First Quarter 2005 Results Presentation. May 10, 2005

Transcription

1 First Quarter 2005 Results Presentation May 10, 2005

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, anticipate, forecast, plan, guidance, believe and similar terms. Such forwardlooking statements include, but are not limited to, expected earnings, future growth and financial performance, the successful implementation of our acquisition and repowering strategy, expected benefits and EBITDA improvements of the initiatives, and the EBITDA impact of the RMR settlement. 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 lowsulfur coal, adverse results in current and future litigation, failure to identify or successfully implement acquisitions and repowerings, and the inability to implement value enhancing improvements to plant operations and companywide processes. 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 May 10, 2005 and is based on assumptions believed to be reasonable as of that date. NRG disclaims any current intention to update such guidance from May 10, 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 Financial and Business Highlights Financial Review Focus on Return on Invested NRG Closing Remarks and Q&A Appendix 3

4 Financial and Business Highlights First quarter results Adjusted EBITDA of $154 million Cash flow from operations of $64 million Net debt/total capital ratio improved to 48% from 49% Transactions completed Enfield sale for $63.5 million effective 4/1/2005 TermoRio arbitration award of $71 million collected Redemption of $375 million of 8% notes on 2/4/2005 $41 million debt repurchase in open markets during January and March 4

5 Plant Operations 100% PRB coal operations successfully implemented at Huntley 67 and Dunkirk 4 Arthur Kill generation levels highest since 2000 due to NYC transmission constraints Capacity factor during Q at Norwalk Harbor doubled from Q due to transmission line maintenance Outsourced Big Cajun II river coalhandling operation Equivalent Availability Factor NRG Safety Record Continuous Focus Q1 Q % 84.6% % 85.5% % NRG 2004 NRG Q Industry 2004 Q3 Q4 93.4% 84.0% 93.9% 84.6% Total US OSHA Recordable Rate

6 Commercial Operations Hedging programs Increased hedges for 2006 PJM hedged at energy prices above BGS prices Hedged NY incity capacity for summer at market cap Secured additional gas transport capacity to support Northeast generation Optimizing value of gas transportation through physical arbitrage Q1 Milestones Completed independent review of risk controls Enhancing capability in market and transmission analysis and valuation of structured transactions Completed renewal/replacement of coal transportation contracts Added 15 approved counterparties improved ability to execute hedging program Initiatives Developing integrated emissions strategy across portfolio and timeframes Increasing focus on secondary arbitrage opportunities Spreads between various coals and emissions Spreads between oils and emissions Capturing location spreads in physical power prices moving our goods to the highest price market Enhancing value by capturing extrinsic value will be balanced with continued focus on market analysis and risk control. 6

7 Value Enhancing Active Hedging Program Northeast DarkSpread Trend: OnPeak 05 and 06 $53 $51 $49 $47 $45 $43 Cal '06 Bal '05 Increase in darks spread produced a negative MTM on hedges Increase coal hedges $41 Fallen dark spreads since March 31st $39 produces offsetting MTM gain $37 Historical dark spread trend $35 11/1/04 12/1/04 1/1/05 2/1/05 3/1/05 4/1/05 5/1/05 Dark spreads have increased with rising natural gas prices providing favorable hedging opportunities for coal margins. Note: Indicative trend for NY dark spread on 10 mmbtu/mwh heat rate (not inclusive of all costs). 7

8 Value Enhancing Growth Hedging Coal Generation 1,2 25% 27% 62% 61% 75% 96% 73% 92% 38% 54% 39% 45% Hedged Energy Open Energy Coal Hedged Coal hedged Eastern and Western Transportation is locked in Year Eastern (mm tons) % hedged Western (mm tons) % hedged Total (mm of tons) % hedged 100% under firm contract for 510 years for PRB coal and 35 years for % % % Eastern coal Completed lease arrangement for new % % % rail cars took delivery of 480 of % % % at March 31, 960 to date % % % Renewed existing lease of 239 rail cars 1. Energy position as of April 26, 2005; excludes capacity revenues and ancillary services 2. Includes Northeast and South Central portfolios 8

9 Value Enhancing Growth Current Focus Improved Plant Performance: Reliability, fuel efficiency, output Cost and Process Control Initiatives: Plants and headquarters Growth Enhance and Expand the Portfolio: Core asset brownfield Select greenfield Bolton acquisitions Fuel supply chain investment Consolidation Arrow thickness generally represents relative capital intensity Enhanced trading, marketing and hedging activity 9

10 Value Enhancing Growth Participating in Capacity Market Reform Across US Region New York New England PJM California Characteristics Demand curve and locational prices in NYC, Long Island, Rest of State (ROS) Demand curve and locational prices for SW Connecticut, Connecticut, Rest of Pool (ROP), Maine, and NEMA Demand curve, locational prices, 4 year forward procurement Resource adequacy requirement for LSEs to enter bilateral capacity contracts to meet reserve requirements Timing and Details Established by FERC in 2002; implemented in 2003; updated in April 05 Developing in hearing at FERC; ALJ recommendation June 15; FERC decision likely in September 05, implementation January 06 Under consideration at PJM, may be proposed to FERC in upcoming months CPUC defining eligible capacity and requirements, rule expected in Central capacity market with demand curve and locational prices market possible in NRG MW affected 1,550 MW NYC 3,050 MW ROS 1,850 MW CT 130 MW ROP 1,100 MW East 800 MW West 950 MW in SP15 Capacity fundamentals and implied potential capacity prices, $/kwmo (1) Mild surplus in NYC Strong surplus in ROS $5 $7 (2006 NYC) $0.50 $1.50 (2006 ROS) Shortage in CT Surplus in ROP $3 $10 (2006 CT) $1 $3 (2006 ROP) Moderate surplus in PJM East Strong surplus in PJM west $2 $4 (2007 East) $0.50 $1.50 (2007 West) Statewide shortage, regional reliability needs not yet clearly defined, SP15 particularly constrained $8 $10 (2007) NRG s current portfolio could have margin upside if NE, PJM and CA adopt NY s basic capacity market model (1) Implied capacity prices derived as follows: a) NY: from FERCapproved demand curve and estimated capacity additions; b) NE: from ISONE and other intervenor proposals and sensitivity scenarios; c) PJM: from PJM draft demand curve recommended to stakeholders and NRG projected capacity supply; and d) CA: assumes new peaker sets pricing consistent with NE estimated peaker costs. 10

11 Financial Results

12 Financial Summary Financial Highlights ($ millions) Adjusted EBITDA ($ millions) Q1 05 Q1 04 Q $257 Operating revenues Kendall Sale (11) Net income West Coast Power (33) EBITDA Mark to Market (40) Adjusted EBITDA $154 $257 Regional Margins (15) O&M Expenses (14) General & Administrative (14) Equity Earnings, net of WCP 21 Other, net 3 Q $154 12

13 Source of Variable Margin (1) $ in millions H L Q Q Q Q Q Volatility Contract Capacity Contract Energy Merchant Capacity Merchant Energy Other (1) See appendix for details on contracted portion of portfolio 13

14 Q Adjusted EBITDA by Operating Segment 300 $ in millions Q Q Thermal, Alt Energy, Nongen & Other Adjusted Total EBITDA Other North America Other Internat l Northeast South Central West Coast Australia

15 Q Cash Flow $ in millions Adjusted EBITDA Interest Payments Cash Income Tax Cash Other NonCash Items Working Capital Changes excludes accrued interest Other Assets & Liabilities CFO Asset Divestitures Capital Expenditures Other Cash used by Investing Foreign Exchange Rate Changes & Other Cash Flow Before Financing Activities $154 (56) (3) 66 (107) 10 $64 0 (12) 104 (2) $154 Cash Flow Before Financing Activities Cash used for Debt Repayments, Dividends, Other Net Cash Flow $154 (501) ($347) 15

16 Liquidity $ millions 3/31/05 12/31/04 Unrestricted Cash: Domestic International Restricted Cash: Domestic International Total Cash $841 $1,223 Letter of Credit Availability Revolver Availability Total Current Liquidity $1,167 $1,566 1 Increase from 12/31/04 to 2/28/05 primarily related to collection of TermoRio settlement. 2 Decrease primarily related to Flinders refinancing which allowed the reclassification of restricted cash to unrestricted cash, which was later used to pay down the Flinders debt. 16

17 Capital Structure Gross debt declined by $538 MM during Q $5.0 $4.0 Gross Debt $3.0 $2.0 $1.0 $0.0 Q4 03 Q1 04 Q4 04 Q1 05 Q4 05 (A) (A) (A) (A) (Est.) Debt to total capital is within our targeted range 75% Debt to Capital 50% Net Debt Target 25% Gross Debt Net Debt 0% Q4 03 Q1 04 Q4 04 Q1 05 Q4 05 (A) (A) (A) (A) (Est.) 17

18 2005 Adjusted EBITDA Guidance 2005 Adjusted EBITDA $600 million 2005 Cash Flow from Operations $467 million Factors Natural Gas Coal Oil Interest rates Sensitivity $1.00/mmbtu ± 10% Movement $1.00/barrel ± 100 bps Results in the following change to 2005 pretax income: < $5 million ± $0.8 million ± $3.7 million Sensitivities are for the remaining 9 months of 2005, assuming current hedged positions. NRG has substantially hedged its downside risk in operating gross margin for 2005, while preserving upside potential. 18

19 Enterprise Value As of 3/31/05 $ in millions Supported Nonsupported Enfield Total Consolidated Debt $ 2,651 $ 582 $ 3,233 Unrestricted Cash (Includes LC) ,004 Restricted Cash Total Cash ,082 Net Debt 2 1, ,151 Value of Preferred Stock Equity Value 4 2,835 2,835 Enterprise Value $4,911 $495 $5,406 Forecasted 2005 Adjusted EBITDA $ 543 $ 41 $16 $ 600 TEV / FY Adjusted EBITDA 9.04x 9.01x Forecasted 2005 EBITDA + $60 MM MTM $ 603 $ 660 TEV / FY Adjusted EBITDA 8.14x 8.19x 1 Unrestricted cash includes expected cash proceeds of $65 MM from sale of Enfield which closed on 4/01/05 and $176 MM unused LC 2 Includes $350 MM fully funded LC 3 Supplemented slide to include preferred stock shares 19 4 Based on a stock price of $32.59 as of May 9, 2005

20 Equity Earnings and Schkopau Equity earnings: Gladstone MIBRAG West Coast Power Rocky Road James River Saguaro $ in millions Forecasted 2005 Equity Earnings Adj EBITDA EBITDA Multiple Enterprise Value 79.2 Depreciation & Interest & Tax Unconsolidated Adj EBITDA x $ 1,304 Net Project Level Debt 1 $ MV of Equity Interest $ 1,112 Implied Multiple Consolidated Germany: Schkopau 900 MW lignite coalfired facility. NRG owns 41.9 percent. E.On is the remaining interest owner and operates the plant. Capacity contract with Vattenfall for 400 MW expires Implied Share Price of Equity Interest Schkopau at March 31, 2005 Power Receivable & Note w/ GBR Capital Lease Equity Value Schkopau Equity Value per Share Implied Equity Value Excluding Schkopau and Equity Earnings $ $ 3.29 $ 1,437 Implied Share Price Excluding Schkopau and Equity Earnings $ x 2 1 Revised depreciation, interest, tax and net project level debt 2 Assumes EBITDA of $434MM and Enterprise Value of $3,216 MM (Adjusted for Schkopau and Equity Interests) 20

21 FOCUS ON Bottom Line Return is What Matters 21

22 Value Enhancing Growth Sources Operations Recapture nameplate capacity Goal: 95% of nameplate capacity Plants: Huntley, Dunkirk, and Indian River Measurement: GADS Opportunity: $15 20 million in EBITDA improvement Reduce forced outages Goal: Significantly reduce MWh lost due to tube leaks Plants: All coal units Measurement: EFOR and EAF Opportunity: 430,000 MWh lost in Q alone Station Service Goal: Reduce outside power purchases/increase MWh for sale Plants: All Measurement: Reduced utility bills and difference between gross and net output Opportunity: Being measure Procurement Goal: Rationalize $400+ spend Plants: All plus corporate Measurement: Total spend Opportunity: 510% Corporate Insurance Procure D&O, property, and health and welfare insurance at more beneficial terms and rates Taxes Reduce cash income and other taxes through a more efficient corporate structure Other Initiatives Corporate procurement card program Improved efficiency of cash investments Improve process to reduce outside fees Cost and Process Control Initiatives Improved Plant Performance 45 projects identified and underway 22

23 Value Enhancing Growth Impact of Plant and Corporate Initiatives Driving Return on Invested Capital at NRG A Key Operating Principle EBITDA Impact (1) ($ in millions) Run Rate Operations Initiatives $ 5 $21 $ 37 $62 Corporate Initiatives (2) Total $30 $54 $75 $100 Cost and Process Control Initiatives Improved Plant Performance (1) Not included in 5/10/2005 guidance (2) Incremental to the $17 million previously targeted and included in 2005 guidance 23

24 Closing Remarks and Questions and Answers

25 Disciplined Value Creation and Growth: Continuous Focus Financial Objectives Focus on liquidity and cash generation Maintain debt/capital ratio range of 45% to 55% Optimize use of excess cash on hand for return to shareholders through active capital allocation program Operational Objectives Contract longterm coal commodity, rail and railcars with minimal price impacts Optimally hedge power sales of coal fleet through 2006 Complete implementation of PRB strategy Implement and expand Strategic Objectives Grow our regional businesses with multiple fuel types and loadfollowing capabilities Promote introduction of locational capacity markets in core regions to ensure adequate compensation to NRG plants in transmissionconstrained load pockets Develop longterm contractbased solutions to enable brownfield development at NRG core fleet 25

26 Appendix

27 Q1 Operating Revenues Q1 05 Q1 04 Capacity $65 MM (11%) $134 MM (22%) $79 MM (13%) $138 MM (23%) By Type Other Energy $402 MM (67%) $383 MM (64%) $55 MM $5 MM $51 MM $21 MM Northeast Other NA $43 MM $40 MM By Region Other Other Int l $49 MM $332 MM $62 MM $331 MM Australia $117 MM $95 MM South Central 27

28 Q1 Operating Expenses and Depreciation Q1 05 Q1 04 Maintenance $41 MM Maintenance $29 MM Other Operating Expenses $184 MM Fuel Cost $276 MM Oil, $69 MM Gas, $70 MM Coal, $137 MM Other Operating Expenses $187 MM Fuel Cost $221 MM Oil, $51 MM Gas, $53 MM Coal, $117 MM 28

29 G&A Expenses & Nonrecurring Items $ in Millions Nonrecurring Charges, Nonrecurring Charges, 7 G&A, 36 Nonrecurring Charges, 5 G&A, 46 G&A, 54 G&A, 75 Nonrecurring Charges, 3 G&A, Nonrecurring Charges, 6 1Q Q Q Q Q

30 Q1 Equity Earnings Q1 05 Q1 04 $1 MM $4 MM $4 MM $6 MM $3 MM $7 MM $7 MM $16 MM $6 MM $1 MM Gladstone Mibrag Enfield West Coast Power Other 30

31 2005 Cash Flow from Operations Guidance $ in millions EBITDA Nonrecurring Items Adjusted EBITDA Interest Payments Income Tax Other Funds used by Operations Working Capital Changes Cash Flow from Operations 2005 Outlook $620 (20) $600 (231) (18) 121 (5) $467 31

32 Debt Schedule (US $mm) 3/31/2005 S S S S S S S S S Xcel Note Senior Credit Facility 8% Notes Camas Conemaugh NEO Northbrook NEO NY Peakers Thermal San Francisco Thermal AudrainCapital Lease SchkopauCapital Lease Itiquira Flinders Total consolidated , $ 3,228.5 S indicates Supported Project 32

33 Core Strategy: Leverage off Asset Base Regional concentration with fuel and dispatchlevel diversity Oil 628 MW 59% West Gas 427 MW 41% South Central Gas 842 MW 11% Northeast Oil Coal 2,350 MW 2,407 MW 30% 30% Dual Fuel 2,284 MW 29% Gas 980 MW 40% Coal 1,489 MW 60% Dispatch Type Note: Other North America includes 1,579 MW outside of core regions Peaking 28% Baseload 37% Intermediate 28% 33

34 International Australia & Germany Aligns well with North American portfolio with coalfired plants Australia Coal 1,390 MW 100% Gladstone Flinders Germany Coal 519 MW 100% MIBRAG Sckhopau 34

35 Operating Statistics Q Region Generation (MWh) Equivalent availability % Average heat rate (Btu / kwh) Net capacity factor % Net owned capacity MW Northeast* 4.0 million 89 10, ,757 South Central 2.6 million 93 10, ,469 West 0.6 million 76 10, ,050 Q Region Generation (MWh) Equivalent availability % Average heat rate (Btu / kwh) Net capacity factor % Net owned capacity MW Northeast* 3.9 million 88 10, ,757 South Central 2.3 million 87 10, ,469 West 0.5 million 73 *Does not include statistics for Keystone and Conemaugh 10, ,321 35

36 South Central Market Overview Comments Assets dispatched according to load Network transmission required for delivery and transmission constraints limit excess sales Market pricing based upon bilateral agreements Verticallyintegrated companies and nonexistent capacity markets Market Participant Generation Type Regulated Utilities Load Servers Merchants Megawatts 27,577 12,793 12,280 Merchants 21% CoGens 10% Regulated Utilities 47% CoGens 5,893 Total Megawatts Summer Peak Megawatts 58,542 32,706 Load Servers 22% 36

37 South Central Asset Overview Asset Location Fuel Type Dispatch Net Capacity (MW) Big Cajun II New Roads, LA Coal Baseload 1,489 Big Cajun I New Roads, LA Gas/Oil Peaking 458 Bayou Cove Jennings, LA Gas Peaking 320 Sterlington Sterlington, LA Gas Peaking of 11 Customers (52% of Cooperative load) 20 years remaining on contracts Sterlington (202 MW; Gas) 4 of 11 Customers (48% of Cooperative load) 49 years remaining Bayou Cove (320 MW; Gas) Big Cajun II (1,489 MW; Coal) Big Cajun I (458 MW; Gas) 37

38 Contracted Position: Australia Asset NRG Ownership % Other Owners Contract Type Length Customers Financial Structure Flinders Two brown coalfired stations 760 MW in 2 stations produced 4,289,838 MWh in 2004: Northern is 520 MW of baseload capacity Playford is 240 MW of refurbished midmerit capacity Leigh Creek mine owned by NRG and operated to supply generating stations 100% N/A Energyonly load following contract up to 420 MW in 2005 and 550 MW in 2006 and beyond Expires 2009 Investment grade retailer Consolidated Gladstone Black coalfired generating station, net ownership of 630 MW and plant operator Produced 3,065,044 MWh produced in % Comalco and a consortium of Japanese corporations Output is fully contracted Expires 2029 Boyne Smelter, operated by power plant partners Enertrade, a market operation owned by the Queensland government Equity investment 38

39 Contracted Position: Germany Schkopau MIBRAG Asset 900 MW (400 MW NRG interest) lignitecoal fired facility Produced 2,560,926 MWh in lignite coal mines produced 19.7 million tonnes total in coalfired power plants totaling 119 MW Mumsdorf Walitz Deuben NRG Ownership % Other Owners Contract Type Length Customers 41.90% E.ON owns remainder of facility and operates plant Capacity contract for 400 MW, accounted for as a Note Receivable Expires 2021 Capacity: Vattenfall 50% Washington Group International owns remaining 50% Longterm various lengths, 100% of coal and power output contracted Various Coal: Lippendorf power plant Schkopau power plant Onsite power plants Power/Steam: Mining operation, local retail provider, local municipalities Financial Structure Consolidated Equity investment 39

40 Contracted Position: Thermal Asset NRG Ownership % Contract Type Length Customers 5 district heating and cooling systems Minneapolis, MN San Francisco, CA Pittsburgh, PA Harrisburg, PA San Diego, CA 88 MW peaking plant and 18 MW coalfired cogeneration facility in Dover, DE 3 highpressure steam projects 100% Longterm Various Approximately 565 customers, primarily commercial and industrial businesses and business districts Financial Structure Consolidated 40

41 Regulation G Appendix Table A1: Adjusted Net Income Reconciliation The following table summarizes the calculation of adjusted net income and provides a reconciliation to GAAP net income/(loss), including per share amounts. (Dollars in thousands, except per share amounts) Net Income Three Months Ended 03/31/2005 $22,618 Diluted EPS $0.26 Three Months Ended 03/31/2004 $30,235 Diluted EPS $0.30 Plus: (Income) Loss from Discontinued Operations, net of tax Corporate relocation charges, net of tax 2, Reorganization items, net of tax 3, Gain on Crockett, net of tax (2,138) (0.02) Gain on TermoRio Settlement, net of tax (8,180) (0.09) Write downs and (gains)/losses on sales of equity method investments, net of tax 1, Adjusted Net Income $14,393 $0.16 $36,470 $

42 Regulation G continued Appendix Table A2: EBITDA Reconciliation The following table summarizes the calculation of EBITDA and provides a reconciliation to net income/(loss): Three Months Ended Three Months Ended Net Income: Plus: 03/31/2005 $22,618 03/31/2004 $ 30,235 Income Tax Expense 4,802 14,280 Interest Expense 53,647 56,885 Amortization and Write Downs of Finance Costs 1,413 2,063 Amortization of Debt Discount/Premium 931 3,781 Refinancing Expenses 25,024 30,417 Depreciation Expense 48,424 55,006 WCP CDWR contract amortization 30,968 Amortization of power contracts 7,528 16,965 Amortization of emission credits EBITDA 3,626 $168,013 6,270 $246,870 Loss from Discontinued Operations 4 1,211 Corporate relocation charges 3,455 1,116 Reorganization items 6,250 Gain on Crockett (3,536) Gain on TermoRio Settlement (13,532) Write Downs/Loss on Sales of Equity Investments Adjusted EBITDA $154,404 1,738 $257,185 42

43 Regulation G continued Appendix Table A3: Net Debt to Capital Reconciliation The following table summarizes the calculation of Net Debt to Capital: Numerator Gross Debt Total Cash Net Debt $3,228,461 (841,284) $2,387,177 Denominator Net Debt to Capital Book Value of Equity Net Debt Capital $2,610,090 2,387,177 $4,997,267 48% 43

44 Regulation G continued Appendix Table A4: First Quarter 2005 Regional EBITDA Reconciliation The following table summarizes the calculation of EBITDA and provides a reconciliation to net income/(loss): Three months ending March 31, 2005 Northeast South Central West Other NA Australia Other Intl Alt. Energy NonGen Corp Net Income: $ 32,860 $ 9,306 $ 3,259 $ (5,162) $ 10,180 $ 42,268 $ 538 $ 5,109 $ (75,740) Plus: Income Tax Expense/Benefit , (408) Interest Expense 88 1,742 4,418 3,619 3, ,243 38,407 Amortization and Write Downs of Finance Costs 6 5 1,402 Amortization of Debt Discount/Premium 598 1,233 (193) (234) (473) Refinancing Expense (9,783) 34,807 Depreciation Expense 18,609 15, ,993 6, ,316 2,739 1,039 Amortization of power contract (2,736) 2,974 7, Amortization of emission credits EBITDA 2,468 $54,025 1,158 $25,210 $3,485 $5,678 $18,132 $50,237 $2,122 $10,091 $(966) Nonrecurring Charges 4 3,451 Discontinued Operations 4 Gain on TermoRio (13,532) Gain on Crockett Adjusted EBITDA $54,029 $25,210 $3,485 (3,536) $2,146 $18,132 $36,705 $2,122 $10,091 $2,485 44

45 Regulation G continued Appendix Table A5: First Quarter 2004 Regional EBITDA Reconciliation The following table summarizes the calculation of EBITDA and provides a reconciliation to net income/(loss): Three months ending March 31, 2004 Net Income: Northeast $87,428 South Central $11,377 West $1,211 Other NA $(11,219) Australia $13,136 Other Int'l $10,330 Alt. Energy $544 NonGen $8,734 Corp $(91,306) Plus: Income Tax Expense/Benefit ,264 4, ,204 Interest Expense (714) 1,716 8,221 5,168 (1,503) 7 2,506 41,484 Refinancing Expense 30,417 Amortization and Write Downs of Finance Costs 2,063 Amortization of Debt Discount/Premium 634 3,965 (185) (5) (284) (344) Depreciation Expense 18,529 16, ,610 5, ,389 3,124 1,341 WCP CDWR contract amortization 30,968 Amortization of power contract 4,485 (3,195) 814 2,484 12, EBITDA Amortization of emission credits 4,751 $114,479 1,519 $ $33,347 $11,396 $38,671 $13,694 $1,939 $14,472 $(10,141) Reorganization Items ,366 Corporate Relocation Charges 1,116 Discontinued Operations 984 (120) 347 Write Downs/Loss on Sales of Equity Investments Adjusted EBITDA $114,800 $29,737 $33,347 (235) $12,295 1,973 $40,644 $13,575 $2,286 $15,160 $(4,659) 45

46 Glossary CFO Cash from operations FFO Funds from operations EBITDA Earnings Before Interest, Taxes, Depreciation and Amortization Free cash flow (FCF) nongaap measure of cash flow which equals cash flow from operations less capital expenditures and dividends Supported assets in core regions that contribute cash and earnings to the parent company Nonsupported assets with significant debt burden that do not contribute cash to the parent company MarktoMarket Recording the price or value of a commodity on a regular basis, to calculate profits and losses from the purchase price relative to current price 46