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2Q_2008_Earnings_FINAL_(Web)
 

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    2Q_2008_Earnings_FINAL_(Web) 2Q_2008_Earnings_FINAL_(Web) Presentation Transcript

    • El Paso Corporation Second Quarter 2008 Financial & Operational Update August 6, 2008
    • Cautionary Statement Regarding Forward-looking Statements This presentation includes certain forward-looking statements and projections. The company has made every reasonable effort to ensure that the information and assumptions on which these statements and projections are based are current, reasonable, and complete. However, a variety of factors could cause actual results to differ materially from the projections, anticipated results or other expectations expressed in this presentation, including, without limitation, changes in unaudited and/or unreviewed financial information; our ability to implement and achieve our objectives in the 2008 plan, including earnings and cash flow targets; the effects of any changes in accounting rules and guidance; our ability to meet production volume targets in our E&P segment; outcome of litigation; our ability to comply with the covenants in our various financing documents; our ability to obtain necessary governmental approvals for proposed pipeline projects and our ability to successfully construct and operate such projects; the risks associated with recontracting of transportation commitments by our pipelines; regulatory uncertainties associated with pipeline rate cases; actions by the credit rating agencies; the successful close of our financing transactions; our ability to successfully exit the energy trading business; our ability to close our announced asset sales on a timely basis; changes in commodity prices and basis differentials for oil, natural gas, and power and relevant basis spreads; inability to realize anticipated synergies and cost savings associated with restructurings and divestitures on a timely basis; general economic and weather conditions in geographic regions or markets served by the company and its affiliates, or where operations of the company and its affiliates are located; the uncertainties associated with governmental regulation; political and currency risks associated with international operations of the company and its affiliates; competition; and other factors described in the company’s (and its affiliates’) Securities and Exchange Commission filings. While the company makes these statements and projections in good faith, neither the company nor its management can guarantee that anticipated future results will be achieved. Reference must be made to those filings for additional important factors that may affect actual results. The company assumes no obligation to publicly update or revise any forward-looking statements made herein or any other forward-looking statements made by the company, whether as a result of new information, future events, or otherwise. Certain of the production information in this presentation include the production attributable to El Paso’s 49 percent interest in Four Star Oil & Gas Company (“Four Star”). El Paso’s Supplemental Oil and Gas disclosures, which are included in its Annual Report on Form 10-K, reflect its proportionate share of the proved reserves of Four Star separate from its consolidated proved reserves. In addition, the proved reserves attributable to its proportionate share of Four Star represent estimates prepared by El Paso and not those of Four Star. Cautionary Note to U.S. Investors—The United States Securities and Exchange Commission permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We use certain terms in this presentation that the SEC's guidelines strictly prohibit us from including in filings with the SEC. U.S. Investors are urged to consider closely the disclosures regarding proved reserves in this presentation and the disclosures contained in our Form 10-K for the year ended December 31, 2007, File No. 001-14365, available by writing; Investor Relations, El Paso Corporation, 1001 Louisiana St., Houston, TX 77002. You can also obtain this form from the SEC by calling 1-800-SEC-0330. Non-GAAP Financial Measures This presentation includes certain Non-GAAP financial measures as defined in the SEC’s Regulation G. More information on these Non-GAAP financial measures, including EBIT, EBITDA, adjusted EBITDA, adjusted EPS, cash costs, and the required reconciliations under Regulation G, are set forth in this presentation or in the appendix hereto. El Paso defines Resource Potential or Resource Inventory as subsurface volumes of oil and natural gas the company believes may be present and eventually recoverable. The company utilizes a net, geologic risk mean to represent this estimated ultimate recoverable amount. 2
    • Our Purpose El Paso Corporation provides natural gas and related energy products in a safe, efficient, and dependable manner 3
    • Our Vision & Values the place to work the neighbor to have the company to own 4
    • Six-Month Scorecard: Accomplishments Pipelines Ruby, Line 300 Committed project inventory $8 billion $1.2 billion future EBITDA* E&P Inventory growth Haynesville, Niobrara, Altamont, Raton CBM Brazil Bia/Camarupim accelerating Pinauna progressing Portfolio Divestitures complete Hedges Improved 2009 position Added $9 x $18 and $10 x $17 collars for 2009 3.4 MM Bbls at $110 Higher earnings and cash flow Financial Ahead of expectations Share buy back Dividend increase Expanded drilling program *EBITDA run rate on pro-rata basis 5
    • 2008 Challenges Project execution Pipeline and E&P Significant project inventory Cost control Pipeline Steel, contractor E&P Services, fuel-related Acquisition integration E&P Employee retention Delayed ramp up MTM volatility Marketing PJM basis 6
    • 2008 Outcomes Earnings Improved $1.40–$1.50* 40%–50% over 2007* EBITDA Improved $3.8 billion–$3.9 billion Capex Higher $3.8 billion Inventory E&P Continued growth Pipelines Largest ever *Assumes full year average natural gas price of $9.75/MMBtu and average oil price of $118 Bbl based on actual prices through August and recent forward prices for September through December; adjusted for MTM impact of production-related derivatives and other items 7
    • Financial Results
    • Financial Results: Three Months Ending June 30 $ Millions, Except EPS Adjusted Diluted EPS Diluted EPS Adjusted from Continuing from Continuing EBITDA $865 $0.39 $0.25 $819 $0.22 $0.29 2008 2007 2008 2007 2008 2007 Earnings growth driven by higher gas prices and lower interest Realized Natural EBIT Interest Expense Gas Price ($Mcf) $499 $231 $470 $221 $9.53 $7.67 2008 2007 2008 2007 2008 2007 Note: Appendix and slides 10 and 11 include details on non-GAAP terms 9
    • Items Impacting 2Q 2008 Results $ Millions, Except EPS Diluted Pre-tax After-tax EPS Income available to common stockholders $191 $ 0.25 Adjustments1 Change in fair value of power contracts $105 $ 67 $ 0.09 Change in fair value of legacy indemnification (9) (6) (0.01) Other legacy litigation adjustments (27) (29) (0.04) Change in fair value of production-related derivatives in Marketing 52 33 0.04 61 39 0.06 Impact of MTM E&P derivatives2 $ 0.39 Adjusted EPS—Continuing operations3 1All adjustments assume a 36% tax rate, except other legacy litigation adjustments, and 761 MM diluted shares 2Includes $75 MM of MTM losses on derivatives adjusted for $14 MM of realized losses from cash settlements 3Reflects fully diluted shares of 769 MM and includes income impact from dilutive securities 10
    • Business Unit Contribution $ Millions Three Months Ended June 30, 2008 Adjusted EBIT DD&A EBITDA EBITDA* Core Businesses $ 295 $ 99 $ 394 $ 428 Pipelines 304 197 501 535 E&P $ 599 $ 296 $ 895 $ 963 Core Businesses Total Other Businesses (153) – (153) (153) Marketing 12 – 12 12 Power 41 2 43 43 Corporate & Other $ 499 $ 298 $ 797 $ 865 Total *Adjusted Pipeline EBITDA for 50% interest in Citrus and adjusted E&P EBITDA for 49% interest in Four Star; Appendix includes details on non-GAAP terms 11
    • Cash Flow and Capital Investment $ Millions Six Months Ended June 30, 2008 2007 $ 410 $ 121 Income from continuing operations 875 939 Non-cash adjustments 1,285 1,060 Subtotal 33 (178) Working capital changes and other* 1,318 882 Cash flow from continuing operations – (17) Discontinued operations $1,318 $ 865 Cash flow from operations $1,175 $1,130 Capital expenditures $ 336 $ 270 Acquisitions $ 659 $ 80 Divestitures $ 75 $ 75 Dividends paid *Includes change in margin collateral of $51 MM in 2008 and $72 MM in 2007 12
    • Marketing Financial Results $ Millions Three Months Ended Six Months Ended June 30, June 30, 2008 2007 2008 2007 EBIT Strategic Change in fair value of production-related derivatives $ (52) $ 9 $ (73) $ (78) Other Change in fair value of natural gas derivative contracts 11 2 11 (22) Change in fair value of power contracts (105) (15) (146) (32) Settlements, demand charges, & other – (12) 5 (19) Operating expenses & other income (7) 21 (10) 21 Other total (101) (4) (140) (52) EBIT $(153) $ 5 $(213) $(130) 13
    • PJM Basis MTM Earnings & Cash Settlements $50 Cash Settlements Change in MTM Value $30 $10 ($10) ($30) ($50) ($70) ($90) ($110) ($130) ($150) Q205 Q305 Q405 Q106 Q206 Q306 Q406 Q107 Q207 Q307 Q407 Q108 Q208 14
    • 2008 Natural Gas and Oil Hedge Positions Positions as of July 15, 2008 (Contract Months July 2008 – Forward) 98 TBtu Ceiling Average cap $10.23/MMBtu 81 TBtu 17 TBtu 2008 Gas $10.75 ceiling/ $7.66 $8.00 floor fixed price 98 TBtu Floor Average floor $7.94/MMBtu Balance at Market Price 1.71 MMBbls Ceiling Average cap $79.54/Bbl 1.26 MMBbls 0.45 MMBbls 2008 Oil $87.80 $56.40 ceiling/ fixed price $55.00 floor 1.71 MMBbls Floor Average floor $79.17/Bbl Hedging strategy preserves upside to higher prices 15 Note: See full Production-Related Derivative Schedule in Appendix
    • 2009 Natural Gas and Oil Hedge Positions Positions as of July 15, 2008 151 TBtu Ceiling Average cap $14.97/MMBtu 143 TBtu 168 TBtu 8 TBtu 2009 Gas $15.41 $9.10 $7.36 ceiling floor fixed price 176 TBtu Floor Balance at Average floor $9.02/MMBtu Market Price 3.43 MMBbls 2009 Oil $109.93 fixed price >50% of oil and domestic natural gas hedged 2009 hedge program enhances revenues by approximately $270 MM Note: See full Production-Related Derivative Schedule in Appendix 16
    • Pipeline Group
    • 2Q Highlights EBIT: $295 MM Throughput increased 6% from 2007 Significant progress on growth projects Ruby Pipeline TGP Line 300 Expansion CIG Raton 2010 WIC expansion Committed backlog increased to $8 billion 18
    • Pipeline Group Financial Results $ Millions Three Months Ended Six Months Ended June 30, June 30, 2008 2007 2008 2007 $ 693 $ 682 EBIT before minority interest $ 303 $ 318 17 – Less minority interest 8 – $ 676 $ 682 EBIT $ 295 $ 318 $ 874 $ 867 EBITDA $ 394 $ 409 $ 938 $ 935 Adjusted EBITDA1 $ 428 $ 445 $ 455 $ 426 Capital expenditures $ 266 $ 232 $ 295 $– Acquisitions2 $– $– 1AdjustedPipeline EBITDA for 50% interest in Citrus 2Gulf LNG acquisition Note: Appendix includes details on non-GAAP terms 19
    • Continued Throughput Increase YTD % Increase 2008 vs. 2007 Independence Hub TGP 5% Elba deliveries to Florida SNG 7% California EPNG 2% Rockies supply, CIG 9% expansions 6% overall increase Note: CIG includes Colorado Interstate Gas, Cheyenne Plains and Wyoming Interstate EPNG includes El Paso Natural Gas and Mojave 20
    • El Paso Backlog: Large and Profitable Total committed backlog $8 billion WIC Medicine Bow Expansion $39 MM Ruby Pipeline Sep 2008 $3 Billion TGP Concord 330 MMcf/d 2011 $21 MM TGP Line 300 Expansion 1.3–1.5 Bcf/d Nov 2009 $750 MM (Phase I & II) 30 MMcf/d 2010-2011 290 MMcf/d WIC Expansion - Kanda CIG High Plains Pipeline Lateral & Wamsutter $216 MM (100%) $55 MM Elba Expansion III & Elba December 2008 2010–2011 Express 900 MMcf/d 240 MMcf/d $1.1 Billion SNG SESH –Phase I 2010–2013 CIG Totem Storage $172 MM 8.4 Bcf / 0.9 Bcf/d & 1.2 Bcf/d WIC Piceance $154 MM (100%) Sep 2008 Lateral July 2009 140 MMcf/d $62 MM SNG Cypress Phase III 200 MMcf/d 4Q 2009 $86 MM 220 MMcf/d Jan 2011 CIG Raton 2010 160 MMcf/d Expansion TGP Carthage TGP Bluewater / 800 Ln Exp $146 MM Expansion $25 MM 2Q 2010 $39 MM SNG South System III/ Nov 2008 130 MMcf/d May 2009 SESH Phase II 340 MMcf/d 100 MMcf/d $352 MM / $69 MM 2011–2012 Gulf LNG 370 MMcf/d / 350 MMcf/d $1+ Billion (100%) Oct 2011 El Paso Pipeline Partners, LP FGT Phase VIII 6.6 Bcf / 1.3 Bcf/d Expansion $2.4 Billion (100%) El Paso Pipeline 2011 800 MMcf/d Note: As of August 6, 2008; El Paso Pipeline Partners owns 10% of SNG & CIG 21
    • Ruby Pipeline Update Market commitments of 1.1 Bcf/d 670 miles of 42quot; pipeline 100% of pipe ordered $3 billion capex Incentive-based construction contracts 1.3–1.5 Bcf/d capacity On the ground since mid-2007 2011 in-service Malin OR ID WY Tuscarora Opal Hub PG&E WIC Ruby Pipeline Cheyenne Paiute Cheyenne CA Plains Uinta Kern River Basin NV CO Piceance Basin CIG UT 22
    • TGP Line 300 Expansion NH VT Marcellus Interconnects MA NY CT MI RI NJ REX-TGP PA Interconnect 125 miles of 30quot; looping OH 15-year contract for 300 MDth/d with Equitable Energy LLC EQT Production $750 MM capex WV 2010–2011 in-service Locked in pipe prices VA KY 23 23
    • Pipeline Summary Committed backlog $8 billion Highly focused on project execution On track to achieve 2008 EBIT & EBITDA targets 24
    • Exploration & Production
    • 2Q Highlights Improved earnings 4% sequential quarter production growth* Continued improvement in controllable unit costs Expanding domestic programs Increasing capital by $200 MM Haynesville and Niobrara Shale Cotton Valley horizontal test successful Altamont acquisition and down spacing Bia/Camarupim project (Brazil) accelerating *Pro forma basis; see appendix for reconciliation 26
    • E&P Results $ Millions Three Months Ended Six Months Ended June 30, June 30, 2008 2008 2007 2007 EBIT1 $ 304 $235 $ 546 $414 EBITDA1 501 424 955 773 Adjusted EBITDA2 535 451 1,021 828 Capital expenditures 400 383 702 735 Acquisition capital 43 16 43 270 1Three months ended includes MTM losses on derivatives of $75 MM in 2008 and $5 MM in 2007. Cash paid related to settlements of these derivatives were $14 MM and $12 MM, respectively. Year-to-date includes MTM losses on derivatives of $110 MM in 2008 and $2 MM in 2007. Cash paid related to settlements of these derivatives were $18 MM and $19 MM, respectively 2Adjusted E&P EBITDA for equity interest in Four Star Note: Appendix includes details on non-GAAP terms 27
    • 97% Drilling Success Rate 2008 YTD Actual Gross Wells Success Completed Rate High PC < 40% 4 0% High Impact Exploration Risk PC 40%–80% Med 12 83% Medium Risk Development and Exploration PC > 80% Low 222 99% Low Risk Domestic Development and Pinauna & Bia/Camarupim Development 238 97% Increasing capital to $1.9 billion 28
    • Total Cash Costs $/Mcfe $2.01 $1.92 $1.92 $0.33 $0.54 $0.42 $0.06 $0.04 $0.05 $0.68 $0.64 $0.63 $1.59 $1.50 $1.47 $0.85 $0.82 $0.79 2Q 2007 1Q 2008 2Q 2008 Direct Lifting Costs General & Administrative Taxes Other Than Production & Income Production Taxes Controllable unit costs down 7% yr/yr 29
    • 2Q Production Update MMcfe/d 1Q–2Q Pro Forma* 1Q–2Q As Reported 4% Increase 6% Decrease 886 857 830 833 808 798 12 14 11 11 14 12 173 134 136 141 202 130 222 236 223 201 195 202 147 155 147 149 155 144 311 308 308 295 308 316 2Q 2007 1Q 2008 2Q 2008 2Q 2007 1Q 2008 2Q 2008 Central Western TGC Central Western TGC GOM/SLA International GOM/SLA International Full year estimate ~860 MMcfe/d Note: Includes proportionate share of Four Star equity volumes Appendix includes details on non-GAAP terms 30 *Excludes volumes from domestic assets sold in 2008 and assumes full year of Peoples in 2007
    • Peoples Acquisition Update Acquisition Rationale Production and Active Rigs Increased scale and • efficiency Adds significant drilling • Closed inventory 120 12 Sep. 2007 Lower lifting costs • 100 10 Current Status 80 8 MMcfe/d Drilled 51 wells thru 2Q08 Rigs 60 6 Expect 95–100 by YE08 40 4 Production growth delayed, lower initial activity levels 20 2 Actively pursuing new 0 0 opportunities 3Q07 4Q07 1Q08 2Q08 3Q08E 4Q08E Haynesville shale Cotton Valley horizontal Production Active Rigs Vicksburg program Acquisition value up significantly 31
    • Arklatex Update 2008 Conventional Program 125–130 gross wells AK ~ $350 MM net capital 8–9 rigs running and growing Holly/Logansport Bethany Longstreet Cotton Valley Horizontal Testing horizontal drilling TX 1 well drilled and completed 4.4 MMcfe/d initial 30-day average LA Additional 30 gross locations currently identified; potential application to other wells in inventory Minden/SE Brachfield Haynesville Shale Exploration 1 well drilled; completion underway Haynesville Shale Approximately 42,500 net acres Lindy Britton #2H CV Horizontal Significant resource potential Miller Land 10H #1 Haynesville 32
    • Haynesville Shale Miller Land Co—H10#1 Perforations Completion underway 5,300' Rodessa 6,700' Hosston 9,000' Cotton Valley Bossier Shale 10,000' 11,500' Haynesville Shale 3,100' 11,700' Haynesville Lime 33
    • Raton Update 2008 CBM Program CO 84 gross wells $46 MM net capital CBM Increased Density Drilling Pursuing 80-acre spacing Hearing held in July with state of New Mexico Would add 500 gross locations and 250 Bcfe risked resource potential Niobrara Shale Exploration 3 wells drilled and completed NM 2 horizontal and 1 vertical Initial flow rates of 0.4–1.8 MMcfe/d Niobrara Shale $2 MM–$3 MM completed well costs Test well locations > 300,000 prospective net acres 34
    • Niobrara Shale VPR E-17A Typical CBM well 1.0 MMcf/d VPR D-95A VPR A-6A 1.8 MMcf/d 0.4 MMcf/d Perforations 1,000' Raton Coal Vermejo Coal 2,000' Trinidad Coal 3,000' Pierre Shale 3,900' 4,000' Niobrara A Shale 5,000' Niobrara B Shale 3,000' Niobrara C Shale 35
    • Altamont-Bluebell Update 2008 Program 8 gross wells drilled 36 recompletions WY $66 MM net capital UT Roll-up Acquisition Consolidates WI in operated assets Closed in 2Q 2008 1.6 MMBOE of proven reserves Altamont-Bluebell Includes remaining interest in Altamont gas plant Increased Density Drilling Pursuing 160-acre spacing Hearing in September 175–200 gross locations and >30 MMBOE risked resource potential 36
    • Bia/Camarupim Development Bia Development Project Project Overview: BM-ES-5 Block Petrobras: 65% Operator Petrobras operated with 24% EP El Paso: 35% working interest Brazil 35–50 MMcfe/d net peak production 4-ESS-177 Rio de Janeiro Bia/ 100–120 Bcfe net resources Camarupim $135 MM net capital total 6-ESS-168 Gas price indexed to basket of imported fuel oils 4-ESS-164 First gas in 1Q 2009 BES-100 Camarupim DOC Area Petrobras: 100% 4 development wells 2 KMS 0 1 2km Gas Discovery well 37
    • Bia/Camarupim Development Project Status: Commercial negotiations in final phase Unitization agreement & plan of development subject to regulatory approval Priority project for government with development activities underway 12quot; pipeline to PLEM completed & 24quot; pipeline being installed FPSO in yard with Oct 2008 delivery date Drilled 1st development well in 2Q 2008 38
    • Pinaúna Development Brazil Pinaúna 1-BAS-64 Rio de 1-BAS-74 Janeiro Project Statistics: 1-BAS-73 15–20 MBOE/d peak production 59–90 MMBOE total resource potential $700 MM–$750 MM total capital Açai 1-ELPS-160 1-ELPS-170A 100% WI Attractive returns at plan prices Cacau Açai ($70/Bbl) East 2.5 km 0 1.5 2.5 Resource Outlook Oil Gas 39
    • Pinaúna Development Development Scope Project Status: 4 Horizontal producers Executed FSO letter of intent 4 Horizontal Water Injectors Awaiting approval of Terms of Reference 1 Gas Producer from IBAMA Permitting & long lead sourcing continues Pinaúna Production MOPU Wellhead First production late 2009, dependent on 25,000 BOPD Oil capacity Platform timing of permit approvals Utility MOPU FSO WD = 20m 383,000 Bbl Oil Capacity 3 Km—6quot; HP Oil, Gas Subsea Pipelines WD = 35– 40m 10 Km—8quot; Crude Subsea Pipeline Açai/Cacau 10 Km—6quot; Fuel Gas Subsea Pipeline Wellhead Platform 40
    • E&P Summary Inventory growing Peoples (Arklatex, TGC) Haynesville & Niobrara shale Brazil, Egypt Projects advancing Bia/Camarupim faster than expected Pinaúna Altamont-Bluebell Domestic activity increasing in 2H 2008 Maintain current rig activity Advance new opportunities Improve exit rate On track for 8%–12% production growth (2007–2010) 41
    • Summary Earnings and cash flow up Pipelines $8 billion backlog Long-term EBIT growth 10%+ E&P Inventory continues to grow Brazil accelerates 2009 volume growth Progress on all fronts 42 42
    • El Paso Corporation Second Quarter 2008 Financial & Operational Update August 6, 2008
    • Appendix
    • Disclosure of Non-GAAP Financial Measures The SEC’s Regulation G applies to any public disclosure or release of material information that includes a non-GAAP financial measure. In the event of such a disclosure or release, Regulation G requires (i) the presentation of the most directly comparable financial measure calculated and presented in accordance with GAAP and (ii) a reconciliation of the differences between the non-GAAP financial measure presented and the most directly comparable financial measure calculated and presented in accordance with GAAP. The required presentations and reconciliations are attached. Additional detail regarding non-GAAP financial measures can be reviewed in El Paso’s full operating statistics, which will be posted at www.elpaso.com in the Investors section. El Paso uses the non-GAAP financial measure “earnings before interest expense and income taxes” or “EBIT” to assess the operating results and effectiveness of the company and its business segments. The company defines EBIT as net income (loss) adjusted for (i) items that do not impact its income (loss) from continuing operations, such as extraordinary items and discontinued operations; (ii) income taxes; and (iii) interest and debt expense. The company excludes interest and debt expense so that investors may evaluate the company’s operating results without regard to its financing methods or capital structure. EBITDA is defined as EBIT excluding depreciation, depletion and amortization. El Paso’s business operations consist of both consolidated businesses as well as investments in unconsolidated affiliates. As a result, the company believes that EBIT, which includes the results of both these consolidated and unconsolidated operations, is useful to its investors because it allows them to evaluate more effectively the performance of all of El Paso’s businesses and investments. Adjusted EBITDA is defined as EBITDA including the proportional share of EBITDA less our recorded equity earnings from our equity investments in Citrus and Four Star. The company believes that adjusted EBITDA is useful to its investors because it allows them to evaluate more effectively the performance of our businesses regardless of the type of ownership structure. Exploration and Production per-unit total cash costs or cash operating costs equal total operating expenses less DD&A, cost of products and services, transportation costs, and ceiling test charges divided by total production. It is a valuable measure of operating efficiency. For 2008, Adjusted EPS is earnings per share from continuing operations excluding the loss related to the change in fair value of an indemnification from the sale of an ammonia plant in 2005, the gain related to an adjustment of the liability for indemnification of medical benefits for retirees of the Case Corporation, gain related to the disposition of a portion of the company’s investment in its telecommunications business, loss on other legacy litigation adjustments, changes in fair value of power contracts, changes in fair value of the production-related derivatives in the Marketing segment and the impact of MTM E&P derivatives. For 2007, Adjusted EPS is earnings per share from continuing operations excluding changes in fair value of production-related derivatives in the Marketing segment, the gain on the sale of ANR and related assets and debt repurchase costs. Adjusted EPS is useful in analyzing the company’s on-going earnings potential. El Paso believes that the non-GAAP financial measures described above are also useful to investors because these measurements are used by many companies in the industry as a measurement of operating and financial performance and are commonly employed by financial analysts and others to evaluate the operating and financial performance of the company and its business segments and to compare the operating and financial performance of the company and its business segments with the performance of other companies within the industry. These non-GAAP financial measures may not be comparable to similarly titled measurements used by other companies and should not be used as a substitute for net income, earnings per share or other GAAP operating measurements. 45
    • 46
    • 47
    • Financial Results Three Months Ended Year-to-date Ended June 30, June 30, ($ Millions, Except EPS) 2008 2007 2008 2007 $ 499 $ 1,099 EBIT $ 470 $ 686 (221) (454) Interest and debt expense (231) (514) 278 645 Income before income taxes 239 172 87 235 Income taxes 70 51 191 410 Income from continuing operations 169 121 – – Discontinued operations, net of income taxes (3) 674 191 410 Net income 166 795 Preferred stock dividends* – 19 10 19 Net income available to common stockholders $ 191 $ 391 $ 156 $ 776 Diluted EPS from continuing operations $ 0.25 $ 0.54 $ 0.22 $ 0.15 Diluted EPS from discontinued operations – – – 0.96 Total diluted EPS $ 0.25 $ 0.54 $ 0.22 $ 1.11 Diluted shares (millions) 761 760 757 699 *Due to timing of declaration, second quarter 2008 dividends were reflected in the first quarter 48
    • 2008 Analysis of Working Capital and Other Changes $ Millions Six Months Ended June 30, 2008 Margin collateral $ 51 Changes in price risk management activities 406 Settlements of derivative instruments (256) Net changes in trade receivable/payable (112) Settlement of liabilities (41) Other (15) Total working capital changes & other $ 33 49
    • Items Impacting YTD 2008 Results $ Millions, Except EPS Pre-tax After-tax Diluted EPS Income available to common stockholders $391 $ 0.54 Adjustments1 Change in fair value of power contracts $146 $ 93 $ 0.12 Change in fair value of legacy indemnification 34 22 0.03 Case Corporation indemnification (65) (27) (0.04) Gain on sale of portion of telecommunications business (18) (12) (0.01) Other legacy litigation adjustments (27) (29) (0.04) Change in fair value of production-related derivatives in Marketing 73 47 0.06 Impact of MTM E&P derivatives2 92 59 0.08 Adjusted EPS—Continuing operations3 $ 0.74 1Alladjustments assume a 36% tax rate, except Case Corporation indemnification and other legacy litigation adjustments, and 760 MM diluted shares 2Includes $110 MM of MTM losses on derivatives adjusted for $18 MM of realized losses for cash settlements 3Reflects fully diluted shares of 768 MM and includes income impact from dilutive securities 50
    • Items Impacting 2Q 2007 Results $ Millions, Except EPS Diluted Pre-tax After-tax EPS Net income available to common stockholders $156 $ 0.22 Adjustments1 Debt repurchase costs $86 $ 55 $ 0.08 Change in fair value of production-related derivatives in Marketing (9) (6) (0.01) Discontinued operations – 5 3 Adjusted EPS—Continuing operations2 $ 0.29 1Adjustments assume 36% tax rate, except for discontinued operations, and 757 MM diluted shares 2Based upon 757 MM diluted shares and includes the income impact from dilutive securities 51
    • Items Impacting YTD 2007 Results $ Millions, Except EPS Diluted Pre-tax After-tax EPS Net income available to common stockholders $ 776 $ 1.11 Adjustments1 Debt repurchase costs $ 287 $ 184 $ 0.26 Change in fair value of production-related derivatives in Marketing 78 50 0.07 Sale of ANR and related assets (0.96) (1,043) (674) Effect of change in number of diluted shares2 (0.01) Adjusted EPS—Continuing operations2 $ 0.47 1Adjustments assume 36% tax rate, except for discontinued operations, and 699 MM diluted shares 2Based upon 757 MM diluted shares and includes the income impact from dilutive securities 52
    • Business Unit Contribution $ Millions Three Months Ended June 30, 2007 Adjusted EBIT DD&A EBITDA EBITDA* Core Businesses $ 318 $ 91 $ 409 $ 445 Pipelines 235 189 424 451 E&P $ 553 $ 280 $ 833 $ 896 Core Businesses Total Other Businesses 5 1 6 6 Marketing 16 – 16 16 Power Corporate & Other (86) – (86) (86) Debt Repurchase Other (18) 5 (13) (13) Total $ 470 $ 6 $ 756 $ 819 *Adjusted Pipeline EBITDA for 50% interest in Citrus and adjusted E&P EBITDA for 43% interest in Four Star; Appendix includes details on non-GAAP terms 53
    • Business Unit Contribution $ Millions Year-to-date Ended June 30, 2008 Adjusted EBIT DD&A EBITDA EBITDA* Core Businesses $ 676 $ 198 $ 874 $ 938 Pipelines 546 409 955 1,021 E&P $1,222 $ 607 $1,829 $1,959 Core Businesses Total Other Businesses (213) – (213) (213) Marketing 10 – 10 10 Power 80 4 84 84 Corporate & Other $1,099 $ 611 $1,710 $1,840 Total *Adjusted Pipeline EBITDA for 50% interest in Citrus and adjusted E&P EBITDA for 49% interest in Four Star; Appendix includes details on non-GAAP terms 54
    • Reconciliation of EBIT/EBITDA $ Millions Three Months Ended Six Months Ended June 30, June 30, 2008 2007 2008 2007 EBITDA $ 797 $ 756 $1,710 $1,243 Less: DD&A 298 286 611 557 EBIT 499 470 1,099 686 Interest and debt expense (221) (231) (454) (514) Income before income taxes 278 239 645 172 Income taxes 87 70 235 51 Income from continuing operations 191 169 410 121 Discontinued operations, net of taxes – (3) – 674 Net Income 191 166 410 795 Preferred stock dividends* – 10 19 19 Net income available to common stockholders $ 191 $ 156 $ 391 $ 776 *Due to timing of declaration, second quarter 2008 dividends were reflected in the first quarter 55
    • Reconciliation of Adjusted Pipeline EBITDA $ Millions Three Months Ended Six Months Ended June 30, June 30, 2008 2007 2007 2008 Citrus equity earnings $ 19 $ 22 $ 32 $ 44 50% Citrus DD&A 13 13 26 25 50% Citrus interest 10 10 19 19 50% Citrus income taxes 12 14 20 26 Other* (1) (1) (1) (2) 50% Citrus EBITDA $ 53 $ 58 $ 96 $ 112 El Paso Pipeline EBITDA $ 394 $ 409 $ 874 $ 867 Add: 50% Citrus EBITDA 53 58 96 112 Less: Citrus equity earnings 19 22 32 44 Adjusted Pipeline EBITDA $ 938 $ 935 $ 428 $ 445 Citrus debt at June 30 (50%) $ 631 $ 466 *Other represents the excess purchase price amortization and differences between the estimated and actual equity earnings on our investment 56
    • Reconciliation of Adjusted E&P EBITDA $ Millions Three Months Ended Six Months Ended June 30, June 30, 20081 20072 20081 20072 Four Star equity earnings $ 16 $3 $ 26 $2 Proportionate share of Four Star DD&A 5 5 11 11 Proportionate share of Four Star interest – – – – Proportionate share of Four Star income taxes 15 10 28 17 Other3 14 12 27 27 Proportionate share of Four Star EBITDA $ 50 $ 30 $ 92 $ 57 El Paso E&P EBITDA $ 501 $ 424 $ 955 $ 773 Add: Proportionate share of Four Star EBITDA 50 30 92 57 Less: Four Star equity earnings 16 3 26 2 Adjusted E&P EBITDA $ 535 $ 451 $1,021 $ 828 1 E&P has a 49% interest in Four Star 2 E&P has a 43% interest in Four Star 3 Represents the excess purchase price amortization 57
    • E&P Cash Costs 2Q 2007 1Q 2008 2Q 2008 Total Per Unit Total Per Unit Total Per Unit ($ MM) ($/Mcfe) ($ MM) ($/Mcfe) ($ MM) ($/Mcfe) $ 346 $ 4.84 $ 377 $ 5.11 $ 374 $ 5.40 Total operating expense (189) (2.64) (212) (2.87) (197) (2.84) Depreciation, depletion and amortization (15) (0.22) (19) (0.26) (21) Transportation costs (0.31) (4) (0.06) (5) (0.06) (10) Costs of products (0.15) – – – – (7) Other (0.09) $ 1.92 $ 1.92 $ 2.01 Per unit cash costs* 71,493 73,762 69,366 Total equivalent volumes (MMcfe)* *Excludes volumes and costs associated with equity investment in Four Star 58
    • Production-Related Derivative Schedule 2008 2009 2010 2011–2012 Notional Avg. Hedge Notional Avg. Hedge Notional Avg. Hedge Notional Avg. Hedge Natural Gas Volume Price Volume Price Volume Price Volume Price (TBtu) ($/MMBtu) (TBtu) ($/MMBtu) (TBtu) ($/MMBtu) (TBtu) ($/MMBtu) Designated—EPEP Fixed price—Legacy 2.3 $ 3.49 4.6 $ 3.56 4.6 $3.70 6.8 $3.88 Fixed price 10.6 $ 8.37 Ceiling 62.9 $ 10.84 101.0 $ 14.58 Floor 62.9 $ 8.00 125.8 $ 8.93 Economic—EPEP Fixed price 3.7 $ 8.24 3.7 $ 12.06 Ceiling 18.4 $ 10.45 41.9 $ 17.40 Floor 18.4 $ 8.00 41.9 $ 9.61 Avg. ceiling 97.9 $ 10.23 151.1 $ 14.97 4.6 $3.70 6.8 $3.88 Avg. floor 97.9 $ 7.94 175.9 $ 9.02 4.6 $3.70 6.8 $3.88 2008 2009 Notional Avg. Hedge Notional Avg. Hedge Crude Oil Price Volume Volume Price ($/Bbl) (MMBbls) (MMBbls) ($/Bbl) Designated—EPEP Fixed price 1.26 $ 87.80 1.93 $109.32 Economic—EPEP Fixed price 1.50 $110.71 Economic—EPM Ceiling 0.45 $ 56.40 Floor 0.45 $ 55.00 Avg. ceiling 1.71 $ 79.54 3.43 $109.93 Avg. floor 1.71 $ 79.17 3.43 $109.93 59 Note: Positions are as of July 15, 2008 (Contract months: July 2008–Forward)
    • Reconciliation of Pro Forma Production Volumes Equivalents, MMcfe/d 2Q 2007 1Q 2008 2Q 2008 Less: Less: Less: Add: Domestic Add: Domestic Pro Add: Domestic Pro Reported Peoples Assets Sold Pro Forma* Reported Peoples Assets Sold Forma* Reported Peoples Assets Sold Forma* Central 224 31 15 240 241 – 8 233 237 – – 237 Western 144 8 5 147 149 – 2 147 155 – – 155 TGC 202 32 39 195 236 – 35 201 223 – 1 222 GOM/SLA 202 1 62 141 173 – 43 130 136 – 2 134 International 14 – – 14 12 – – 12 11 – – 11 Total consolidated 786 72 121 737 811 – 88 723 762 – 3 759 Proportionate share of Four Star 71 – – 71 75 – – 75 71 – – 71 Total with Four Star 857 72 121 808 886 – 88 798 833 – 3 830 *Pro forma excludes volumes from domestic assets sold in 2008 and assumes full year of Peoples in 2007 60
    • PJM Basis Description Exposure to Day-Ahead price differentials between PJM West Hub and 4 locations within East Hub Total exposure equals 20 MM MWh and extends through April 2016 Energy typically flows from supply areas in West Hub to high demand areas in East Hub East-West spread settlements driven by transmission congestion and marginal production costs West Hub price often set by baseload coal; East Hub price often set by natural gas-fired generation 32% increase in forward natural gas price led to 45% increase in forward PJM basis spread during 2Q 2008 61