Second Quarter 2007 Results Presentation. August 2, 2007

Transcription

1 Second Quarter 2007 Results Presentation August 2, 2007

2 Safe Harbor Statement This Investor Presentation contains forwardlooking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of Forwardlooking statements are subject to certain risks, uncertainties and assumptions and typically can be identified by the use of words such as expect, estimate, should, anticipate, forecast, plan, guidance, believe and similar terms. Such forwardlooking statements include our adjusted EBITDA, adjusted cash flow from operations, free cash flow, and free cash flow guidance, expected earnings, future growth and financial performance, our acquisition, commercial operations and repowering strategy, expected benefits and EBITDA improvements of the FORNRG initiatives, and expected benefits and timing of the capital allocation plan and RepoweringNRG projects and our projected environmental capital expenditure spend. 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, changes in government regulation of markets and of environmental emissions, the condition of capital markets generally, our ability to access capital markets, unanticipated outages at our generation facilities, 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, our ability to realize value through our commercial operations strategy, and our ability to achieve the expected benefits of our comprehensive capital allocation plan and RepoweringNRG projects. 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, cash flow from operations, free cash flow, and adjusted free cash flow guidance are estimates as of August 2, 2007 and is based on assumptions believed to be reasonable as of that date. NRG disclaims any current intention to update such guidance from August 2, 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 Current Highlights RepoweringNRG produces first success / first revenues at Long Beach Full hedging strategy enables guidance increase notwithstanding falling gas prices and weak summer weather Prudent capital structure insulates Company from deteriorating credit markets and enables several options, including status quo option RepoweringNRG big projects poised for major milestone breakthroughs Sound Strategy / Strong Implementation 3

4 Edison International RFO: Aug. 14 Long Beach Emergency Repowering: Timeline and Overview Contract Awarded: Nov. 10 Project Timeline CPUC Approval: Jan. 25 Permit Issued: April Aug. Sept. Oct. Nov. Dec. Jan. Feb. Mar. April May June July Aug. Permit Application: Nov. 17 Site Prep begins: Dec. 1 Construction Commences: April 25 Start up Testing initiated: July 22 Commercial Operations: Aug. 1 Location Long Beach, CA MW 260 Fuel Natural Gas Technology Alstom Rebuild of 11D5 Generators with SCR/CO Catalyst installation Offtaker SCE Term 10 Years Unlevered NRG Cash Investment* $75 million ($289/KW) Est. Annual EBITDA $25 million * Noncash contribution included plant buildings and equipment, land, emissions credits, and corporate collateral A Competitive Advantage on Super Fast Track Projects 4

5 Long Beach Emergency Repowering: A Good Project, A Sound Precedent Benefits to Customer Significant incremental capacity in less than one year from issuance of RFP Located in load center Less expensive than alternative bids No construction risk, limited permitting risk Benefits to NRG Long Beach from mothballed cost center to profit center in one year Site value and other underutilized assets (air credits) optimized Reduced risk outside the fence (all necessary interconnects preexisting) Reduced O&M mobilization risk Ideal first project for NRG s new EPC group (established processes and procedures) Credibility on Future Fast Tracks; Capability on Future Repowerings 5

6 Financial Highlights Three months 6/30/07 $533 million of Adjusted EBITDA ($328 million in 2006) excluding marktomarket $336 million operating cash flow (excluding $17 million cash inflow related to hedges) $113 million (2.7* million shares) repurchased Six months 6/30/07 $1,042 million of Adjusted EBITDA ($621 million in 2006) excluding marktomarket $562 million operating cash flow (excluding $103 million cash inflows related to hedges) $215 million (5.7*million shares) repurchased * Split adjusted $1.9 billion of liquidity ($795 million of unrestricted cash) 58.6% net debttocapital ratio, down from prior period 3/31/07 Raising guidance by $50 million to $2.2 billion due to solid performance from all Regions 6

7 Plant Operations: Q NRG Classic Only NRG Texas Only OSHA Recordable Safety Record 1 FY FY FY Ind Avg YTD Total NRG NA ) 2005 adjusted to include Texas, which was consolidated effective February 2, 2006 EFOR at Coal Plants NRG Classic: NRG Texas: Generation (Million MWh) Q Q Coal Gas/Oil Coal Nuclear Gas Total: Aggregate Inventory 6.1% 3.7% 2.8% 0.0% 7.4% 7.6% 2.6% 2.6% 6.8% 2.9% 8.1% 2.7% 5.4% 2.3% Q Q FY04 FY05 FY06 Excludes Huntley 65,66 Includes Huntley 65,66 CLASSIC NRG NRG TEXAS 2Q07 and 2Q06 EFOR excluding Huntley 65, 66, Transmission, & Indian River #4 were 6.0% and 6.3%, respectively 2006 Goal: Ind. Avg 2008 Goal: 1st Quartile Industry Comp.: Top Decile Inventory on Hand at Maximum Burn (Days) Dec05 Jan06 1. Coal and Transportation Flexibility 2. Ample Rail Car Fleet 3. Improved Transfer and Unloading Processes Feb06 Mar06 Apr06 May06 Jun06 Jul06 Aug06 Sep06 Oct06 Nov06 Dec06 Jan07 Feb07 Mar07 Apr07 May07 Jun07 New Target Inventory Range Improved performance of most assets allows management to concentrate on underperformers 7

8 FORNRG: Focus on Return on Invested Capital (ROIC) Culture: Employees are engaged corporatewide to focusing on projects that drive bottom line results $250 FORNRG EBITDA ($mm) $235 $250 $200 $200 $150 $144 $100 $50 $35 1 $ A 2006A 2007E 2008E 2009E 1 Recurring Corporate Operations Procurement Low Risk, low capital investments in existing fleet provide big return in high gas, high heat rate environment 8

9 Plant Ops and Corporate Drivers and Results Corporate Achievements To Date: Dramatic reduction in insurance premium Efficient cash management More efficient property and income tax plan Targets To Come: Outage planning Outage support Procurement sourcing 1. EFOR Reduction Comprehensive Boiler Tube Failure Reduction program is a key driver of the 23% reduction in NRG Classic coal EFOR from full year 2005 to 2Q YTD 2007 (from 8.1% to 6.2%)* 2. Capacity Recovery 3. Heat rate Plant Operations Air in Leakage repairs and unit optimization led to a 78MW recovery over the last two years Largely driven by 2007 Spring Outage work, Heat rates for the Classic Coal plants have improved 0.9% since Dec 2006 * Excluding Indian River 4, 2Q YTD EFOR was 5.0% New corporate and procurement projects offer future year potential FORNRG upside (as of yet unquantified) 9

10 OP Commercial Ops: Optimizing Portfolio (OP) Tactical (Short Term) Focus: Baseload / Midmerit / Peaking assets Market interface & asset management Fuel supply and logistics Active risk management & trading Maximize value (Capture extrinsic) Strategic (Long Term) Focus: Baseload assets Market view of commodity prices Minimize credit requirements Reduce earnings volatility Risk and Financial Reporting Analytics Fundamental & Technical Analysis Economic Dispatch Risk NRG s Portfolio Optimization and Risk Management Cycle Trading Structured Transactions Origination Risk Management Commercial operations focuses on capturing full extrinsic value in addition to the intrinsic value of the portfolio 10

11 OP 110% Commercial Ops: Hedging Baseload in the Medium Term Baseload Power Hedge Position Dark Spread 11/1/2006 4/20/2007 7/17/ % 91% 96% 3% 88% 64% 57% 55% $/mmbtu /1/2006 4/20/2007 7/17/ % 57% 60% $400 NRG s gross margin exposure to changes in gas price 1 $395 23% Q1 Hedged Energy New Hedges Open Energy Hedged Fuel 1. Percentage hedges are based on total executed baseload hedges divided by forecasted baseload generation as of 7/12/2007. Forecasted baseload generation are subject to changes from market volatility, commodity prices, supply and demand conditions, planned and forced outage assumptions. Since the 5/2/2007 earnings call, changes in the energy hedge percentages of 3%, 0%, 0%, 0% and (1)% in years 2008, 2009, 2010, 2011 and 2012; respectively, reflect these impacts coupled with incremental new hedges. 2. Includes financial gas swaps (reflected in equivalent MWh by taking the volume in MMbtu s and divided by the forward market implied heat rate in ERCOT) and gas collar structures which allow downside protection beyond a floor price while preserving market participation in an upside move beyond the capped price. 3. Includes Northeast, South Central and Texas portfolios within the U.S portfolio and excludes West, Thermal and International values reflect balance of year positions only. 5. Hedged fuel represents weighted average of coal and uranium; coal includes Westmoreland Jewett Mine volumes. 6. Percentage fuel hedge position in 2007 includes coal purchased forward for building additional inventory primarily to mitigate operational constrains related to coal delivery. Millions $300 $218 $205 $200 $127 $100 $41 $0 ($100) ($39) ($123) ($200) ($214) ($202) ($300) ($400) ($395) Q207current levels for rising NG prices Q207current levels for falling NG prices 1 See footnotes on slide 13 Hedging targets to minimize earnings and cash flow volatility to gas prices while 11

12 OP Commercial Ops: Hedge Profile Sensitivities ERCOT 7X24 Heat Rate Heat Rate Sensitivity 1,2,3,4 Gross margin change from 1 mmbtu/mwh expansion in market heat rate ($mm) $450 $400 $350 $386 $415 $402 MMBtu/MWh /20/ /18/2006 NRG's Cedar Bayou Break Even Greenfield CCGT Break Even $300 $250 $200 $150 $100 $50 $111 $ $ Q2 2007current levels for rising Heat rates 1. Based on hedge positions as of 7/12/2007 and current market prices of gas and power and due to the asymmetric nature of some of the instruments used for hedging, the losses from a $1/MMbtu downward move in gas for years 2008 through 2011 will be lower relative to an upward move. 2. Gas sensitivities are derived by converting all the hedge positions and generation positions to net equivalent gas positions using a weighted average market implied heat rate against a $1/Mmbtu move in gas prices. 3. Heat rate sensitivities are derived by taking the net of all power hedge positions and generation positions against a 1 MMbtu/MWh move in heat rates multiplied by the existing gas prices for each year. 4. The above sensitivities exclude impact from non baseload assets, which have a potential to add value as gas prices increase and as heat rates rise. capturing heat rate upside from tightening reserve margins in our core Northeast and Texas regions 12

13 OP Heat Rate Optionality Extends to Oil/Gas Fleet PJM Frequency of High Heat Rate Hours (MMBTU / MWH) ERCOT Frequency of High Heat Rate Hours (MMBTU / MWH) Year >8 >10 >15 Year >8 >10 > , , , ,182 1, , ,296 1, , Source: Transco Z6 NY Gas Index and NRG estimates; not weather normalized ,432 1, Source: HSC Gas Index and NRG estimates; not weather normalized Region ERCOT NEPOOL PJM NYC Tightening Reserve Margins Source: ISO and NRG estimates % 13.3% 21.8% (12.5%) % 5.2% 19.1% (24.2%) Northeast 37% (3% PJM, 60% NY and 37% NEPOOL) Gas/Oil Fleet: ~13,900 MW Central 10% Heat rate expansion due to tightening reserve margins expected to drive increased capacity utilization of our oil/gas fleet Gas/ Oil Gas Gas West 14% Gas Texas 39% Texas example: every ½ heat rate move means 1.5% to 2% improvement in gas fleet capacity factor 13

14 OP Capacity Markets Continue to Show Strong Pricing Results N E W Y O R K P J M N E P O O L $/KWMo $/KWMo $14.00 $12.00 $10.00 $8.00 $6.00 $4.00 $2.00 $0.00 $/KWMo $7.00 $6.00 $5.00 $4.00 $3.00 $2.00 $1.00 $0.00 $16.00 $14.00 $12.00 $10.00 $8.00 $6.00 $4.00 $2.00 $0.00 Jan06 May06 Jan06 Feb06 Jul06 Feb06 Mar06 Mar06 Apr06 Sep06 Apr06 May06 May06 Nov06 Jun06 Jun06 Jul06 Jan07 Jul06 2,472 MW Aug06 Aug06 Mar07 Sep06 Sep06 Oct06 NYC May07 Nov06 Jul07 Dec06 Eastern MAAC Oct06 Nov06 Dec06 Jan07 1,368 MW Jan07 Mar07 Feb07 Apr07 May07 NY Rest of State 1,056 MW Sep07 Feb07 Nov07 Jan08 Mar08 PJM Rest of Pool Mar MW 254 MW Apr07 May07 Jun07 Jul07 Jun07 Aug07 Jul07 May08 Sep07 Aug07 Jul08 Oct07 Sep MW Nov07 Oct07 Sep08 Dec07 Jan08 Nov07 Nov08 Feb08 Dec07 Mar08 Jan08 Jan09 Apr08 Feb08 Mar09 May08 Mar08 May09 1,368 MW incity; 2,472 MW rest of state FERC has ordered NYISO to file a proposal for a revised incity ICAP market by early October 1,056 MW Eastern MAAC; 137 MW PJM rest of pool Next auction in October for planning year 2009/2010 1,980 MW in New England All capacity receives transition payments through May 2010 Forward capacity auction in February 2008 for capacity commitments starting June 2010 LFRM next auction late August for Oct/May 2008 faststart reserve units Norwalk Harbor (Units 1&2) FERC conditionally approved RMR effective June 19 th (subject to refund) LFRM FCM Capacity market auction results in Northeast with early progress to develop such a market in California are reflecting the need for new power sources in our core markets 14

15 % Contribution by Technology 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% # of Projects MW MWh Invested Capital Avoided CO 2 Nuclear Clean Coal Wind Gas Coal A Comprehensive Development Program that Meets the Growing Energy Needs of our Domestic Markets 15

16 Cedar Bayou 4: Fast Track Projects with significant locational value Project Highlights Location Houston, TX Permit July 2007 Technology Siemens 501FD2 Fuel Natural Gas MW 550MW gross COD Summer 2009 Offtaker Merchant Equity Partner 50% EnergyCo (joint venture between PNM Resources and Cascade Investment) Cash Contribution* $105 million Unlevered NRG cash investment ~$380/KW * Noncash contribution included onsite infrastructure and services, and some of the major equipment which NRG had been holding in inventory Faster Cheaper Advantageously Located 16

17 Cedar Bayou: Significant Competitive Advantages Marginal Cost ($/MWh) $140 $120 $100 $80 $60 $40 WA Parish 7 WA Parish 8 $20 NRG Units on ERCOT Houston Zone Supply Curve Cedar Bayou marginal cost Current Average Load Average load in Cal 11* Cedar Bayou 1 TH Wharton CC & PH Robinson 2 WA Parish 5 WA Parish 6 $0 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000 20,000 * Assuming 2% annual load growth Source: Energy Velocity Cumulative Capacity (MWs) WA Parish 4 Current Max Load in Max Load Cal'11* WA Parish 1,2 WA Parish 3 & Cedar Bayou 2 & SR Bertron Greens Bayou TH Wharton CTs San Jacinto Low marginal cost Lower total cost than any other new entrant Monetize site values Advantages: Capitalize on existing interconnections and work force Deploy stranded equipment Share effort with aligned partner 17

18 Padoma Wind Power Insert Picture Strategy Development focused Partner with committed wind industry players where possible Focus on markets with existing fossil assets to enable firm wind origination Focus efforts on merchant wind (perhaps with gas hedges), in order to capture carbon upside Status Wind Projects Under Development totaling ~442 MW (before partners) and 350 MW (net ownership) Two sites in Texas Construction on first to begin Fall 2007; second in Summer 2008 Several Texas sites in early development One site in California in advanced development Construction scheduled for Summer 2009 Several California sites in active development Wind turbines secured for three sites from GE, Siemens and undisclosed 50% partner Net NRG cash contribution ~$252 million Measured Entrance into Renewables to Support our Core Fleet 18

19 Proactive Approach to Preparing for Carbon Regulation Strategic Approach Route Benefit to NRG 1. Shape Policy Act as resource to public policy makers Entering coalitions with key stakeholders (e.g., United States Climate Action Partnership) (USCAP, Global 3C Initiative) Federal GHG legislation now 2. Manage Price Risk Join Chicago Climate Exchange (CCX) Price Discovery regarding offsets (e.g, February 2007 RFP for RGGI offsets) Monetize early carbon reduction efforts Develop carbon market and trading expertise Understand EU Emission Trading Scheme System (e.g. Mibrag) Nuclear Attractive baseload with no carbon 3. Advance New Technology (Our Green Lineup ) Gasified Coal (IGCC) with CCS Wind (Padoma) Plasma Arc Low cost fuel with high level of carbon removal No fuel cost with no carbon emissions Repower smaller units with fuel flexibility including biomass Concentrate the Focus/ Move the Needle 19

20 Environmental Capital Expenditure Update Projected Potential Spend Key Considerations Total range of costs: $1.0 $1.5 billion Range of costs driven by available options at sites Investment includes air quality control projects, landfill upgrades, and installation of technology for water intake systems. ($mm) $450 $400 $350 $300 $250 $200 $150 $100 $50 $ Huntley/Dunkirk Indian River Big Cajun II Other Investment in Controls Creates Value and Options for NRG Assets 20

21 Repowering NRG Construction Project Status Long Beach 260 MW Completed Cedar Bayou 550 MW (gross) 275 MW (net) Summer 2007 Cos Cob 38 MW January 2008 Big Cajun MW (gross) 115 MW (net) First Quarter 2008 Project construction on a manageable timeline 21

22 Delivering Value to Stakeholders Creating Shareholder Value Existing Fleet Operational excellence Active commercial management Improved market design Multiregion, multifuel, multidispatch Carbon friendly Responsive to customer needs Carbon Policy Shape policy Manage price risk Advance new technology A coordinated plan to provide for the present while preparing for the future 22

23 Financial Results

24 Adjusted EBITDA $ millions MtM gain Northeast GM 12 South Central GM (36) Dev. Costs 22 Other MtM gain $ millions MtM gain Texas GM 115 (59) Northeast GM Dev. Costs (46) SO2 Sales & Other 1, MtM loss Texas GM 621 Portfolio Change 3 2 nd Quarter Year to Date $79 million of forward MtM gains and includes the reversal of $35 million MtM gain in $44 million of forward MtM gains and includes the reversal of $92 million MtM gain in NRG Texas acquired 2/2/06. West Coast Power acquired 3/31/06 Revenue drivers Addition of Texas and West Coast Power Texas contract prices due to hedge reset Improved Texas baseload generation Northeast prices, generation, and merchant capacity Lower S0 2 sales Cost drivers Addition of Texas and West Coast Power Timing of STP refueling and other major maintenance projects Development mostly STP 24

25 Q2 Free Cash Flow in millions Variance YTD YTD Adjusted EBITDA, excluding MTM $ 1,042 $ 621 $ 421 Interest payments cash (278) (127) (151) Refinancing payments (127) 127 Income tax cash (14) (6) (8) Cash collateral (payments)/receipts (103) 272 (375) Working capital 1 (182) (40) (142) Other assets & liabilities (6) 11 (17) Adjusted Cash from Operations $ 459 $ 604 $ (145) Capital expenditures (127) (74) (53) Free Cash Flow $ 332 $ 530 $ (198) Repowering Captial Expenditures (78) (78) Preferred dividends (28) (23) (5) FCF after Repower & Preferred Dividends $ 226 $ 507 $ (281) 1 Excludes accrued income tax and accrued interest Working capital and collateral requirements offset higher adjusted EBITDA in 2007 Operating Cash Flow 25

26 Liquidity Jun. 30, Dec. 31, Jun. 30, In millions Domestic Unrestricted Cash $ 708 $ 427 $ 859 International Unrestricted Cash Total Unrestricted Domestic Restricted Cash International Restricted Cash Total Restricted Total Cash $ 847 $ 839 $ 1,015 Synthetic LCs Capacity $ 1,300 $ 1,500 $ 1,000 Current use (1,222) (967) (884) Availability $ 78 $ 533 $ 116 Revolver Capacity $ 1,000 $ 1,000 $ 1,000 Non Trade LCs issued (71) (145) (154) Revolving line Availability $ 929 $ 855 $ 846 Total Liquidity $ 1,854 $ 2,227 $ 1,977 Cash from operations used to fund capex and share repurchases 26

27 2007 Guidance in millions, except Cash Flow Per Share 8/2/2007 5/2/2007 Adjusted EBITDA Guidance $ 2,200 $ 2,150 Interest payments (624) (624) Income tax (23) (15) Cash collateral (71) (71) Working Capital and Other (62) (42) Free Cash Flow Yield % 7.9% Cash from Operations $ 1,420 $ 1,398 Maintenance and Environmental CAPEX (350) (370) Free Cash Flow 1,070 1,028 Repowering NRG (280) (80) Cash Flow Per Share 2 $4.46 $3.06 Preferred Dividends (55) (55) FCF after Repower & Div. $ 735 $ Cash Flow yield based on common stock share price of $38.55 and projected 8/2/2007 free cash flows before repowering and preferred dividends 2 Using 239,829,787 shares outstanding as of 6/30/2007 Base business After Repower and Preferred Div. Adjusted EBITDA guidance raised with strong YTD performance. Repowering Capital increased $200M for Cedar Bayou and wind projects 27

28 CAPEX Q1+Q2 & Forecast for 2007 In millions Maintenance Environmental Repowering NRG Total Q1+Q2 Northeast $ 17 $ 19 $ 1 $ 36 Texas South Central 4 4 West Int'l/Padoma/Thermal $ 109 $ 19 $ 78 $ Guidance Northeast Texas South Central West Int'l/Padoma/Thermal $ 230 $ 120 $ 280 $ 630 Repowering spending for the first half of 2007 includes: Long Beach ($65M), Padoma Wind ($9M), Cedar Bayou ($3M), Cos Cob ($0.6M) 2007 Environmental CAPEX is primarily for bag houses at Dunkirk and Huntley and scrubbers at Indian River and Big Cajun II Guidance Repowering CAPEX of $280M includes: Padoma Wind ($177M), Long Beach ($75M), Cedar Bayou ($16M), Cos Cob ($6M), and STP ($4M) 28

29 Capital Allocation 2007 Plan: Complete Phase II of Capital Allocation Shares Repurchased Amount (millions).. Q2 share repurchases 2,699,200 $ Q1 share repurchases 3,000, Anticipated third quarter 2007 purchases TBD 53.. Expected full year 2007 purchases $ 268. Phase II repurchases in Q ,425, Total Phase II TBD $ Plan: Implement Ongoing Return of Capital to Shareholders Holdco funding placed, awaiting regulatory approval of structure 25 basis point reduction in first lien pricing grid Dividend and Repowering amendments obtained Q4 formation of Holdco uncertain due to credit market environment Alternatives to Holdco structure being evaluated For 2008, if common share dividend is delayed, then share repurchases will be increased 29

30 2007 Objectives Objective Status Repowering NRG Economic returns Structure Capital Allocation Complete phase II Define next phase Portfolio management Assets Hedges Drive shareholder value Achieve financial targets Optimize capital structure FORNRG Repowering NRG Long Beach complete Cedar Bayou, Cos Cob announced Wind projects advancing Capital Allocation $215M share purchase through Q2 2007, $53 million targeted for completion in 2007 Holdco facilitates targeted ongoing returns Alternative plan being developed pending market conditions Portfolio management Monetized Red Bluff/Chowchilla Added incremental hedges including heat rate Drive shareholder value Raised guidance Within targeted range On track to meet goals 30

31 Closing Remarks and Questions and Answers

32 Appendix: Financial and Operating Statistics

33 Adjusted EBITDA by Region 2nd Quarter Year to Date $ in Millions Change Change Texas $ 360 $ 279 $ 81 $ 610 $ 371 $ 239 Northeast (29) South Central (18) West International Thermal Corporate 9 (12) (15) 28 Adj. EBITDA $ 577 $ 393 $ 184 $ 994 $ 761 $ 233 Less: MtM Fwd. Positions 100 (8) (11) Add: Prior Year MtM Reversal 35 (20) (65) 157 Less: Ineffectiveness (21) 53 (74) (20) Adj. EBITDA excluding MtM $ 533 $ 328 $ 205 $ 1,042 $ 621 $ 421 Note: 2006 Texas YTD figures are as of February 2, 2006 acquisition of Texas Genco 33

34 2Q Plant Performance 2 nd Quarter Generation Sold 2 nd Quarter Availability in thousands MWh Change % Texas 12,265 12,741 (476) 4% Northeast 3,073 2, % South Central 3,004 2, % West (292) 73% Total 18,450 18,771 (321) 2% Equivalent Net Availability Capacity 2007 Factor Factor Texas 87.6% 51.1% Northeast 77.2% 18.3% South Central 85.7% 51.2% West 86.9% 7.4% Texas Nuclear 2,170 2,455 (285) n/a Texas Coal 8,447 7, n/a NE & SC Coal 4,964 4, % Baseload 15,581 14, % Oil (45) 42% Gas Texas 1,377 2,532 (1,155) 46% Gas Other (49) 8% Dual % Jet 0% Intermediate/Peaking 2,110 3,358 (1,248) 37% Equivalent Net Availability Capacity 2006 Factor Factor Texas 88.9% 54.2% Northeast 74.7% 16.3% South Central 87.6% 49.4% West 88.7% 16.0% Purchased Power % Total 18,450 18,771 (321) 2% Note: Texas generation reflects ownership as of February 2, Relates to New England plants which run on either oil or gas 34

35 YTD Plant Performance YTD Generation Sold YTD Quarter Availability in thousands MWh Change % Texas 23,245 20,054 3,191 16% Northeast 6,696 6, % South Central 5,831 5, % West (547) 79% Total 35,919 32,422 3,497 11% Equivalent Net Availability Capacity 2007 Factor Factor Texas 84.5% 48.7% Northeast 82.2% 19.9% South Central 88.3% 53.6% West 83.7% 7.1% Texas Nuclear 4,532 4, n/a Texas Coal 16,033 11,871 4,162 n/a NE & SC Coal 10,670 10, % Baseload 31,235 26,495 4,740 18% Oil % Gas Texas 2,172 3,206 (1,034) 32% Gas Other 783 1,113 (330) 30% Dual % Jet 1 1 0% Intermediate/Peaking 3,569 4,616 (1,047) 23% Equivalent Net Availability Capacity 2006 Factor Factor Texas 85.5% 48.7% Northeast 81.8% 17.8% South Central 91.1% 52.7% West 83.4% 17.5% Purchased Power 1,115 1,311 (196) 15% Total 35,919 32,422 3,497 11% Note: Texas generation reflects ownership as of February 2, Relates to New England plants which run on either oil or gas 35

36 Fuel Statistics 2 nd Quarter Year to Date Consol Consol Consol Consol 1 Domestic Cost of Gas ($/mmbtu) $ 6.32 $ 6.24 $ 6.47 $ 6.68 Coal Consumed (mm Tons) PRB Blend 72% 71% 74% 75% Northeast 63% 58% 64% 60% Coal Costs (mm BTU) $ 1.59 $ 1.77 $ 1.67 $ 1.82 Northeast $ 1.89 $ 2.74 $ 2.19 $ 2.68 South Central $ 1.79 $ 1.59 $ 1.80 $ 1.53 Texas $ 1.42 $ 1.54 $ 1.44 $ 1.58 Coal Costs ($/Tons) $ $ $ $ Northeast $ $ $ $ South Central $ $ $ $ Texas $ $ $ $ Includes NRG Texas from February 2,

37 Q2 Operating Revenues $ in millions Q2 07 Q2 06 Capacity $193M (12%) $288M (19%) $295M (20%) $405M (27%) By Type Other Energy $1,067M (69%) $802M (53%) Northeast $303M Texas $395M By Region Other International $875M $163M $941M $125M $45M $49M West South Central $29M $44M $42M $39M $1,548 million $1,502 million 37

38 YTD Operating Revenues 1 $ in millions YTD 07 YTD 06 Capacity $282 (10%) $562M (20%) $487M (19%) $695M (27%) By Type Other Energy $2,014M (70%) $1,355M (54%) Northeast $718 Texas $737M By Type Other $1,570M $1,347M International $314M $266M West South Central $57M $87M $50M $93M $69M $87M 1 Q includes two months of Texas results $2,858 million $2,537 million 38

39 Operating Expenses and Depreciation $ in millions Maintenance $114M D&A $161M Other OpEx $120M Maintenance $208M D&A $322M Other OpEx $276M Q2 07 Q2 06 Other COGS $125M Fuel Cost $484M Other COGS $213M Fuel Cost $930M Nuclear $15M Oil $18M Gas $185M Coal $266M Maintenance $109M Other OpEx $107M D&A $177M Other COGS $73M Fuel Cost $543M YTD 07 Other YTD 06 Nuclear $31M Oil $69M Gas $292M Coal $538M Maintenance $177M Other OpEx $216M D&A $295M COGS $194M Fuel Cost $895M Nuclear $24M Oil $22M Gas $243M Coal $254M Nuclear $26M Oil $40M Gas $350M Coal $479M 39

40 Equity Earnings $ in millions ($1M) Q2 07 Q2 06 $1M $2M $7M $2M $5M ($3M) $8 million $8 million YTD 07 YTD 06 $4M ($1M) $9M $15M $14M $12M $21 million $29 million Gladstone MIBRAG West Other 40

41 Appendix: Reg. G Schedules

42 Reg. G Appendix Table A1: Second Quarter 2007 Regional EBITDA Reconciliation The following table summarizes the calculation of adjusted EBITDA and provides a reconciliation to net income/(loss) (dollars in millions) Texas Northeast South Central West International Thermal Corporate Total Net Income (Loss) (4) (121) 149 Plus: Income Tax (7) 101 Interest Expense Amortization of Finance Costs 7 7 Amortization of Debt (Discount)/Premium 1 1 Refinancing Expense Depreciation Expense ARO Accretion Expense 2 2 Amortization of Power Contracts (61) (6) (67) Amortization of Fuel Contracts Amortization of Emission Credits 9 9 EBITDA Gain on Sale of Equity Method Investments (1) (1) Adjusted EBITDA

43 Reg. G Appendix Table A2: Second Quarter 2006 Regional EBITDA Reconciliation The following table summarizes the calculation of adjusted EBITDA and provides a reconciliation to net income/(loss) (dollars in millions) Texas Northeast South Central West International Thermal Corporate Total Net Income (Loss) (14) (115) 203 Plus: Income Tax Interest Expense Amortization of Finance Costs 5 5 Amortization of Debt (Discount)/Premium 2 2 Depreciation Expense Amortization of Power Contracts (222) (4) (226) Amortization of Fuel Contracts Amortization of Emission Credits EBITDA (9) 412 (Income)/Loss from Discontinued Operations 2 (3) (1) Station Service Reserve Reversal (15) (15) Acquisition Integration Costs 5 5 Mirant Legal Defense 6 6 Gain on Sale of Equity Method Investments (3) (11) (14) Adjusted EBITDA (12)

44 Reg. G Appendix Table A3: Year to date 2007 Regional EBITDA Reconciliation The following table summarizes the calculation of adjusted EBITDA and provides a reconciliation to net income/(loss) (dollars in millions) Texas Northeast South Central West International Thermal Corporate Total Net Income (Loss) (209) 214 Plus: Income Tax (11) 157 Interest Expense Amortization of Finance Costs Amortization of Debt (Discount)/Premium 3 3 Refinancing Expense Depreciation Expense ARO Accretion Expense 3 3 Amortization of Power Contracts (108) (11) (119) Amortization of Fuel Contracts Amortization of Emission Credits EBITDA ,013 Gain on Sale of Equity Method Investments (1) (1) Gain on Asset Sale of Red Bluff & Chowchilla (18) (18) Adjusted EBITDA

45 Reg. G Appendix Table A4: Year to date 2006 Regional EBITDA Reconciliation The following table summarizes the calculation of adjusted EBITDA and provides a reconciliation to net income/(loss) (dollars in millions) Texas Northeast South Central West International Thermal Corporate Total Net Income (Loss) (292) 229 Plus: Income Tax 11 (2) Interest Expense Amortization of Finance Costs Amortization of Debt (Discount)/Premium 4 4 Refinancing Expense Depreciation Expense Amortization of Power Contracts (263) (8) (271) Amortization of Fuel Contracts Amortization of Emission Credits (2) 27 EBITDA (Income)/Loss from Discontinued Operations 1 (13) (12) Station Service Reserve Reversal (15) (15) Acquisition Integration Costs 7 7 Audrain Asset Sale Adjustment 2 2 Mirant Legal Defense 6 6 Legal Settlement (67) (67) Write Down (Gains) on Sale of Equity Method Investments (3) (8) (11) Adjusted EBITDA (15)

46 Reg. G Appendix Table A5: First Half 2006 Free Cash Flow reconciliation The following table summarizes the calculation of adjusted free cash flow and provides a reconciliation to cash flow from (used by) operations First Half 2006 Cash Flow from Operations $ 677 Reclassification of payment of financing element of acquired derivatives (73) Adjusted Cash Flow From Operations $ 604 Capital Expenditures (74) Preferred Dividends (23) Adjusted Free Cash Flow $

47 Reg. G Appendix Table A6: Net Debt to Total Capital Reconciliation ($mm) The following table summarizes the calculation of Net Debt to Total Capital June 30, 2007 Numerator: Gross Debt 8,735 Total Cash 847 Net Debt 7,888 Denominator: Net Debt 7,888 Preferred 1,139 Book Value of Equity 4,441 Capital 13,468 Net Debt to Capital 58.6% 47

48 Reg. G EBITDA, adjusted EBITDA, free cash flow, cash flow yield and cash flow per share and adjusted net income 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 and adjusted net income 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 news release. Adjusted EBITDA is presented as a further supplemental measure of operating performance. Adjusted EBITDA represents EBITDA adjusted for the hedge reset, restructuring, impairment and corporate relocation charges, discontinued operations, and write downs and gains or losses on the sales of equity method investments and other assets; 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 news release. Free cash flow is cash flow from operations less capital expenditures and preferred stock dividends and is used by NRG predominantly as a forecasting tool to estimate cash available for debt reduction and other capital allocation alternatives. The reader is encouraged to evaluate each adjustment and the reasons NRG considers it appropriate for supplemental analysis. In addition, in evaluating free cash flow, the reader should be aware that in the future NRG may incur expenses similar to the adjustments in this news release. Cash flow yield and cash flow per share are important measures to investors evaluating our company because they demonstrate the efficiency of our cash generation for shareholders relative to market stock price and expected cash available for investment and capital allocation, respectively. 48