Locking in Future Cash Flow in a Volatile Commodity Market

Transcription

1 Locking in Future Cash Flow in a Volatile Commodity Market Lehman Brothers High Yield and Syndicated Loan Conference Orlando, Florida March 57, 2006

2 Safe Harbor Statement This Investor Presentation contains forwardlooking statements within the meaning of Section 27A of the Securities Act of 933 and Section 2E of the Securities Exchange Act of 934. Forwardlooking 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, guidance, believe and similar terms. Such forwardlooking statements include, but are not limited to, immediate and longterm consequences of Hurricane Katrina on operations, expected earnings, future growth and financial performance, the successful implementation of our acquisition and repowering strategy, expected benefits and results of capital allocation initiatives, expected benefits and EBITDA improvements of the FORNRG initiatives, and Big Cajun II Unit 4 construction and our success in securing commercial arrangements for the output of the facility. 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, weather conditions, 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, unanticipated outages at generation facilities, our ability to convert facilities to western coal successfully, adverse results in current and future litigation, failure to identify or successfully implement acquisitions and repowerings, the inability to implement value enhancing improvements to plant operations and companywide processes and the ability to file for RMR renewals successfully in the near term. NRG undertakes no obligation to update or revise any forwardlooking statements, whether as a result of new information, future events or otherwise. The adjusted EBITDA guidance is an estimate as of March 7, 2006 and is based on assumptions believed to be reasonable as of that date. NRG disclaims any current intention to update such guidance from March 7, The foregoing review of factors that could cause NRG s actual results to differ materially from those contemplated in the forwardlooking 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 2

3 Agenda General Overview 2005 Financial Results The NRG Credit 3

4 The New NRG: Creating Value Where We Began Where We Have Been Where We Are Going Exit from Chapter (2/03) Beyond Back to Basics Management not distracted by legacy issues Streamlined business hin value optimizing way Demonstrated record of returning capital to shareholders Current Intrinsic Growth (e.g. FORNRG ) Extrinsic Opportunity (e.g. TG Acquisition) Stakeholder Value Regionally focused wholesale power generation business Strong balance sheet with substantial cash flow Streamlined organization focused on value enhancing growth Reduced costs and improved risk mitigation from increased scale and diversity Support and enhancement of asset portfolio through dynamic trading and marketing activity Uniquely positioned, both financially and commercially, in the wholesale generation sector 4

5 Capital Structure Philosophy: Maintain Balance on the Balance Sheet $50.00 $ /24/2004: NRG completes Batesville sale, eliminating $292mm debt 0/2/2005: NRG announces Texas Genco Sept. 2005: NRG transaction completes $229mm bond repurchase $20.00 $5.00 $40.00 $0.00 $35.00 $30.00 $25.00 $20.00 $5.00 $0.00 /8/04 7/9/2004: NRG completes McClain sale, eliminating $57mm debt 3/8/04 5/8/04 7/8/04 2//2004: NRG completes Kendall sale, eliminating $450mm debt 9/8/04 /8/04 /8/05 Feb. 2005: NRG completes $46mm bond repurchase 2/27/2004: NRG completes senior debt refinancing and repurchase of 3mm common shares 3/8/05 5/8/05 NRG stock 7/8/05 8//2005: NRG completes $250mm ASR 2/6/2005: NRG announces Audrain sale, $42mm in liabilities elminated 9/8/05 NRG bonds /8/05 /8/06 3/8/06 $05.00 $00.00 $95.00 $90.00 $85.00 $80.00 Manage to BB metrics without regard to whether the agencies get it 5

6 Strategy: Capitalizing on Value Enhancing Opportunities in Multiple Regions Our Customer Focus Extracting maximum value from existing fleet West Northeast Acquisitions which enhance our existing regional lineups South Central Load serving entities in our core regions Willing to contract for their bulk generation needs at a price that factors in: Load variability Transmission constraints Fuel cost risks Drives Our Asset Mix Reinvestment through repowering key assets Texas Investments in complementary businesses Regionally focused, multifuel Assets across the merit order Located around transmission constraints Ability to procure, transport and trade all of the commodities involved in our business Asset scale, diversity and location provide value creation opportunities 6

7 Commercial Operations: Built on a Matched Book Foundation $/mmbtu Henry Hub Forward Prices 9/30/2005 2/28/2005 3/3/ Market weakness impacts front end of curve while back end remains supported by fundamentals NRG Combined Hedging Coal 7% 6% 2% 3% 32% 42% 67% 84% 77% 20% 79% 69% 8% 68% 5% 9% 58% 53% 20% 33% 9% 20% which continues to drive the long term value of the Company s hedging program Hedged Energy Open Energy Hedged Lignite Hedged PRB Hedged Other. Energy positions as of February 5,2006; excludes capacity, revenues and ancillary services. 2. Includes Northeast, South Central and ERCOT portfolios within the U.S portfolio and excludes Thermal and International. 3. Includes a cal07 000MW peak power put option purchase for an average strike price of $82, providing price protection at the same time preserving 75% of a potential upside value. 4. Includes financial gas swaps sold reflected in equivalent MWh by taking the volume in MMBtu's and divided by the forward market heat rate in ERCOT. 5. Percentage of coal based on total tons hedged for of 34.8 million, 32.4 million 24.7 million, 24.5 million, 2.9 million, respectively. 7

8 Portfolio Diversification: True Multiple Regional Businesses Texas,9 MW total 37% coal 0% nuclear 53% gas Up to 88% of expected revenue contracted through 2008 Northeast 7,099 MW total 29% coal 50% oil 2% gas 63% of expected gross margin contracted in 2006 RMR agreements Capacity market design developing South Central 2,395 MW total 62% coal 38% gas Longterm contracted through Western,044 MW total () 00% gas RMR contracts Resource adequacy requirement beginning June 2006 Australia,305 MW total 00% coal Contracted up to 72% through 2009 Germany 455 MW total 00% coal Contracted 00% through 202 NonGeneration Thermal 5 district energy systems Contracted longterm Other,468 MW Other North America (2) 56 MW Brazil 2 Resource Recovery facilities, Minnesota ()Does not include pending acquisition of Dynegy s share of West Coast Power totaling 904 MW, following close of transaction total regional capacity will be,948 MW (2)Includes 577 MW at Audrain which is being sold to AmerenUE and 65 MW at Rocky Road which is being sold to Dynegy, following the close of these transactions total regional capacity will be 726 MW A leading independent wholesale power generation company with over 25,000 total MW 8

9 2005 Financial Results

10 2005 Key Financial Results $ in millions Gross Margin () $,82 $,340 O&M G&A Interest Expense Adj EBITDA $603 $97 Adj EBITDA less MTM $722 $92 Asset Portfolio Changes 0 (244) With Portfolio Changes $722 $668 () Gross margin results include a $9 mm domestic net MTM economic hedging loss in 2005 and a $59 mm domestic net MTM gain in 2004 Gross margin, excluding MTM impact of economic hedges, increased by $79 million. Driven by: + Higher demand and prices for Northeast generation + Sales of excess emissions allowances Partially offset by: South Central purchased energy Portfolio changes ($80 million) EBITDA improvement, net of asset portfolio changes, achieved through higher margins and includes over $50 million incremental O&M investment to improve plant performance 0

11 Cash Flow $ in millions Q4 FY FY Adjusted EBITDA $240 $603 $97 Interest Payments Cash (68) (239) (295) Income Tax Cash (2) (2) (34) Unrealized (Gains)/Losses on Derivatives (09) 43 (74) Collateral (Posted) Returned 93 (405) (7) Working Capital (22) (6) (58) Other Assets & Liabilities (40) 3 42 Cash from Operations $82 $68 $645 Net Cash Flow $ ($598) $554 Strong 4Q cash flow from operations as collateral returned Full year net cash flow reflects $645 million of net debt prepayments and $405 million in posted cash collateral

12 Liquidity Feb. 28, Dec. 3, Dec. 3, $ in millions Unrestricted Cash $ 764 $ 506 $,0 Restricted Cash Total Cash $ 827 $ 570 $,224 LC Capacity $,000 $ 350 $ 350 Current use Availability $ 230 $ 38 $ 93 Revolver Capacity $,000 $ 50 $ 50 Non Trade LCs issued 55 Availability $ 845 $ 50 $ 50 Total Liquidity $,902 $ 758 $,567 Ample liquidity to support our active forward hedging program 2

13 Adjusted Capitalization Table Estimated Feb. 28, Dec. 3, $ in millions st Lien Term B $ 3,575 $ 795 High Yield Notes 3,600,080 Project Level Debt/Other Total Debt $ 7,987 $ 2,682 Preferred Stock $, Other Equity 4,776,825 Capitalization $ 3,90 $ 5,59 Debt to Capital 57% 52% Net Debt to Capital 55% 46% The Company s targeted capital structure range set at 45% to 60% debt to total capital 3

14 Second Lien Structure (Pro Forma) 0,000 9,000 8,000 7,000 Total Base Load Capacity g 8,559 MW MW 6,000 5,000 4,000 3,000 2,000 2 nd Lien Capacity,000 Current Volume Under 2 nd Lien $.3 billion of second lien capacity used as of February 28, 2006, with additional $572 million in LC posted to support our hedged position 4

15 2006 Guidance $ in millions Revised Original Variance Adjusted EBITDA $,600,600 Plus MTM adjustment 6 46 (30) Adjusted EBITDA, including MTM,76,746 (30) Interest payments (475) (65) 40 Income taxes (5) (5) Other funds used by operations (207) (237) 30 Return of posted collateral Working capital changes (37) (37) Cash from operations $,387 $, Capital Expenditures (3) (3) Free Cash Flow $,076 $ Adjusted EBITDA guidance reaffirmed; Cash from Ops guidance raised for final debt pricing & terms 5

16 Financial Plan 2006 Manage balance sheet to targeted levels Deliver financial performance and guidance target Active capital allocation Reinvestment in assets and expansion Define and implement opportunities for capital return to shareholders 6

17 NRG Credit

18 Rating Agency: Attitude towards NRG Industry concerns (2004) Reality today NRG score. Debt problems everywhere Not for the industry and certainly not for NRG. No significant corporate principal due until Longevity of power plants 3. Fragmented industry A problem for the merchants with new gasfired plants, a virtue for NRG a. Public policy precludes market share b. Transmission limited, new plants far from load c. Market does not compensate peakers d. Big revenue and cost factors outside management control e. Merchants compete against ratebase generation True True, old NRG plants are near load centers, inside transmission constraints Improving, less true in capacity markets plus NRG has baseload Less true, as NRG achieves scale Not true in our core markets 8

19 Rating Agency: Attitude towards NRG Industry concerns (2004) Reality today NRG score 4. Oversupply will remain until 200 at least Our core markets (Northeast, California, probably even Texas) will be short reserve margin long before Declining energy intensivity of US economy hurts merchant industry 6. Industry is afflicted by weak credit fundamentals Impact is imperceptible, baseload demand in Texas is growing at 3% per year NRG fundamentals have improved since December 2003 Total debt to capital decreased by nearly 20% prior to the acquisition financing Moody s corporate rating improved from B2 to Ba3 (2 notch increase) Overall cost of secured debt decreased by 200 bps 9

20 Rating Agency: Attitude towards NRG Industry concerns (2004) Reality today 7. No winning business model False NRG is the successful merchant generation business model: Maintain balance in balance sheet and ample liquidity Focus on markets with true competitive market design Don t compete against ratebased regulation Build multifuel, acrossthemerit order scaled portfolios in those markets Hedge to put floor on downside while preserving upside Avoid cash collateralization of longdated hedges 20

21 Question and Answers

22 Appendix

23 Operating Revenues YTD 05 YTD 04 $ in millions $3 MM (5%) Capacity $563 MM (2%) $372 MM (6%) $62 MM (26%) By Type Other Energy $2,04 MM (74%) $,364 MM (58%) Northeast $5 MM ($6 MM) $70 MM $58 MM $94 MM $65 MM $86 MM Non Gen $63 MM By Region Alt Energy Other NA $22 MM $,554 MM $57 MM $8 MM $,25 MM Other Other Int l $552 MM $48 MM Australia South Central $2,708 million $2,348 million 23

24 Operating Expenses and Depreciation $ in millions YTD 2005 YTD 2004 Other COGS Other COGS Maintenance $28 MM $3 MM Oil, $270 MM Maintenance $76 MM $90 MM Oil, $05 MM D & A $94 MM Fuel Cost $,26 MM Gas, $396 MM Coal, $550 MM D & A $208 MM Other OpEx Fuel Cost $86 MM Gas, $233 MM Coal, $478 MM Other OpEx $307 MM $322 MM 24

25 2005 Equity Earnings $ in millions $9 MM YTD 2005 YTD 2004 $7 MM $7 MM $8 MM $6 MM $24 MM $2 MM $22 MM $26 MM $69 MM $29 MM $6 MM $04 million $60 million Gladstone Mibrag Enfield West Coast Power Other Rocky Road 25

26 2005 Adjusted EBITDA by Operating Segment ($ in millions) Northeast Includes $9 mm of MTM losses versus $60 mm in MTM gains for South Central Higher purchased energy costs 8 85 West Coast 6 70 Australia Other Internat l Sale of Kendall 9 77 Other North America Change in Allocations & Regional Structure 49 6 Thermal, Alt Energy, Nongen & Other Adjusted Total EBITDA 26

27 2006 Guidance Current Environment Unfavorable Weather Near Term Gas/Power Prices Favorable NRG Texas Gas Assets NYC Capacity Market Excess Emission Allowance Revenues FORNRG Sensitivities Natural Gas $.00/mm BTU $65 million Coal ± $.00/ton ± $.0 million Oil ± $.00/barrel ± $.0 million Interest Rates ± 00 bps ± $33.7 million Maintaining current guidance, however, if unseasonable weather trend or downward pressure on gas prices continues in 2006, guidance revision is likely 27

28 Operating Statistics 2005 vs Region Generation (MWh) Equivalent availability % Net capacity factor % Net owned capacity MW Northeast 5.3 million ,972 South Central 0. million 9 5 2,395 Western.6 million 87 8,044 Texas 45.9 million , Region Generation (MWh) Equivalent availability % Net capacity factor % Net owned capacity MW Northeast 3.2 million ,972 South Central 0.5 million ,395 Western 2.4 million 88 26,044 Texas 45.5 million ,53 *Does not include statistics for Keystone and Conemaugh 28

29 NRG Classic Operational Statistics by Primary Fuel Coal Net MWh EAF Net capacity Net owned capacity Full year ,32, % 66.% 5,385 Full year ,472, % 63.7% 5,385 Gas Net MWh EAF Net capacity Net owned capacity Full year ,548, %.0% 4,799 Full year ,465, % 9.8% 4,799 Oil Net MWh EAF Net capacity Full year 2004,380, % 4.4% Full year ,58, % 0.% Excludes Batesville, McClain, Kendall, Long Beach and Cadillac Net owned capacity 3,563 3,563 29

30 NRG Texas Operational Statistics by Primary Fuel Coal Net MWh EAF Net capacity factor Net owned capacity Full year ,22, % 87.5% 4,064 Full year ,299, % 87.6% 4,077 Nuclear Net MWh EAF Net capacity factor Net owned capacity Full year ,580, % 97.2% 770 Full year ,79, % 9.2%,0 Gas Net MWh EAF Net capacity factor Net owned capacity Full year 2004 Full year ,734,79 6,803, % 86.9% Above capacities reflect available capacity only. Coal increase from 4,064 MW to 4,077 MW is due to changes at Limestone and W.A. Parish. Nuclear reflects the increase in ownership from 30.8% to 44% effective May Gas capacity reflects the following units unavailable: Fullyear 2004 P.H. Robinson units 4, Webster, and T.H. Wharton unit 2 Fullyear 2005 P.H. Robinson units,3 and 4, Webster, T.H. Wharton unit 2, Deepwater 7, H.O. Clarke, and Cedar Bayou unit 3 9.5% 8.3% 6,492 5,94 30

31 Enhanced Commercial Operations Inventory on Hand at Maximum Burn (Days) Maintained adequate inventory levels to meet dispatch needs despite PRB congestion issues January05. Coal and Transportation Flexibility 2. Ample Rail Car Fleet 3. Improved Transfer and Unloading Processes February05 March05 April05 May05 June05 July Aggregate Inventory August05 September05 October05 November05 December05 $22.00 $20.00 } Target $8.00 Inventory $6.00 Range $4.00 $2.00 $0.00 $8.00 $6.00 $4.00 //2005 2//2005 PRB prices were influenced primarily by strong demand during a period of supply infrastructure constraints 3/4/2005 4/4/2005 5/5/ PRB Prices 6/5/2005 7/6/2005 8/6/2005 9/6/2005 PRB 8800 PRB /7/2005 /7/2005 2/8/2005 /8/2006 2/8/ % incity requirement and revised load forecast from NYISO provide upside from forecasted prices Opportunistically Monetizing Excess SO 2 Emissions Allowances $/KWMo $4.00 $2.00 $0.00 $8.00 $6.00 $4.00 $2.00 $0.00 NYC spot capacity prices Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec NRG Classic* Cumulative excess at beginning of year Sales (allowances) Revenues ($ in thousands) Weighted average sales price Actual vs. expected allowance consumption YTD Cumulative excess of SO 2 allowances to generation needs for the year Remaining allowances through 2009 net of sales and 2005 consumption ,36 35,052 $3,5 $ 889 (,569) 5, ,79 *On current forecasts, excess allowances > 200,000. No sales of SO 2 allowances todate at NRG Texas ,427 46,077 $54,364 $,80 3,627 59, ,74 3

32 Capacity Market Updates Recent Regulatory Developments. February, 2006, the Federal Energy Regulatory Commission approved the RMR contracts for NRG s Connecticut plants until the units are no longer needed for reliability, or a suitable market alternative is implemented. 2. March 6, 2005, the FERC settlement judge filed a comprehensive settlement of the LICAP case with the Commission. The settlement, if approved by the Commission, will provide a transition to a welldesigned capacity market. 3. February 9, 2006, the New York Independent System Operator (NYISO) increased the New York City locational capacity requirement to 83% from 80%. 4. February 3, 2006, Texas PUC terminated NRG Texas obligation to offer 5% of its capacity in mandatory capacity auctions Impact. Moderately Positive Longer term Continued sharing of energy margins 2. Moderately Positive Preserves RMRs until market alternatives established Establishes initial floor and riskreducing bidding rules in capacity market Provides for a transition payment for nonrmr resources 3. Positive Equivalent to 330 MW additional demand incity 4. Moderately Positive Bilateral market allows both buyers and sellers to realize benefits of liquidity and diversity Effectively frees up approximately 200+ MW of baseload capacity for market sales The net impact of these regulatory changes is expected to be moderately positive over time 32

33 Appendix: Reconciliations

34 Reg. G Reconciliation Appendix Table A: Fourth Quarter 2005 Regional EBITDA Reconciliation The following table summarizes the calculation of EBITDA and provides a reconciliation to net income/(loss): Three months ending December 3, 2005 Northeast South Central Western Other NA Australia Other Int'l Other Total Net Income (Loss): $ 46 $ 7 $ (25) $ (25) $ (2) $ $ (58) $ 64 Plus: Income Tax Expense/(Benefit) Interest Expense Amortization of Finance Costs 3 3 Amortization of Debt Discount/(Premium) () Refinancing Expenses 2 2 Depreciation Expense Amortization of Power Contract (4) 3 () Amortization of Emission Credits 2 3 EBITDA $ 66 $ 32 $ (24) $ (7) $ $ 20 $ 8 $ 96 Loss from Discontinued Operations 4 5 Write Down and (Gain)/Losses on Sales of Equity Method Investments Gain on settlement (7) (7) Gain on sale of land (4) (4) TermoRio legal matters 3 3 Adjusted EBITDA $ 59 $ 32 $ 3 $ $ $ 23 $ 2 $

35 Reg. G Reconciliation Appendix Table A2: Fourth Quarter 2004 Regional EBITDA Reconciliation The following table summarizes the calculation of EBITDA and provides a reconciliation to net income/(loss): Three months ending December 3, 2004 Northeast South Central Western Other NA Australia Other Int'l Other Total Net Income (Loss): $ 9 $ 7 $ 22 $ $ (2) $ 0 $ (09) $ 9 Plus: Income Tax Expense/(Benefit) (6) (3) 8 Interest Expense Amortization of Finance Costs 2 2 Amortization of Debt Discount/(Premium) 3 () 3 Refinancing Expenses 4 4 Depreciation Expense WCP CDWR Contract Amortization Amortization of Power Contracts (3) Amortization of Emission Credits 2 3 EBITDA $ 2 $ 23 $ 49 $ 9 $ $ 20 $ (6) $ 28 Income from Discontinued Operations 5 (4) Corporate Relocation charges 4 4 Reorganization items (2) (2) Impairment charges 2 2 Write Downs and (Gain)/Loss on Sales of Equity Investments 2 2 Adjusted EBITDA $ 2 $ 23 $ 49 $8 $ $ 20 $ (8) $ 25 35

36 Reg. G Reconciliation Appendix Table A3: Fullyear 2005 Regional EBITDA Reconciliation The following table summarizes the calculation of EBITDA and provides a reconciliation to net income/(loss): Twelve Months ending December 3, 2005 Northeast South Central Western Other NA Australia Other Int'l Other Total Net Income (Loss): $ 222 $ $ (0) $ (39) $ 5 $ 89 $ (204) $ 84 Plus: Income Tax Expense Interest Expense Amortization of Finance Costs 7 7 Amortization of Debt Discount/(Premium) 2 5 (2) 5 Refinancing Expense (0) Depreciation Expense Amortization of Power Contracts (4) Amortization of Emission Credits 0 4 () 3 EBITDA $ 306 $ 7 $ (9) $ (5) $ 6 $ 9 $ 49 $ 592 Income from Discontinued Operations () (6) (7) Corporate Relocation charges 6 6 Impairment charges 6 6 Gain on settlement (7) (7) Gain on sale of land (4) (4) TermoRio legal matters () () Gain on Crockett contingency (3) (3) Write Down and (Gains)/Losses on Sales of Equity Method Investments 27 6 (2) 3 Adjusted EBITDA $ 299 $ 7 $ 8 $ 9 $ 6 $ 96 $ 49 $

37 Reg. G Reconciliation Appendix Table A4: Fullyear 2004 Regional EBITDA Reconciliation The following table summarizes the calculation of EBITDA and provides a reconciliation to net income/(loss): Twelve months ending December 3, 2004 Northeast South Central Western Other NA Australia Other Int'l Other Total Net Income (Loss): $ 322 $ 49 $ 65 $ (8) $ 0 $ 78 $ (320) $ 86 Plus: Income Tax Expense/(Benefit) (0) (5) Interest Expense Amortization of Finance Costs 9 9 Amortization of Debt Discount/(Premium) 3 5 () (4) 3 Refinancing expense Depreciation Expense WCP CDWR contract amortization 6 6 Amortization of power contracts 6 (4) Amortization of emission credits EBITDA $ 45 $ $ 85 $ 48 $ 69 $ 05 $ 33 $ 966 (Income)/ Loss from discontinued operations (4) (2) (25) Corporate Relocation Charges 6 6 Reorganization Items (4) (3) Impairment charges Write down of notes receivable 5 5 FERCauthorized settlement with CL&P (39) (39) Write Downs, (Gain)/Loss on Sales of Equity Investments 4 6 Adjusted EBITDA $ 45 $ 5 $ 85 $ 77 $ 70 $ 93 $ 6 $97 37

38 Reg. G Reconciliation Appendix Table A5: Net Debt to Capital Reconciliation 3Dec05 Estimated 28Feb06 Numerator Gross Debt 2,682 7,987 Total Cash Net Debt 2,2 7,60 Denominator Net Debt 2,2 7,60 Mezzanine Preferred Book Value of Equity 2,23 5,668 Capital 4,589 3,074 Net Debt to Capital 46% 55% 38

39 Reg. G Reconciliation EBITDA and Adjusted EBITDA are nongaap 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 should not be construed as an inference that NRG s future results will be unaffected by unusual or nonrecurring 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 believes debtholders 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 noncash 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 presentation. 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 gains or 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. 39