Exhibit 99.C

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.

Our Purpose El Paso Corporation provides natural gas and related energy products in a safe, efficient, and dependable manner

the place to work the neighbor to have the company to own Our Vision & Values

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

2008 Challenges Cost control ? Pipeline ? Steel, contractor ? E&P ? Services, fuel-related Acquisition integration ? E&P ? Employee retention ? Delayed ramp up MTM volatility ? Marketing ? PJM basis Project execution ? Pipeline and E&P ? Significant project inventory

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 2008 2007 Net Income to Common 865 819 $865 $819 Adjusted EBITDA Diluted EPS from Continuing 2008 2007 EPS-Diluted Continuing 0.25 0.22 $0.25 $0.22 Adjusted Diluted EPS from Continuing 2008 2007 Adjusted EPS Diluted Continuing 0.39 0.29 $0.39 $0.29 EBIT 2008 2007 EBIT 499 470 $499 $470 Interest Expense 2008 2007 Interest Expense 221 231 $221 $231 Realized Natural Gas Price ($Mcf) 2008 2007 Realized NG Price 9.53 7.67 $9.53 $7.67 Earnings growth driven by higher gas prices and lower interest $ Millions, Except EPS Note: Appendix and slides 10 and 11 include details on non-GAAP terms

Items Impacting 2Q 2008 Results Income available to common stockholders Adjustments1 Change in fair value of power contracts Change in fair value of legacy indemnification Other legacy litigation adjustments Change in fair value of production-related derivatives in Marketing Impact of MTM E&P derivatives2 Adjusted EPS-Continuing operations3 $ 105 (9 ) (27 ) 52 61 Pre-tax $ 191 $ 67 (6 ) (29 ) 33 39 After-tax $ 0.25 $ 0.09 (0.01 ) (0.04 ) 0.04 0.06 $ 0.39 Diluted EPS 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 $ Millions, Except EPS

Business Unit Contribution Core Businesses Pipelines E&P Core Businesses Total Other Businesses Marketing Power Corporate & Other Total Three Months Ended June 30, 2008 $ 295 304 $ 599 (153 ) 12 41 $ 499 Adjusted EBITDA* EBIT DD&A EBITDA *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 $ Millions $ 99 197 $ 296 - - 2 $ 298 $ 394 501 $ 895 (153 ) 12 43 $ 797 $ 428 535 $ 963 (153 ) 12 43 $ 865

Cash Flow and Capital Investment $ 410 875 1,285 33 1,318 - $ 1,318 $ 1,175 $ 336 $ 659 $ 75 Income from continuing operations Non-cash adjustments Subtotal Working capital changes and other* Cash flow from continuing operations Discontinued operations Cash flow from operations Capital expenditures Acquisitions Divestitures Dividends paid 2008 Six Months Ended June 30, $ 121 939 1,060 (178 ) 882 (17 ) $ 865 $ 1,130 $ 270 $ 80 $ 75 2007 *Includes change in margin collateral of $51 MM in 2008 and $72 MM in 2007 $ Millions

Marketing Financial Results Strategic Change in fair value of production-related derivatives Other Change in fair value of natural gas derivative contracts Change in fair value of power contracts Settlements, demand charges, & other Operating expenses & other income Other total EBIT EBIT $ Millions $ (52 ) 11 (105 ) - (7 ) (101 ) $ (153 ) Three Months Ended June 30, 2008 2007 $ 9 2 (15 ) (12 ) 21 (4) $ 5 $ (73 ) 11 (146 ) 5 (10 ) (140 ) $ (213 ) Six Months Ended June 30, 2008 2007 $ (78 ) (22 ) (32 ) (19 ) 21 (52 ) $ (130 )

PJM Basis MTM Earnings & Cash Settlements Change in MTM Value Cash Settlements

2008 Natural Gas and Oil Hedge Positions 0.45 MMBbls $56.40 ceiling/ $55.00 floor Balance at Market Price Ceiling Floor 1.71 MMBbls Average cap $79.54/Bbl 1.71 MMBbls Average floor $79.17/Bbl Note: See full Production-Related Derivative Schedule in Appendix 98 TBtu Average cap $10.23/MMBtu 81 TBtu $10.75 ceiling/ $8.00 floor 17 TBtu $7.66 fixed price 98 TBtu Average floor $7.94/MMBtu Ceiling Floor 1.26 MMBbls $87.80 fixed price Positions as of July 15, 2008 (Contract Months July 2008 - Forward) 2008 Gas 2008 Oil Hedging strategy preserves upside to higher prices

Balance at Market Price Note: See full Production-Related Derivative Schedule in Appendix 151 TBtu Average cap $14.97/MMBtu 8 TBtu $7.36 fixed price 176 TBtu Average floor $9.02/MMBtu Ceiling Floor 3.43 MMBbls $109.93 fixed price 2009 Gas 2009 Oil 2009 Natural Gas and Oil Hedge Positions 143 TBtu $15.41 ceiling 168 TBtu $9.10 floor >50% of oil and domestic natural gas hedged 2009 hedge program enhances revenues by approximately $270 MM Positions as of July 15, 2008

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

Pipeline Group Financial Results EBIT before minority interest Less minority interest EBIT EBITDA Adjusted EBITDA1 Capital expenditures Acquisitions2 Three Months Ended June 30, 2008 2007 $ 303 8 $ 295 $ 394 $ 428 $ 266 $ - $ 318 - $ 318 $ 409 $ 445 $ 232 $ - $ Millions 1Adjusted Pipeline EBITDA for 50% interest in Citrus 2 Gulf LNG acquisition Note: Appendix includes details on non-GAAP terms Six Months Ended June 30, 2008 $ 693 17 $ 676 $ 874 $ 938 $ 455 $ 295 2007 $ 682 - $ 682 $ 867 $ 935 $ 426 $ -

Continued Throughput Increase YTD T-put 9 2 7 5 TGP Elba deliveries to Florida SNG 7% 9% EPNG CIG Rockies supply, expansions 6% overall increase 5% Independence Hub Note: CIG includes Colorado Interstate Gas, Cheyenne Plains and Wyoming Interstate EPNG includes El Paso Natural Gas and Mojave 2% California YTD % Increase 2008 vs. 2007

CIG High Plains Pipeline $216 MM (100%) December 2008 900 MMcf/d TGP Carthage Expansion $39 MM May 2009 100 MMcf/d SNG South System III/ SESH Phase II $352 MM / $69 MM 2011-2012 370 MMcf/d / 350 MMcf/d Elba Expansion III & Elba Express $1.1 Billion 2010-2013 8.4 Bcf / 0.9 Bcf/d & 1.2 Bcf/d SNG Cypress Phase III $86 MM Jan 2011 160 MMcf/d CIG Totem Storage $154 MM (100%) July 2009 200 MMcf/d WIC Piceance Lateral $62 MM 4Q 2009 220 MMcf/d SNG SESH -Phase I $172 MM Sep 2008 140 MMcf/d El Paso Pipeline El Paso Pipeline Partners, LP TGP Concord $21 MM Nov 2009 30 MMcf/d Gulf LNG $1+ Billion (100%) Oct 2011 6.6 Bcf / 1.3 Bcf/d CIG Raton 2010 Expansion $146 MM 2Q 2010 130 MMcf/d El Paso Backlog: Large and Profitable FGT Phase VIII Expansion $2.4 Billion (100%) 2011 800 MMcf/d Total committed backlog $8 billion TGP Bluewater / 800 Ln Exp $25 MM Nov 2008 340 MMcf/d Note: As of August 6, 2008; El Paso Pipeline Partners owns 10% of SNG & CIG Ruby Pipeline $3 Billion 2011 1.3-1.5 Bcf/d WIC Expansion - Kanda Lateral & Wamsutter $55 MM 2010-2011 240 MMcf/d TGP Line 300 Expansion $750 MM (Phase I & II) 2010-2011 290 MMcf/d WIC Medicine Bow Expansion $39 MM Sep 2008 330 MMcf/d

Ruby Pipeline Update Malin Opal Hub UT NV OR CO ID CA WY CIG Kern River Paiute Tuscarora PG&E WIC Cheyenne Plains Cheyenne Uinta Basin Piceance Basin 670 miles of 42" pipeline $3 billion capex 1.3-1.5 Bcf/d capacity 2011 in-service Market commitments of 1.1 Bcf/d 100% of pipe ordered Incentive-based construction contracts On the ground since mid-2007 Ruby Pipeline

TGP Line 300 Expansion 125 miles of 30" looping 15-year contract for 290 MMcf/d with Equitable Energy LLC $750 MM capex 2010-2011 in-service Locked in pipe prices Marcellus Interconnects EQT Production NY PA WV OH KY CT MA RI NH VT MI NJ VA REX-TGP Interconnect

Pipeline Summary Committed backlog $8 billion Highly focused on project execution On track to achieve 2008 EBIT & EBITDA targets

Exploration & Production

*Pro forma basis; see appendix for reconciliation 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

E&P Results EBIT1 EBITDA1 Adjusted EBITDA2 Capital expenditures Acquisition capital $ 304 501 535 400 43 2007 2008 Three Months Ended June 30, $ 235 424 451 383 16 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 $ Millions $ 546 955 1,021 702 43 2007 2008 Six Months Ended June 30, $ 414 773 828 735 270

97% Drilling Success Rate High Low Risk 2008 YTD Gross Wells Completed 0% 83% 99% Actual Success Rate 4 12 222 238 97% PC > 80% Low Risk Domestic Development and Pinauna & Bia/Camarupim Development PC < 40% High Impact Exploration Med PC 40%-80% Medium Risk Development and Exploration Increasing capital to $1.9 billion

Total Cash Costs $/Mcfe 2Q 2007 1Q 2008 2Q 2008 Direct Lifting Costs 0.85 0.819 0.79 General & Administrative 0.68 0.643 0.63 Taxes Other Than Production & Income 0.06 0.041 0.05 0.2 0.2 0.2 Production Taxes 0.333 0.418 0.54 $1.92 $0.06 $0.68 $0.33 $0.85 $1.92 $0.04 $0.64 $0.42 $0.82 $0.79 $0.54 $0.63 $0.05 $2.01 Controllable unit costs down 7% yr/yr $1.59 $1.50 $1.47

2Q Production Update Note: Includes proportionate share of Four Star equity volumes Appendix includes details on non-GAAP terms *Excludes volumes from domestic assets sold in 2008 and assumes full year of Peoples in 2007 MMcfe/d 2Q 2007 1Q 2008 2Q 2008 Central 295 316 308 Western 144 149 155 TGC 202 236 223 GOM/SLA 202 173 136 International 14 12 11 308 223 136 11 833 155 1Q-2Q As Reported 6% Decrease 316 236 173 12 886 149 295 202 202 14 857 144 2Q 2007 1Q 2008 2Q 2008 Central 311 308 308 Western 147 147 155 TGC 195 200 222 GOM/SLA 141 130 134 International 14 12 11 1Q-2Q Pro Forma* 4% Increase 308 222 134 11 830 155 195 141 14 808 147 311 308 201 130 12 798 147 Full year estimate ~860 MMcfe/d

Peoples Acquisition Update Acquisition Rationale Increased scale and efficiency Adds significant drilling inventory Lower lifting costs Current Status Drilled 51 wells thru 2Q08 Expect 95-100 by YE08 Production growth delayed, lower initial activity levels Actively pursuing new opportunities Haynesville shale Cotton Valley horizontal Vicksburg program 3Q07 4Q07 1Q08 2Q08 3Q08E 4Q08E Production 70 69.62 70.85 90.63 103.28 117.02 Active Rigs 5 5 5 7 9 10 Production and Active Rigs Closed Sep. 2007 Acquisition value up significantly MMcfe/d Rigs

Arklatex Update 2008 Conventional Program 125-130 gross wells ~ $350 MM net capital 8-9 rigs running and growing Cotton Valley Horizontal Testing horizontal drilling 1 well drilled and completed 4.4 MMcfe/d initial 30-day average Additional 30 gross locations currently identified; potential application to other wells in inventory Haynesville Shale Exploration 1 well drilled; completion underway Approximately 42,500 net acres Significant resource potential Haynesville Shale Lindy Britton #2H CV Horizontal Miller Land 10H #1 Haynesville TX AK LA Holly/Logansport Bethany Longstreet Minden/SE Brachfield

Haynesville Shale Miller Land Co-H10#1 Completion underway 11,700' 11,500' 10,000' 9,000' 6,700' 5,300' Rodessa Hosston Cotton Valley Bossier Shale Haynesville Shale Haynesville Lime 3,100' Perforations

Raton Update 2008 CBM Program 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 2 horizontal and 1 vertical Initial flow rates of 0.4-1.8 MMcfe/d $2 MM-$3 MM completed well costs > 300,000 prospective net acres NM CO Niobrara Shale Test well locations

Niobrara Shale 5,000' 4,000' 3,000' 2,000' 1,000' Pierre Shale Niobrara C Shale Niobrara B Shale Niobrara A Shale Trinidad Coal Vermejo Coal Raton Coal Typical CBM well VPR D-95A 1.8 MMcf/d VPR E-17A 1.0 MMcf/d VPR A-6A 0.4 MMcf/d Perforations 3,900' 3,000'

Altamont-Bluebell Update 2008 Program 8 gross wells drilled 36 recompletions $66 MM net capital Roll-up Acquisition Consolidates WI in operated assets Closed in 2Q 2008 1.6 MMBOE of proven reserves 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 UT WY Altamont-Bluebell

Gas Discovery well Bia/Camarupim Development Project Overview: Petrobras operated with 24% EP working interest 35-50 MMcfe/d net peak production 100-120 Bcfe net resources $135 MM net capital total Gas price indexed to basket of imported fuel oils First gas in 1Q 2009 4 development wells 4-ESS-177 6-ESS-168 Bia/ Camarupim 4-ESS-164 Bia Development Project Rio de Janeiro Brazil 2 KMS 0 1 2km BM-ES-5 Block Petrobras: 65% Operator El Paso: 35% BES-100 Camarupim DOC Area Petrobras: 100%

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 12" pipeline to PLEM completed & 24" pipeline being installed FPSO in yard with Oct 2008 delivery date Drilled 1st development well in 2Q 2008

Pinauna Development Project Statistics: 15-20 MBOE/d peak production 59-90 MMBOE total resource potential $700 MM-$750 MM total capital 100% WI Attractive returns at plan prices ($70/Bbl) Resource Outlook Oil Gas 1-BAS-64 1-BAS-73 1-BAS-74 1-ELPS-160 1-ELPS-170A Pinauna Cacau Acai Acai East 0 1.5 2.5 2.5 km Rio de Janeiro Brazil

Pinauna Development 3 Km-6" HP Oil, Gas Subsea Pipelines Development Scope 4 Horizontal producers 4 Horizontal Water Injectors 1 Gas Producer WD = 20m Utility MOPU Acai/Cacau Wellhead Platform Pinauna Wellhead Platform Project Status: Executed FSO letter of intent Awaiting approval of Terms of Reference from IBAMA Permitting & long lead sourcing continues First production late 2009, dependent on timing of permit approvals 10 Km-8" Crude Subsea Pipeline 10 Km-6" Fuel Gas Subsea Pipeline WD = 35- 40m Production MOPU 25,000 BOPD Oil capacity FSO 383,000 Bbl Oil Capacity

E&P Summary Inventory growing Peoples (Arklatex, TGC) Haynesville & Niobrara shale Brazil, Egypt Projects advancing Bia/Camarupim faster than expected Pinauna 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)

Summary Earnings and cash flow up Pipelines $8 billion backlog Long-term growth 10%+ E&P Inventory continues to grow Brazil accelerates 2009 volume growth Progress on all fronts

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

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Financial Results EBIT Interest and debt expense Income before income taxes Income taxes Income from continuing operations Discontinued operations, net of income taxes Net income Preferred stock dividends* Net income available to common stockholders Diluted EPS from continuing operations Diluted EPS from discontinued operations Total diluted EPS Diluted shares (millions) $ 686 (514 ) 172 51 121 674 795 19 $ 776 $ 0.15 0.96 $ 1.11 699 2007 Year-to-date Ended June 30, $ 1,099 (454 ) 645 235 410 - 410 19 $ 391 $ 0.54 - $ 0.54 760 2008 ($ Millions, Except EPS) $ 470 (231 ) 239 70 169 (3 ) 166 10 $ 156 $ 0.22 - $ 0.22 757 2007 Three Months Ended June 30, $ 499 (221 ) 278 87 191 - 191 - $ 191 $ 0.25 - $ 0.25 761 2008 *Due to timing of declaration, second quarter 2008 dividends were reflected in the first quarter

2008 Analysis of Working Capital and Other Changes $ 51 406 (256 ) (112 ) (41 ) (15 ) $ 33 Margin collateral Changes in price risk management activities Settlements of derivative instruments Net changes in trade receivable/payable Settlement of liabilities Other Total working capital changes & other Six Months Ended June 30, 2008 $ Millions

Items Impacting YTD 2008 Results Income available to common stockholders Adjustments1 Change in fair value of power contracts Change in fair value of legacy indemnification Case Corporation indemnification Gain on sale of portion of telecommunications business Other legacy litigation adjustments Change in fair value of production-related derivatives in Marketing Impact of MTM E&P derivatives2 Adjusted EPS-Continuing operations3 $ 146 34 (65 ) (18 ) (27 ) 73 92 Pre-tax $ 391 $ 93 22 (27 ) (12 ) (29 ) 47 59 After-tax $ 0.54 $ 0.12 0.03 (0.04 ) (0.01 ) (0.04 ) 0.06 0.08 $ 0.74 Diluted EPS 1All adjustments 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 $ Millions, Except EPS

Items Impacting 2Q 2007 Results Net income available to common stockholders Adjustments1 Debt repurchase costs Change in fair value of production-related derivatives in Marketing Discontinued operations Adjusted EPS-Continuing operations2 $ 86 (9 ) 5 Pre-tax $ 156 $ 55 (6 ) 3 After-tax $ 0.22 $ 0.08 (0.01 ) - $ 0.29 Diluted EPS 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 $ Millions, Except EPS

Items Impacting YTD 2007 Results Net income available to common stockholders Adjustments1 Debt repurchase costs Change in fair value of production-related derivatives in Marketing Sale of ANR and related assets Effect of change in number of diluted shares2 Adjusted EPS-Continuing operations2 $ 287 78 (1,043 ) Pre-tax $ 776 $ 184 50 (674 ) After-tax $ 1.11 $ 0.26 0.07 (0.96 ) (0.01 ) $ 0.47 Diluted EPS 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 $ Millions, Except EPS

Business Unit Contribution Core Businesses Pipelines E&P Core Businesses Total Other Businesses Marketing Power Corporate & Other Debt Repurchase Other Total Three Months Ended June 30, 2007 $ 318 235 $ 553 5 16 (86) (18) $ 470 Adjusted EBITDA* EBIT DD&A EBITDA *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 $ Millions $ 91 189 $ 280 1 - - 5 $ 6 $ 409 424 $ 833 6 16 (86) (13) $ 756 $ 445 451 $ 896 6 16 (86) (13) $ 819

Business Unit Contribution Core Businesses Pipelines E&P Core Businesses Total Other Businesses Marketing Power Corporate & Other Total Year-to-date Ended June 30, 2008 $ 676 546 $ 1,222 (213 ) 10 80 $ 1,099 Adjusted EBITDA* EBIT DD&A EBITDA *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 $ Millions $ 198 409 $ 607 - - 4 $ 611 $ 874 955 $ 1,829 (213 ) 10 84 $ 1,710 $ 938 1,021 $ 1,959 (213 ) 10 84 $ 1,840

Reconciliation of EBIT/EBITDA EBITDA Less: DD&A EBIT Interest and debt expense Income before income taxes Income taxes Income from continuing operations Discontinued operations, net of taxes Net Income Preferred stock dividends* Net income available to common stockholders $ 797 298 499 (221 ) 278 87 191 - 191 - $ 191 Three Months Ended June 30, 2008 2007 $ Millions $ 756 286 470 (231 ) 239 70 169 (3 ) 166 10 $ 156 $ 1,710 611 1,099 (454 ) 645 235 410 - 410 19 $ 391 Six Months Ended June 30, 2008 2007 $ 1,243 557 686 (514 ) 172 51 121 674 795 19 $ 776 *Due to timing of declaration, second quarter 2008 dividends were reflected in the first quarter

Reconciliation of Adjusted Pipeline EBITDA $ 19 13 10 12 (1) $ 53 $ 394 53 19 $ 428 Citrus equity earnings 50% Citrus DD&A 50% Citrus interest 50% Citrus income taxes Other* 50% Citrus EBITDA El Paso Pipeline EBITDA Add: 50% Citrus EBITDA Less: Citrus equity earnings Adjusted Pipeline EBITDA Citrus debt at June 30 (50%) Three Months Ended June 30, 2008 2007 $ 22 13 10 14 (1 ) $ 58 $ 409 58 22 $ 445 *Other represents the excess purchase price amortization and differences between the estimated and actual equity earnings on our investment $ Millions $ 32 26 19 20 (1) $ 96 $ 874 96 32 $ 938 $ 631 Six Months Ended June 30, 2008 2007 $ 44 25 19 26 (2) $ 112 $ 867 112 44 $ 935 $ 466

Reconciliation of Adjusted E&P EBITDA $ 16 5 - 15 14 $ 50 $ 501 50 16 $ 535 Four Star equity earnings Proportionate share of Four Star DD&A Proportionate share of Four Star interest Proportionate share of Four Star income taxes Other3 Proportionate share of Four Star EBITDA El Paso E&P EBITDA Add: Proportionate share of Four Star EBITDA Less: Four Star equity earnings Adjusted E&P EBITDA Three Months Ended June 30, 20081 20072 $ 3 5 - 10 12 $ 30 $ 424 30 3 $ 451 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 $ Millions $ 26 11 - 28 27 $ 92 $ 955 92 26 $ 1,021 Six Months Ended June 30, 20081 20072 $ 2 11 - 17 27 $ 57 $ 773 57 2 $ 828

Per Unit ($/Mcfe) 2Q 2007 $ 4.84 (2.64 ) (0.22 ) (0.06 ) - $ 1.92 71,493 $ 346 (189 ) (15 ) (4 ) - E&P Cash Costs Total operating expense Depreciation, depletion and amortization Transportation costs Costs of products Other Per unit cash costs* Total equivalent volumes (MMcfe)* *Excludes volumes and costs associated with equity investment in Four Star Total ($ MM) Total ($ MM) $ 374 (197 ) (21 ) (10 ) (7 ) $ 5.40 (2.84 ) (0.31 ) (0.15 ) (0.09 ) $ 2.01 69,366 Per Unit ($/Mcfe) 2Q 2008 $ 377 (212 ) (19 ) (5 ) - $ 5.11 (2.87 ) (0.26 ) (0.06 ) - $ 1.92 73,762 Total ($ MM) Per Unit ($/Mcfe) 1Q 2008

Production-Related Derivative Schedule Designated-EPEP Fixed price-Legacy Fixed price Ceiling Floor Economic-EPEP Fixed price Ceiling Floor Avg. ceiling Avg. floor Designated-EPEP Fixed price Economic-EPEP Fixed price Economic-EPM Ceiling Floor Avg. ceiling Avg. floor 2.3 10.6 62.9 62.9 3.7 18.4 18.4 97.9 97.9 1.26 0.45 0.45 1.71 1.71 $ 3.49 $ 8.37 $ 10.84 $ 8.00 $ 8.24 $ 10.45 $ 8.00 $ 10.23 $ 7.94 $ 87.80 $ 56.40 $ 55.00 $ 79.54 $ 79.17 4.6 101.0 125.8 3.7 41.9 41.9 151.1 175.9 1.93 1.50 3.43 3.43 $ 3.56 $ 14.58 $ 8.93 $ 12.06 $ 17.40 $ 9.61 $ 14.97 $ 9.02 $ 109.32 $ 110.71 $ 109.93 $ 109.93 4.6 4.6 4.6 $ 3.70 $3.70 $ 3.70 2008 Notional Volume (TBtu) Avg. Hedge Price ($/MMBtu) 2009 Notional Volume (TBtu) Avg. Hedge Price ($/MMBtu) Notional Volume (TBtu) Avg. Hedge Price ($/MMBtu) 2010 Notional Volume (MMBbls) Avg. Hedge Price ($/Bbl) 2008 Natural Gas Crude Oil 6.8 6.8 6.8 $ 3.88 $ 3.88 $ 3.88 Notional Volume (TBtu) Avg. Hedge Price ($/MMBtu) 2011-2012 Note: Positions are as of July 15, 2008 (Contract months: July 2008-Forward) Notional Volume (MMBbls) Avg. Hedge Price ($/Bbl) 2009

Reconciliation of Pro Forma Production Volumes Equivalents, MMcfe/d Central Western TGC GOM/SLA International Total consolidated Proportionate share of Four Star Total with Four Star 224 144 202 202 14 786 71 857 31 8 32 1 - 72 - 72 Reported Add: Peoples Less: Domestic Assets Sold Pro Forma* 15 5 39 62 - 121 - 121 240 147 195 141 14 737 71 808 2Q 2007 Reported 237 155 223 136 11 762 71 833 - - - - - - - - Add: Peoples Less: Domestic Assets Sold Pro Forma* - - 1 2 - 3 - 3 237 155 222 134 11 759 71 830 2Q 2008 *Pro forma excludes volumes from domestic assets sold in 2008 and assumes full year of Peoples in 2007 241 149 236 173 12 811 75 886 - - - - - - - - Add: Peoples Less: Domestic Assets Sold Pro Forma* 8 2 35 43 - 88 - 88 233 147 201 130 12 723 75 798 1Q 2008 Reported

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