. Upon termination of this Agreement, the Operator shall turn over a copy of all such books, logs, ledgers, manuals, reports and records to Owner. 13

14 (b) Operator shall establish and maintain an information system reasonably satisfactory to Owner to provide storage and ready retrieval of Facility and Ash Landfill operating data, including such information necessary to verify and support calculations for preparation of documents pursuant to the RDF Facility and Loan Agreements. (c) Operator shall prepare and maintain, on a current basis, proper, accurate, and complete books and records and accounts of all transactions related to the Facility and Ash Landfill, including information necessary to verify calculations made pursuant to this Agreement. (d) At all reasonable times Owner shall have access to the records maintained pursuant to this Section and may audit the recordkeeping practices and systems used to generate the data required by this Section. Owner shall have the right to determine whether such practices and systems are in accordance with generally accepted accounting principles and may cause Operator to make such changes as necessary to conform with such principles. Operator's records shall also include all data required by the MPUC and shall be in a form which satisfies all data requirements of the MPUC. This provision does not require Operator to utilize the Uniform System of Accounts of the MPUC. (e) Owner's right of access to the records described in this Section 3.14 and Operator's obligation to maintain and preserve the same shall survive for a six (6) year period following the termination of this Agreement. (f) With the exception of information relating to Operator's training program, all reports, data and other documents prepared by Operator in connection with the Facility, Ash Landfill or Contract Services shall be the property of Owner as and when the same are prepared and shall be used by Operator only in the performance of Contract Services. 3.15 Custody and Access. After the Commencement Date, Operator shall assume responsibility for the care, custody and control of the Facility and the Ash Landfill. Upon reasonable notice, Operator shall allow Owner and its agents and designees full, unrestricted access to the Facility and the Ash Landfill and all reports, data, information and documents related to the RDF Facilities and Contract Services in Operator's possession at the Facility and Ash Landfill, provided that Owner and its agents and designees agree to comply with all 14

15 applicable safety and security procedures which Operator deems necessary or advisable. 3.16 Enforcement of Warranties. Operator shall preserve and maintain all warranties or guarantees of which Owner is beneficiary regarding the Facility, Facility Equipment, Ash Landfill, Ash Landfill Equipment, Equipment, and Materials or any component thereof and shall notify Owner of any claims which Owner may have under such warranties or guarantees of which Operator becomes aware during the performance of Contract Services. Operator shall manage and operate the Facility and Ash Landfill consistent with the conditions applicable to all such warranties and guarantees so as to preserve their effectiveness and shall take no action which may adversely affect any claim under any warranty or guarantee without the express written consent of the Owner. 3.17 No Liens or Encumbrances. Operator shall keep and maintain the Facility, Ash Landfill, Facility Equipment and Ash Landfill Equipment free and clear of all Liens and encumbrances (other than Liens created or permitted by Owner) resulting from acts or omissions of Operator or its subcontractors or work done at the request of Operator or its subcontractors. In the event any Lien is imposed and unless (i) execution and enforcement are effectively stayed, (ii) all claims which the Lien secures are being actively contested in good faith, with due diligence and by appropriate proceedings and (iii) Operator has posted a bond or created a financial reserve sufficient to fully satisfy and release any contested Lien, Operator shall immediately take whatever actions are necessary to satisfy and release the Lien. Operator agrees to indemnify and hold Owner harmless from all claims, judgments, losses, damages, and defense costs, including reasonable attorneys' fees, incurred or suffered by Owner as a result of the imposition or pendency of any Lien (other than Liens created or permitted by Owner) or Owner's reasonable response to any such Lien, including, but not limited to, all costs incurred to remove or satisfy any such Lien if Operator fails to do so as required by this Agreement. 3.18 Facility Performance. If any significant deficiency in performance of the Facility or Ash Landfill occurs, including, but not limited to, a failure to meet any warranty or obligation under the RDF Facility Agreements, or if such a deficiency is projected, Operator shall notify Owner of the deficiency or projected deficiency and shall state Operator's opinion as to the cause of the deficiency or projected deficiency and prepare a report in detail, as required, together with a plan to remedy the problem. Upon Owner's request, Operator shall make available those of its personnel necessary to review and assess the cause of the deficiency or projected deficiency with Owner. 15

16 3.19 Periodic and Annual Review (a) Status meetings shall be held quarterly between Owner's Representative and Operator's Representative, or more frequently as may be necessary for the purpose of reviewing Operator's provision of the Contract Services. (b) At least (10) ten days before each quarterly status meeting, Operator shall submit to Owner (i) a progress report, in detail acceptable to Owner, covering all operations conducted during the quarter with respect to operations and maintenance, procurement, Improvements, labor relations, significant interactions with UPA and any Governmental Authorities, and other significant matters, which report shall include (with respect to quantitative items) a comparison of such items to corresponding values for the then preceding quarter and year and listing of any significant operation problems along with remedial actions planned and a brief summary of major activities planned for the next reporting period. (c) As soon as available, and in any event within forty-five (45) days after the end of each Contract Year, Operator shall submit to Owner an annual report certified by the Operator's Representative describing in detail substantially similar to that contained in the quarterly reports referred to in Section 3.19(b) above, all of the Facility and Ash Landfill operations for the preceding Contract Year and presenting a comparison of the Facility and Ash Landfill operations with the Annual Operating Budget for the Contract Year and with those obtained for the preceding Contract Year, if any (the "Annual Report"). Within thirty (30) days after the submission of each Annual Report, the Operator's Representative shall meet with Owner's Representative to review and discuss the report and to report upon any other aspects of the operations at the Facility and Ash Landfill that Owner may request. (d) Operator shall prepare any additional reports required by the RDF Facility Agreements, Permits, Laws or any Governmental Authority in a timely and complete manner. 3.20 Litigation; Permit Lapses. Upon obtaining notice or knowledge thereof, Operator shall submit prompt written notice to Owner of: (i) any litigation, or material claim, dispute or action, threatened in writing or filed, concerning the Facility, the Ash Landfill, the RDF Facility Agreements, or the Contract Services; (ii) any written refusal or threatened refusal to grant, renew or extend or any pending or written threatened action that might affect the granting, renewal or extension of, any license, permit, approval, authorization 16

17 or consent concerning the Facility or Ash Landfill or the Contract Services; and (iii) any dispute with any Governmental Authority concerning the Facility or Ash Landfill or the Contract Services, any Permit, or any dispute with respect to any RDF Facility Agreement. ARTICLE IV OWNER RESPONSIBILITIES 4.1 Access. Owner shall provide and grant to Operator right of access to the Facility and the Ash Landfill, throughout the term of this Agreement. 4.2 Accommodations. Owner shall make available such offices, storage facilities, unloading docks, restrooms, office equipment and facilities as are reasonably necessary to perform the Contract Services, and as are reasonably practicable, at the Facility and Ash Landfill. This section does not require Owner to invest in Improvements or to expend funds for items which are properly included in Operator's overhead expenses. 4.3 Manuals and Drawings. Owner shall provide Operator with all current Operating Manuals and with all as built drawings, specifications, warranties, diagrams, test results and other documents and information which Owner may have with respect to the RDF Facilities, which is necessary to Operator's provision of the Contract Services. Should any such information be classified as confidential or proprietary, Owner shall seek to obtain all necessary authorizations, releases, acknowledgments or other approvals necessary to provide Operator access to and use of such information. Operator shall comply with all reasonable requests to protect the confidential and proprietary nature of such information, including, but not limited to, any requirements contained in any RDF Facility Agreement. 4.4 Cooperation. Without limiting Operator's obligations hereunder, Owner shall make reasonable efforts to cooperate with Operator in its performance of the Contract Services. 4.5 Representatives. Each Party shall designate a representative who shall be principally responsible for administration of this Agreement and for communications between the Parties. The designation of the representative for each Party may be changed at any time by written notice. 17

18 ARTICLE V ANNUAL OPERATING BUDGET 5.1 Preparation of Budget. No later than ninety (90) days prior to the beginning of each Contract Year, Operator shall submit for Owner's review and approval, a proposed budget on a monthly basis, for the Contract Services to be performed in the next succeeding Contract Year. The proposed Annual Operating Budget shall be based on Operator's assessment of the necessary Contract Services for the next Contract Year and shall reflect the most economical and reasonable means of performing such activities in accordance with the Standards of Performance. The proposed Annual Operating Budget shall include: (i) the proposed amount to be spent annually for Reimbursable Costs and the Management Fee then in effect; (ii) the proposed amounts to be spent for the purchase of Equipment, Materials, Supplies and services in accordance with Section 3.3, identifying the items to be purchased; (iii) a proposed inventory plan; (iv) proposed Improvements, with a statement describing the purpose and necessity of each Improvement and the estimated cost of each Improvement; and (v) the estimated Performance Incentive, including a schedule detailing its calculation in accordance with Section 6.6. 5.2 Owner's Review. (a) Within thirty (30) days after Owner receives Operator's proposed Annual Operating Budget, Owner shall notify Operator in writing of Owner's approval or of any proposed revisions to the proposed Annual Operating Budget. Within 30 days following receipt of Owner's revisions, Operator shall either confirm to Owner its ability and agreement to perform the Contract Services during the Contract Year in question in accordance with the proposed Annual Operating Budget as revised by Owner, or Operator shall object to Owner's revisions in writing stating in detail the reason for each objection. Owner and Operator shall use their best efforts to agree upon an Annual Operating Budget, which shall be approved in writing by both Parties, approval for which shall not be unreasonably withheld. If Owner and 18

19 Operator are unable to agree upon an Annual Operating Budget, Owner and Operator shall present the dispute for dispute resolution in accordance with Article VIII. In the event an Annual Operating Budget has not been agreed upon by the first day of any Contract Year, the Annual Operating Budget shall be the Annual Operating Budget used for the preceding Contract Year. Each Annual Operating Budget shall remain in effect throughout the applicable Operating Year, subject to updating, revision and amendment as may be proposed by either Party and consented to in writing by the other Party, consent for which may not be unreasonably withheld. (b) If, during any Contract Year, Operator determines that any category within an Annual Operating Budget will vary for the Contract Year by more than ten percent (10%) or one hundred thousand dollars ($100,000), whichever is greater, Operator shall immediately notify Owner and shall follow Owner's instructions regarding further expenditures for the operation and maintenance of the Facility and Ash Landfill pursuant to this Agreement. Until such time as Operator receives such instructions, Operator shall continue to operate and maintain the Facility and Ash Landfill according to the terms of this Agreement as permitted under the Annual Operating Budget then in effect. At no time, without Owner consent, shall Operator be entitled to make expenditures in any Annual Operating Budget category which exceed the amount allocated for such category; provided, however, that the foregoing limitation shall not apply in the case of Emergencies, which shall be governed by Section 3.12. ARTICLE VI PAYMENT 6.1 As the sole and exclusive compensation and reimbursement to Operator for the performance of the Contract Services Owner shall pay Operator, in the manner and at the times specified, the Reimbursable Costs, the Management Fee and the Performance Incentive, adjusted as necessary in accordance with Sections 6.3, 6.4, 6.9, and 6.10. 6.2 Reimbursable Costs. Subject to any limitations on expenditures in this Agreement, Owner shall reimburse Operator for the following costs incurred by Operator in performing the Contract Services, to the extent properly incurred by Operator pursuant to this Agreement and supported by adequate documentation (the "Reimbursable Costs"): 19

20 (a) the actual payroll cost for its personnel to the extent involved in the performance of the Contract Services, including, but not limited to, necessary overtime, plus the actual cost of associated payroll taxes, unemployment and disability insurance, worker's compensation insurance, benefits and other statutory compensation; (b) the actual cost of Materials, Equipment and Supplies and services provided by Operator or any subcontractor; (c) the actual cost of any insurance paid by Operator to provide the coverages set forth in Section 7.2, except for payments for deductibles to be paid by Operator pursuant to Section 6.4, and any claims not covered by insurance as described in Section 7.2(b). (d) the actual fees and costs necessary to obtain and maintain Permits, including fees and costs arising from any changes in Laws or Permits after the execution of this Agreement; (e) the actual cost of any Improvements approved by Owner, as incurred; (f) any other cost or expense designated as a Reimbursable Cost in this Agreement; and (g) All other costs necessary for conducting the business of the Facility and Ash Landfill. 6.3 Adjustments for Owner Provided Services. To the extent Operator obtains or utilizes any Equipment, Materials, Supplies or services of any type from Owner for its performance of the Contract Services ("Owner Provided Services"), the value of the Owner Provided Services shall be computed in accordance with procedures established in the Administrative Agreement and approved by the MPUC as set forth in Exhibit D. Owner shall have the right to set off or recoup the value of Owner Provided Services against amounts due to Operator each month for Reimbursable Costs as invoiced by Operator pursuant to Section 6.7. When Owner exercises its right to set off or recoup for the value of Owner Provided Services, Owner shall provide Operator with documentation, in reasonable detail, showing the basis for the set off or recoupment and the calculation of the amount due Owner. Any such set off or recoupment shall be without prejudice to Operator's right to contest the amount claimed by Owner or the basis for that claim. 20

21 6.4 Exclusions from Reimbursable Costs. (a) Operator shall be responsible for payment of any fines or penalties (or settlements in lieu of fines or penalties) payable to any Governmental Authority, to the extent caused by the negligent acts or omissions or willful misconduct of Operator, or Operator's failure to comply with any Law, Permit or any provision of this Agreement, and such fines or penalties shall not be considered Reimbursable Costs or otherwise result in any increase in the costs to be borne by Owner. Owner shall be responsible for the payment of any other fines or penalties (or settlements in lieu of fines or penalties) payable to any Governmental Authority as a result of the failure of the Facility or Ash Landfill to comply with applicable Laws or Permits. Operator also shall be responsible for payment of all costs and expenses (including reasonable attorneys' fees and expenses) incurred by Owner which arise from any negligent acts or omissions or willful misconduct of Operator or Operator's failure to comply with any Law, Permit or any provision of this Agreement, and Owner shall be entitled to offset or recoup such amounts in the same manner as provided in Section 6.3. (b) Owner shall not be liable for any additional costs incurred by Operator, or related fees, to the extent such costs are incurred by Operator as a result of (i) performance of Contract Services in a manner inconsistent with the Standards of Performance; (ii) Contract Services performed to remedy a problem, fault or deficiency created or aggravated by Operator's failure to conform to the Standards of Performance, or Equipment, Materials, Supplies or services procured from any other Person to remedy any such problem, fault or deficiency; or (iii) Operator's negligent acts or omissions, willful misconduct or failure to comply with any Law, Permit or any provision of this Agreement. Any such additional costs or expenses shall not be included as Reimbursable Costs. 6.5 Base Management Fee. Owner shall pay to Operator an annual Base Management Fee of two hundred fifty thousand dollars ($250,000) for each Contract Year, adjusted as set forth in Section 6.10, commencing on the Effective Date and continuing for each Contract Year thereafter. The Base Management Fee shall be earned in monthly installments of one-twelfth of the annual Base Management Fee for that Contract Year and paid along with incurred Reimbursable Costs as provided in Section 6.7. If Operator provides Contract Services at any time for only a portion of a month, the Base Management Fee shall be prorated accordingly. The Base Management Fee shall constitute full 21

22 payment for the services described in Article III, all Operator overhead and profit for the Contract Services and general and administrative costs incurred by Operator. 6.6 Performance Incentive. In addition to the Base Management Fee and Reimbursable Costs, Owner shall pay Operator a Performance Incentive, calculated independently for each Contract Year, based on Actual Pretax Income Before Management Fees of the Facility and the Ash Landfill, minus Specified Owner Return adjusted to a pretax basis, minus the Base Management Fee. The components of this calculation shall be determined as follows: (a) Actual Pretax Income Before Management Fees shall be determined as: (i) the sum of all revenues and income items other than income taxes of the Facility and the Ash Landfill, computed in accordance with generally accepted accounting principles (GAAP), minus (ii) the sum of all expenses other than income taxes of the Facility and the Ash Landfill, computed in accordance with GAAP, plus (iii) the Base Management Fee, and Performance Incentive amounts. Such amount shall exclude cumulative effect adjustments recorded as a result of implementing changes in accounting principles or methods of applying such principles, as defined by generally accepted accounting principles, attributable to periods prior to the first Contract Year for which a Performance Incentive is payable to Operator. (b) Specified Owner Return shall be calculated as the product of Average Owner Equity for the Contract Year multiplied by the Approved Utility Return. (c) Average Owner Equity shall be calculated based on the thirteen-month average of the Owner Equity invested in the Facility and the Ash Landfill for the Contract Year. The thirteen monthly Owner Equity amounts to be averaged shall be the consecutive month-end balances, as described in (d), beginning with December prior to the start of the Contract Year and ending with December of the Contract Year. (d) Subject to audit verification under Section 6.9, Owner Equity shall be presumed to be represented by the balance included in Account 20.01.03 (Division 60) of the Owner's accounting records (related to the Facility and the Ash Landfill). Owner Equity shall include the cumulative amount of Owner cash invested in the Facility and the Ash Landfill, assuming: (i) monthly distribution to the Owner of all net income earned by the Facility and Ash Landfill, computed in 22

23 accordance with GAAP; (ii) monthly distribution to the Owner of 60% of the depreciation expense and 100% of the deferred income tax expense of the Facility and Ash Landfill, such amounts computed in accordance with GAAP; (iii) reduction of monthly distributions to the Owner under (i) and (ii) for 60% of Improvements, equipment or other items to be capitalized in the property, plant and equipment accounts of the Facility and Ash Landfill, such amounts computed in accordance with GAAP; and (iv) no other equity contributions from or distributions to the Owner unless approved in writing by both Parties. (e) Approved Utility Return shall be the rate of return on common equity approved by the MPUC in the most recent general rate proceeding of the Owner for which a Final Nonappealable Order has been issued. This rate of return shall be expressed as a percentage, and will be rounded to the nearest one-hundredth of one percent. (f) If the net numerical result of the calculated Performance Incentive is less than zero for any Contract Year, the actual Performance Incentive due to the Operator from the Owner shall be zero for that year. (g) For purposes of monthly payments of the Performance Incentive during each Contract Year, an estimate of Performance Incentive amounts shall be made using revenues and expenses (as defined in paragraph 6.6(a)) included in the final Annual Operating Budget agreed to by the Operator and Owner under Sections 5.1 and 5.2. No later than the March 31 following the end of each Contract Year, estimated Performance Incentive amounts shall be trued-up to actual amounts based on actual revenues and expenses of the Facility and Ash Landfill (as defined in 6.6(a)) and the actual Owner Equity for the Contract Year. Subject to audit verification under Section 6.9, such revenues and expenses shall be presumed to be represented by the corresponding revenues and expenses recorded in the Owner's accounting records related to the Facility and the Ash Landfill. 6.7 Payments. (a) By the twentieth day following the end of each month, Operator shall present an invoice to Owner reflecting amounts due for Reimbursable Costs incurred and due for the preceding month, the monthly portions of the Base Management Fee and Performance Incentive and the appropriate adjustments. The precise format of the invoice and the required amount of documentation in support of the invoice shall be established by agreement of the Parties, but in any event shall be sufficient to accurately and completely describe the Contract Services 23

24 provided and each significant Reimbursable Cost so as to allow for meaningful review by Owner and, if necessary, MPUC, parties to the RDF Facilities Agreements, or any Government Authority. The invoice shall also state whether or not the Facility and Ash Landfill operation conformed to the applicable Annual Operating Budget during the billing period and, if not, the extent and reason for any material deviation and any related remedial action. No Reimbursable Costs shall be invoiced by Operator unless they were incurred in accordance with the applicable Annual Operating Budget, as amended, supplemented or modified. Except for costs and expenses arising from an Emergency, any cost or expense incurred or to be incurred by Operator in order to perform the Contract Services which is not contemplated or included in the Annual Operating Budget, or which exceeds the amount included for that cost or expense in the Annual Operator Budget, and which will cause an increase in the Annual Operating Budget of more than $100,000, shall be submitted to Owner separately for approval and, if approved, the Annual Operating Budget shall be amended accordingly and the increase allowed as a Reimbursable Cost. (b) Upon receipt of an invoice from Operator, Owner shall apply any setoff, recoupment or adjustments pursuant to Sections 6.3 and 6.4 or otherwise appropriate. The balance due Operator shall be due and payable within 30 days after receipt of the invoice by Owner. If the due date falls on a weekend or legal holiday, the due date shall be the next working day. (c) Owner shall make payment of bills via wire transfer of funds if requested in writing by Operator, or other similar means at Operator's sole Expense, and if the request contains adequate payment information. Owner shall be entitled to conclusively presume, without any liability whatsoever, that the payment information furnished by Operator (including name, financial institution, account numbers, payee, etc.) is accurate. In no event will Owner be required to pay any bill more than once where the invoice was first paid in accordance with Operator's instructions. 6.8 In addition to any setoff, recoupment or adjustment otherwise made by Owner, if Owner disputes the validity, reasonableness or accuracy of any invoice submitted to it for payment, it shall provide Operator an explanation of the reasons for its dispute within the time provided for payment by Section 6.6(b). If Owner disputes only part of a statement submitted to it for payment, then it shall pay to Operator the undisputed portion of such statement in 24

25 accordance with Section 6.6 and notify Operator in writing of the amount disputed in accordance with this Section. All such disputes shall be resolved pursuant to Article VIII of this Agreement. 6.9 Audit Rights. Notwithstanding the payment of any amount pursuant to Sections 6.6 and 6.7, Owner shall remain entitled at Owner's expense to conduct an audit and review of all payments made to Operator on a time and material or cost reimbursable basis, together with any supporting documentation in accordance with the provisions of Section 6.2 for a period of three (3) years from and after the close of each Contract Year. Any audit and review may be conducted by Owner or by its designee and the person conducting the audit and review shall be entitled to inspect, copy and audit any of Operator's financial books, records, accounts, and ledgers relating to the Facility, Ash Landfill or the Contract Services. Operator shall cooperate with auditors and promptly respond to any questions relating to any audit. Operator shall retain all information described above for a period of six (6) years. If, pursuant to any audit and review, it is determined that any amount previously paid by Operator within the prior three years did not constitute a due and payable item hereunder, including without limitation, a properly payable Reimbursable Cost, Operator shall repay Owner such amount immediately upon demand, with interest determined in accordance with Section 6.11, or Owner may offset or recoup such amount for any payment that subsequently may become due to Operator pursuant to this Agreement. If, pursuant to any such audit or review, it is determined that Operator is entitled to additional payment or reimbursement, Owner shall pay Operator such amount immediately upon demand, with interest in accordance with Section 6.11. 6.10 Management Fee Adjustment. If the calculation of the Performance Incentive pursuant to Section 6.6 should produce a result which is less than zero, the Owner and Operator agree that the Management Fee arrangements will be reevaluated to determine if the definitions of Performance Incentive and/or Specified Owner Return should be modified in order to provide the Owner with a reasonable return on equity invested and the Operator with fair compensation for services provided. Such modifications shall be made, in the form of an amendment to this Agreement, only if agreed to by both Parties. 6.11 Interest. Any amount owed to either Party by the other Party shall accrue interest each day from the date the amount is due until the date received at the rate equal 25

26 to the rate established by the First Bank National Association, Minneapolis, Minnesota as its prime rate plus one percent per annum, computed and compounded daily. ARTICLE VII INSURANCE 7.1 Standards. All insurance carried and maintained by Operator pursuant to this Agreement shall be with insurance companies which are authorized to transact insurance business and cover risks in the State of Minnesota and which are rated "Excellent" or better by Best's Insurance Guide and Key Ratings or other insurance companies of recognized responsibility and satisfactory to the Owner, and, to the extent applicable, the parties to the Service Agreements, Ash Management Agreement, Loan Agreement and UPA Agreement, except to the extent Operator qualifies to self-insure the required coverages. 7.2 Operator Provided Insurance. (a) Coverages - Operator shall at all times throughout the Term of this Agreement carry and maintain or cause to be maintained, at its own expense, insurance with coverage as follows: i. Worker's Compensation and Employer's Liability Coverage Operator shall maintain or cause to be maintained Worker's Compensation insurance written in accordance with statutory limits and Employer's Liability in an amount not less than $1,000,000 per occurrence and in the annual aggregate. The Employer's Liability coverage shall not contain an occupational disease exclusion. Such policy or policies shall contain an all states endorsement or stop gap endorsement and alternate employer coverage. ii. Comprehensive Automobile Liability Coverage - Operator shall maintain or cause to be maintained Comprehensive Automobile Liability insurance covering all owned, non-owned and hired vehicles used by Operator or its permissive users in connection with Contract Services. Such coverage shall be written in an amount not less than $1,000,000 per occurrence. iii. Excess (or Umbrella) Liability Coverage - Operator shall maintain Excess (or Umbrella) Liability insurance written on an occurrence basis or on an acceptable claims-made basis providing coverage for a limit 26

27 of $9,000,000 per occurrence and annual aggregate in excess of the insurance required in Sections 7(a)(ii) and 7(a)(v). iv. Subcontractor Insurance - Operator shall require all of Operator's subcontractors to obtain, maintain and keep in force during the time in which they are engaged in performing services hereunder reasonably adequate coverage in accordance with Operator's normal practice (but not less than Worker's Compensation insurance written in accordance with statutory limits and Employer's Liability, Comprehensive Automobile Liability and Commercial General Liability each with limits of not less than $1,000,000 per occurrence and in the aggregate) and furnish Owner with acceptable evidence of such insurance upon its request. v. Commercial General Liability Coverage. Commercial or Comprehensive General Liability insurance with a combined single limit of not less than $1,000,000 per occurrence and in the annual aggregate. Such coverage shall also include premises/operations, explosion, collapse and underground hazard, broad form contractual, products/completed operations, independent contractors, broad form property damage and personal injury. vi. Property and Boiler and Machinery Coverage. Property and Boiler and Machinery insurance on an "all risk" replacement cost basis with extended coverages, providing coverage for the Facility and Ash Landfill, Facility Equipment and Ash Landfill Equipment, which shall include coverage for removal of debris and shall insure the buildings, structures, boiler and machinery, equipment, facilities, fixtures and other properties constituting a part of the Facility and Ash Landfill in an amount satisfactory to Owner with a deductible of not greater than $1,000,000. (b) Deductibles. All deductibles or self-insured retentions for the coverages specified in Section 7(a) shall be the sole responsibility of Operator. (c) Endorsements. Any insurance policies provided in accordance with Section 7(a) shall be endorsed to provide that if any insurance policy is canceled for any reason whatsoever, or any substantial change is made in the coverage that affects the interest of Owner, UPA, Anoka County, Hennepin County, Sherburne County or the Tri-County Commission, the cancellation or change shall not be effective as to Owner until thirty (30) days after receipt by Owner of written notice sent by registered mail from the insurer of such cancellation or change or ten (10) days in the event of nonpayment of premiums. In 27

28 addition, any insurance provided in accordance with Sections 7(a) (ii), (iii), (iv), (v), and (vi) shall be endorsed to provide that: i. Owner, UPA, Anoka County, Sherburne County, Hennepin County and the Tri-County Commission shall be additional insureds in each case with the understanding that any obligation imposed upon Operator (including the liability to pay premiums) shall be the sole obligation of Operator and not that of Owner or the other additional insureds. ii. The insurer waives all rights of subrogation against Owner or any other additional insured and any other right to deduction due to outstanding premiums, whether by attachment or otherwise. This provision shall apply to the insurance provided under Section 7.2(a)(i) as well. iii. The insurance shall be primary without right of contribution of any other insurance carried by or on behalf of Owner, or any other additional insured with respect to its interest as such in the Facility or Ash Landfill. iv. To the extent the policies are written to cover more than one insured, all terms, conditions, insuring agreements and endorsements (other than the limits of liability) shall operate in the same manner as if there were a separate policy covering each insured. Any insurance provided in accordance with Section 7(a)(i) shall be endorsed to provide that the insurer thereunder waives all rights of subrogation against Owner and the additional insureds and any other right to deduction due to outstanding premiums, whether by attachment or otherwise. (d) On the Effective Date, and each Contract Year thereafter, the Parties shall arrange to furnish each other with an approved certificate reflecting all required insurance and copies of policies, if requested. Such certification shall be executed by each insurer or by an authorized representative of each insurer. Such certificate or notice, as the case may be, shall identify insurers, the type of insurance, the insurance limits, the policy term and shall specifically list the special provisions enumerated for such insurance required by this Article VII. 28

29 7.3 Owner Provided Insurance. (a) Owner shall carry and maintain, or cause to be maintained, throughout the Term of this Agreement, at its own expense, insurance with coverage as follows: i. Excess (or Umbrella) Liability Coverage. Owner shall maintain excess (or Umbrella) Liability Insurance providing coverage for a limit of $9,000,000 per occurrence and in the annual aggregate in excess of any Commercial General Liability insurance carried by Owner. ii. Worker's Compensation and Employer's Liability Coverage Owner shall maintain or cause to be maintained Worker's Compensation insurance written in accordance with statutory limits and Employer's Liability in an amount not less than $1,000,000 per occurrence and in the annual aggregate. The Employer's Liability coverage shall not contain an occupational disease exclusion. Such policy or policies shall contain an all states endorsement or stop gap endorsement and alternate employer coverage. iii. Comprehensive Automobile Liability Coverage - Owner shall maintain or cause to be maintained Comprehensive Automobile Liability insurance covering all owned, non-owned and hired vehicles used by Owner or its permissive users in connection with Contract Services. Such coverage shall be written in an amount not less than $1,000,000 per occurrence. (b) Deductibles. All deductibles for the coverages specified in Section 7.3.(a), (i), (ii), and (iii) shall be the sole responsibility of Owner, except that Operator shall be responsible for such deductibles to the extent the claim arises out the negligence or willful misconduct of Operator, or Operator's breach of this Agreement, in the performance of the Contract Services not to exceed $100,000 per occurrence pursuant to Section 7.3(a) (i) or $200,000 per occurrence pursuant to Section 7.3 (a)(ii) and (iii). Any such deductible or self-insured retention paid by Operator shall not be deemed to be a Reimbursable Cost hereunder. (c) Endorsements. Any insurance provided in accordance with Section 7.3(a) shall be endorsed to provide that Operator shall be an insured for losses occurring at the Facility or Ash Landfill with the understanding that, except as expressly provided in Section 7.3(b), any 29

30 obligation imposed upon Owner (including the liability to pay premiums) shall be the sole obligation of Owner and not that of Operator. To the extent policies are written to cover more than one insured, all terms, conditions, insuring agreements and endorsements (other than the limits of liability) shall operate in the same manner as if there were a separate policy covering each insured. 7.4 Optional Insurance Responsibilities. If requested by Owner in writing, Operator shall assist Owner in obtaining for its own account the insurance Owner is required to maintain pursuant to Section 7.3(a) subject to Owner reimbursing Operator for its reasonable costs incurred in providing such assistance. ARTICLE VIII DISPUTE RESOLUTION 8.1 Arbitration and Mediation Standards. (a) Any controversy or claim arising out of or relating to the Agreement, or the breach thereof, shall be subject to resolution by mediation or binding arbitration as set forth in this Article VIII. (b) Prior to initiation of mediation and arbitration, the Owner Representative and Operator Representative designated under Article 16.3 or other persons designated by the Parties shall meet for the purposes of discussing and resolving the controversy or claim. If the dispute is not resolved within 30 days, the Parties agree to submit the dispute to mediation in accordance with the commercial mediation rules of the American Arbitration Association, or other mediation procedures agreed to by the Parties, before proceeding to arbitration. The Parties agree to each pay one-half the costs of the mediation. 8.2 Mediation Procedure. (a) The Parties shall have ten days to agree upon a mutually acceptable and neutral mediator and, if the parties cannot so agree, they shall jointly request the American Arbitration Association or other agreed mediation service to propose potential mediators and to assist in the selection of a disinterested mediator. 30

31 (b) The Parties shall, with the mediator, devise procedures appropriate for negotiating a resolution of the dispute(s). The Parties agree to participate in good faith in the mediation and related negotiations, and to expeditiously exchange information and documents necessary for the fair and full discussion of the dispute(s). (c) The mediator shall be disqualified as a witness, consultant, expert, or counsel for either party with respect to the dispute(s) and any related matters. The Parties agree that the mediator shall not be liable to either party for any statement, action or omission related to the mediation. The mediator shall keep confidential all information disclosed in private discussions with either Party when that Party has requested that the information be kept confidential. (d) The Parties agree that the mediation procedure is a compromise negotiation for purposes of the Federal Rules of Evidence and any State rules of evidence. The entire procedure is confidential, and no stenographic, visual or audio record shall be made. All conduct, statements, promises, offers, views and opinions, whether oral or written, made in the course of the mediation by either of the Parties, their agents, employees, representatives or other invitees and by the mediator (who will be the Parties' joint agent for purposes of these compromise negotiations) are confidential and shall, in addition and where appropriate, be deemed to be work product and privileged. Such conduct, statements, promises, offers, views and opinions shall not be discoverable or admissible for any purposes, including impeachment, in any litigation or other proceeding involving the Parties, and shall not be disclosed to anyone not an agent, employee, expert, witness, or representative of either of the Parties; provided, however, that evidence otherwise discoverable or admissible is not excluded from discovery or admission as a result of its use in the mediation. (e) The Parties agree to participate in the mediation for a period of 30 days, which period may be extended by agreement. If the Parties are not successful in resolving the dispute(s) through mediation, then they agree to submit the unresolved dispute(s) or portions thereof to binding arbitration as provided in Section 8.3. 31

32 8.3 Arbitration Procedure. All disputes arising between the Parties which relate to the validity, interpretation or performance of this Agreement, and which are not successfully resolved by the Parties or through the mediation process prescribed in Article 8.2, shall be submitted to arbitration at the request of either party to the dispute, in accordance with the Commercial Arbitration Rules of the American Arbitration Association then in effect, and with the following provisions. (a) The demand for arbitration shall be filed in writing with the other party to this Agreement and with the Minneapolis, Minnesota office of the American Arbitration Association within ten days of the conclusion of mediation. No arbitration initiated by the Parties shall include by consolidation, joinder or in any other manner, any other person unless such person and both Parties agree to the inclusion and unless such person is substantially involved in a common question of law or fact or its presence is required if complete relief is to be accorded in the arbitration. This agreement to arbitrate between the Parties, and any fully executed subsequent agreement to arbitrate with a third party, shall be specifically enforceable under the Minnesota or federal arbitration act, whichever is applicable. (b) If the dispute(s) submitted to arbitration is identified as involving claims whose total value exceeds $250,000, the Parties shall be entitled to utilize the discovery provisions contained in Minnesota Rules of Civil Procedure 26-37 and 45 with the following exceptions: (1) Each party shall be limited to three depositions unless approval of the arbitrator(s) is obtained for additional depositions, which approval shall only be granted upon a showing of good cause; (2) Each party shall be restricted to no more than 25 interrogatories, with subparts counted as separate interrogatories. (3) All discovery issues shall be determined by order of the arbitrators upon motion made to them by either Party. When a Party is asked to reveal material which the Party considers to be proprietary information or trade secrets, the Party shall bring the matter to the attention of the arbitrators who shall make such protective orders as are reasonable and necessary or as are otherwise provided by law. 32

33 (c) The arbitrators shall have jurisdiction and authority to interpret, apply, or determine compliance with the provisions of this Agreement insofar as shall be necessary to the determination of issues properly before the arbitrators. In making the decision, the arbitrators shall issue appropriate findings and conclusions regarding the issues. The arbitrators shall not have jurisdiction or authority to alter the provisions of this Agreement or any applicable law or rule of civil procedure. The arbitrators shall have the authority to require either Party to specifically perform its obligations under this Agreement. The arbitrators shall render a decision within sixty (60) days after the completion of the hearing on the matter. (d) The arbitration shall be closed to observation or monitoring by third parties. (e) The award rendered by the arbitrator(s) shall be final and judgment may be entered upon it in accordance with applicable law in any court having jurisdiction. Any decision (including orders arising out of disputes as to the scope or appropriateness of a request for, or a response to, discovery) of the arbitrators may be enforced in state or federal district court, whichever is applicable, with all costs, including attorneys fees, paid by the losing Party. Nothing in Article VIII shall prohibit a Party from instituting litigation to enforce a final decision of the arbitrators. (f) The administrative expense of any arbitration, including compensation for the arbitrator(s), shall be borne and paid equally by the Parties unless the arbitrator(s) finds that the position taken by either Party on any issue is not substantially justified, in which case all or part of the costs and fees of the Party prevailing on that issue shall be awarded to it. Except as provided herein, each Party shall bear its own costs and fees. (g) All arbitration proceedings under this Article 8 shall take place in Minneapolis, Minnesota at a location agreed upon by the Parties and, in the event of failure to agree, the arbitrators shall determine the most convenient location based on the location of the majority of the documentary evidence and prospective witnesses. (h) Pending the final decision of the arbitrators, the Parties agree to diligently proceed with the performance of all obligations, including the payment of all sums, required by this Agreement. To the extent practicable and consistent with all Laws and Permits, RDF Facility Agreements and Loan Agreement the interpretation or decision of the 33

34 nonaggrieved party shall take precedence until the dispute is resolved, but shall not relieve the nonaggrieved Party from any liability resulting from such interpretation or decision to the extent it is ultimately determined to be wrong by the arbitrators. (i) Nothing in this Article VIII shall preclude a Party from seeking specific performance of this Agreement or similar injunctive relief in state or federal court if the Party seeking such equitable relief would otherwise be irreparably harmed by the passage of time involved for the completion of the mediation and arbitration processes set forth in this Article. Any judicial decree or order granting such specific performance shall be effective only to the extent and for the time period necessary to prevent the irreparable harm specifically found by the court. Final resolution of any underlying dispute, or related issues, shall still occur pursuant to the provisions of this Article VIII. 8.4 Compromise and Settlement. (a) Except as may be necessary for (i) any review by the MPUC, FERC, or other Governmental Authority; or (ii) any enforcement proceeding under Section 8.3(e), no communications sent or documents delivered by either Party because of a proceeding under Article VIII shall be disclosed by the other Party to a third person if that communication or document contains the caption "Privileged and Confidential; Settlement Proceedings" or similar caption. (b) Except as may be necessary for (i) any review by the MPUC, FERC or other rate regulatory agency of any matter determined to be within its exclusive jurisdiction; or (ii) any enforcement proceeding, the arbitrators' decision shall be deemed to be a settlement between the Parties and the decision shall be treated as a settlement for all purposes in the future. 8.5 Effect of Termination. This Article VIII shall survive the termination of the Agreement as necessary to resolve any disputes arising out of, in connection with, or relating to the Agreement. 34

35 ARTICLE IX TERM 9.1 Effective Date. This Agreement shall not become effective until the Effective Date, which shall be the first day after all conditions precedent identified in this Section 9.1 have been fully and satisfactorily performed and satisfied: (a) The Agreement has been executed by authorized representatives of Owner and Operator. (b) Any consent to this Agreement which is required from a party to any RDF Facility Agreement, the Loan Agreement, or the UPA Agreement has been received in writing by Owner in a form executed by an authorized representative of the party. Operator and Owner are not aware of any such necessary consent at this time. (c) The MPUC approves the Agreement in a Final Nonappealable Order, pursuant to Minnesota Statutes Chapter 216B, in which the MPUC finds that the amounts to be paid to Seller under the Agreement are reasonable and in the public interest. In the event NSP is unable to obtain a Final Nonappealable Order of the MPUC specifically approving the Agreement without significant modification to the Agreement by the MPUC, the Agreement shall terminate unless NSP and Seller mutually agree in writing to accept the modification. 9.2 Term. This Agreement shall remain in full force and effect until December 31, 2003, or until the expiration or termination of all of the RDF Facility Agreements and UPA Agreement, whichever is earlier. 9.3 Options to Extend. Owner shall have the option to extend the term of this Agreement for up to two additional three (3) year terms. To exercise its options, Owner shall provide written notice to Operator of its intent to exercise the option no later than 180 days prior to the expiration of the Term. 35

36 9.4 Services Prior to Effective Date. Services provided by Operator since the Commencement Date and prior to January 1, 1996 shall be paid for and performed in accordance with the Administrative Agreement, including appropriate compensation or offsets for Owner Provided Services. To the extent practicable and approved by the MPUC the Parties shall begin performance of this Agreement as of January 1, 1996 and the First Contract Year shall be deemed to be calendar year 1996. If the MPUC fails to approve this Agreement, including the provisions for Operator's fees, for any portion of the period between January 1, 1996 and the Effective Date, Operator shall be entitled only to reimbursement as allowed by the Administrative Agreement and the MPUC. 9.5 Termination. This Agreement may be terminated only by mutual written agreement of the Parties, pursuant to the default provisions of Article XV, or under the following circumstances: (a) Upon damage to, or destruction of, a substantial portion of the Facility or Ash Landfill, which cannot reasonably be expected to be repaired or rebuilt within one calendar year; (b) if the Effective Date does not occur within six months of the date this Agreement is executed. 9.6 Termination Procedure. (a) Upon the effective date of termination of this Agreement authorized under Section 9.5, the Operator shall (i) discontinue performance of the Contract Services, (ii) place no further orders or subcontracts for Materials, Equipment, Supplies, services, or labor, except as authorized in advance by Owner or required of Operator to avoid giving rise to an Event of Default under this Agreement, (iii) make every reasonable effort to obtain cancellation of affected subcontracts or, at Owner's request, cause the assignment of any such contracts to Owner or its replacement operator upon terms satisfactory to Owner, and (iv) take such other action as may be reasonably requested by Owner for the orderly closeout and transition of Operator's operation and maintenance activities, including cooperation with any replacement operator. After deduction of any amounts owed by Operator to Owner, upon termination pursuant to this Article, Owner shall pay, or cause to be paid, to Operator (A) the amount, if any due and payable to Operator pursuant to this Agreement up to and including the date of 36

37 termination, and (B) except in the case of a termination of Operator pursuant to Article X, all reasonable documented costs incurred by Operator for its own efforts to implement termination and the resulting reasonable costs actually incurred for turnover and demobilization, excluding any loss of anticipated profit. Such payments to Operator shall not duplicate any other payments hereunder made to Operator. Operator and Owner shall use reasonable efforts to minimize all termination costs. (b) Other than as set forth in this Section 9.6, Owner shall have no liability to Operator for costs, expenses or losses of any kind or nature incurred by Operator as a result of such termination. In no event shall the aggregate payments of Owner hereunder exceed the amount due for the then-current Contract Year, pro-rated for any partial Contract Year. Within sixty (60) Days following the effective date of termination, Operator shall submit to Owner its final invoice statement which Owner shall review and make payments on in accordance with the provisions of Article VI. Upon Operator's receipt of final payment in full from Owners, this Agreement shall terminate and neither Party shall have any further obligation to the other Party except with respect to those provisions of this Agreement which by their terms survive. ARTICLE X INDEMNIFICATION 10.1 Indemnity. Operator and Owner agree to defend, indemnify, and hold each other, and their respective officers, directors, employees, and agents, harmless from and against all claims, demands, losses, liabilities, and expenses (including reasonable attorneys' fees) (collectively "Damages") for personal injury or death to persons and damage to each other's physical property or facilities or the property of any other person or corporation to the extent arising out of, resulting from, or caused by the negligent or intentional acts, errors, or omissions of the indemnifying Party. Furthermore, each Party shall defend, indemnify, and hold the other harmless from and against all damages that are or were incurred or suffered by the indemnified Party and which relate to the indemnifying Party's breach or failure to perform any of the covenants, agreements, obligations, representations, or warranties contained in the Agreement, except as provided in Section 10.2. Nothing in this section shall relieve Operator or Owner of any liability to the other for any breach of the Agreement. This indemnification shall apply notwithstanding the active or passive negligence of the indemnitee. Neither Party shall be indemnified to 37

38 the extent its Damages result from its sole negligence or willful misconduct. These indemnity provisions shall not be construed to relieve any insurer of its obligation to pay claims consistent with the provisions of a valid insurance policy. 10.2 Limitation of Liability. (a) For all claims, causes of action and damages the Parties shall be entitled to the recovery of actual damages allowed by law unless otherwise limited by the Agreement. (b) Except as otherwise specifically and expressly provided in the Agreement, no Party shall be liable to the other Party under the Agreement for any indirect, special, or consequential damages, including but not limited to, loss of use, loss of revenue, loss of profit, interest charges, cost of capital, or claims of its customers to which service is made from any cause, except to the extent such damages are covered under an insurance policy for the benefit of the liable Party. Notwithstanding the foregoing, the arbitrators under Article VIII can award consequential damages against a Party which willfully violates its obligations under the Agreement with knowledge that the other Party is suffering consequential damages if the arbitrators determine that such an award appears necessary to prevent repetition of such willful misconduct. In no event shall one Party's liability to the other exceed any limit of liability established for either Party under any Requirement of law. (c) Notwithstanding the limitation set forth in Section 10.2(b), Operator shall be liable for all damages, including, but not limited to, loss of use, loss of revenue, loss of profit, and other indirect, special or consequential damages suffered or incurred by Owner, directly or through claims or causes of actions by others, arising from or relating to the occurrence of any breach, event of default, or failure to comply with the terms of any RDF Facility Agreement, UPA Agreement or Loan Agreement to the extent caused by Operator's negligent acts or omissions, willful misconduct, or breach of this Agreement. 10.3 Survival. The indemnity obligation of Section 10.1 and any other indemnity obligation provided under this Agreement shall survive the expiration of the term or termination of this Agreement for any reason and shall remain in full force and effect. All waivers and disclaimers of liability, releases from liability and limitations on liability shall also survive the expiration of the Term or 38

39 termination of the Agreement and shall apply at all times unless otherwise expressly indicated. 10.4 Notice of Litigation. If any Party indemnified pursuant to this Article X or otherwise under this Agreement (each an "Indemnified Party" and collectively the "Indemnified Parties") receives notice or acquires knowledge of any claim that may reasonably result in a claim for indemnification by such Indemnified Party against the other Party (the "Indemnifying Party") pursuant to this Article X or otherwise, the Indemnified Party shall, as promptly as possible, give the Indemnifying Party notice of such claim, including a reasonably detailed description of the facts and circumstances relating to such claim, and a complete copy of all notices, pleadings and other papers related thereto, and the basis for its potential claim for indemnification in reasonable detail and shall cooperate with the Indemnifying Party in responding to the claim. Subject to the limitations on the Indemnifying Party's indemnity obligations, the Indemnifying Party shall assume on behalf of the Indemnified Party, and conduct with due diligence and good faith the defense of, any suit against one or more of the Indemnified Parties, whether or not the Indemnifying Party is joined as a party. Without relieving the Indemnifying Party of its obligations and subject to the Indemnifying Party's control over the defense and settlement of any suit, the Indemnified Party may elect to participate in the defense of any suit, at its own expense. The Indemnifying Parties' indemnity is for the exclusive benefit of the Indemnified Parties and their assignees and in no event shall inure to the benefit of any other Person. 10.5 Cost Treatment. Any amounts paid by Operator to Owner or otherwise arising from or related to any indemnified claim pursuant to Section 10.1 or other indemnity obligations of this Agreement shall not be Reimbursable Costs and shall be paid at Operator's sole cost and expense. 10.6 Limitation of Liability. With the exception of liabilities arising from Operator's indemnity and similar obligations pursuant to Section 10.1, 3.17, 6.4, 6.8, 11.4 and 13.3, and the payment of deductibles for coverage provided under Section 7.2(b) which are expressly not governed by this Section, Operator's aggregate liability to Owner with respect to any and all claims arising out of the performance or nonperformance of its obligations under this Agreement, whether based in 39

40 contract, tort, warranty or otherwise shall not exceed, net of all insurance proceeds applied to each such liability or related claim: (i) For all claims arising and for which damages accrue solely within one Contract Year, the amount of $1,000,000 or the total of the Management Fee and Performance Bonus due to Operator for that Contract Year, whichever is less. (ii) for all claims made or for which damages accrue on a continuing basis or over more than one Contract Year, the amount of $3,000,000 multiplied by the number of Contract Years or the total of the Management Fee and Performance Bonus due to Operator for the affected Contract Year, less any amounts paid pursuant to the preceding subparagraph (i) for each of the Contract Years whichever is less. ARTICLE XI REPRESENTATIONS AND WARRANTIES 11.1 Representations by Operator. Operator represents and warrants to Owner: (a) (i) Operator is duly organized, validly existing and in good standing under the laws of the jurisdiction of its formation; (ii) has the power and authority to own and operate its business and property, to own or lease the property it occupies and to conduct the business in which it is currently engaged; (iii) is duly qualified as a corporation in Delaware and is in good standing under the laws of Minnesota and each jurisdiction where its ownership, lease or operation of property or the conduct of its business requires such qualification and the failure to be so qualified would have a material adverse affect on the business, operations, financial condition or prospects of Operator; (iv) is in compliance with all material Requirements of Law, applicable to Operator or its operations; and (v) is in compliance with all material Contractual Obligations applicable to Operator or its operations. 40

41 (b) The execution, delivery, performance and observance by Operator of its obligations under the Agreement is within Operator's powers, have been duly authorized by all necessary corporate action and do not and will not: (i) require any consent or approval of the shareholders of Operator which has not been obtained; (ii) contravene, conflict or violate any provision of any Requirement of Law presently in effect having applicability to Operator; (iii) require the consent or approval of or filing or registration with any Governmental Authority or other Person which is not specified as a condition precedent to the Agreement; (iv) result in a breach of or constitute a default under any Contractual Obligation. (c) The Agreement is a legal, valid and binding obligation of Operator, is enforceable against Operator in accordance with its respective terms except as enforceability may be limited by applicable bankruptcy, insolvency, reorganization or similar laws affecting the enforcement of creditors' rights generally. (d) No litigation, arbitration, investigation or other proceeding is pending or threatened against Operator, except as listed on Exhibit E, (i) with respect to the Agreement or the transaction contemplated thereby, the Facility, Ash Landfill, RDF Facility Agreements, UPA Agreement or Loan Agreement; or (ii) which would, if adversely determined, have a material adverse effect on the business, operations, property or financial or other condition of Operator taken as a whole, or the ability of Operator to perform its obligations under the Agreement. (e) To the best of Operator's knowledge and belief, no exhibit, contract, report or document furnished by Operator to Owner in connection with the negotiation or execution of the Agreement contains any material misstatement of fact or omits to state a material fact or any fact necessary to make the statements contained therein not misleading. 41

42 (f) To the best of Operator's knowledge and belief, all Permits required by any Governmental Authority for the operation and maintenance of the Facility and Ash Landfill have been obtained and are valid and in full force and effect. The Facility and Ash Landfill are in compliance with each Permit as of the date of this Agreement, and Operator has received no notice and is not otherwise aware of any default, violation or potential default or violation of any such Permit. (g) Operator has filed or caused to be filed all tax returns which were required to be filed and has paid all taxes shown to be due and payable on said returns or on any assessments made against it or any of its property and all other taxes, fees or other charges imposed on it or any of its property by any Governmental Authority; and no tax liens have been filed and no claims are being asserted with respect to any such taxes, fees or other charges. (h) The Facility and Ash Landfill have been and are currently operated in full compliance with all Environmental Laws and operated in full compliance with all Permits, licenses, rules or orders promulgated, issued or otherwise required by a Governmental Authority having jurisdiction or enforcement power over any Environmental Law. Operator has no knowledge of and has not received notice of any past, present or future actions or plans which, with respect to the Facility or Ash Landfill, may interfere with or prevent compliance or continued compliance with Environmental Laws or may give rise to any liability under any Environmental Law or to any common law or legal liability or otherwise form the basis of any claim, action, demand, suit, proceeding, hearing, study or investigation under the Environmental Laws and there is no civil, criminal or administration action, suit, demand, claim, hearing notice or demand letter, notice of violation, investigation or proceeding pending or threatened against Operator relating to the compliance with any Environmental Law of the Facility or Ash Landfill. (i) Operator intends to operate and maintain the Facility and Ash Landfill in accordance with the Standards of Performance, applicable Laws and Permits, the RDF Facility Agreements, Loan Agreement, and the terms of this Agreement. (j) No Event of Default or Potential Event of Default exists hereunder. 11.2 Owner's Representations. Owner represents and warrants to Operator: 42

43 (a) (i) Owner is duly organized, validly existing and in good standing under the laws of the jurisdiction of its formation; (ii) has the power and authority to own and operate its business and property, to own or lease the property it occupies and to conduct the business in which it is currently engaged; (iii) is duly qualified as a corporation in Minnesota and is in good standing under the laws of each jurisdiction where its ownership, lease or operation of property or the conduct of its business requires such qualification and the failure to be so qualified would have a material adverse affect on the business, operations, financial condition or prospects of Owner; (iv) is in compliance with all material Requirements of Law, applicable to Owner or its operations; and (v) is in compliance with all material Contractual Obligations applicable to Owner or its operations. (b) The execution, delivery, performance and observance by Owner of its obligations under the Agreement is within Owner's powers, have been duly authorized by all necessary corporate action and do not and will not: (i) require any consent or approval of the shareholders of Owner which has not been obtained; (ii) contravene, conflict or violate any provision of any Requirements of Law presently in effect having applicability to Owner; (iii) require the consent or approval of or filing or registration with any Governmental Authority or other Person which is not specified as a condition precedent to the Agreement; (iv) result in a breach of or constitute a default under any Contractual Obligation. (c) The Agreement is a legal, valid and binding obligation of Owner, is enforceable against Owner in accordance with its respective terms except as enforceability may be limited by applicable bankruptcy, 43

44 insolvency, reorganization or similar laws affecting the enforcement of creditors' rights generally. (d) No litigation, arbitration, investigation or other proceeding is pending or threatened against Owner, except as listed on Exhibit E. (i) with respect to the Agreement or the transaction contemplated thereby, the Facility, Ash Landfill, RDF Facility Agreements, UPA Agreement or Loan Agreement; or (ii) which would, if adversely determined, have a material adverse effect on the business, operations, property or financial or other condition of Owner taken as a whole, or the ability of Owner to perform its obligations under the Agreement. (e) To the best of Owner's knowledge and belief, no exhibit, contract, report or document furnished by Owner to Operator in connection with the negotiation or execution of the Agreement contains any material misstatement of fact or omits to state a material fact or any fact necessary to make the statements contained therein not misleading. (f) Prior to the Commencement date, the Facility and Ash Landfill were operated in full compliance with all Environmental Laws and operated in full compliance with all Permits, licenses, rules or orders promulgated, issued or otherwise required by a Governmental Authority having jurisdiction or enforcement power over any Environmental Law. Owner has no knowledge of and has not received notice of any past, present or future actions or plans which, with respect to the Facility or Ash Landfill, may interfere with or prevent compliance or continued compliance with Environmental Laws or may give rise to any liability under any Environmental Law or to any common law or legal liability or otherwise form the basis of any claim, action, demand, suit, proceeding, hearing, study or investigation under any Environmental Law and there is no civil, criminal or administration action, suit, demand, claim, hearing notice or demand letter, notice of violation, investigation or proceeding pending or threatened against Owner relating to the compliance with any Environmental Law of the Facility or Ash Landfill. 11.3 Owner's and Operator's Reliance. Operator agrees and acknowledges that Owner is relying on and will continue to rely on Operator's representations and warranties and, that such reliance 44

45 is reasonable, and that Owner will rely on such representations in its filings and presentations to the MPUC in connection with this Agreement. Owner agrees and acknowledges that Operator is relying on and will continue to rely on Owner's representations and warranties and that such reliance is reasonable. 11.4 Indemnity If at any time during the Term of the Agreement any of the representations and warranties made by either of the Parties are or become untrue, then the Party which made the representation or warranty agrees to indemnify and hold harmless the other Party against any and all claims, demands, suits, actions, costs, and liabilities, damages, losses or judgments arising out of, relating to or resulting from any such untrue representation or warranty, as well as against any fees, costs, charges, or expenses (including attorneys' fees) which the other Party might incur in the defense of any such claim, suit, action or similar such demand made or filed which may adversely affect the other Party as a consequence of the untrue representation or warranty. ARTICLE XII FORCE MAJEURE 12.1 Force Majeure. Neither Operator nor Owner shall be liable to the other for any failure to perform pursuant to the terms and conditions of this Agreement to the extent such performance was prevented by an event of Force Majeure. Force Majeure as used in this Agreement means any event beyond the reasonable control of the Party affected and which, with the exercise of due care, the Party could not reasonably have been expected to avoid, including, but not limited to, acts of God, explosions or fires, floods, hurricanes, tornadoes, lightning, earthquakes, drought, epidemics, blight, famine, quarantine, blockade, acts or inactions of Governmental Authorities, war, insurrection or civil strife, rebellion, sabotage or strike. To be excused from performance pursuant to this provision, however, the Party affected must (i) give notice to the other Party, including full details of the event of Force Majeure and its creation of an inability to perform, as soon as practicable after the occurrence relied upon and (ii) exercise due diligence to remove its inability to perform with all reasonable speed and using all reasonable measures. The burden of proof to establish the existence of an event of Force Majeure and any resulting inability to perform on its part shall be on the Party seeking an excuse from performance due to Force Majeure. 45

46 12.2 Exclusions from Definition of Force Majeure. Notwithstanding anything in the Agreement to the contrary, "Force Majeure" shall not mean: (a) Inclement weather affecting operation or maintenance of the Facility or Ash Landfill. (b) Changes in market conditions, governmental action, or weather conditions that affect the cost of Operator's Contract Services, Equipment, Materials, or Supplies. (c) Unavailability of equipment, repairs or spare parts for the Facility, Facility Equipment, Ash Landfill or Ash Landfill Equipment, except where due to a strike against a third person which was not reasonably foreseeable, and the consequences of which could not be avoided by due care and planning. (d) Inability to obtain, maintain or renew any Permit or any delay in obtaining, maintaining, or renewing any Permit for any reason within the control of the Party. (e) Litigation or administrative or judicial action pertaining to the Agreement, to the RDF Facilities, the acquisition, maintenance or renewal of financing or any Permits, or the maintenance or operation of the RDF Facilities. (f) Any event to the extent caused by the negligence, willful misconduct or breach of this Agreement by the Party claiming Force Majeure. (g) Any event to the extent it could have been prevented by reasonable diligence or was otherwise within the control of the Party claiming Force Majeure. (h) Any breakdown or failure of any mechanical or other component of the Facility, Ash Landfill, Facility Equipment or Ash Landfill Equipment which fully or partially curtails operations to the extent caused by the design or construction of the component or the failure to properly operate and maintain the component, irrespective of whether the failure is attributable to the negligence or fault of the Party asserting Force Majeure. 46

47 (i) Failure to perform by any subcontractor, vendor, manufacturer, supplier, provider or other third party unless the failure is also caused by a qualifying event of Force Majeure as defined in this Agreement. In this respect, the compliance of any Person contracting with Operator or Owner with the terms of the applicable contract, purchase order or other agreement shall be deemed to be within the control of Owner or Operator, as applicable. ARTICLE XIII HAZARDOUS MATERIALS 13.1 Environmental Laws. Any terms mentioned in the following subsections which are defined in state local, or federal environmental statutes and/or regulations promulgated in relation thereto shall have the meaning subscribed to such terms in said statutes and regulations. These state, local and federal environmental statutes, rules and regulations include, without limitation, (1) the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), 42 U.S.C. Sections 9601-9657; (2) the 1986 Superfund Amendments and Reauthorization Act (SARA), codified as a part of 41 U.S.C. Section 9601 et seq.; (3) the Minnesota Environmental Response and Liability Act (MERLA), Minn. Stat. Sections 115B.01-115B.17; (4) the Resource Conservation and Recovery Act (RCRA), 42 U.S.C. Sections 6901-6987; (5) legislation and regulations governing underground storage tanks (UST), including applicable federal laws and the Minnesota Petroleum Tank Release Clean-Up Act, Minn. Stat. Sections 115C.01-115C.10; and (6) state and federal laws creating any liens for clean-up costs, including applicable provisions of SARA and comparable Minnesota laws, Minn. Stat. Sections 514.671-514.676; (7) Groundwater Protection Act, Minn. Stat. Sections 103H.001-103H.280; (8) the Clean Air Act, 42 U.S.C. Sections 7401 et seq.; (9) the federal Clean Water Act, 33 U.S.C. Sections 1321 et seq.; (10) the Hazardous Materials Transportation Act, 49 U.S.C. Sections 1802 et seq.; (11) the Toxic Substances Control Act, 15 U.S.C. Sections 2601 et seq.; (12) the federal Water Pollution Control Act, 15 U.S.C. Sections 2601 et seq.; and (13) any federal, state, county, municipal, local or other statute, law, ordinance or regulation enforcing, governing or related to the creation, handling, release, containment, transport or disposal of any pollutant, contaminant, hazardous or unhealthy substance or to human health or the environment; and any regulations interpreting, applying or complementing each of the statutes described in clauses (1) through (13). These statutes, rules and regulations, as amended from time to time, are referred to collectively as the "Environmental Laws." 47

48 The term "release" shall have the meaning specified in CERCLA and MERLA, and the terms "solid waste" and "disposal" (or "disposed") shall have the meanings specified in RCRA; provided, in the event CERCLA, SARA, RCRA, MERLA or MPTRCA is amended so as to broaden the meaning of any term defined thereby, such broader meaning shall apply subsequent to the effective date of such amendment. "Hazardous Materials" means asbestos, ureaformaldehyde, polychlorinated biphenyls ("PCBs"), nuclear fuel or material, chemical waste, radioactive material, explosives, known carcinogens, petroleum products and by-products and other dangerous, toxic or hazardous pollutants, contaminants, chemicals, materials or substances listed or identified in, or regulated by, any Environmental Laws. 13.2 Owner's Indemnity. Owner agrees to indemnify, defend and hold Operator harmless from and against any claim, suit, loss, cost, liability, fine or damage (including reasonable attorneys' fees) arising from or assessed or incurred as a result of any release or other violation of any Environmental Law based on conditions existing at the Facility Site or Ash Landfill Site or created prior to the Commencement Date, made or asserted by any Person, and whether or not supported by fact or law. 13.3 Operator's Indemnity. Operator agrees to indemnify, defend and hold Owner harmless from and against any claim, suit, loss, cost, liability, fine or damage (including reasonable attorneys' fees) arising from or assessed or incurred as a result of any release or other violation of any Environmental Law based on releases or other conditions occurring or created at the Facility Site or Ash Landfill Site after the Commencement Date, including, but not limited to, any negligent or culpable handling of Hazardous Materials in the course of performing the Contract Services, made or asserted by any Person, and whether or not supported by fact or law. 13.4 Hazardous Wastes. Operator shall arrange for the proper collection, removal, transportation, and disposal of any Hazardous Materials furnished, used, applied, generated or stored at the RDF Facilities or emanating from the RDF Facilities including, but not limited to, used oils, greases, and solvents from flushing and cleaning processes performed under this Agreement. All costs associated with the transportation and disposal of Hazardous Materials to or from the RDF Facilities by Operator in connection with its performance of the Contract 48

49 Services pursuant to the terms of this Agreement shall be a Reimbursable Cost. Operator shall comply with all applicable Laws and Permits in collecting, handling, removing, transporting or disposing of any Hazardous Materials, and shall be responsible for determining whether any material or substance is a Hazardous Materials and for interpreting and applying any Environmental Law. ARTICLE XIV DEFAULT 14.1 Events of Default. The following occurrences or events, or any of them, by or against either Operator or Owner, shall constitute an Event of Default under this Agreement. (a) A material breach of any of the terms, conditions, warranties, covenants, or representations expressed in this Agreement; or (b) the filing of a petition commencing a voluntary case under the Federal Bankruptcy Code or for liquidation, reorganization or any similar arrangement under federal or state law relating to bankruptcy, insolvency, winding up or adjustment of debts; or (c) the admission in writing of its insolvency or inability to pay its debts generally as they become due or the acquiescence in or consent to any involuntary case commenced as described in Section 15.1(d) or the declaration of such Party as bankrupt or insolvent under the Federal Bankruptcy code or any other federal or state law relating to bankruptcy, insolvency, winding up or adjustment of debts; or (d) the filing of a petition against it commencing an involuntary case under the Federal Bankruptcy Code or proposing the adjudication of such Party as a debtor or bankrupt or proposing its liquidation or reorganization pursuant to any federal or state law relating to bankruptcy, insolvency, winding up or adjustment of debts; or (e) the dissolution of any Party or failure to maintain such Party's good standing or qualification to do business in the State of Minnesota or state of organization; or (f) an assignment for the benefit of creditors. 49

50 (g) with respect to the Operator, an Event of Default occurs under any of RDF Facility Agreements or Loan Agreement due to the negligent or intentional acts or omissions of the Operator or Operator's breach of this Agreement. 14.2 Notice of Event of Default and Cure Rights. (a) For any Event of Default arising under Sections 15.1(a) and (e), the right of termination granted under Section 15.3 shall be subject to a written notice of the Event of Default. Unless the nature of the default requires more immediate action to cure, which shall be set forth in the notice, the defaulting Party shall be provided thirty (30) calendar days from the date of receipt of the notice to cure the Event of Default. Failure to cure the default within this thirty (30) day period shall constitute a material breach of the Agreement granting to the nondefaulting Party the right to terminate the Agreement pursuant to Section 15.3. (b) For any Event of Default described by Sections 15.1(b), (c), (d) and (f), notice of default shall not be required and termination may be effected in accordance with Section 15.3 by the nondefaulting Party to the extent permitted by applicable law. (c) For any Event of Default by Operator pursuant to Section 15.1(g), Owner shall immediately provide written notice to Operator of the Event of Default, along with a copy of any notice of default received by Owner with respect to the underlying agreement in default or a description of the default in reasonable detail. Operator shall have the balance of any cure period provided to Owner under the agreement in default to cure the underlying default. If Operator fails to cure the underlying default within the available cure period, Owner shall have the right to terminate this Agreement pursuant to Section 15.3. 14.3 Termination; Waiver. (a) In the event the defaulting Party fails to correct the Event of Default within the period for curative action under Section 15.2 of the Agreement with respect to the Events of Default outlined in Sections 15.1(a), (e) and (g) or upon the occurrence of any other Event of Default set forth in Sections 15.1(b), (c), (d) and (f) or 15.5, the nondefaulting Party may terminate the Agreement at its sole discretion by notifying the defaulting Party in writing of the nondefaulting Party's intent to terminate the Agreement and of the effective date of such termination. 50

51 (b) Upon the occurrence of an Event of Default or subsequent termination resulting from an Event of Default, the nondefaulting Party shall have the right to pursue any and all legal and equitable remedies, including specific performance and including all actual damages and remedies as provided under the Agreement or related documents, against the defaulting Party and shall be entitled to recover from the defaulting Party all expenses (including reasonable attorneys' fees) incurred by the nondefaulting Party in connection with the pursuit of such remedies. (c) Any waiver at any time by either Party of its rights with respect to an Event of Default under the Agreement, or with respect to any other matters arising in connection with the Agreement, shall not be a waiver with respect to any subsequent default or other matter. 14.4 Obligations Upon Termination. In the event that Owner elects to terminate this Agreement as a result of Operator's default and without limiting any other right or remedy of Owner, Owner may employ any other person, firm or corporation to perform the Contract Services by whatever method Owner may deem expedient. Furthermore, Operator shall, at Owner's expense, perform the following services relative to the Contract Services affected by its default, regardless of whether or not Owner elects to terminate this Agreement as a result of such default: (a) assist Owner in preparing an inventory of all Equipment, Materials, or Supplies in use or in storage at the Facility and Ash Landfill; and (b) assign to Owner such subcontracts and other contractual agreements relating to Operator's performance of the Contract Services as may be designated by Owner. Furthermore, Operator shall execute all documents reasonably requested by Owner and take such other steps as are reasonably requested by Owner that may be required to assign and vest in Owner or its designee all rights, benefits, interests and title in connection with the contracts or obligations; and (c) For a period not to exceed 90 days, assist Owner in training Operator's successor and effectuating the transition to a successor Operator. 51

52 ARTICLE XV MISCELLANEOUS 15.1 Non-Assignment. The rights and obligations of this Agreement may not be assigned by either Party without the prior written consent of the other Party, which consent shall not be unreasonably withheld. Any purported assignment of this Agreement in the absence of the required consent shall be void. 15.2 Notices. Any notice, demand, request, or communication required or authorized by the Agreement shall be delivered either by hand, facsimile, overnight courier or mailed by certified mail, return receipt requested, with postage prepaid, to: Northern States Power Company 414 Nicollet Mall Minneapolis, MN 55401 Attn:______________ on behalf of Owner; and to: NRG Energy, Inc. 1221 Nicollet Mall, Suite 700 Minneapolis, MN 55403-2445 Attn:_____________________ on behalf of the Operator. The designation and titles of the person to be notified or the address of such person may be changed at any time by written notice. Delivery of any such notice, demand, request, or communication shall be deemed delivered on receipt if delivered by hand or facsimile and on deposit by the sending party if delivered by courier or U.S. mail. 15.3 Captions. All titles, subject headings, section titles and similar items are provided for the purpose of reference and convenience and are not intended to be inclusive, definitive or to affect the meaning of the contents or scope of the Agreement or any of its provisions. 52

53 15.4 No Third-Party Beneficiary. No provision of the Agreement is intended to nor shall it in any way inure to the benefit of any third party, so as to constitute any such person a third-party beneficiary under the Agreement, or of any one or more of the terms hereof, or otherwise give rise to any cause of action in any person not a Party hereto. 15.5 Entire Agreement Modification and Waiver. The Agreement, together with all exhibits attached hereto, constitutes the entire agreement between the Parties relating to the transaction described and supersedes any and all prior oral or written understandings. No amendment, addition to, or modification of any provision hereof shall be binding upon the Parties, and neither Party shall be deemed to have waived any provision of any remedy available to it unless such amendment, addition, modification or waiver is in writing and signed by a duly authorized officer or representative of the applicable Party or Parties. 15.6 Governing law. The Agreement is made in the State of Minnesota and shall be interpreted and governed by the laws of the State of Minnesota without giving effect to its conflict of law provisions, and/or the laws of the United States, as applicable. 15.7 Contract Drafting. The Parties expressly agree that neither Party shall be deemed solely responsible for drafting all or any portion of the Agreement and, in the event of a dispute, responsibility for any ambiguities arising from any provision of the Agreement shall be shared equally by both Parties. 15.8 Form of Business Relationship. (a) The duties, obligations, and liabilities of the Parties are intended to be several and not joint or collective. The Agreement shall not be interpreted or construed to create an association, joint venture, fiduciary relationship or partnership between Operator and Owner or to impose any partnership obligation or liability or any trust or agency obligation or relationship upon either Party. Operator and Owner shall not have any right, power, or authority to enter into any agreement or undertaking for, or act on behalf of, or to act as or be an agent or representative of, or to otherwise bind, the other Party. 53

54 (b) The relationship between Owner and Operator shall be that of contracting party to independent contractor. Accordingly, subject to the specific terms of the Agreement, Owner shall have no general right to prescribe the means by which Operator shall meet its obligations under the Agreement. (c) Operator shall be solely liable for the payment of all wages, taxes, and other costs related to the employment of persons to perform Operator's obligations under the Agreement, including all federal, state, and local income, social security, payroll, and employment taxes, and statutorily mandated workers' compensation coverage. None of the persons employed by Operator shall be considered employees of Owner for any purpose; nor shall Operator represent to any person that he or she is or shall become an employee or agent of Owner. 15.9 Good Faith and Fair Dealing: Reasonableness. The Parties agree to act reasonably and in accordance with the principles of good faith and fair dealing in the performance of the Agreement. Unless expressly provided otherwise in this Agreement, (i) wherever the Agreement requires the consent, approval, or similar action by a Party, such consent, approval or similar action shall not be unreasonably withheld or delayed, and (ii) wherever the Agreement gives a Party a right to determine, require, specify or take similar action with respect to matters, such determination, requirement, specification or similar action shall be reasonable. 15.10 Severability. Should any provision of the Agreement be or become void, illegal, or unenforceable, the validity or enforceability of the other provisions of the Agreement shall not be affected and shall continue in force. The Parties will, however, use their best endeavors to agree on the replacement of the void, illegal, or unenforceable provision(s) with legally acceptable clauses which correspond as closely as possible to the sense and purpose of the affected provision and the Agreement as a whole. 15.11 Confidentiality. The Agreement and exhibits incorporated by reference, and all amendments shall be considered proprietary and shall not be provided to a third party without prior written approval of the other Party, unless a Party is required to disclose such information by law or court order or when such information is already in the public domain. In the event certain information must be 54

55 provided pursuant to a regulatory proceeding, the Parties shall take reasonable steps to protect the confidentiality of proprietary information. 15.12 Cooperation. The Parties agree to reasonably cooperate with each other in the implementation and performance of the Agreement. Such duty to cooperate shall not require either Party to act in a manner inconsistent with its rights under the Agreement. 15.13 Successors and Assigns. This Agreement shall be binding upon the Parties, their successors and permitted assignees. IN WITNESS WHEREOF, the Parties have caused this Agreement to be executed as of the day and year first written above. NORTHERN STATES POWER COMPANY, a Minnesota corporation By: ------------------------------------- Its: President, NSP Electric NRG ENERGY, INC., a Delaware corporation By: ------------------------------------- Its: Vice President Ops & Engr. 55

1 Exhibit 10.36 AGREEMENT FOR THE SALE OF THERMAL ENERGY AND WOOD BYPRODUCT BETWEEN NORTHERN STATES POWER COMPANY AND NORENCO CORPORATION This Agreement, effective as of the first day of December, 1986, between Northern States Power Company, a Minnesota corporation (hereinafter referred to as "NSP") and NORENCO Corporation, a Minnesota corporation (hereinafter referred to as "NORENCO"), a wholly owned subsidiary of NSP. WITNESSETH WHEREAS, NSP owns and operates the Allen S. King Electric Generating Plant comprised of a high pressure boiler, which supplies steam to an extraction condensing turbine-generator, and a low pressure heating boiler; and WHEREAS, NSP desires to sell steam to NORENCO, and NORENCO desires to purchase such steam from, NSP to resell to Andersen Corporation (hereinafter "Andersen") and the State of Minnesota Correctional Facility, Stillwater (hereinafter "State"); and -1-

2 WHEREAS, NORENCO desires to sell wood byproduct purchased from Andersen to NSP to be used as fuel and NSP desires to purchase such wood byproduct from NORENCO; and WHEREAS, it is the intention of both NSP and NORENCO that NORENCO reimburse NSP for all of NSP's incremental costs associated with the sale of steam to NORENCO. NOW THEREFORE, the parties hereby agree as follows: 1. Term-Effective Date 1.1 This Agreement shall become effective on December 1, 1986, and shall continue through December 31, 2006. 2. Conditions of Service 2.1 NSP shall use its best efforts to produce and deliver to NORENCO and NORENCO shall use its best efforts to purchase and accept from NSP all of NORENCO's current Steam requirements at Andersen and the State. 2.2 Steam sales from NSP's King Plant to NORENCO may at NSP's option be interrupted during electric system emergencies and times of peak electric loads. 2.3 NORENCO will reimburse NSP for the incremental cost associated with replacement electric energy at all times steam is being purchased for resale. 2.4 NORENCO shall make in a manner acceptable to NSP, all modifications, adjustments, and additions to NSP's existing boilers, pipes, valves, meters, controls, buildings, yards, -2-

3 tracks and all other equipment and machinery (collectively called Generating Equipment) at the King Plant necessary to produce steam of the quality specified and in the quantity required by this Agreement (herein sometimes referred to as Steam). 2.5 NORENCO shall obtain all necessary franchises, licenses, permits, rights of way or easements and purchase, construct and install a transport system which will connect King Plant to Andersen and the State. The transport system (herein called the Supply System) shall include all pipes, pumps, valves, meters, controls, wires, insulation and other equipment necessary to: (a) transport Steam from the King Plant to Andersen and the State; (b) transport condensate from Andersen and the State to the King Plant; (c) provide for control of Steam and communications between the King Plant and Andersen and the State; and (d) transport wood byproduct from Andersen to the King Plant. 2.6 Throughout the Term of this Agreement NORENCO shall obtain, renew, and maintain all licenses, permits and other governmental authorizations necessary to furnish Steam, condensate and wood byproduct through the Supply System. NSP shall use its best efforts to change or challenge rules, regulations, laws -3-

4 or ordinances which would prevent NSP from furnishing Steam hereunder or using wood byproduct as a fuel. 2.7 Throughout the Term of this Agreement NSP shall own, operate, maintain, repair, and adjust the Generating Equipment. NSP will not purchase any equipment not required for electric generation. 2.8 At NORENCO's expense, which shall be NSP's incremental cost, NSP shall, throughout the Term of this Agreement, operate, maintain, repair and adjust NORENCO-purchased equipment installed on NSP property. 2.9 NORENCO shall not, by reason of this Agreement, the termination of this Agreement or the payments made pursuant to this Agreement, acquire title or ownership in or to the Generating Equipment of the King Plant. 2. 10 All Steam produced and delivered from the King Plant shall meet the following specifications when measured at the delivery point: (a) Temperature: 0 to 10 degrees F above saturated steam conditions with variations required for load control. (b) Pressure: 150 to 250 pounds per square inch gauge (PSIG) with variations required for load control. (c) Steam flow rate: 0 to 160,000 pounds per hour. 2.11 Delivery point as used in Article 2 of this Agreement shall be the point where the Steam exits the Steam conditioning valve and enters the Supply Line at the King Plant. -4-

5 2.12 During each fiscal year of the Term of this Agreement, NORENCO shall provide 100% of the water necessary to produce Steam for NORENCO at the King Plant by delivering to NSP the condensate return water or pay NSP for the cost of any makeup required. NORENCO shall return the condensate in a condition acceptable for the King boilers. 3. Cost of Service For any Steam delivered to NORENCO by NSP, the costs shall be recovered by NSP from NORENCO as specified in this Section 3. The calculation of these costs includes the use of coefficients which are to be updated at least annually by NSP. The costs recovered by NSP are to be reviewed annually by NSP to ensure that the provisions of this Agreement recover all appropriate costs. Corrections to billings will be made if it can be demonstrated by either party to the other party's satisfaction that the monthly payments made by NORENCO to NSP are in error by at least plus or minus 1%. Any corrections to billings will be consistent with the incremental cost approach. 3.1 Cost to Provide Steam From the King Turbine Cold Reheat Extraction Line The King Plant turbine-generator will be operated as required by NSP for electric generation. When the turbine-generator is in operation, Steam will be provided to NORENCO from the turbine cold reheat extraction line. NORENCO will be charged for the cost of replacement energy generation (or loss of the oppor- -5-

6 tunity to sell electricity for resale) due to NORENC0's Steam requirements as follows: (a) The cost of replacement energy is calculated as the difference in the cost of NSP generation and purchases to supply NSP native requirements with and without the supply of Steam to NORENCO. The change in NSP generation cost will include such items as the changes in fuel and maintenance for startup and hours of operation, and the incremental ash disposal cost. The change in billing cost for purchases with and without the supply of Steam to NORENCO will also be used in the calculation. (b) NORENCO will be charged monthly for incremental costs associated with the loss of the opportunity to sell electricity for resale due to NORENCO's Steam requirements. This incremental cost is calculated as the estimated lost revenues from sales for resale from the King Plant minus the estimated avoided electrical production costs, had this energy been generated at the King Plant. (c) The cost of replacement energy shall be calculated using the NSP System Operations computer program and the following coefficients or information: (1) Total Steam Flow in MMBTU's to NORENCO (2) Electric power MW hours lost per MMBTU delivered to NORENCO (3) Cost of replacement energy per MW Hour -6-

7 3.2 Cost to Provide Steam from the King Heating Boiler The King Plant heating boiler may be used to provide Steam to Andersen and the State when the King Plant turbine generator is not in operation. NORENCO will be charged for operation of the heating boiler (including standby operation) as provided in 3.2.1 - 3.2.3. 3.2.1 Fuel Cost (a) NORENCO will be charged for any incremental fuel used due to heating boiler operations for NORENCO. For oil usage the cost will be calculated as follows: Cost = Gallons of oil used for x Oil cost per NORENCO gallon (b) For gas usage, the cost will be calculated as follows: Cost = Millions of BTU of gas x Gas cost per used for NORENCO million BTU (c) The King Plant will report monthly the gallons of oil and the millions of BTU's of gas used for the heating boiler. If the heating boiler is used to supply steam to both NSP and NORENCO, the costs will be prorated based on NORENCO Steam Flow and NSP steam flow. 3.2.2 Incremental Maintenance Cost Each month, NORENCO shall pay NSP for the cost of -7-

8 incremental maintenance of the King Plant heating boiler as calculated using NSP Power Production's incremental maintenance coefficient. 3.2.3 Incremental Auxiliary Cost Each month, NORENCO shall pay NSP for the cost of incremental auxiliary electrical power usage for the King Plant heating boiler as calculated using the average incremental system generation cost for that month. 3.3 Incremental Operating Cost Any other incremental operating costs including overtime or operating personnel required by NSP to provide Steam to NORENCO shall be reported and charged to NORENCO. 3.4 Thermal Equipment Operation and Maintenance Any operation or maintenance of thermal only equipment (equipment installed for thermal use only) will be charged on separate work orders to NORENCO. 3.5 Supply of Gas or Oil If NSP supplies any oil or natural gas to NORENCO, NORENCO shall reimburse NSP for the replacement cost of that oil or natural gas including appropriate carrying and handling charges. 3.6 Administrative and General Costs Administrative and general costs are covered by the Administrative Services Agreement dated January 1, 1983, and any amendments thereto, between NSP and NORENCO. 3.7 NSP Surcharge -8-

9 A 5% surcharge will be added to items 3.2.2 through 3.4. 4. Sale of wood Byproduct to NSP 4.1 NORENCO is responsible for transporting and for all costs related to transporting the wood byproduct from Andersen to the King Plant site or to other mutually agreed to NSP sites if King Plant is out of service. 4.2 NSP agrees to use reasonable efforts to burn wood byproduct from NORENCO up to thirteen (13) tons per hour and up to 80,000 tons per year of wood byproduct when the King Plant is operating or to utilize it at other NSP generating plants capable of handling and burning such wood byproduct when the King Plant is out of service. NORENCO will annually provide NSP with a forecasted wood byproduct delivery schedule. NORENCO agrees to supply all such wood byproduct received from Andersen to NSP at the locations specified in 4.1 above unless NSP in its sole discretion is unable to utilize such wood byproduct. 4.3 Whenever NSP receives wood byproduct from NORENCO, NSP shall pay for all such wood byproduct at the following rate: (a) For wood byproduct burned at the King Plant NSP shall pay NORENCO at the average cost per MMBTU for solid fuel delivered to the King Plant during the calendar year on a BTU equivalent basis. (b) For wood byproduct delivered to other NSP generating plants, NSP shall pay NORENCO the average cost per -9-

10 MMBTU of solid fuel (on an equivalent BTU basis) during the calendar year at such other NSP plants. The cost per MMBTU in (a) and (b) above shall be estimated at the beginning of each calendar year for billing purposes and the billings adjusted after the close of the year to reflect the year's actual average cost. 5. Billing 5.1 NSP will bill NORENCO, and NORENCO will bill NSP, by the 20th of the month following the month in which the costs were incurred. The amount of each month's bill shall be increased by 1% to cover working capital and miscellaneous costs. 5.2 NORENCO will pay NSP, and NSP will pay NORENCO, no later than ten (10) days following the date of NSP's bill and the date of NORENCO's bill, respectively. Interest shall accrue on payments which are overdue at the daily commercial prime rate in effect at the Norwest Bank Minneapolis. 5.3 NSP will provide NORENCO with a cost component schedule along with its bill similar to that shown in Table 1. NORENCO will provide NSP with a cost component schedule along with its bill similar to that shown in Table II. 5.4 The total monthly cost billed shall be calculated pursuant to Articles 3 and 4 of this Agreement. 6. Liability 6.1 NORENCO shall hold harmless and indemnify NSP from -10-

11 any and all claims, loss, damage or liability, including injury to and death of persons, caused directly or indirectly by the Steam or the use of NORENCO's facilities after the delivery of Steam to NORENCO, other than those resulting solely from the negligence of NSP or its agents or employees (excluding persons assigned to NORENCO on a full-time basis). NSP likewise shall hold harmless and indemnify NORENCO from any and claims, loss, damage or liability, including injury to and death of persons, caused directly or indirectly by steam or the use of NSP's facilities before the delivery of steam to NORENCO, other than those resulting solely from the negligence of NORENCO or its agents or employees (including those persons assigned to NORENCO on a full-time basis). 6.2 Notwithstanding any other provision of this Agreement, neither NSP nor NORENCO in any event shall be liable to the other, whether arising under contract, tort (including negligence), or otherwise, for claims of customers or any other third parties, or for loss of use of capital or revenue, or for loss of anticipated profits, or for any other special, indirect, incidental or consequential loss or damage of any nature arising at any time or from any cause whatsoever. 6.3 No provision of this Agreement shall in any way inure to the benefit of any third person (including the public at large) so as to constitute any such person a third party beneficiary of this Agreement or of any one or more of the terms -11-

12 hereof, or otherwise give rise to any cause of action in any person not a party hereto. 6.4 The provisions of this section and of any other sections of this Agreement providing for limitation, of or protection against liability shall apply to the full extent permitted by law and regardless of fault and shall survive the expiration or termination of this Agreement. 7. Continuity of Service 7.1 NSP shall not be liable to NORENCO for its failure to deliver Steam, and NORENCO shall not be liable to NSP for its failure to receive Steam, when such failure on the part of either party shall be due to accident to or breakage of pipelines or equipment, fires, floods, storms, weather conditions, strikes, lockouts or other industrial disturbances, riots, legal interference, acts of God or public enemy, shutdowns for necessary repairs and maintenance, or, without limitation by enumeration, any other cause beyond the reasonable control of the party failing to deliver or receive Steam provided such party shall promptly and diligently take such action as may be necessary and practicable under the then existing circumstances to remove the cause of failure and resume the delivery or receipt of Steam. Furthermore, NSP shall not be liable for its failure to deliver Steam provided that such failure is (i) due to any scheduled or unscheduled maintenance shutdown of King Plant -12-

13 boilers or (ii) due to operating conditions on King Plant boilers and turbine that warrant curtailment of the delivery of Steam to NORENCO. NSP shall have the sole right to determine when those conditions exist. NSP and NORENCO shall cooperate with each other regarding maintenance and Steam service curtailment, and shall use their best efforts to coordinate inspections, maintenance and repairs to their respective facilities. NSP shall provide NORENCO with reasonable advance notice as possible of scheduled interruption or curtailment of Steam service. 8. Miscellaneous 8.1 This Agreement shall bind and inure to the benefit of the respective successors and assigns of the parties hereto, and any reference to any of the parties hereto shall be deemed to include all successors and assigns. Notwithstanding the foregoing, no assignment shall relieve a party of its duties and obligations to the other party under this Agreement if the assignee defaults in such duty or obligation, unless such other party consents to the novation in writing. 8.2 Unless designated otherwise in writing, all notices from NORENCO to NSP shall be delivered to: D. E. Gilberts Senior Vice President-Power Supply Northern States Power Company 414 Nicollet Mall Minneapolis, MN 55401 -13-

14 Unless designated otherwise in writing, all notices from NSP to NORENCO shall be delivered to: H. S. Wick Vice President NORENCO Corporation 414 Nicollet Mall P.O. Box 1396 Minneapolis, MN 55440 8.3 All payments and reimbursements required to be made by NORENCO to NSP pursuant to this Agreement shall be directed to: Manager, General Accounting Northern States Power Company 414 Nicollet Mall Minneapolis, MN 55401 8.4 All payments and reimbursements required to be made by NSP to NORENCO pursuant to this Agreement shall be directed to: Manager, Business Operations NORENCO Corporation P.O. Box 1396 Minneapolis, MN 55440 8.5 The costs and charges provided for herein are exclusive of any present or future federal, state, municipal or other sales or use tax with respect to the personnel or products covered hereby, or any other present or future excise tax upon or measured by the gross receipts from this transaction or any allocated portion thereof or by the gross value of the personnel or products covered hereby. If NSP is required by applicable law or regulations to pay or collect any such tax or taxes on account of this transaction or the personnel or products covered hereby, then such amount shall be paid by NORENCO in addition to the costs or charges provided for herein. -14-

15 8.6 This Agreement shall be construed in accordance with and be governed by the laws of the State of Minnesota. IN WITNESSETH WHEREOF, the parties hereto have caused this instrument to be executed by their respective officers thereunto duly authorized as of the day and year below written. NORENCO CORPORATION NORTHERN STATES POWER COMPANY By______________________________ By__________________________________ Its_____________________________ Its_________________________________ Date____________________________ Date________________________________ 00476 -15-

16 TABLE I NSP CHARGES TO NORENCO 3.1(a) Cost for Replacement Generation $ ------------- (b) Lost Opportunity Cost $ ------------- 3.2.1 Heating Boiler Fuel Cost Gas $ ------------- Oil $ ------------- 3.2.2 Incremental Maintenance Cost $ ------------- 3.2.3 Incremental Auxiliary Cost $ ------------- 3.3 Incremental Operating Cost $ ------------- 3.4 Thermal Equipment Operation and Maintenance $ ------------- 3.5 Supply of Gas and Oil $ ------------- 3.6 Administrative and General Costs $ ------------- 3.7 NSP Surcharge $ ------------- 00476.4 -16-

17 TABLE II NORENCO WOOD BYPRODUCT SALE TO NSP Tons of wood byproduct delivered to NSP _______________ Tons BTU's per pound _______________ BTU/lb. * NSP Equivalent cost for coal delivered to King Plant during the year $ _______________ /MMBTU * An estimated cost will be used during the year and retroactively adjusted as necessary at the end of the year. 00476.5 -17-

1 EXHIBIT 10.37 [NSP LOGO] NORTHERN STATES POWER COMPANY 414 NICOLLET MALL ROGER D. SANDEEN MINNEAPOLIS, MINNESOTA 55401-1993 VICE PRESIDENT TELEPHONE (612) 330-5907 AND CONTROLLER April 4, 1991 Mr. Roland J. Jensen, President NRG Group, Inc 1221 Nicollet Avenue Minneapolis, MN 55403 Subject: Federal and State Income Tax Sharing Agreement Between Northern States Power Company (NSP) and NRG Group, Inc. Dear Mr. Jensen, To formalize the system of determining the income tax liability attributable to each corporation that joins in filing consolidated Federal and State income tax returns with NSP the following agreement is proposed. The subsidiaries that comprise NRG Group, Inc shall pay to NSP the amount of Federal and State income tax computed as if the NRG Group had actually filed separate Federal and separate State tax returns. Payments shall be made on or about the time that estimate payments or income tax returns are due. If the NRG Group incurs tax losses, NSP shall reimburse NRG to the extent there is a tax benefit from the consolidated returns. NRG Group shall join in an election to this effect in the 1991 tax returns. Sincerely, /s/ Roger D. Sandeen Roger D. Sandeen /s/ Roland J Jensen - ------------------------- Approved Roland J Jensen

1 EXHIBIT 10.38 EXECUTION COPY SUPPORT AGREEMENT THIS SUPPORT AGREEMENT (this "AGREEMENT"), dated as of March 27, 2000, is made by NORTHERN STATES POWER COMPANY, a Minnesota corporation ("PARENT"), in favor of Citicorp USA, Inc., as agent for the lenders party to the Credit Agreement referred to below (the "AGENT"). WHEREAS, Parent is the owner of 100% of the outstanding common stock of NRG Energy, Inc., a Delaware corporation (the "Subsidiary"); WHEREAS, Subsidiary intends from time to time to make borrowings from the lenders party to the $300,000,000 Credit Agreement, dated as of the date hereof (such agreement as it may be amended and in effect from time to time, the "CREDIT AGREEMENT"), among Subsidiary, the lenders party thereto and Citicorp USA, Inc., as Administrative Agent (such lenders and the Administrative Agent being hereinafter collectively referred to as the "LENDERS"), and to issue debt securities to the Lenders pursuant to the Credit Agreement (such borrowings and debt securities, including without limitation all interest, fees, expenses and other amounts payable in accordance with the documentation relating to such borrowings and debt securities being hereinafter collectively referred to as the "DEBT"); WHEREAS, Parent desires to take certain actions to enhance and maintain the financial condition of Subsidiary as hereinafter set forth in order to enable Subsidiary and its subsidiaries to incur indebtedness on more advantageous and reasonable terms; and WHEREAS, the Lenders will rely upon this Agreement in making loans or extending credit to Subsidiary under the Credit Agreement; NOW, THEREFORE, in consideration of the premises, and other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, and in order to induce the Lenders to enter into, and extend credit to Subsidiary under, the Credit Agreement: SECTION 1. STOCK OWNERSHIP. During the term of this Agreement, Parent will own all of the voting common stock now or hereafter issued and outstanding of Subsidiary and all other subsidiaries of Parent. SECTION 2. SUFFICIENT FUNDS. Parent intends to manage the affairs of Subsidiary consistent with Subsidiary's having sufficient funds to make payments in respect of the Debt in accordance with the terms of the Credit Agreement. Parent hereby agrees that, if and to the extent that it provides funds to Subsidiary in furtherance of its intention described above, Parent will provide those funds to Subsidiary in the form of equity and not in the form of debt. SECTION 3. WAIVERS. Parent hereby waives any failure or delay on the part of any Lender in asserting or enforcing any of its rights or in making any claims or demands hereunder

2 and agrees that Subsidiary need not assert or enforce any such rights or make any such claims or demands hereunder. Subsidiary or any Lender may at any time, without Parent's consent, without notice to Parent and without affecting or impairing any Lender's rights or Parent's obligations hereunder, do any of the following with respect to the Debt: (a) make changes modifications, amendments or alterations, by operation of law or otherwise, including, without limitation, any increase in the principal amount of such Debt or the rate of interest payable thereon or any changes in the method of calculating the rate of interest payable thereon, (b) grant renewals and extensions and extensions of time, for payment or otherwise, (c) accept new or additional documents, instruments or agreements relating to or in substitution of said Debt, or (d) otherwise handle the enforcement of their respective rights and remedies in accordance with their business judgment. SECTION 4. AMENDMENT. This Agreement may be amended or terminated at any time by written amendment or agreement signed by Parent and the Agent. SECTION 5. RIGHTS OF LENDERS. Sections 1, 2 and 3 of this Agreement inure to the benefit of the Lenders. In the event that Parent fails to comply with any of its obligations hereunder, any Lender may enforce its rights under Sections 1, 2 and 3 hereof directly against Parent. SECTION 6 NOTICES. Any notice, instruction, request, consent, demand or other communication required or contemplated by this Agreement shall be in writing, shall be given or made by United States first class mail, facsimile transmission or hand delivery, addressed as follows: If to Parent: Northern States Power Company 414 Nicolett Mall 5th Floor Minneapolis, Minnesota 55401 Attention: Treasurer Facsimile: (612) 330-6926 Telephone: (612) 330-7769 If to the Agent: Citicorp USA, Inc. 399 Park Avenue, 4th Floor Zone 20 New York, New York 10043 Attention: J. Nicholas McKee Facsimile: 212-793-6130 Telephone: 212-559-1503 SECTION 7. SUCCESSORS. This Agreement shall be binding upon Parent and its successors and assigns and is also intended for the benefit of Lenders, and, each Lender shall be entitled to the full benefits of this Agreement and to enforce the covenants and agreements contained herein as set forth in Section 5. This Agreement is not intended for the benefit of any person other than Lenders and shall not confer or be deemed to confer upon any such person any benefits, rights or remedies hereunder.

3 SECTION 8. GOVERNING LAW. This Agreement shall be governed by the laws of the State of New York. SECTION 9. COUNTERPARTS. This Agreement may be executed by the parties in one or more separate counterparts, each of when executed shall be deemed an original and all of which, when taken together, shall constitute one and the same agreement.

4 IN WITNESS WHEREOF, Parent has caused this Agreement to be executed by its officer thereunto duly authorized, as of the date first above written. NORTHERN STATES POWER COMPANY By Paul Pender ---------------------------- Name: Paul Pender Title: Vice President-Finance & Treasurer Accepted and agreed to as of the date first above written: CITICORP USA, INC., as Agent By ---------------------------- Name: Title

5 IN WITNESS WHEREOF, Parent has caused this Agreement to be executed by its officer thereunto duly authorized, as of the date first above written. NORTHERN STATES POWER COMPANY By --------------------------- Name: Title: Accepted and agreed to as of the date first above written: CITICO USA, INC., as Agent By SANDIP SEN --------------------------- Name: SANDIP SEN Title: Managing Director

6 REFUSE DERIVED FUEL SUPPLY AGREEMENT BETWEEN NORTHERN STATES POWER COMPANY AND NRG RESOURCE RECOVERY, INC. This Agreement shall, upon execution, govern the operational and financial relationship between Northern States Power Company (hereinafter referred to as "NSP") and NRG Resource Recovery, Inc. (hereinafter referred to as "NRG-RR"), Whereas, NSP requires fuel for steam electric power plants operated at Mankato, Minnesota and Red Wing, Minnesota known as the Wilmarth and Red Wing Steam Plants, respectively (hereinafter referred to as the "Steam Plants"); and Whereas, the Steam Plants consume volumes of refuse derived fuel (hereinafter referred to as "RDF") as fuel for the generation of electrical energy in the Steam Plants; and Whereas, NRG-RR manages and operates Resource Recovery Facilities at Newport, Minnesota and Elk River, Minnesota (hereinafter referred to as "Facilities") for NSP; and Whereas, the parties desire to increase landfill abatement through increased production and combustion of RDF in a manner that is conomic, to NSP's ratepayers. Whereas, the Facilities produce RDF and deliver it to the Steam Plants; Now, therefore NRG-RR and NSP mutually agree as follows: 1.0 TERM 1.1 This Agreement shall be in effect from January 1, 1992 through December 31, 2001. The term of this Agreement shall thereafter automatically renew and continue in full force and effect for successive periods of five full years each unless either party terminates this Agreement by delivering to the other party not less than six months prior to the end of any five year term, written notice of termination. 1.2 In the event the waste processing Service Agreement among NSP and Ramsey and Washington Counties dated November 6, 1986, and any subsequent amendments is terminated, NRG-RR shall immediately notify NSP in writing and this Agreement shall become null and void. 1

7 2.0 SOURCE OF RDF The primary sources of RDF to be transferred under this Agreement are the Facilities. The Facilities process municipal solid waste under contract with various counties in the Twin Cities Metropolitan Area. 3.0. QUANTITY OF RDF 3.1 NRG-RR agrees to process and deliver to the Steam Plants, and NSP agrees to accept and to pay for quantities of RDF within the following limits: TABLE I RDF DELIVERY SCHEDULE MINIMUM EXPECTED ANNUAL TONNAGE WEEKLY TONNAGE -------------- -------------- 340,000 6900 (+-) 500 3.2 NRG-RR shall annually provide NSP with a written forecast of monthly deliveries from the Facilities to NSP. This forecast shall be provided to the NSP Fuel Resources Department and to the Steam Plants for inclusion in the annual NSP Production Budget but in no event will the schedule be delivered later than July 31 for deliveries to be made during the following year. (The forecast of deliveries for calendar year 1992 is included in Appendix A). The forecast shall reflect expected monthly waste deliveries and processing at the Facilities as well as expected outages scheduled at the steam Plants and the Facilities. 3.3 It is the expectation of the parties to increase RDF production and burning to 350,000 tons by 1993, 360,000 tons by 1994, and 370,000 tons by 1995. 3.4 In the event that NSP can consume quantities of fuel at the Steam Plants in excess of the Minimum Annual Tonnage of RDF identified in paragraph 3.1 in this Agreement, NSP shall notify NRG-RR that it is soliciting bids to supply such additional quantities. If NSP has identified other sources of fuel acceptable to support the Steam Plants' operations, NSP shall allow NRG-RR to offer additional quantities of RDF to satisfy the additional fuel consumption. NRG-RR must provide such offer no later than five (5) working days after NSP has notified NRG-RR of such opportunity to offer additional quantities of RDF. 2

8 In the event that NRG-RR offers terms for the supply of additional RDF that NSP determines to meet or are better than offers from sources, then NSP and NRG-RR will execute an agreement to provide additional RDF that is acceptable to both parties. 4.0 QUALITY OF RDF 4 1. TABLE 2 RDF QUALITY CRITERIA (PROXIMATE ANALYSIS) EXPECTED AVERAGE MAXIMUM MINIMUM ------- ------- ------- BTU/lb 5,000-5,500 N/A 5,000 Ferrous Metals --- 1.00% --- Glass --- 3.50% --- Moisture --- 40.00% --- Non-Ferrous Metal --- .75% --- Rigid Particle Size --- 12"x12" --- Ash (dry) --- 15% --- 95% of all RDF delivered to the Steam Plants shall be less than 6 inches in any dimension. The Facilities shall attempt to the best of their abilities to avoid delivery of material that includes excessively long and fibrous material such as cords, hosiery, belting, rope, etc. In the event that such long fibrous material may be delivered, the Steam Plants shall accept and process such materials if NSP determines that it is feasible to do so. If NSP determines that it is not feasible to process such materials, NSP shall reject and return the materials pursuant to paragraph 4.3 below. In the event that such material causes a Steam Plant to curtail operations to clean and/or repair equipment such an event will at the discretion of the Steam Plant be considered to be an unexpected interruption. 4.2 It is anticipated that RDF shall have the maximum and minimum characteristics shown above. In the event any one of the maximums or minimums listed above is exceeded for a period of one week, NRG-RR and NSP shall use reasonable efforts to resolve the problems causing the RDF material to exceed the limitations stated above. If such problems are not resolved within 30 days after the one week period, NSP shall, in its sole discretion, have the option to suspend performance under this Agreement. If NRG-RR cannot resolve the problems or provide a substitute supply of RDF and give reasonable assurance of performance within 30 days from the date of suspension, NSP shall 3

9 have the option to terminate this Agreement effective immediately by giving written notice thereof to NRG-RR. 4.3. The Steam Plants shall have up to twelve (12) hours after arrival of a truckload of RDF at the Steam Plants to reject the truckload based on RDF quality criteria described in paragraph 4.1. Return of any rejected truckloads shall be at NRG-RR's expense. NSP shall not have any responsibility for its disposition or the cost of such disposition. The Steam Plant shall not landfill RDF. 4.4. The Newport Facility will provide the Red Wing plant with two open top trailers for collecting and hauling ferrous removed from RDF shipped to the plant. The Newport Facility will be responsible for maintenance of the ferrous trailers, transportation and disposal costs of the ferrous providing that the trailers are used to dispose of ferrous only. Recovered ferrous tons thus transported and disposed of will be subtracted from the burn incentive tons delivered each month. 5.0. DELIVERY OF RDF 5.1. RDF is expected to be shipped to the Steam Plants by means of transfer trailers. NRG-RR will pay for equipment and charges associated with delivering RDF to the Steam Plants with the exceptions listed in (8.0.). 5.2. NRG-RR will also be responsible for the following fuel handling activities at the Steam Plants: a. Contact control room to enter gate and determine where to stage trailer. b. Stage trailers inside receiving building. c. Crank down landing gear. d. Hook-up hydraulic hoses. e. Open trailer door. f. Unhook tractor from full trailer. g. Hook-up to empty trailer. h. Clean off rear of trailers, doors, bumpers. i. Close door and secure. j. Crank up landing gear. k. Disconnect hydraulic hoses and store properly. 1. Return tractor to Facility. m. Notify control room of any problems which might occur. 4

10 5.3. Deliveries are expected to occur seven (7) days per week. NRG-RR shall use all reasonable efforts to produce and deliver RDF consistent with the Steam Plant burn requirements. The Steam Plants will use all reasonable efforts to receive and burn RDF consistent with NRG-RR's production requirements. In order to facilitate the coordination of daily deliveries, each Steam Plant will, by 1300 hours each day, notify each Facility as to the operating status and the estimated RDF deliveries needed for the next day and immediately notify the Facilities of any unscheduled outages. 5.4. The Steam Plants shall each use all reasonable efforts to receive and burn 700 tons of RDF per day at each Steam Plant. 5.5. It is anticipated that deliveries shall be curtailed during scheduled maintenance outages at the Steam Plants. It is expected that scheduled outages will occur in November, December, January, and February, and should be coordinated with NRG-RR so that outages at UPA's Elk River Station and Hennepin County's HERC Facility can also be accommodated. Such scheduled maintenance outages last approximately three weeks per plant and occur once per year. NSP, and NRG-RR, will exchange projected annual maintenance outage schedules no later than August 31 of the year preceding the scheduled maintenance outages. In order to confirm the actual outage dates, NSP shall notify NRG-RR at least two (2) weeks before the beginning of such scheduled outages. Unexpected interruptions in the operation of the Steam Plants may also occur that could require the curtailment of deliveries of RDF. Unexpected interruptions shall include but not be limited to events described in paragraph 4.1 above. In such an event, the Steam Plants shall notify the Facilities within one (1) hour after the beginning of such an interruption so that deliveries can be reduced or curtailed. The Steam Plants shall notify the Facilities as soon as possible that plant operations have resumed so that RDF deliveries can resume. 5

11 It is also anticipated that operations at the Facilities will be interrupted from time to time for scheduled maintenance and repairs. NRG-RR shall notify the Steam Plants at least two (2) weeks prior to the beginning of such interruptions. Unexpected interruptions in the operation of the Facilities may also occur. In such an event, the Facilities will notify the Steam Plants within one (1) hour after the beginning of such an interruption if the interruption is expected to affect scheduled RDF deliveries. The Facilities shall attempt, to the best of their abilities to continue deliveries of RDF which meet the specifications set forth in this Agreement during such interruptions. 6.0. WEIGHING AND ANALYSIS 6.1. The driver of each vehicle transporting RDF to the Steam Plants shall deliver a weight ticket to the Steam Plant for each load delivered. Each weight ticket shall include, as a minimum, the following information for each delivery: a. Ticket number b. Location of originating RDF Facility c. Loading date and time d. Vehicle identification number e. Gross and tare weight of vehicle and net tons of RDF 6.2. All loads will be weighed on the Facilities' scales and recorded by Facilities' personnel on weight tickets. Facilities' plant scales shall be certified semi-annually at Facility's expense. NSP Fuel Resource personnel will be notified in advance and shall have the right to observe any such certifications. Copies of all scale certifications will be forwarded to the Fuel Resources Department. The net weights from the Facilities' weight tickets will be used to determine amounts due under this Agreement. 6.3. Sampling of RDF deliveries shall be conducted by the Facilities in accordance with Appendix B. Costs associated with testing of samples shall be the responsibility of NSP. 6

12 7.0. PRICE 7.1. Fuel Price Up To 196,560 Tons Per Year The Fuel Price for the first 196,560 tons of RDF delivered per year shall be $8.025 per ton which shall be effective January 1, 1991. The as received heating value shall be guaranteed to be 5,500 BTU per pound. In the event that the actual as received heating value is greater than 5,600 BTU per pound or less than 5,400 BTU per pound, a Fuel Price adjustment will be calculated by NSP as shown in the following example: If the actual as received heating value (AHV) is less than 5,400 BTU per pound, the Fuel Price adjustment (FPAH) will be: FPAL = (5,500 - AHV) * (Fuel Price)* 196,560 ------------------------------------- 5,500 The Fuel Price Adjustment (FPAL) will be paid to NSP. If the actual as received heating value (AHV) is greater than 5,600 BTU per pound, the Fuel Price Adjustment (FPAH) will be: FPAH = (AHV - 5,500) * (Fuel Price)* 196,560 ------------------------------------- 5,500 The Fuel Price Adjustment (FPAH) will be paid to NRG-RR. The Fuel Price adjustment will be calculated by NSP and verified by NRG-RR no later than 30 days after delivery of the first 196,560 tons per year and payment will be due no later than 15 days after calculation of the Fuel Price Adjustment. 7.2. Fuel Price above 196,560 Tons Per Year The Fuel Price for tons of RDF burned above 196,560 tons per calendar year shall be $0.00 FOB destination. 7.3. Fuel Price Escalation An adjusted Fuel Price to be paid for the first 196,560 tons to be delivered during the calendar year shall be calculated in February of each year. The Fuel Price shall be adjusted annually at the same rate of change as the Unweighted Arithmetic Average of the annual "as delivered" fuel costs ($/Million BTU basis) at NSP's portion of Sherburne County, A S King and Riverside generating facilities. The annual "as delivered" fuel costs at the three generating facilities shall be calculated based on the monthly reports submitted to the Federal Energy Regulatory Commission on Form 423. These monthly reports will be weight averaged to determine the annual "as 7

13 delivered" fuel cost for each generating facility. See Appendix C for example calculation. 7 4. RDF Burn Incentive As an incentive to the Steam Plants to maximize RDF consumption, NRG-RR will pay NSP a Burn Incentive Rate for each ton of RDF burned at the Steam Plants when the total RDF consumed at the Steam Plants exceeds 168,480 tons. The Burn Incentive Rate shall be $14.35 per ton of RDF burned above 168,480 tons per calendar year, as of January 1, 1992. The incentive payments will be paid to NSP on a monthly basis for burning amounts above 168,480/12 = 14,040 tons with monthly true-ups for months where less tons are burned. 7.5 RDF Burn Incentive Escalation An Adjusted Burn Incentive per ton shall be calculated in January of each year by NRG Resource Recovery. The Burn Incentive Rate shall be adjusted annually at the same rate of change to the CPI(U), as published in the Bureau of Labor Statistics CPI detailed Report. An Adjusted Burn Incentive Rate (ABI) shall be calculated in January of each year based upon the most recent CPI(U) in effect at that time, the CPI(U) inaffect as of January 1, 1992 which shall be 137.9 and $14.35 per ton base Burn Incentive Rate. The calculation shall be as follows: ABI = (CPI(U)/137.9) ($14-35/ton). 7.6 Minimum Delivery Guarantee NRG-RR guarantees to deliver a minimum of 340,000 tons of RDF to the Steam Plants each calendar year. If NRG-RR delivers less than 340,000 tons per year, and the failure to deliver said tons is due to either the low supply of MSW or the inability of NRG-RR to process and transport the guaranteed tonnage, then NRG-RR shall pay the RDF Burn Incentive to the Steam Plants as though 340,000 tons were delivered. 7.7 Minimum Burn Guarantee NSP guarantees to burn a minimum of 340,000 tons of RDF produced by NRG-RR per year. If NSP is unable to burn 340,000 tons due to lack of Steam Plant availability, then NSP will pay to NRG-RR an amount equal to 340,000 tons minus total tons burned times the then current RDF Burn Incentive Rate or Adjusted Burn Incentive Rate per ton. 8

14 8.0 PRICE ADJUSTMENT The following circumstances may result in additional charges and such charges shall be the responsibility of the appropriate Steam Plant. 8.1 When a plant requests RDF to be delivered and the trailers have been dispatched from the Facility but the plant is unable to accept the RDF for reasons other than those listed in Section 4.3 requiring the RDF to be transferred to another plant or returned to the Facility. 8.2 When a plant, during the handling or unloading of a trailer, damages the trailer during some action that is not the direct responsibility of the Facility or the hauler. 8.3 When a plant, during operations or the cessation of any operation, causes a tractor to be held either at the Steam Plant or the Facility or there is a delay in the return of the tractor to the Facility that results in additional waiting time charges as defined in NRG-RR's agreement with its contract haulers. 8.4 When a plant causes a tractor to return to the Facility without a trailer and there is an additional trip charge to retrieve the trailer from the plant and return it to the Facility. 8.5 In the event that the Steam Plants consume less than 196,560 tons during any calendar year due to NSP's inability to perform, NRG-RR and NSP shall share equally in all additional costs and penalties associated with transportation and landfilling RDF assessed against and actually incurred by NRG-RR as described in the terms of the Service Agreement between NRG-RR and Ramsey and Washington Counties in effect on the date of the execution of this Agreement. RDF landfilled under conditions of "Uncontrollable Circumstances" as defined in the Service Agreement between NRG-RR and Ramsey and Washington Counties in effect on the date of the execution of this Agreement and referenced in Section 11.0 of this Agreement, shall be excluded from any cost sharing referenced in this paragraph 8.5. 8.6 In the event that NRG-RR or its contractors damage Steam Plant equipment or facilities, NRG-RR or its contractors shall be liable for required repairs. 9

15 9.0. BILLING AND PAYMENT 9.1 By the fourth working day of each month, the Fuel Resources Department shall provide to NSP's Financial Accounting Department, documentation of tons of RDF and corresponding Million BTU's (MBTU's) consumed at each Steam Plant and the total dollars to be paid to NRG-RR. An informational copy of this documentation shall be sent to each Facility as well as to the NRG-RR Accountant. 9.2. By the fifth working day each month, each Facility shall provide to the NRG Accountant documentation of tons of RDF delivered to the Steam Plants from each Facility, tons of ferrous landfilled from the Red Wing Plant and RDF Burn Incentive Tons to be paid to the Steam Plants. An informational copy of this documentation shall be sent to each Steam Plant, as well as to the Fuel Resources Department. 9.3. Payment for items listed above will take place by the 20th of the month through the NSP-NRG-RR "Intercompany Bill" transaction. 10.0.AUDIT OF SELLERS BOOKS AND RECORDS NRG-RR agrees that NSP, at any time during normal business hours, shall have access to and the right to examine and audit any documents or records necessary to verify the tonnage amounts pertinent to the transactions outlined in this Agreement. NSP shall conduct no less than one audit per calendar year to verify quantities of RDF actually produced at the Facilities and delivered to the Steam Plants during the then current year and for the entire preceding year. All expenses incurred by the examining party shall remain a cost of such party. 11.0.UNCONTROLLABLE CIRCUMSTANCES NRG-RR and NSP recognize that NSP's agreements with the Counties provide that the Facilities non-performance or delayed performance may at the discretion of the Counties be excused in the event of "Uncontrollable Circumstances" as defined in these agreements. NRG-RR and NSP agree that any occurrence giving rise to a claim of uncontrollable circumstances shall be immediately communicated to all representatives of the Operating Committee. The Operating Committee shall decide whether to claim the excuse and any other action to be taken. 12.0.OPERATING COMMITTEE 12.l Any controversies or claims arising out of or relating to any terms of this Agreement or the inability of either NSP or NRG-RR to perform shall be resolved by an Operating Committee consisting of three NRG-RR representatives,three NSP 10

16 NSP representatives, and a seventh member mutually agreed to by both parties. The seventh member may change from time to time at the request of either party. The Operating Committee shall resolve all claims within thirty (30) days. 12.2.The Operating Committee will conduct at least once a year a formal review of the overall operations of the production and use of RDF during the year. This formal review meeting should be conducted during the fourth calendar quarter and should include a review of at least the following items: * Actual Facilities performance including production rates, production yield, RDF quality, etc. * Actual Steam Plant performance including fuel handling activities, plant heat rates, residuals disposal, etc. * Scheduled and unscheduled outage events. * Review existing and potential RDF production capacities. * Review existing and potential RDF utilization capacities. * Facility and Steam Plant Availabilities. 13.0.NOTIFICATIONS Any notice, demand, or other communication required or permitted to be served or given in writing by one party upon or to the other party hereto, shall be deemed to have been duly given or served if mailed to the respective parties hereto at the address stated, or elsewhere, as each may direct by prior written notice: Northern States Power Company 414 Nicollet Mall - RN09 Minneapolis, Minnesota 55401 Attn: Manager, Fuel Resources Ramsey/Washington Resource Recovery Facility 2901 Maxwell Avenue Newport, Minnesota 55055 Attn: Plant Superintendent Elk River Resource Recovery Facility 10700 - 165th Ave. N. W. Elk River, Minnesota 55303 Attn: Plant Superintendent NRG Resource Recovery, Inc. 1221 Nicollet Mall Minneapolis, Minnesota 55401 Attn: Vice President Operations 11

17 14.0. ASSIGNMENT Neither party shall assign or transfer any interest in this Agreement without the prior written consent of the other party. Such consent shall not be unreasonably withheld. 15.0. GOVERNING LAW This Agreement shall be interpreted and construed according to the laws of the State of Minnesota. 16.0. REGULATORY REVIEW 16.1 NSP and NRG-RR agree that regulatory approval by the Minnesota Public Utilities Commission (MPUC) of the transactions covered by this Agreement or any amendment to this Agreement shall be a condition precedent to the effectiveness of this Agreement. Such approval shall be by written order. In accordance with the regulatory authority of the MPUC under the Minnesota Public Utilities Act, including, but not limited to, Minnesota Statues Sections 216B.09, 216B.23 and 216B.48 such written order must authorize recovery from ratepayers of the Minnesota jurisdiction portion of the amounts paid to NRG-RR by NSP under the terms of this Agreement or any amendment to this Agreement. 16.2 NSP shall promptly file with the MPUC an application under 216B.48 for any authority necessary to consummate this Agreement. NSP and NRG-RR shall cooperate and use their best efforts to secure approval from the MPUC. If the MPUC shall not approve the foregoing application in total and without modification or condition, NSP and NRG-RR may then mutually agree to amend this Agreement, or if mutual agreement is not reached, this Agreement shall become null and void 90 days after receipt of the final order. 17.0. TERMINATION OF PRIOR AGREEMENTS This Agreement when duly executed by both parties supersedes and replaces in its entirety all previous agreements both formal and informal whether written or oral between the two parties. 12

18 In Witness Whereof, the parties have caused this Agreement to be executed by their duly Authorized representatives as of the day and year written above. NRG RESOURCE RECOVERY, INC. NORTHERN STATES POWER COMPANY By: By: ---------------------------------- --------------------------------- K. E. Gelle C. J. Blair President Executive Vice President NRG Resource Recovery, Inc. Power Supply And: --------------------------------- P. D. Jones Vice President Operations NRG Resource Recovery, Inc. Approved as to Form: Approved as to Form: - ------------------------------------- ----------------------------------- Vice President & General Counsel Attorney 13

1 EXHIBIT 10.39 ADMINISTRATIVE SERVICES AGREEMENT THIS AGREEMENT, effective as of the 1st day of January, 1992, by and between Northern States Power Company, a Minnesota corporation (hereinafter called "NSP"), and NRG THERMAL CORPORATION, a Minnesota corporation (hereinafter called "Thermal") supersedes and replaces the Administrative Services Agreement dated January 1, 1985, between NSP and NORENCO Corporation, Thermal's predecessor in interest, which had been previously approved by the Minnesota Public Utilities Commission ("MPUC") pursuant to its Order dated March 18, 1986 in Docket No. E-002/M-86-21. WITNESSETH: WHEREAS, Thermal is a wholly-owned subsidiary of NRG Group, Inc., a wholly-owned subsidiary of NSP, and is authorized to engage in general non-utility business activities including, but not limited to, the design, construction, ownership and operation of steam transmission and supply facilities; and WHEREAS, Thermal needs from time to time to retain the services of certain NSP employees; and WHEREAS, NSP is ready and willing to provide and assign

2 such employees to Thermal if and when NSP determines such employees are available; and WHEREAS, the parties desire to enter into an agreement to provide for the rendering of and charging for certain services by each party to the other party, which services are not provided for in any other agreement between the parties; and WHEREAS, it is the intent of the parties that each party recover from the other party any administrative and general costs actually incurred by one party on behalf of the other party. NOW THEREFORE, the parties agree as follows: ARTICLE I PERSONNEL ASSIGNED 1.01 If available and upon request, NSP agrees to provide and assign certain NSP employees to Thermal. Determination of availability of such employees shall be at NSP's sole discretion. The NSP employees assigned to Thermal are specified in attached Appendix A which is incorporated by reference. Appendix A will be updated and amended from time to time by the mutual agreement of the parties. 2

3 ARTICLE II SERVICES RENDERED 2.01 If available and upon request or ratification, each party will, at its cost, render management, supervisory, construction, engineering, accounting, legal, financial and other similar services to the other party. ARTICLE III CHARGES 3.01 The charges to be billed and paid under this Agreement shall consist of actual costs for labor, transportation and employee expenses, materials and supplies and other expenses. These expenses are defined in attached Appendix B which is incorporated by reference. Thermal shall be charged according to the procedures specified in this Article III and in the attached Appendix C which is incorporated by reference. When one party renders services for which the other party is proportionately chargeable, the party receiving the services shall pay the proportional actual costs of the services. 3

4 Bills shall be rendered by the 20th of the month following the month in which the costs were incurred. Each month's bill shall be increased by 1% to cover handling costs, working capital requirements and miscellaneous costs. Bills shall be paid no later than 10 days following the date of the rendered bill. Interest shall accrue on payments which are overdue at the daily commercial prime rate in effect at the Norwest Bank of Minnesota, N.A. from the date that interest first accrues through the date of payment. ARTICLE IV REGULATION 4.01 This Agreement is subject to the review of any regulatory body which has jurisdiction. ARTICLE V ASSIGNMENT 5.01 This Agreement shall not be assigned by either party without first obtaining the written consent to the assignment from the other party. 4

5 ARTICLE VI TERM 6.01 This Agreement shall continue in effect unless cancelled by either party upon sixty (60) days prior written notice to the other party or by mutual agreement of the parties. ARTICLE VII GOVERNING LAW 7.01 This Agreement shall be construed in accordance with and be governed by the laws of the State of Minnesota. 5

6 IN WITNESS WHEREOF, the parties have caused this Agreement to be executed in their respective corporate names by their respective duty authorized officers on the day and year below written. NRG THERMAL CORPORATION NORTHERN STATES POWER COMPANY By Ronald J. Will By James T. Daudiet ---------------------------- ------------------------------------ Ronald J. Will James T. Daudiet Executive Vice President - Finance Its President and CEO Its and Chief Financial Officer --------------------------- ----------------------------------- Date February 24, 1992 Date February 24, 1992 -------------------------- ---------------------------------- 6

7 APPENDIX A NSP PERSONNEL ASSIGNED January 1, 1992 NRG THERMAL CORPORATION None 7

8 APPENDIX B COMPONENTS OF ACTUAL COSTS Labor Charges for engineering services shall be for time charged at an agreed upon billing rate by classification of employee. The billing rate shall include an average salary, by employee classification, plus engineering and supervision costs and indirect labor costs. The engineering services billing rates shall be reviewed and adjusted annually and at other times as necessary. Labor costs for all services, other than engineering services, shall be for the time charged at actual salary and wage rates paid to employees plus indirect labor costs. Indirect labor costs shall consist of non-productive labor costs (e.g., vacation, sickness and holidays) and other employee benefit costs (e.g., major medical, pension and life insurance). Transportation and Employee Expenses Transportation costs charged to either party shall be for actual miles or hours used. 8

9 Employee expenses shall consist of meals, lodging, transportation and other miscellaneous costs incurred by and reimbursable to employees when rendering services to the receiving party. Materials and Supplies The cost of materials and supplies charged to either party shall be actual costs plus purchasing and warehousing expenses and shipping expense. Other Expenses Costs included in the "other expenses" category shall include communication services, accounting, printing, postage, permits, and other miscellaneous costs directly attributable to work performed for the other party. Other Expenses also shall include miscellaneous proratable operating expenses, such as invoiced services, computer services, engineering, construction, research, testing lab, etc. 9

10 APPENDIX C ACCOUNTING AND CHARGING PROCEDURES Expenses as set forth below may be charged directly or through special work orders. Special work orders are issued to record costs for functions which are not assignable solely to either party. These work order costs shall be prorated on a proper ratio reflecting the benefit to the respective parties. Whenever a new work order is initiated involving costs that are assignable to both parties, it shall be approved by the appropriate officer or department head of each party. Work orders and applicable prorates shall be reviewed and revised as needed, and at least annually. LABOR Employees of one party may charge time to the other party on either a fixed payroll distribution basis or on an exception basis. Employees of one party charging time to the other party on a fixed payroll distribution basis should not charge time on an exception basis to the other party unless the service performed was not contemplated in determining the fixed payroll distribution. Employees of one party who engage in work solely or primarily for the 10

11 benefit of the other party on a regular basis, may charge their time on a fixed payroll distribution basis, based upon a time analysis. The hours charged shall be subject to review whenever the employee's duties change, whenever the function of the department changes, and on an annual basis. The party receiving charges for time should be advised of the name of the employee (or in the case of engineering services the classification of the employee), the service he or she performs and the percent of time engaged in work for the other party. These charges will be subject to review and approval by the department head or an officer of the party receiving those charges. Exception time charges must be reviewed and approved by the department head from which the service originates. Exception time charges received from one party also will be subject to review and approval by the department head or an officer of the receiving party. Charges for time from employees on bi-weekly and weekly payrolls should be handled in the same manner as described above. Transportation and Employee Expenses Transportation shall be recorded on transportation sheets for the actual miles or hours used for the benefit of the receiving company. The miles or 11

12 hours used shall be charged at prevailing rates. Employee expenses shall be charged on the basis of expenses submitted for reimbursement by employees and approved by the appropriate department head or officer. Materials and Supplies Materials and supplies provided by one party for the benefit of the other party shall be received by and charged upon the basis of requisition orders. Other Expenses Approved copies of invoices for materials or services or other appropriate documentation shall provide the accounting basis for these charges. 12

1 EXHIBIT 21.1 NRG SUBSIDIARY LIST APRIL 17, 2000 PLACE OF SUBSIDIARY NAME INCORPORATION 1. Arthur Kill Power LLC Delaware 2. Astoria Gas Turbine Power LLC Delaware 3. Bioconversion Partners, L.P. California 4. Brimsdown Power Limited England and Wales 5. Cabrillo Power I LLC Delaware 6. Cabrillo Power II LLC Delaware 7. Cadillac Renewable Energy LLC Delaware 8. Camas Power Boiler Limited Partnership Oregon 9. Camas Power Boiler, Inc. Oregon 10. Carolina Energy, Limited Partnership Delaware 11. Carquinez Strait Preservation Trust, Inc. California 12. Cobee Energy Development LLC Delaware 13. Cobee Holdings Inc. Delaware 14. Cogeneration Corporation of America Delaware 15. Collinsville Operations Pty Ltd Australia 16. Collinsville Power Joint Venture (unincorporated) Australia 17. Compania Boliviana de Energia Electrica S.A. Canada (Nova Scotia 18. Compania Electrica Central Bulo Bulo S.A. Bolivia 19. Coniti Holding B.V. Netherlands 20. Connecticut Jet Power LLC Delaware 21. Croatia Power Group Cayman Islands 22. Crockett Cogeneration, A California Limited Partnership California 23. Curtis/Palmer Hydroelectric Company New York 24. Cypress Energy Partners, Limited Partnership Delaware 25. Devon Power LLC Delaware 26. Dunkirk Power LLC Delaware 27. ECK Generating, s.r.o. Czech Republic 28. El Segundo Power, LLC Delaware 29. Elk River Resource Recovery, Inc. Minnesota 30. Energeticke Centrum Kladno, s.r.o. Czech Republic 31. Energy Developments Limited Australia (Queensland) 32. Energy Investors Fund, L.P. Delaware 33. Energy National, Inc. Utah 34. Enfield Energy Centre Limited England and Wales Page 1

2 PLACE OF SUBSIDIARY NAME INCORPORATION 35. Enfield Holdings B.V. Netherlands 36. Enfield Operations (UK) Limited England and Wales 37. Enfield Operations, L.L.C. Delaware 38. ENI Chester, Limited Partnership Oregon 39. ENI Crokett Limited Partnership Oregon 40. ENI Curtis Falls, Limited Partnership Oregon 41. Enifund, Inc. Utah 42. Enigen, Inc. Utah 43. ESOCO Crockett, Inc. Oregon 44. ESOCO Fayetteville, Inc. Oregon 45. ESOCO Molokai, Inc. Utah 46. ESOCO Orrington, Inc. Utah 47. ESOCO Soledad, Inc. Utah 48. ESOCO Wilson, Inc. Oregon 49. ESOCO, Inc. Utah 50. Four Hills, LLC Delaware 51. Gladstone Power Station Joint Venture (unincorporated) Australia 52. Graystone Corporation Minnesota 53. Gunwale B.V. Netherlands 54. Huntley Power LLC Delaware 55. Interenergy Limited Ireland 56. Inversiones Bulo Bulo S.A. Bolivia 57. Jackson Valley Energy Partners, L.P. California 58. Kanel Kangal Elektrik Limited Sirketi Turkey 59. Kiksis B.V. Netherlands 60. Killingholme Generation Limited United Kingdom 61. Killingholme Holdings Limited United Kingdom 62. Killingholme Power Limited United Kingdom 63. Kingston Cogeneration Limited Partnership Canada (Ontario) 64. Kissimee Power Partners, Limited Partnership Delaware 65. Kladno Power (No. 1) B.V. Netherlands 66. Kladno Power (No. 2) B.V. Netherlands 67. Kraftwerk Schkopau Betriebsgesellschaft mbH Germany 68. Kraftwerk Schkopau GbR Germany 69. KUSEL Kutahya Seyitomer Elektrik Limited Sirketi 70. Lakefield Junction LLC Delaware 71. Lakefield Junction LP Delaware 72. Lambique Beheer B.V. Netherlands 73. Landfill Power LLC Wyoming Page 2

3 PLACE OF SUBSIDIARY NAME INCORPORATION 74. Langage Energy Park Limited United Kingdom 75. Le Paz Incorporated Minnesota 76. LFG Partners, L.L.C. Delaware 77. Long Beach Generation LLC Delaware 78. Long Island Cogeneration, L.P. New York 79. Louisiana Energy Services, L.P. Delaware 80. Louisiana Generating LLC Delaware 81. Loy Yang Power Management Pty Ltd Australia (Victoria) 82. Loy Yang Powers Partners Australia 83. Loy Yang Power Projects Pty Ltd Australia (Victoria) 84. Maine Energy Recovery Company Maine 85. Matra Powerplant Holding B.V. Netherlands 86. MIBRAG B.V. Netherlands 87. Mid-Continent Power Company, L.L.C. Delaware 88. Middletown Power LLC Delaware 89. Minnesota Methane Holdings LLC Delaware 90. Minnesota Methane II LLC Delaware 91. Minnesota Methane LLC Wyoming 92. Minnesota Waste Processing Company, L.L.C. Delaware 93. Mitteldeutsche Braunkohlengesellschaft mbH Germany 94. MM Albany Energy LLC Delaware 95. MM Biogas Power LLC Delaware 96. MM Burnsville Energy LLC Delaware 97. MM Corona Energy LLC Delaware 98. MM Cuyahoga Energy LLC Delaware 99. MM El Sobrante Energy LLC Delaware 100. MM Erie Power LLC Delaware 101. MM Ft. Smith Energy LLC Delaware 102. MM Hackensack Energy LLC Delaware 103. MM Hartford Energy LLC Delaware 104. MM Lopez Energy LLC Delaware 105. MM Lowell Energy LLC Delaware 106. MM Martinez Energy LLC Delaware 107. MM Nashville Energy LLC Delaware 108. MM Northern Tier Energy LLC Delaware 109. MM Phoenix Energy LLC Delaware 110. MM Prima Deshecha Energy LLC Delaware 111. MM Prince William Energy LLC Delaware Page 3

4 PLACE OF SUBSIDIARY NAME INCORPORATION 112. MM Riverside LLC Delaware 113. MM San Diego LLC Delaware 114. MM SKB Energy LLC Delaware 115. MM Spokane Energy LLC Delaware 116. MM Tacoma LLC Delaware 117. MM Tajiguas Energy LLC Delaware 118. MM Tauton Energy LLC Delaware 119. MM Tonoka Farms Energy LLC Delaware 120. MM Tri-Cities Energy LLC Delaware 121. MM Tulare Energy LLC Delaware 122. MM West Covina LLC Delaware 123. MM Woodville Energy LLC Delaware 124. MM Yolo Power LLC Delaware 125. MMSB Transco Holdings LLC Delaware 126. Montville Power LLC Delaware 127. Mt. Poso Cogeneration Company, A California Limited California Partnership 128. NEO Albany, L.L.C. Delaware 129. NEO Burnsville, LLC Delaware 130. NEO Corona LLC Delaware 131. NEO Corporation Minnesota 132. NEO Cuyahoga, LLC Delaware 133. NEO Edgeboro, LLC Delaware 134. NEO El Sobrante LLC Delaware 135. NEO Erie LLC Delaware 136. NEO Findlay, LLC Delaware 137. NEO Fitchburg LLC Delaware 138. NEO Ft. Smith LLC Delaware 139. NEO Hackensack, LLC Delaware 140. NEO Hartford, LLC Delaware 141. NEO Landfill Gas Holdings Inc. Delaware 142. NEO Landfill Gas Inc. Delaware 143. NEO Lopez Canyon LLC Delaware 144. NEO Lowell LLC Delaware 145. NEO Martinez LLC Delaware 146. NEO MESI LLC Delaware 147. NEO Nashville LLC Delaware 148. NEO Northern Tier LLC Delaware 149. NEO Phoenix LLC Delaware 150. NEO Prima Deshecha LLC Delaware Page 4

5 PLACE OF SUBSIDIARY NAME INCORPORATION 151. NEO Prince William, LLC Delaware 152. NEO Riverside LLC Delaware 153. NEO San Bernardino LLC Delaware 154. NEO San Diego LLC Delaware 155. NEO SKB LLC Delaware 156. NEO Spokane LLC Delaware 157. NEO Tacoma, L.L.C. Delaware 158. NEO Tajiguas LLC Delaware 159. NEO Taunton LLC Delaware 160. NEO Tomoka Farms LLC Delaware 161. NEO Tri-Cities LLC Delaware 162. NEO Tulare LLC Delaware 163. NEO West Covina LLC Delaware 164. NEO Woodville LLC Delaware 165. NEO Yolo LLC Delaware 166. North American Thermal Systems Limited Liability Ohio Company 167. Northbrook Acquisition Corp. Delaware 168. Northbrook Carolina Hydro, L.L.C. Delaware 169. Northbrook Energy, L.L.C. Delaware 170. Northeast Generation Holding LLC Delaware 171. Norwalk Power LLC Delaware 172. NR(Gibraltar) Gibralter 173. NRG Affiliate Services Inc. Delaware 174. NRG Artesia Operations Inc. Delaware 175. NRG Arthur Kill Operations Inc. Delaware 176. NRG Asia-Pacific, Ltd. Delaware 177. NRG Astoria Gas Turbine Operations Inc. Delaware 178. NRG Cabrillo Power Operations Inc. Delaware 179. NRG Cadillac Inc. Delaware 180. NRG Cadillac Operations Inc. Delaware 181. NRG Caymans Company Cayman Islands 182. NRG Caymans-C Cayman Islands 183. NRG Caymans-P Cayman Islands 184. NRG Central U.S. LLC Delaware 185. NRG Collinsville Operating Services Pty Ltd Australia 186. NRG Connecticut Affiliate Services Inc. Delaware 187. NRG Connecticut Generating LLC Delaware 188. NRG del Coronado Inc. Delaware 189. NRG Development Company Inc. Delaware Page 5

6 PLACE OF SUBSIDIARY NAME INCORPORATION 190. NRG Devon Operations Inc. Delaware 191. NRG Dunkirk Operations Inc. Delaware 192. NRG Eastern LLC Delaware 193. NRG El Segundo Operations Inc. Delaware 194. NRG Energeticky Provoz, s.r.o. Czech Republic 195. NRG Energy Center Grand Forks LLC Delaware 196. NRG Energy Center Minneapolis LLC Delaware 197. NRG Energy Center Pittsburgh LLC Delaware 198. NRG Energy Center Rock Tenn LLC Delaware 199. NRG Energy Center San Diego LLC Delaware 200. NRG Energy Center San Francisco LLC Delaware 201. NRG Energy Center Washco LLC Delaware 202. NRG Energy CZ, s.r.o. Czech Republic 203. NRG Energy Development GmbH Germany 204. NRG Energy Jackson Valley I, Inc. California 205. NRG Energy Jackson Valley II, Inc. California 206. NRG Energy Ltd. England and Wales 207. NRG Energy PL Sp. z.o.o. Warsaw, Poland 208. NRG Energy, Inc. Delaware 209. NRG Gladstone Operating Services Pty Ltd Australia 210. NRG Gladstone Superannuation Pty Ltd Australia 211. NRG Huntley Operations Inc. Delaware 212. NRG International Development Inc. Delaware 213. NRG International II Inc. Delaware 214. NRG International Services Company Delaware 215. NRG International, Inc. Delaware 216. NRG Lakefield Inc. Delaware 217. NRG Lakefield Junction LLC Delaware 218. NRG Latin America Inc. Delaware 219. NRG Long Beach Operations Inc. Delaware 220. NRG Louisiana LLC Delaware 221. NRG Mextrans Inc. Delaware 222. NRG Middletown Operations Inc. Delaware 223. NRG Montville Operations Inc. Delaware 224. NRG Morris Operations Inc. Delaware 225. NRG New Roads Generating LLC Delaware 226. NRG New Roads Holdings LLC Delaware 227. NRG Northeast Affiliate Services Inc. Delaware 228. NRG Northeast Generating LLC Delaware Page 6

7 PLACE OF SUBSIDIARY NAME INCORPORATION 229. NRG Norwalk Harbor Operations Inc. Delaware 230. NRG Oklahoma Operations Inc. Delaware 231. NRG Operating Services, Inc. Delaware 232. NRG Oswego Harbor Power Operations Inc. Delaware 233. NRG PacGen Inc. Delaware 234. NRG Pittsburgh Thermal Inc. Delaware 235. NRG Power Marketing Inc. Delaware 236. NRG Rocky Road LLC Delaware 237. NRG San Diego Inc. Delaware 238. NRG San Francisco Thermal Inc. Delaware 239. NRG Services Corporation Delaware 240. NRG South Central Generating LLC Delaware 241. NRG Sunnyside Operations GP Inc. Delaware 242. NRG Sunnyside Operations LP Inc. Delaware 243. NRG Thermal Corporation Delaware 244. NRG Thermal Operating Services LLC Delaware 245. NRG Victoria I Pty Ltd Australia 246. NRG Victoria II Pty Ltd Australia 247. NRG Victoria III Pty Ltd Australia 248. NRG West Coast Inc. Delaware 249. NRG Western Affiliate Services Inc. Delaware 250. NRGenerating Energy Trading Ltd. United Kingdom 251. NRGenerating Holdings (No. 1) B.V. Netherlands 252. NRGenerating Holdings (No. 11) B.V. Netherlands 253. NRGenerating Holdings (No. 12) B.V. Netherlands 254. NRGenerating Holdings (No. 13) B.V. Netherlands 255. NRGenerating Holdings (No. 14) B.V. Netherlands 256. NRGenerating Holdings (No. 15) B.V. Netherlands 257. NRGenerating Holdings (No. 16) B.V. Netherlands 258. NRGenerating Holdings (No. 17) B.V. Netherlands 259. NRGenerating Holdings (No. 18) B.V. Netherlands 260. NRGenerating Holdings (No. 19) B.V. Netherlands 261. NRGenerating Holdings (No. 20) B.V. Netherlands 262. NRGenerating Holdings (No. 21) B.V. Netherlands 263. NRGenerating Holdings (No. 22) B.V. Netherlands 264. NRGenerating Holdings (No. 23) B.V. Netherlands 265. NRGenerating Holdings (No. 3) B.V. Netherlands 266. NRGenerating Holdings (No. 4) B.V. Netherlands 267. NRGenerating Holdings (No. 5) B.V. Netherlands 268. NRGenerating Holdings (No. 6) B.V. Netherlands Page 7

8 PLACE OF SUBSIDIARY NAME INCORPORATION 269. NRGenerating Holdings (No. 7) B.V. Netherlands 270. NRGenerating Holdings (No. 8) B.V. Netherlands 271. NRGenerating Holdings (No. 9) B.V. Netherlands 272. NRGenerating Holdings GmbH Switzerland 273. NRGenerating International B.V. Netherlands 274. NRGenerating Rupali B.V. Netherlands 275. NRGenerating, Ltd. United Kingdom 276. O Brien Biogas (Mazzaro), Inc. Delaware 277. O Brien Biogas IV LLC Delaware 278. O Brien California Cogen Limited California 279. O Brien Cogeneration, Inc. II Delaware 280. O Brien Standby Power Energy, Inc. Delaware 281. Okeechobee Power I, Inc. Delaware 282. Okeechobee Power II, Inc. Delaware 283. Okeechobee Power III, Inc. Delaware 284. ONSITE Energy, Inc. Oregon 285. ONSITE Funding Corporation Oregon 286. ONSITE Limited Partnership No. 1 Oregon 287. ONSITE Marianas Corporation Commonwealth of the Northern Marianas Islands 288. ONSITE Soledad, Inc. Oregon 289. ONSITE/US Power Limited Partnership No. 1 New Jersey 290. Orrington Waste, Ltd. Limited Partnership Oregon 291. Oswego Harbor Power LLC Delaware 292. P.T. Dayalistrik Pratama Indonesia 293. Pacific Crockett Energy, Inc. Utah 294. Pacific Crockett Holdings, Inc. Oregon 295. Pacific Generation Company Oregon 296. Pacific Generation Development Company Oregon 297. Pacific Generation Holdings Company Oregon 298. Pacific Generation Resources Company Oregon 299. Pacific Kingston Energy, Inc. Canada (Ontario) 300. Pacific Orrington Energy, Inc. Oregon 301. Pacific Recycling Energy, Inc. Oregon 302. Pacific-Mt. Poso Corporation Oregon 303 Penobscot Energy Recovery Company, Limited Maine Partnership 304. Pittsburgh Thermal, Limited Partnership Delaware 305. Power Operations, Inc. Delaware Page 8

9 PLACE OF SUBSIDIARY NAME INCORPORATION 306. Project Finance Fund III, L.P. Delaware 307. Pyro-Pacific Operating Company California 308. Rocky Road LLC Delaware 309. RSD Power Partners, L.P. Delaware 310. Saale Energie GmbH Germany 311. Saale Energie Services GmbH Germany 312. Sachsen Holding B.V. Netherlands 313. San Bernardino Landfill Gas Limited Partnership, a California California limited partnership 314. San Francisco Thermal, Limited Partnership Delaware 315. San Joaquin Valley Energy I, Inc. California 316. San Joaquin Valley Energy IV, Inc. California 317. San Joaquin Valley Energy Partners I, L.P. California 318. San Joaquin Valley Energy Partners IV, L.P. California 319. Scoria Incorporated Minnesota 320. Scudder Latin American Power I-C L.D.C. Cayman Islands, British West Indies 321. Scudder Latin American Power II-C L.D.C. Cayman Islands, British West Indies 322. Scudder Latin American Power II-Corporation A Cayman Islands, British West Indies 323. Scudder Latin American Power II-Corporation B Cayman Islands, British West Indies 324. Scudder Latin American Power II-P L.D.C. Cayman Islands, British West Indies 325. Scudder Latin American Power I-P L.D.C. Cayman Islands, British West Indies 326. Somerset Operations Inc. Delaware 327. Somerset Power LLC Delaware 328. South Central Generation Holding LLC Delaware 329. Sterling (Gibraltar) Gibraltar 330. Sterling Luxembourg (No. 1) s.a.r.l. Luxembourg 331. Sterling Luxembourg (No. 2) s.a.r.l. Luxembourg 332. Sterling Luxembourg (No. 3) s.a.r.l. Luxembourg 333. Sterling Luxembourg (No. 4) s.a.r.l. Luxembourg Page 9

10 PLACE OF SUBSIDIARY NAME INCORPORATION 334. STS Hydropower Ltd. Michigan 335. STS Turbine & Development, L.L.C. Delaware 336. Suncook Energy LLC Delaware 337. Sunnyside Cogeneration Associates Utah 338. Sunnyside Operations Associates L.P. Delaware 339. Sunshine State Power (No. 2) B.V. Netherlands 340. Sunshine State Power B.V. Netherlands 341. Tacoma Energy Recovery Company Delaware 342. The PowerSmith Cogeneration Project, Limited Delaware Partnership 343. Tosli (Gibraltar) B.V. Netherlands 344. Tosli Acquisition B.V. Netherlands 345. Tosli Investments N.V. Netherlands 346. Tosli Luxembourg (No. 1) s.a.r.l. Luxembourg 347. Tosli Luxembourg (No. 2) s.a.r.l. Luxembourg 348. Turners Falls Limited Partnership Massachusetts 349. Wainstones Power Limited England and Wales 350. WCP (Generation) Holdings LLC Delaware 351. West Coast Power LLC Delaware Page 10

1 Exhibit 23.1 CONSENT OF INDEPENDENT ACCOUNTANTS We hereby consent to the use in this Registration Statement on Form S-1 of our report dated March 17, 2000 relating to the consolidated financial statements of NRG Energy, Inc., and our report dated March 7, 2000 relating to the curve-out financial statements of Cajun Electric, which appear in such Registration Statement. We also consent to the references to us under the headings "Experts" and "Selected Financial Data" in such Registration Statement. PricewaterhouseCoopers LLP Minneapolis, Minnesota April 18, 2000

5 This schedule contains financial information extracted from the December 31, 1999 Financial Statements included in the Company's Form 10-K and is qualified in its entirety by reference to such Form 10-K. 1,000 YEAR DEC-31-1999 JAN-01-1999 DEC-31-1999 31,483 0 126,562 186 119,181 323,970 2,076,172 156,849 3,431,684 524,355 1,941,398 0 0 1 893,653 3,431,684 432,518 500,018 269,900 390,498 (78,406) 0 93,376 31,114 (26,081) 57,195 0 0 0 57,195 0 0