First Quarter 2004 Financial Results

1. First Quarter 2004 Financial Results May 11, 2004

2. Safe Harbor Statement This Investor Presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are subject to certain risks, uncertainties and assumptions and typically can be identified by the use of words such as “expect,” “estimate,” “anticipate,” “forecast,” “plan,” “believe” and similar terms. Such forward-looking statements include, but are not limited to, expected earnings, future growth and financial performance, timing of debt maturities, resolution of litigation and bankruptcy claims, the hiring of new independent auditors, the successful closing of announced transactions, the successful implementation of our acquisition and repowering strategy, the outcome of hearings on our RMR agreements and cost tracker for scheduled expenses, and FERC’s approval of the basic LICAP market design . Although NRG believes that its expectations are reasonable, it can give no assurance that these expectations will prove to have been correct, and actual results may vary materially. Factors that could cause actual results to differ materially from those contemplated above include, among others, general economic conditions, hazards customary in the power industry, competition in wholesale power markets, the volatility of energy and fuel prices, failure of customers to perform under contracts, changes in the wholesale power markets and related government regulation, the condition of capital markets generally, our ability to access capital markets, our substantial indebtedness and the possibility that we may incur additional indebtedness, adverse results in current and future litigation, delays in hiring new independent auditors, delays in or failure to meet closing conditions in announced transactions, failure to identify or successfully implement acquisitions and repowerings, adverse rulings on our RMR agreements and cost tracker for scheduled expenses, resulting in us refunding certain payments received to date, and FERC not approving the basic LICAP market design. NRG undertakes no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors that could cause NRG’s actual results to differ materially from those contemplated in the forward-looking statements included in this Investor Presentation should be considered in connection with information regarding risks and uncertainties that may affect NRG's future results included in NRG's filings with the Securities and Exchange Commission at www.sec.gov.

3. Agenda • Progress Year-to-Date • Q1 Financial Results • Strategy

4. Highlights • Strong first quarter operating performance • $266 million in adjusted EBITDA • $316 million in Free Cash Flow • Liquidity continues to strengthen – $1.4 billion at end of Q1 • Post-Chapter 11 emergence plan solidly on track • Internal reorganization proceeding in accordance with plan

5. The First 100 Days’ Objectives Financial Priorities 1. Simplify capital structure 2. Ensure our liquidity 3. Reduce borrowing costs Operational Priorities 1. Keep plants running safely, reliably and efficiently 2. Increase contracted portion of merchant generation 3. Maintain momentum in asset sale program 4. Resolve commercial issues with Connecticut plants Organizational Priorities 1. New CFO 2. Expedited phase-out of external advisers 3. Redirected management team 4. Restructured corporate organization

6. Operational Performance - Core Regions • Our plants in the Northeast dealt successfully with periods of unusually cold weather • Our fuel diverse fleet of generators in New York and Connecticut, helped maintain affordable electric prices during gas price spikes • The Western Region successfully completed thirteen planned outages at seven different plants Generation(MWh) Equivalentavailability% Average heatrate(Btu / kWh) Net capacityfactor% Net ownedcapacityMW In-marketavailability% Region Northeast 2.9 million 81 11,400 38 7,884 95 South Central 2.8 million 85 10,700 57 2,469 98 0.9 million 72 11,600 18 1,321 99 West

7. Operational – 2004 Hedging Activity GigaWatt hours 10,000 “In the money”Generation (1) 8,000 Energy Sales (2) 6,000 Fuel Hedges (3) 4,000 2,000 0 Entergy New York PJM Nepool For the balance of 2004, the Company has hedged 48% of “In the money” generation with forward energy commitments and has locked in the energy margin from those sales by purchasing 80% of the forward fuel requirements (1) ‘In the money’ generation is derived by multiplying the forward positive spark spread (on an hourly basis) by the available capacity of each unit and aggregating by region (2) Energy sales are actual monthly forward sales, including load serving contract commitments (3) Fuel Hedges are actual fuel purchases converted, according to each plant’s heat rate, to an equivalent amount of generation (MWh)

8. Asset Sales - 2004 • We continue to make progress rationalizing the Company’s non-core assets for value: Actual or expected cash proceeds (Millions) Balance Sheet Debt (Millions) Name Location Status Calpine Cogen Various, U.S. $3 N/A Completed PERC Maine $17 $25 Completed Loy Yang A Australia $27 N/A Completed Cobee Bolivia $50 $24 Completed Batesville Mississippi $27 $292 Executed PSA Others (4) Various $20 $45 Executed PSAs TOTAL $144 $386

9. Connecticut Status RMR Agreements • FERC has approved, subject to hearing and refund, NRG’s RMR agreements for Middletown, Montville and Devon units 11-14 (1,392 MW in total) • These RMR agreements will remain in effect until the LICAP market is implemented • FERC has also approved, subject to hearing and refund, NRG’s Cost Tracker for scheduled expenses incurred until LICAP implementation • The RMR Agreements, together with the Cost Tracker, will cover NRG’s cost of service for Middletown, Montville and Devon 11-14 until the LICAP market is implemented • FERC had previously approved, subject to hearing and refund, an RMR Agreement for Devon 7 & 8 although ISO-NE recently notified NRG that one unit is not needed for reliability after April 2004 - as a result, NRG plans to retire Unit 8 in May. Locational Installed Capacity (LICAP) market • Proposed LICAP market in New England that would pay Norwalk, Connecticut Jet Power, Middletown, Montville and Devon 11-14 (1,812 MW in total) $5.34 per kW-month • Should provide a positive cash flow for the Connecticut fleet as a whole • FERC is expected to approve the basic LICAP market design sometime this summer * These RMR agreements are expected to contribute up to $30 million of revenue per quarter *

10.            Current Objectives: Checklist Financial Priorities $2.7 billion refinanced two-tier security structure withweighted average cost of 6.8% (revolver undrawn) 1. Simplify capital structure Liquidity of nearly $1.4 billion 2. Ensure our liquidity Corporate debt maturities of less than $53 million due over next six years 3. Reduce borrowing costs Operational Priorities 1. Keep plants running safely, reliablyand efficiently 96% IMA from coal-fired fleet, safety record better than industry standard 2. Increase contracted portion ofmerchant generation High percentage of coal requirements contracted andsubstantial portion of economic energy production sold forward 3. Maintain momentum in assetsale program $146 million in asset dispositions as of May 7, 2004 completed- $97 million in cash, $49 million in debt reduction 4. Resolve commercial issues with Connecticut plants RMR agreements approved by FERC. LICAP expected summer or fall 2004 Organizational Priorities Bob Flexon appointed as CFO 1. New CFO 2. Expedited phase-out ofexternal advisers Bankruptcy legal/financial advisers role severelycurtailed; positive 1Q ’04 cash flow impact 3. Redirected management team Corporate restructuring with regional emphasis Streamlined HQ to be relocated in core region 4. Restructured corporate organization

11. Financial Results

12. First Quarter Financial Highlights Strong financial operating performance • Reported net income of $30 million or $0.30 per share • Net income of $34 million or $0.34 per share excluding non-recurring items Improved liquidity • Net cash flow of $280 million • Liquidity increased by $188 million over last quarter Strengthened financial position • Refinanced $503 million of senior credit facility • Executed interest rate swaps lowering interest expense by $20 million over the next two years

13. Key Financial Highlights Operating revenues 621 Operating income 125 Net income 30 EBITDA 259 Adjusted EBITDA 266 $ millions

14. 1st Quarter 2004 Spark Spreads -North America Dark Gas Dual Fuel/Oil Spread1,2 SpreadSpread Spark Spread $99,813 $1,507 $31,013 (000s) $/MWh $31.23 $10.44 $39.15 1 Dark spread is the spread between energy prices and coal-fired generation costs 2 Does not include LaGen

15. North American Generation by Fuel Fuel Cost‘03 ($000) Fuel Cost$/MWh Fuel Cost Q1’04 ($000) Fuel Cost$/MWh Fuel MWh ‘03 MWh Q1 ‘04 Coal 20,971,991 328,303 15.65 5,554,714 91,734 16.51 Gas* 5,478,208 259,725 47.41 1,372,617 70,689 51.50 Oil* 1,771,370 106,038 59.86 793,684 46,302 58.34 Total 28,221,569 694,066 7,721,015 208,725 * Gas and Oil MWh are estimated since certain assets are dual fuel

16. EBITDA by Operating Segment ($ millions)EBITDA Adj Adj EBITDA Northeast 114.5 0.3 114.8 South Central 29.0 0.7 29.7 West Coast 33.4 0.0 33.4 Other NA 20.7 (0.4) 20.3 International 55.1 (0.1) 55.0 Alt. Energy & Services 16.3 0.7 17.0 Corp – Unallocated (10.0) 5.5 (4.5) Total 259.0 6.7 265.7

17. First Quarter Cash Flow $ millions Adjusted EBITDA 266 Interest Payments (43) Income Tax Payments (3) Other funds used by operations (20) FFO 200 Other working capital changes 25 Xcel settlement, net 125 CFO 350 Asset Sales 3 CapEx (35) Other Cash Used by Investing (2) FCF 316 Cash Used by Financing (38) Other sources of cash 2 Net Cash Flow 280

18. 2004 Sensitivity Analysis Results in the following change to2004 pre-tax income Factor Increased by: Factors Natural Gas $1.00/mmbtu $39.0 million Coal $1.00/ton ($0.2) million Oil $1.00/bbl ($1.4) million Interest rates 100 bps ($8.4) million Pricing as of 3/31/04, assuming current hedged positions

19. Liquidity 03/31/0412/31/03 Unrestricted: Domestic Unrestricted Cash 665 418 International Unrestricted Cash 168 134 Restricted Cash: Domestic 123 111 International 52 46 Total Cash 1,008 709 Letter of Credit Availability 137 248 Revolver Availability 250 250 Total Current Liquidity $1,395 $1,207 $ millions

20. Credit/Collateral $ millions March 31, 2004 Use of $250 million LC facility Xcel Energy (Resource Recovery) 33 Bank of New York (Peaker facility) 36 PMI support 44 Total $113 Uses of Collateral supporting PMI Letters of Credit* 49 Guarantees 56 Prepays/Deposits 28 Margin 24 Total $157 * Includes $5 million posted under separate LC facility

21. Near-Term Corporate Debt Maturities $ millions 20 15 10 5 0 2004 2005 2006 2007 2008 2009 * Less than $53 million in corporate debt maturities in aggregate over remainder of decade *

22. Other Items • Independent Auditors • Staff Appointment • Controller • Chief Risk Officer • Director Internal Audit • Director Planning and Analysis • Treasurer

23. Conclusions • Strong financial results, cash flow and liquidity • Improving our reporting to enhance understanding of results • Building the team

24. Strategy: “Beyond Back to Basics”

25. Current Stated Strategies Dynegy Calpine El Paso Williams Allegheny Reliant Cut G&A Sell non-core assets Economy–driven (demand side) price recovery Fuel mismatch Leverage off logistics platform(service provider) Trading Greenfield Mothball marginal assets Exit power business Corporate Strategy – Industry Perspective 1997 1998 1999 2000 2001 2002 2003 2004 Each wholesale power generation company represents a different commodity risk proposition but their overall strategies have stayed in lockstep with each other IPP Industry Strategies MPoM MPoM MPoM MPoM BtB BtB BtB MPoM “Asset-light” Trading

26. NRG – Back to Basics Our Back to Basics strategy is in full swing and visible progress is being made: Reduced corporate burden 33% reduction in corporate headcount Sale of non-core assets $293 million in cash and $672 million in debt reduction in 2003 and year to date 2004 with more to come Delevering of balance sheet In connection with asset sales and with mandatory offer Optimizing plant operations / Investment in PRB conversion, fuel handling processes coal handling and environmental remediation Fixing Connecticut and Connecticut on track; on to California California

27. How are We Making Money: Diversified Asset Portfolio* Northeast Our Competitive Advantages • Sizeable asset base in the right markets • Long term contracts / relationships with retail cooperatives in South Central • Locational advantage • Healthy balance sheet • Flexibility to act in best interest of stakeholders West Oil2,350 MW 30% Coal 2,407 MW30% Gas 693 MW 56% Dual Fuel 628 MW 44% Dual Fuel 2,284 MW 29% Gas842 MW 11% South Central • Core Regions: • Northeast • South Central • West Gas 980 MW 40% Coal 1,489 MW 60% Our Competitive Advantages • Sizeable asset base in the right markets • Long-term contracts / relationships with retail cooperatives in South Central • Locational advantage • Healthy balance sheet • Flexibility to act in best interest of stakeholders Relative Weaknesses • Aging fleet • Gaps in our ability to serve load shaped contracts Fuel, dispatch and market diversified asset portfolio * Other North America includes 4,172 MW outside of core regions

28. Market Environment in whichWe Operate On the deregulation / reregulation spectrum, we are entering a period of stasis. The five ISOs will move forward methodically to refine their market model. Other regions are static. Further utility disaggregation is unlikely. Industry consolidation, while desirable, necessary and inevitable, will be delayed by the merchant generation industry’s current debt mountain. Supply-demand imbalance has peaked, but how long we remain in the commodity price cycle trough is an open issue. The timing of the correction depends much more on the actions of industry participants (supply) than on the strength of economic recovery (demand). While one can argue about the sustainability of currently high gas prices, higher gas volatility (on a delivered basis) is a near certainty. And now Eastern coal has shown more volatility. Deregulation / Reregulation Industry Structure Market Fundamentals Role of Fuel

29. 1 MUST own a generation portfolio at a competitive cost relative to replacement cost 2 MUST be geographically diversified, in multiple markets Keys to Success in Merchant Generation Industry: Four fundamentals Four imperatives • Capital intensive - yes;Labor intensive - no • Highly cyclical, inelastic demand, supply driven • Pure commodity, but inability to store cause very high volatility 3 MUST have scale in key markets 4 MUST develop and expand our route to market • Assets relatively illiquid and generally movable

30. Assessing NRG Relative to the Four Imperatives Competitive Generation Excellent. $350/kW enterprise value across fleet – 50% discount to replacement cost Geographic Diversity Excellent. Core – 3 domestic markets and 2 international markets Scale Better than average. One of the bigger generators in the Northeast; but not scale in the true sense Route to Market Average. No retail customers, trading activity slowly expanding -

31. Hedging – in the Future What are the elements of a successful strategy to hedge a substantial portion of our generation capacity with retail load providers? • Generation which is price competitive on both a SRMC and LRMC basis; • Generation that competitively serves load-shaping requirements through base, intermediate and peaking capacity; • Generation, from various fuels, such that we can offer the retail load providers at least a partial hedge against gas price spikes We must own . . . . . . plus it helps if we have . . . • The scale to negotiate as equals • Limited or no competitors with comparable capabilities

32. Brownfield Development – an Opportunity and a Necessity Our key assets, while not as old as they seem, are aging Typical life expectancy range of a steam boiler with typical maintenance based on equivalent operating years. Years Age (years) Equivalent Operating Years The redevelopment of brownfield coal sites using clean coal technology should be cheaper, quicker and cleaner

33. Repowering Opportunities 2008 and Beyond Brownfield sites provide a distinct advantage in siting new generation projects due to existing infrastructure and transmission access. • What are the ingredients to brownfield success? • Advance planning • Cheaper, quicker, cleaner • Immediate relief • Long-term PPA New Capacity(net MW) Replaced(MW) Status Project El Segundo Combined Cycle 618 350 Planning & Permitting Big Cajun Supercritical Coal-Fired 675 New Permitting Arthur Kill Combined Cycle 600 300 Concept Big Cajun Repowering Concept Dunkirk Repowering 675 600 Concept Encina Combined Cycle 880 300 - 900 Concept Huntley Repowering 675 700 Concept Indian River Repowering 675 - 900 182 - 767 Concept Somerset Repowering 250 - 450 112 Concept Norwalk Harbor Combined Cycle 659 0 Concept Middletown Combined Cycle 810 400 Concept

34. Acquisitions - Why? Why would a company that aggressively acquired its way into Chapter 11 consider an active acquisition strategy just a few months after emergence? • Economies of scale (G&A, operations, procurement) • Average down portfolio LRMC recovery (EV/kW capacity) • Increase market diversity • Enhance ability to successfully contract with retail load providers • Improve optionality in capacity markets • Secure fuel supply for our plant • Grow earnings and earnings potential (but not at the expense of the balance sheet)

35. Select Acquisitions – Enhancing our Regional Businesses At a time when power plants are selling at a significant discount to replacement cost, we may have attractively priced opportunities to fill out gaps in our regional line-ups. = Our line-up range Upstate New York merit order Entergy merit order $/MWh $/MWh 120 120 $6.20/MMBtu gas $6.20/MMBtu gas $4.20/MMBtu gas $4.20/MMBtu gas 100 100 80 80 60 60 40 40 20 20 0 0 0 10,000 20,000 30,000 40,000 50,000 0 500 1,000 1,500 2,000 2,500 MWs MWs

36. NRG: Working Towards a Super-Regional Business Model We are transitioning NRG from a loose collection of power plants into three coherent regional businesses, each focused on developing as a foundation to their businesses, commercial relationships with the in-market retail load providers Region Northeast South Central West Total MWs 180,000 50,000 60,000 Our MWs 7,884 2,469 1,321 (2,692 gross) Market Share 4% 5% 2% (4% gross) Principal Strength Base load coal Base load coal /long term contracts Locational advantage PrincipalVulnerability Reduction intransmission constraints Shortfall of our generation relative to load we serve Lack of capacitymarket

37. Summary - The New NRG Extracting maximum value from existing fleet Reinvestment in repowering life extension of key assets Northeast WestCoast SouthCentral Selective acquisitions to fill out regional line-ups Objective: To create a set of regional businesses with sustainable low (total) cost, fuel diversified asset portfolio competitively positioned to secure their key customers

39. Supplemental information

40. Adjusted EBITDA Reconciliation The following table summarizes the calculation of EBITDA and provides a reconciliation to net income/(loss) for the periods indicated: Reorganized NRG Predecessor NRG March 31, 2004March 31, 2003 (Dollars in thousands) Net Income / (Loss) $ 30,235 $ (12,632) Plus: Income Tax Expense 14,208 32,878 Interest expense, excluding amortization of debt issuance costs and debt discount/ (premium) noted on the following page 78,543 169,345 Depreciation and amortization 58,637 64,071 WCP CDWR contract amortization (included in equity in earnings of unconsolidated affiliates) 30,968 ---- Amortization of power contracts 16,477 ---- Amortization of emission credits 6,270 ---- Amortization of debt issuance costs and debt discount/(premium) 23,639 6,732 EBITDA $ 258,977 $ 260,394 Plus: (Income) on Discontinued Operations, net of Income taxes (2,391) (161,550) Corporate relocation charges 1,116 ---- Reorganization charges 6,250 ---- Restructuring and impairment charges ---- 22,136 Write downs and losses on sales of equity method investments 1,738 16,591 Adjusted EBITDA $ 265,690$ 137,571

41. Adjusted EBITDA Reconciliation (cont.) EBITDA, Adjusted EBITDA and adjusted net income are non-GAAP financial measures. These measurements are not recognized in accordance with GAAP and should not be viewed as an alternative to GAAP measures of performance. The presentation of Adjusted EBITDA and adjusted net income should not be construed as an inference that NRG’s future results will be unaffected by unusual or non-recurring items. EBITDA represents net income before interest, taxes, depreciation and amortization. EBITDA is presented because NRG considers it an important supplemental measure of its performance and believe debt-holders frequently use EBITDA to analyze operating performance and debt service capacity. EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our operating results as reported under GAAP. Some of these limitations are: • EBITDA does not reflect cash expenditures, or future requirements for capital expenditures, or contractual commitments; • EBITDA does not reflect changes in, or cash requirements for, working capital needs; • EBITDA does not reflect the significant interest expense, or the cash requirements necessary to service interest or principal payments, on debts; • Although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA does not reflect any cash requirements for such replacements; and • Other companies in this industry may calculate EBITDA differently than NRG does, limiting its usefulness as a comparative measure. Because of these limitations, EBITDA should not be considered as a measure of discretionary cash available to use to invest in the growth of NRG’s business. NRG compensates for these limitations by relying primarily on our GAAP results and using EBITDA and Adjusted EBITDA only supplementally. See the statements of cash flow included in the financial statements that are a part of this press release. Adjusted EBITDA is presented as a further supplemental measure of operating performance. Adjusted EBITDA represents EBITDA adjusted for reorganization, restructuring, impairment and corporate relocation charges, discontinued operations, and write downs and losses on the sales of equity method investments; factors which we do not consider indicative of future operating performance. The reader is encouraged to evaluate each adjustment and the reasons NRG considers it appropriate for supplemental analysis. As an analytical tool, Adjusted EBITDA is subject to all of the limitations applicable to EBITDA. In addition, in evaluating Adjusted EBITDA, the reader should be aware that in the future NRG may incur expenses similar to the adjustments in this presentation.