Exhibit 99.B

May 24, 2011

This presentation release 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 release, including, without limitation, our ability to execute our strategy of selling assets to El Paso Pipeline Partners, L.P.; our ability to pay dividends declared; changes in unaudited and/or unreviewed financial information; volatility in, and access to, the capital markets; our ability to implement and achieve objectives in our 2011 plan and updated guidance, including achieving our earnings and cash flow targets; the effects of any changes in accounting rules and guidance; our ability to meet production volume targets in our Exploration and Production segment; the uncertainty of estimating proved reserves and unproved resources, the future level of service and capital costs; the availability and cost of financing to fund our future exploration and production operations; the success of our drilling programs with regard to proved undeveloped reserves and unproved resources; our ability to successfully identify new Midstream opportunities; our ability to comply with the covenants in our various financing documents; our ability to obtain necessary governmental approvals for proposed pipeline and E&P 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; credit and performance risk of our lenders, trading counterparties, customers, vendors and suppliers; changes in commodity prices and basis differentials for oil, natural gas, and power; 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, including the risk of a global recession and negative impact on natural gas demand; 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. In addition, there are a variety of risks and other factors associated with our proposed spin-off of our Exploration and Production segment that could negatively impact our ability to implement the transaction and/or its project results, including, without limitation, risks typically inherent in spin-off and related transactions of this type; our ability to pay the targeted initial dividend and to increase the dividend thereafter for our pipeline and midstream businesses, our ability to execute on our debt reduction strategy; risks associated with the level of debt to be incurred by the Exploration and Production segment; the availability of the capital markets for raising capital and additional debt; once separated, the ability of the businesses to successfully operate independently; our ability to obtain all necessary regulatory approvals to implement the separation of the businesses, including, but not limited to, confirmation of the tax-free nature of the transaction; and the receipt of final approval of our board of directors of the separation and related transactions. As a result, there is a risk that the proposed separation may not be completed as contemplated, including the risk that there may be material changes in timing and/or terms of the transaction or that the transaction may not be completed at all. 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 includes the production attributable to El Paso's 48.8 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 interest in the proved reserves of Four Star separate from its consolidated proved reserves. In addition, the proved reserves attributable to its interest in Four Star represent estimates prepared by El Paso and not those of Four Star. Cautionary Note to U.S. Investors - Investors are urged to closely consider the disclosures and risk factors in our Forms 10-K and 10-Q, available from our offices or from our website at http://www.elpaso.com, including the inherent uncertainties in estimating quantities of proved reserves.

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 the company to own the company to own the company to own

Damaged brand Diffused business Bloated overhead Leverage on the precipice Making payroll From pillar-to-post Co. pride at rock bottom Purposeful company Highly focused Efficient Durable balance sheet Looking over horizon Execution-focused Values driven Team EP Well-positioned for next 80+ years 2003 2011+

Carlsbad recovery Reasonable growth prospects Purchasing department Good pipeliners Tactically focused No MLP Industry safety leader Best backlog in service Supply chain management Superior execution track record Much more strategic Top-performing MLP Biggest, best pipeline franchise 2003 2011+

High-risk strategy Disadvantaged portfolio Poor execution Low inventory High-cost High repeatability Cored-up Top-tier Competitive inventory Low-cost A top-tier E&P company 2003 2011+

Outstanding Midstream Co.-Sold 2004 Deep midstream knowledge Retained A synergistic new leg on the stool Re-entry 2010 Important starter kit Focused strategy Great partner Outstanding growth prospects 2003 2011+

Financial strength restored Free cash and investment grade profile in 2012 Pipes complete backlog, but more growth to come E&P a top-tier competitor Deep inventory in core areas Growing oil volumes Midstream adds new growth vehicle MLP strategy creating value for EP & EPB

Do our businesses have greater capacity to create value together or apart? Will investors value the businesses more highly as independent entities - now and over time? We've answered these questions

Unanimous conclusion of Mgmt. and Board Tax-free spin of E&P company Will not require shareholder vote Subject to: IRS tax ruling and other customary approvals Finalization of capital structure Final Board approval Market conditions Target completion by year-end 2011 We will create two enduring businesses with similar DNA - Zygosity

Because it is the right thing to do for shareholders Structural impediments gone Balance sheet in shape Pipeline backlog largely complete E&P well positioned & growing Recent valuations have shifted burden of proof Exciting value creation for the company's businesses Allows investors to assess businesses independently Simplifies and focuses equity stories Greater management focus on each company

Large stand-alone independent Well capitalized ~20% EBITDA growth in 20121 Inventory - large, oily, profitable, repeatable Low-cost in core areas Mature execution model Excellent growth/returns outlook Strong leadership Doug Foshee - Non-Executive Chairman Brent Smolik - CEO Dane Whitehead - CFO E&P industry leader 1 Assumes E&P capital consistent with 2011 levels and forward 2012 prices as of May 20, 2011

Premier interstate pipeline franchise Growing midstream business Best in class MLP/100% owned high-growth GP Substantial cash generation & growth Pipeline/Midstream synergies Targeting $0.60 dividend in 2012 Targeting low double-digit dividend growth Seasoned management team remains Doug Foshee remains Chairman & CEO Targeting 14% + total return Strong competitor in corporate yield space

Two high-quality companies Both well capitalized Both with great futures Each more nimble Motivated, unified management Substantial and sustainable valuation uplift Target completion by year end We will continue to outperform

J. R. Sult Executive Vice President & Chief Financial Officer

Greater management focus on distinct business strategies Growth-oriented E&P business Yield-oriented Pipeline and Midstream businesses with substantial and growing dividend Credit enhancing to El Paso Corporation Greater flexibility to grow businesses supported by separate equity currencies Independent capital structures & credit profiles = lower cost of capital Improved capital markets access Increased flexibility and efficiency in capital allocation

Our drive toward investment grade profile has been unwavering Key drivers: MLP drop down strategy Exceeding expectations Expect more to come Growth in businesses Key barrier will be behind us

Largest pure-play interstate natural gas transportation company Investment-grade business and financial characteristics Leverage will be comparable to investment-grade peers and will improve Complete backlog Continue MLP strategy Well-positioned to prosper independently Substantial scale and operational diversification Multi-year inventory of low-risk growth opportunities Growing oil weighting Expect 2012 EBITDA up ~20%1 Leverage consistent with key competitors $2B - $2.25B net debt El Paso Corp. E&P Co. Stand-alone capitalization and credit profile will drive lower cost of capital 1 Assumes E&P capital consistent with 2011 levels and forward 2012 prices as of May 20, 2011

Submit IRS tax ruling Finalize capital structure E&P company debt Liability management Credit facilities SEC filings Separation agreements Final BOD approval Target completion by YE 2011

Financial & operational results ahead of schedule Continued MLP drop-down execution Successfully completed 6th transaction Funding debt reduction Additional price risk management Good progress on all fronts

Production growth & prices driving higher earnings and operating cash flow 1 Updated guidance assumes $4.50/MMBtu (NYMEX) and $107/Bbl (WTI)

Additional capital for Eagle Ford Central Activity not inflation Funded by increased cash flow & non-core divestitures Higher 2011 production and exit rate Pipelines updated for Ruby $3.2 $3.6 $ Billions

1Represents the average floor price for 2011 and the average fixed price for 2012. 2Excludes 1.46 MMBbl of $95 call options. Note: NYMEX & WTI pricing is as of May 17, 2011, and hedge positions are as of May 17, 2011. Natural gas production with floors reflects domestic production. 2011 percentages based on remaining 2011E production. 2012 percentages based on FY 2011E production. Expected production includes the company's interest in Four Star.

Pat Johnson Vice President, Strategy

Growing long-term demand Economy ? Electricity ? Gas Environmental and climate regulation Power: Coal ?, Renewables ? Dramatic supply growth Unconventional production: Shales ?, Rockies ? Changing trade balance Imports: Canada ?, LNG ?; Exports: Mexico ?, LNG ?, NGL? Persistent oil-gas price disparity Resource swaps: Gas Liquid Infrastructure impetus New sources ? New plumbing ? New money (2010-2020)

EASTERN CANADA NW and ALASKA 0.7% WESTERN CANADA MEXICO Source: El Paso April 2011 Macro Forecast 2010/2020 Volumes in Bcf/d 2010/2020 Volumes in Bcf/d 2.8 3.0 0.7% 6.1 8.0 2.8% 3.6 4.3 1.8% 9.6 12.1 2.4% 12.2 17.0 3.3% 10.8 12.3 1.3% 4.2 5.0 1.8% 14.9 17.3 1.5% 6.0 8.0 2.9% 5.2 5.6 0.9% 6.3 6.1 -0.3% NORTH AMERICA TOTAL 2010 81.7 2020 98.8 2010-2020 CAGR 1.9%

PRIMARY ENERGY CONSUMPTION BY SOURCE & SECTOR, 2009 (Quadrillion Btu) 35.3 PETROLEUM 23.4 NATURAL GAS 19.7 COAL 7.7 RENEWABLE ENERGY (Including hydro) 27.0 TRANSPORTATION 18.8 INDUSTRIAL 10.6 RESIDENTIAL & COMMERCIAL 38.3 ELECTRIC POWER 8.3 NUCLEAR SUPPLY SOURCES % OF SOURCE % OF SECTOR DEMAND SECTORS SECTORS SECTORS Source: Energy Information Administration Annual Energy Review 2009 72 22 5 1 3 32 35 30 7 <1 93 12 26 9 53 100 94 41 17 1 3 40 18 7 1 3 7 22 11 11 48 76

4.8 1.98 2.3 1.83 0.6 0.00 16.6 8.49 10.5 0.86 13.6 5.72 8.2 1.64 Projected Retirements-57 GW2 Announced Retirements-21 GW ? 9 Bcf/d gas capacity CATR-NOx, Sox HAPS Rule-Hg Waste Management Rules-ash Water Use Rules-cooling systems Tailoring and NSPS Rules-GHG State and local initiatives 1Ventyx 2El Paso estimate Coal Generation Capacity (GW)

Sources: RPS - ICF Integrated Energy Outlook, Q1-2011; Gas backup - INGAA Foundation: Firming Renewables Renewables dampen demand for gas but increase demand for infrastructure ? 33 GW generation, 5 Bcf/d pipeline, up to $15 B capital HI: 20% 2020 Mandatory Voluntary No targets

Major Sources (2010/2020) in Bcf/d Source: El Paso April 2011 Macro Forecast WESTERN CANADA 16.7 17.8 ROCKIES 9.4 10.7 APPALACHIA 2.8 9.1 MID CONTINENT 13.5 15.0 SOUTH TEXAS 4.4 7.8 NA LNG IMPORTS 1.7 2.4 GULF OF MEXICO 6.8 5.1 NA LNG EXPORTS 0.2 0.9 ARKLATEX 8.6 14.9 L48 PRODUCTION 2010: 57.7 2020: 74.0

Source: Wood Mackenzie, State Production Data Haynesville & Marcellus Time Zero is 1Q 2008; Fayetteville Time Zero is 2004; Barnett Time Zero is 1982 Haynesville Marcellus Fayetteville Barnett PERFORMANCE DRIVERS Technology Geology Geography MMcf/d Months Since First Production

Lower 48 Supply in Bcf/d Source: El Paso April 2011 Macro Forecast ; ICF <5% 7% 12% >15% Net Trade (% of total supply)

Source: El Paso April 2011 Macro Forecast 1Production + LNG imports CANADA DEMAND ? Western Canada Oil Sands Eastern Canada Coal Generation Retirements All Canada: GHG Coal Replacement Policy +2.7 CANADA SUPPLY WCSB Conventional ? Unconventional ? LNG exports +1.01 +0.7 MEXICO SUPPLY Gas Production declines as drilling shifts to oil LNG imports trail demand growth +0.41 MEXICO DEMAND ? Powergen and Industrial Growth Oil Conversion +2.0 Net Exports to Mexico Net Imports from Canada CUMULATIVE CHANGE FROM 2010-2020 IN BCF/D 4 Bcf/d

Source: Baker Hughes ; PIRA * From Combustible Fuel Sources Oil Gas Oil/Misc Gas Vertical/Directional Horizontal 84% 53% 57% 20% U.S. DRILLING MEXICO DRILLING MEXICO POWER GENERATION Oil/Coal Gas

ETHYLENE INFRASTRUCTURE GROWTH Source: Wells Fargo Securities, LLC U.S. TRADE BALANCE Ethylene Derivative Exports-NGL Equivalent NGL Exports NGL Imports Net Trade ( X% of Total Supply) Potential Projects Likely Projects Current Ethane Demand Export trend continues to enlarge market

Changes 2010-2020 (Bcf/d) -0.5 1.1 -0.3 2.4 5.3 0.5 0.3 0.4 0.3 1.8 2.2 0.2 0.2 -1.1 -1.1 -0.4 0.6 -0.2 -0.1 -0.4 -0.3 0.5 0.4 Source: El Paso April 2011 Macro Forecast 0.7 0.2 EAST COAST LNG GULF COAST LNG LNG EXPORT WEST COAST LNG 1.5 1.4 0.3

Source: INGAA Foundation, April 2011 PROJECTED ACTUAL Source: Energy Information Administration Expected capital expenditures of >$100 B

Right places, right time EP acreage Industry shale plays

Jim Yardley President, Pipeline Group

UNIQUE FRANCHISE EXCELLENT FUNDAMENTALS LONG-TERM GROWTH

Note: As of 12/31/10

Industry leader Integrity programs go beyond regulations Heavily involved in shaping industry positions Strong commitment across organization Established new role-Sr. VP of Pipeline Safety Completing system-wide pipeline integrity program >$1 billion invested in past decade

Percentage of total revenue increases with TGP rate case Note: Percentage of total revenue from reservation charges as of 12/31/10 > 90% > 90%

*Average percentage of contract expirations as of 12/31/10. Amounts include Florida Gas Transmission volumes New expansions increase average contract life AVERAGE CONTRACT EXPIRATION EXCEEDS 6 YEARS 9%

TGP Overall long-term regulated returns EPNG CIG SNG FGT First case in 15 years Improves revenue stability Addresses lower throughput Higher but competitive rates Just filed early rate settlement Next case expected in 2013 Expect to file in 2014

NATIONAL FOOTPRINT Economies of scale; diversity Best positioned for future growth HIGHLY INTEGRATED SYSTEMS (CONNECTIVITY) Better base business and opportunity set SUPERIOR PROJECT EXECUTION Delivering profitable growth What Differentiates EP's Pipeline Group?

Note: Domestic statistics based on publicly reported data as of 12/31/10 1 Includes jointly-owned pipelines, and volumes for KMI and BWP are reported in Bcf/d Creates economies of scale and diversity

Source: El Paso Corporation Rockies Demand Mexico Demand Southeast Demand Northeast Demand Power Generation Demand growth and oil conversions Power Generation Demand growth and coal & oil replacements Power Generation Coal replacements In all the best markets/supply basins Power Generation Coal replacements, renewable back-up Northwest Demand

HIGH VALUE "FIRST MILE" SERVICE Physical requirements service Diversity of supply options Connectivity to growth basins HIGH VALUE "LAST MILE" SERVICE Physical requirements service Extensive connectivity Multiple connections to LDC EP Pipelines more integrated than point-to-point

>100 customer delivery meters and >70 receipt meters in the Rockies >150 customer delivery meters in NE >300 customer delivery meters in SE >500 customer delivery meters in SW Strong market positions

Project costs within 7%-8% of budget 19 projects ('07-'11) On budget excluding Ruby Major projects of competitors 20%-90% over budget Effective risk sharing $8.5 $14.9 2007 YE 2011 YE2 $ Billions Proportionate Rate Base1 75% Growth Yields profitable growth 1Includes the company's proportionate interest in Ruby, Gulf LNG and Florida Gas Transmission 2 Estimated

Completing original $8 B backlog Projects to generate significant cash flow 1Phase two of three-phase project, includes SESH II ?

Construction progressing toward July completion Now expect $3.65 billion cost Favorable long-term market fundamentals Large Rockies resource base Canadian exports to US declining Near-term challenges Especially slower Rockies production growth Long-term strategic asset

SNG South System III* $111 Million 2012 125 MMcf/d TGP NE Supply Diversification $73 Million 2012 250 MMcf/d TGP NE Upgrade Project $416 Million 2013 620 MMcf/d Elba Express Phase B $30 Million 2014 220 MMcf/d Pipelines generate significant cash in 2012 *Phase III of three-phase project which includes SESH Phase II. Phase I placed in-service January '11, Phases II and III in-service in June '11 and June '12, respectively. ALL PROJECTS FULLY-SUBSCRIBED

Estimated $7 billion1 annual total industry spend Expect to capture our share 2014-2020 Bcf/d Eastern powergen ~5 Marcellus/Utica ~6 Mexico ~2 Rockies/NW powergen ~1 1 INGAA Foundation, April 2011. Transmission mainline and laterals, compression, storage

Expected coal and fuel oil plant closures ~12 GW generation ~2 Bcf/d capacity Includes announced closures by Progress, Southern, FPL Growing electric market SNG/FGT have strong positions in growing region Note: El Paso estimate of potential closures (through 2020) Coal plant Oil plant

Expected coal and nuclear plant closures ~18 GW generation ~3 Bcf/d capacity Includes announced closures by TVA, AEP, KY Utilities TGP has available capacity in TN, KY, OH TGP well positioned to capture future growth Note: El Paso estimate of potential closures (through 2020) Coal plant Nuclear plant

2.1 1.3 Bcf/d Ideally located in northeast PA 2008 2009 2010 Mar 2011 Now 33 interconnect receipt points into TGP - 14 more under construction PA Drilling locations TGP Marcellus Shale

CANADA CANADA Success to date; more to come $50 MM-$60 MM revenues from Marcellus backhauls 2012-2013 Completing >$1 billion of expansions; fully-subscribed Area expecting production growth > 6 Bcf/d Excellent position in Utica Marcellus Shale Utica Shale TGP High-activity drilling areas

EPNG and TGP provide significant deliveries to Mexico Expect power generation and industrial growth Additional growth from: Fuel oil conversions PEMEX emphasizing oil over gas Recently contracted 185 MMcf/d EPNG expansion EPNG and TGP set to win El Paso Pipelines PEMEX Current gas-fired plant Future gas-fired plant Est. U.S./Mexico Exports (Bcf/d)

Expected coal closures and renewable generation back-stop ~ 6 GW generation ~ 1 Bcf/d capacity Strong environmental mandates in CO, OR, WA CIG strong market position Ruby provides new capacity/supply diversity Note: El Paso estimate of potential closures (through 2020)

$7 billion1 per year in total industry spend Expect to capture our share 1 INGAA Foundation, April 2011. Transmission mainline and laterals, compression, storage

Unique franchise Scale/scope Positioning Connectivity Execution Stable earnings and cash flow Significant known growth, cash generation Positioned for future growth opportunities

J. R. Sult Executive Vice President & Chief Financial Officer

2010 was best year yet $2.4 B drop down transactions $1.4 B equity raised (most ever by an MLP) Drop down strategy has been win/win for EP shareholders & EPB unit holders Continued execution results in rapid growth of GP distributions (via IDR) Strong start in 2011

JANUARY WIC Kanda Lateral MAY SNG Cypress II SEPTEMBER SNG SESH I OCTOBER WIC Medicine Bow NOVEMBER CIG High Plains SEPTEMBER $736 MM acquisition 30% interest in CIG 15% interest in SNG NOVEMBER Largest MLP IPO $541 MM 100% interest in WIC 10% interest in SNG 10% interest in CIG 10% interest in CIG 10% interest in CIG 10% interest in CIG 10% interest in CIG 10% interest in CIG 10% interest in CIG 2011 2010 2009 2008 Nov. 2007 JUNE/JULY $215 MM acquisition 18% interest in CIG JUNE CIG Totem Storage SEPTEMBER WIC Piceance Lateral MARCH $810 MM acquisition 51% of SLNG 51% Elba Express JUNE $492 MM acquisition 20% interest in SNG NOVEMBER $1,133 MM acquisition 49% of SLNG 49% Elba Express 15% interest in SNG MARCH SLNG Elba IIIA Elba Express NOVEMBER WIC System Exp. DECEMBER CIG Raton 2010 Exp. JANUARY SNG SSIII Phase I Growth through acquisitions-$4.1 B Completed expansion projects-$1.6 B March $667 MM acquisition 25% interest in SNG

Market Cap ($ Billions)

MLP franchise has expanded Positions have been cored up

$/Unit 13 consecutive increases 2008 2009 2010 1Q 2011 ~25% total annual return to unitholders since IPO

$2 $50 GP distribution growth a multiple of EPB distribution growth On track for $60 MM-$70 MM for 2011

GP distributions can double with 10% increase from current distribution level1 Current Annualized Distribution level 1Assumes 10% increase from current annualized per-unit distribution level; includes hypothetical issuance of 40 million new LP units Hypothetical EPB Distribution per LP unit GP benefit from same hypothetical Issuance of 40 MM LP units

$925 MM equity raised so far More than assumed in all 2011 Well positioned for second drop down this year Demand for best in class MLP continues to be outstanding Trajectory for continued execution of MLP strategy is excellent

El Paso committed to continue dropdowns Greater valuation in MLP Grow GP distributions (via IDR) Use cash proceeds to continue balance sheet improvement Large inventory of suitable assets Only one-third of proportional Pipeline EBITDA in EPB ~ $3 billion NOL provides significant flexibility

Mark Leland President, Midstream Group

Processing Fractionation Petrochem Industry Interstate Pipelines NGL Pipeline Gas and Oil/Condensate Gathering / Trucking Treating Stabilization Storage Midstream provides services between the wellhead and interstate pipelines

Substantial Midstream Player in key basins where El Paso operates An Important and Visible Growth Driver to El Paso Corporation A BU that Adds Value directly and indirectly to Pipeline and E&P Groups Source of supply for pipelines Optimize underutilized pipe capacity Ensure infrastructure available for E&P Execution and results driven-Customer Oriented A BU where EP Employees want to come to work and where EP BU's want to recruit 78

EP acreage Industry shale plays $30 B of gathering and processing infrastructure to be added in North America by 20201 1Estimates from INGAA's North American Infrastructure Study

Midstream opportunities executed in partnership El Paso owns 50% of El Paso Midstream Investment Company (EPMIC) EPMIC owns 100% of Altamont assets Partner has committed $500 MM over 4 years Capital efficient vehicle to develop Midstream business

Conventional oil play Drilling activity and oil production are increasing Gathering and processing infrastructure easily expandable Midstream services include: Gathering and compression Treating Processing Third-party fractionation NGL marketing Key Producers: EP / BBG / DVN / Ute Energy / NFX / BRY Natural Gas Oil

1,002 pipeline miles 402 producing wells 23,000 hp compression 40 MMcf/d plant capacity Altamont debottleneck project (50% capacity increase) Third-party gathering expansion 25-mile low-pressure gathering header for new third-party volumes Increases dedicated acreage by ~115,000 acres (54% increase) $25 MM expansion capex (100% basis) El Paso Acreage Third Party Field Extensions Altamont Gathering System Third Party Step Out Line

DIMMIT LA SALLE GAS GATHERING SYSTEM 70 miles of 6" to 12" diameter pipe Capacity of 150-170 MMcf/d ~ $50 MM total capex E&P plus third-party shippers OIL GATHERING SYSTEM 68 miles 6" to 12" diameter pipeline 80,000 Bbls/d capacity ~$50 MM total capex Fully operational gas system mid-summer; oil system early-fall OIL VOLATILE OIL WET GAS DRY GAS TX Edwards Reef EP acreage CRGS In-Service CRGS Under Construction Oil Line Under Construction Oil Terminal

EXPECTED GAS INTERCONNECTS FOR PROCESSING AND TAKE- AWAY Regency Enterprise Energy Transfer Kinder-Copano OIL TAKE-AWAY Immediate on-lease trucking Central terminal trucking Pipeline take-away E&P and third-parties to enjoy multiple gas and oil export options DIMMIT LA SALLE OIL VOLATILE OIL WET GAS DRY GAS TX Edwards Reef EP acreage CRGS In-Service CRGS Under Construction Oil Line Under Construction Oil Terminal Oil Terminal

EPM concentrating on rich gas and oil windows of Marcellus and Utica shales >100 Tcf expected ultimate recovery in southwest PA alone Capturing value of NGLs can increase returns by upwards of 30% Marcellus wet gas continues ~4-5 gallons of ethane per Mcf of gas; approx 16% of the wet gas stream Utica shale expected oil with associated gas TGP has available capacity Marcellus Shale Utica Shale TGP Rich Gas Area

PROJECT SCOPE MEPS will: Collect purity ethane in S.W. Marcellus Redeliver to the Gulf Coast Initial capacity-60,000 to 80,000 BPD; expandable to 100,000 BPD Best pipeline option to premium gulf-coast markets ~ $1 billion total capex STATUS Active discussions with Producers and Petrochemical Companies Ethylene Cracker Tennessee Gas Pipeline

Utica Shale Underlies Marcellus Shale Most drilling currently in eastern Ohio Expected to be oil/condensate with rich associated gas TGP is situated primarily in the oily and rich gas sections of the play El Paso has relationships with key producers Opportunity to provide rich-gas gathering header, in-field gathering and processing, fractionation including ethane solution via MEPS WET GAS TGP OIL CONDENSATE DRY GAS Rich Gas Area Play in early development lacks midstream infrastructure

Oil play with associated rich gas WIC Medicine Bow lateral is situated in the Wyoming region of the play EP has strong relationship with major acreage holders in Wyoming Niobrara Opportunity to provide rich-gas gathering header (WIC), in-field gathering and processing Available WIC capacity Play in early development lacks midstream infrastructure FALL RIVER CONVERSE NIOBRARA GOSHEN SCOTTS BLUFF WELD MORGAN GARDEN DEUEL SEDGWICK PHILLIPS BANNER MORRILL KIMBALL LOGAN CHEYENNE Rawlins C.S. & Plant Laramie C.S. Cheyenne C.S. NATRONA ROUTT JACKSON LARAMIE LARIMER SIOUX DAWES BOX BUTTE SHERIDEN SHANNON BENNETT GRANT WY NE SD CARTION ALBANY WIC CIG PLATTE WIC Medicine Bow Lateral CO POWDER RIVER BASIN DJ BASIN NIOBRARA SHALE

MEPS well positioned to provide Gulf Coast ethane supply Camino Real Gathering System provides Eagle Ford shale Midstream platform Evaluating option to participate in larger Eagle Ford Rich Gas pipeline and processing project Competing for major projects in Utica and Niobrara Continue to advance Altamont infrastructure JV provides financially efficient platform Midstream poised to participate in $30 B gathering and processing 10-year build out

Brent Smolik President, Exploration & Production

Strategy is consistent and fully operational Executing well in all phases of our business Inventory is bigger, lower risk, oilier and more profitable Supportive organizational culture and structure is in place Delivering value and sustainable growth Performance among industry's best

EXECUTION! E&P strategy Asset portfolio Organizational capability

Build and apply competencies in assets with repeatable programs and significant project inventory Sharpen execution skills to improve capital and expense efficiency and maximize returns Add assets with inventory that fit our competencies and divest assets that do not ? ? ? ? ?

EGYPT BRAZIL

3.7 Tcfe 8.0 Tcfe 30% CAGR Haynesville, Eagle Ford & Wolfcamp have driven significant growth Net Risked Resource

Eagle Ford & Wolfcamp have been impactful Oil is >2/3 of future value

Oil Resources Gas Resources HAYNESVILLE EAGLE FORD WOLFCAMP ALTAMONT 1As of 12/31/10 (includes PUD locations and is shown on an unrisked basis >10 years of drilling locations

2007 2008 2009 2010 Peoples Acquisition (Haynesville) Sale of ~1/2 GOM & S. TX assets Eagle Ford Leasing Flying J Acquisitions (Altamont) Wolfcamp/ Eagle Ford Leasing High-grading will continue Sales and additions/oil vs natural gas Continued evaluation of new opportunities New additions must compete with current inventory

DRILLING OPERATIONS Gross Wells Drilled (No.) 154 Footage Drilled (MM ft) 1.6 Rig Count (average) 13 COMPLETION OPERATIONS Gross Wells Completed 142 Stages Completed 1,178 Vol. Pumped (MM bbl) 7.0 Sand Pumped (MM lbs) 317 PRODUCTION OPERATIONS Gross Wells1 5,664 Net operated production (MMcfe/d) 629 Note: El Paso operated assets only 1 As of December 31, 2010

Committed to responsible operations Improved engagement with contractors and service providers Enhanced programs to improve integrity and reliability TRIR Zero employee incidents YTD

Improved reliability and management Pursuing value added investments Workovers, restimulations, pump upgrades, facility de- bottlenecks Overall base decline ~35% No Active Drilling EXAMPLE: RATON PRODUCTION (MMcfe/d)

2010 Tcfe Reserves up 22% from YE 20091 38% Proved undeveloped Reserve life increased to 12 yrs 40% of proved value is oil2 3.41 1 Including the company's 48.8 percent interest in Four Star Oil & Gas Company 2 Based on YE 2010 PV-10, which assumes 2010 pricing

MMcfe/d 782 Production up ~3% from 2009 2010 Exit Rate-800 MMcfe/d ~20% of 2010 revenue from oil 2010

2010 ($/Mcfe) $1.40 $3.55 2010 2007

2010 ($/Mcfe) $0.73 $0.88 2010 2007

ACQUIRE POSITION DELINEATE/ DE-RISK INFILL DRILL LOW Maturity HIGH PILOT WELLS DEVELOPMENT

Rapid production growth Top- or top-quartile program by any measure Holly area economic at sub $4 gas price Continue to drive efficiencies 4-5 year remaining inventory Excellent position in the heart of the play Wells drilled: 86 Wells producing: 79 Wells in backlog: 7

Current net production 265 MMcf/d MMcf/d (Net)

Higher productivity a function of: Excellent acreage position Well design optimization Lateral length Number of stages Pumping rate Total stage volumes Proppant concentrations 1 Cumulative six-month production based on available state reported production data as of April 2011 2 Average per well based on newly producing horizontal gas wells in 2010 targeting the Haynesville Shale (deeper than 11,450 ft.) CUMULATIVE SIX-MONTH PRODUCTION1 El Paso Industry Average2

Avg. Frac Stages Per Day

Highest volume/capital efficiency in portfolio Lowest LOE/unit (~$0.05-$0.10/Mcfe) Best F&D of core programs ($1.55-$1.95 Mcfe) Anchor gas drilling program CUMULATIVE EBITDA/CAPITAL @ $4.00/MCF (NYMEX)* *Based on type model results for a single Holly area Haynesville well

Maintain 4-rig base-load program Continue to drive efficiencies Drilling Completion Fracs per day Frac design Continue to deliver profitable growth

Large oil inventory >800 future locations 125 MMboe resource* Substantial production growth potential Improved well productivity Continuous operational improvement Applying new technologies to 3 billion barrel field *As of December 31, 2010. Indicates risked resource potential

Boe/d (Net) 19% CAGR Current net production >9,000 Boe/d

Continue drilling in geographically focused areas Expected efficiency gains: Shorter, more efficient rig moves Repeatable drilling program execution Optimized completion designs Facility and artificial lift savings Targeted capex savings of 20% per well

Maintain active oil drilling program: 2-3 rigs Continue to drive efficiencies Drilling Vertical Well Completions Analyze 3-D seismic for natural fracture identification Evaluate EOR options Long-term value and production growth

Maintain active oil drilling program: 2-3 rigs Continue to drive efficiencies Drilling Vertical Well Completions Analyze 3-D seismic for natural fracture identification Evaluate EOR options Long-term value and production growth

WEBB LA SALLE MC MULLEN FRIO ZAVALA MAVERICK ATASCOSA Early mover with low acreage costs Advantaged acreage position in LaSalle county In development mode Oil production growing rapidly Piloting phase in North Maintain gas option in South Central area exceeding expectations TX Edwards Reef DIMMIT DUVAL MEXICO Sligo Reef Dry Gas Oil Wet Gas Volatile Oil

Delineation wells drilled across block Results at or above type model Improving drilling efficiencies Infrastructure under construction 4 rigs running TX Production growth will accelerate in the second half of 2011 Wells drilled: 34 Wells completed: 24 Wells on-line: 12

*Best well to date in area

Gross IP (24)-BOEPD 9 wells > 800 BOED 11 wells 600-800 BOED 1 wells < 600 BOED

Current productive capacity 5,600 Bbl/d and 12 MMcf/d, net Gross Volumes (BOED)

DEPTH CAPITAL COST LATERAL LENGTH IP 24-HOUR (6:1) EUR (6:1) IRR F&D (6:1) WELL SPACING INVENTORY 7,000'-10,000' $7.0 MM-$9.0 MM 4,500'-5,500' 600-1,100 BOED 400-900 MBOE 25%->50% $12-$20 ($/BOE) 120 acres >200 MMBOE, ~570 locations Economics assume $4.00/MMBtu Gas, $56/Bbl NGL and $80/Bbl Oil Note: Capital, Production and EUR are gross numbers and do not account for royalties Reducing spacing to 80 acres adds ~100 MMBOE & 280 locations

*Shows the average drilling time (spud to total depth) & average feet per day for all development wells drilled in each quarter; excludes pilot wells 2 rigs now doing the work of 3

Planning for annual rig growth to 5-7 rigs by 2013 Further well optimization Increase multi-pad drilling Frac designs, lateral length Remain focused on Central area Evaluate 80-100 acre spacing units Pilot North area, maintain Southern gas Highest oil production growth potential in portfolio

Encouraging initial results Delineating acreage >800 locations-Upper Wolfcamp only Entire 138,000 acreage position unitized for 7-year term Optimizing: lateral length, frac stages, flow back rates, artificial lift Early mover with excellent position in emerging oil play

Dean WFMP WFMPA WFMPB WFMPC WFMPD Upper Wolfcamp Lower Wolfcamp El Paso 39-7 #1 4,000' 4,000' 7000' 4,000' El Paso 43-22 #1 EOG 40-14 #1 El Paso 8-12 #1 A A' A' A Lateral Length: Gamma Ray Porosity Organic Content Lateral Placement

PARAMETER MODEL RESULTS Depth Ft. 5,800-7,000 5,880-7,930 Thickness Ft. 400-850 976-1,080 Net Pay Ft. 200-425 544-680 Porosity % 7.0-15.0 9.4-12.0 Organic content 4.0-15.0 4.0-8.2 Note: Approximately 53% of section is Upper Wolfcamp Thicker gross section More net pay Better quality intervals Entire Wolfcamp section still perspective

8,000' 7,000' 6,000' 5,000' 7,500' 6,500' 6,500' 5,500' 6,000' 5,500' 5,000' 5,000' IRION CROCKETT 43-22-1H 39-7-1H 38-29-1H 43-19-1H 11-18-1H EP drilling wells Offset drilling wells EP completing wells EP completed wells Drilled offset horizontal well 8-12-1H 8-7-1H 47-18-1H

REAGAN IRION CROCKETT 8-12-1H 43-22-1H 39-7-1H 38-29-1H 43-19-1H 47-18-1H 8-7-1H 11-18-1H 11-18-1H EP completed wells EP well waiting on completion EP drilling wells Offset drilling wells Offset completed wells

TX REAGAN IRION CROCKETT 8-12-1H 43-22-1H 39-7-1H 38-29-1H 43-19-1H 47-18-1H 8-7-1H 11-18-1H +7000' Laterals 2000'- 4500' Laterals Activity trending to longer laterals

Longer laterals expected to increase production, EUR & value WELL LATERAL LENGTH STAGES STAGE SPACING IP24 IP24 PER STAGE EP 39 7-1H 4,000 12 333 337 28 EP 43-22-1H 3,600 13 277 393 30 EP 812-1H 4,300 15 287 346 23 Average 3,967 13 299 358 27 Offset 1 7,400 21 352 667 32 Offset 2 7,700 24 321 747 31 Offset 3 6,300 16 394 568 35 Average 7,133 20 356 661 33

Encouraged by early results Increased to 2-rig program Continuing to delineate acreage with opportunity to grow to 5-7 rigs by 2013 Optimize development plan Lateral length, frac stages, vertical vs. horizontal, artificial lift

Eagle Ford: 3-4 Focus: Gain Efficiencies Wolfcamp: 2-3 Focus: Delineate acreage Haynesville: 4 Focus: Base load gas drilling Altamont: 2-3 Focus: Base load oil drilling 11-14 RIG PROGRAM 2011 capital increase to $1.6 B to drill 35 incremental net oil wells

Accelerates development of highest value programs Advances oil production growth Results in higher 2011 exit rate Maintains momentum Increases 2011 reserve adds Operational efficiencies & safety benefits Improves performance and value creation

Note: Updated guidance assumes $4.50/MMBtu Gas (NYMEX) and $107/Bbl Oil (WTI)

Executing-Strategy, Portfolio, & People Inventory is large and profitable with oil and gas options Core programs performing very well Delivering attractive returns Have built capacity for double-digit growth Production EBITDA-Greater growth rate than production due to oil revenues Will continue top-tier performance

Creating two enduring public companies Each with a bright future Management in place and energized Each will be well capitalized Focus on execution will remain Tremendous outcome for all our stakeholders

Financial

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, or included in the body of this presentation. El Paso uses the non-GAAP financial measure "Segment earnings before interest expense and income taxes" or "Segment EBIT" to assess the operating results and effectiveness of the company and its business segments. The company believes that Segment EBIT is useful to its investors because it allows them to use the same performance measure analyzed internally by our management to evaluate the performance of our businesses and investments without regard to the manner in which they are financed or the company's capital structure. The company defines Segment EBIT as net income (loss) adjusted for interest and debt expense and income taxes. Segment EBIT does not reflect a reduction for any amounts attributable to noncontrolling interests. We also use the non-GAAP financial measure of Segment EBITDA, which is defined as Segment EBIT excluding depreciation, depletion and amortization. El Paso also uses the terms Adjusted Segment EBIT, Adjusted Segment EBITDA and Adjusted EPS as the company believes these measures are useful to investors in analyzing the company's on- going earnings potential. For its 2011 outlook, the company defines Adjusted Segment EBIT as Segment EBIT excluding mark-to-market impact of E&P financial derivatives and including anticipated cash settlement proceeds of E&P financial derivatives based on guidance assumption prices. Adjusted Segment EBITDA is defined as Adjusted Segment EBIT excluding depreciation, depletion and amortization. For the company's 2011 outlook, Adjusted EPS is defined as earnings per share attributable to El Paso Corporation common stockholders, excluding losses on debt extinguishment and anticipated mark-to-market impact of E&P financial derivatives and including anticipated cash settlement proceeds of E&P financial derivatives and the effect of the change in the number of diluted shares. Our Exploration and Production segment uses per-unit total cash operating costs is a non-GAAP measure calculated on a per Mcfe basis equal to total operating expenses less DD&A, transportation costs, ceiling test and other impairment charges, and the cost of products and services, divided by total equivalent production. Exploration and Production per-unit lease operating expenses is a non-GAAP measure calculated on a per Mcfe basis equal to lease operating expenses divided by total equivalent production. The sum of lease operating expenses and production taxes equals production costs. The sum of production costs, cost of products, transportation costs, DD&A, G&A, ceiling test and other impairment charges and other operating expenses equals total operating expenses. Per-unit total cash operating costs and per-unit lease operating expenses are valuable measures used by oil and gas companies and analysts to evaluate operating performance and efficiency. The company's Exploration and Production segment also utilizes the terms Reserve Replacement Costs or "RRC" and Reserve Replacement Ratio or "RRR." These measures are discussed further in this appendix. El Paso uses the compound annual growth rate or "CAGR", which is the average annual growth rate over a period of years. The company believes this metric is useful for investors because it displays the historical or projected performance over time. Compounded growth rates are the industry standard of measurement within the investment community and therefore El Paso feels it is preferred to using the simple average of year-to-year growth rates. 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.

We calculate two primary metrics, (i) a reserve replacement ratio and (ii) reserve replacement costs, to measure our ability to establish a long-term trend of adding reserves at a reasonable cost in our core asset areas. The reserve replacement ratio is an indicator of our ability to replenish annual production volumes and grow our reserves. It is important for us to economically find and develop new reserves that will more than offset produced volumes and provide for future production given the inherent decline of hydrocarbon reserves. In addition, we calculate reserve replacement costs to assess the cost of adding reserves which is ultimately included in depreciation, depletion and amortization expense. We believe the ability to develop a competitive advantage over other natural gas and oil companies is dependent on adding reserves in our asset areas at lower costs than our competition. We calculate these metrics as follows: Reserve replacement ratio Sum of reserve additions1 Actual production for the corresponding period Reserve replacement costs/Mcfe Total oil and gas capital costs2 Sum of reserve additions1 1Reserve additions include proved reserves and reflect reserve revisions for prices and performance, extensions, discoveries and other additions and acquisitions and do not include unproved reserve quantities or proved reserve additions attributable to investments accounted for using the equity method. All amounts except for 2011 estimates are derived directly from the table presented in Item 8, Financial Statements and Supplementary Data, Supplemental Natural Gas and Oil Operations in the company's 2010 Annual Report on Form 10-K. 2Total oil and gas capital costs include the costs of development, exploration and property acquisition activities conducted to add reserves and exclude asset retirement obligations. All amounts except for 2011 estimates are derived directly from the table presented in Item 8, Financial Statements and Supplementary Data, Supplemental Natural Gas and Oil Operations in the company's 2010 Annual Report on Form 10-K. We show the calculation of domestic reserve replacement costs excluding the impact of acquisitions, performance and price-related revisions on reserves to demonstrate the effectiveness of our domestic drilling program exclusive of economic factors (such as price) outside of our control. The reserve replacement ratio and reserve replacement costs per unit are statistical indicators that have limitations, including their predictive and comparative value. As an annual measure, the reserve replacement ratio is limited because it typically varies widely based on the extent and timing of new discoveries, project sanctioning and property acquisitions. In addition, since the reserve replacement ratio does not consider the cost or timing of future production of new reserves, it cannot be used as a measure of value creation. The exploration for and the acquisition and development of natural gas and oil reserves is inherently uncertain as further discussed in the Company's SEC filings. One of these risks and uncertainties is our ability to spend sufficient capital to increase our reserves. While we currently expect to spend such amounts in the future, there are no assurances as to the timing and magnitude of these expenditures or the classification of the proved reserves as developed or undeveloped.

$ Billions 1 Updated guidance assumes $4.50/MMBtu (NYMEX) and $107/Bbl (WTI)

1Adjustments exclude losses on debt extinguishment and the mark-to-market impact of E&P financial derivatives and include cash settlement proceeds of E&P financial derivatives based on guidance assumption prices 2All adjustments assume a 36% tax rate Adjusted Segment EBITDA1 Less: DD&A Adjusted Segment EBIT1 Less: Interest and debt expense Less: Income taxes Adjusted net income1 Adjustments related to derivatives and other1,2 Net income $3.4-$3.6 1.1 $2.3-$2.5 0.9 0.3-0.4 $1.1-$1.2 0.3 $0.8-$0.9 ($ Billions) Twelve Months Ending December 31, 2011

Net income attributable to EPC common stockholders Adjustments related to derivatives and other1 Adjusted net income attributable to EPC common stockholders $0.5-$0.6 0.3 $0.8-$0.9 $0.62-$0.72 0.38 $1.00-$1.10 ($ Billions, Except EPS) After-tax Diluted EPS 1Adjustments exclude losses on debt extinguishment and the mark-to-market impact of E&P financial derivatives and include cash settlement proceeds of E&P financial derivatives based on guidance assumption prices. All adjustments assume a 36% tax rate.

Note: U.S. Domestic positions are as of May 17, 2011 (contract months: April 2011 - Forward) 1Swap option not extended by counterparty in 2012 due to low prices 2Three-Way Collars - Average floor is calculated using the highest floor 2011 2011 2012 2012 2013 2013 Natural Gas Notional Volume (TBtu) Average Hedge Price Notional Volume (TBtu) Average Hedge Price Notional Volume (TBtu) Average Hedge Price Economic - EPEP Fixed Price - Legacy 3.5 $3.88 2.3 $3.93 Fixed Price 130.7 $5.75 102.2 $6.06 Fixed Price - Extendible1 5.5 $6.07 Collars - Ceiling 13.8 $7.29 Collars - Floor 13.8 $6.00 Avg Ceiling 153.4 $5.86 104.5 $6.01 Avg Floor 153.4 $5.74 104.5 $6.01 2011 2011 2012 2012 2013 2013 2014 2014 2015 2015 Crude Oil Notional Volume (MMbbls) Average Hedge Price Notional Volume (MMbbls) Average Hedge Price Notional Volume (MMbbls) Average Hedge Price Notional Volume (MMbbls) Average Hedge Price Notional Volume (MMbbls) Average Hedge Price Economic - EPEP Fixed Price 1.51 $87.54 0.64 $100.13 Written Calls - Ceiling 1.46 $95.00 2.92 $96.88 1.10 $100.00 1.10 $100.00 Three-Way Collars - Ceiling 2.75 $94.27 5.76 $114.16 1.55 $128.34 Three-Way Collars - Floor2 2.75 $85.14 5.76 $92.54 1.55 $100.00 Three-Way Collars - Floor 2.75 $65.00 5.76 $67.54 1.55 $75.00 Avg Ceiling 4.26 $91.88 7.86 $109.46 4.47 $107.79 1.10 $100.00 1.10 $100.00 Avg Floor2 4.26 $85.99 6.40 $93.30 1.55 $100.00

Program Statistics Operated producing wells1: 43 Average WI2: 85 % Average NRI2: 70 % Future drilling locations3: 269 Operated: 138 PUD reserves: 306 Bcfe Unrisked resource potential3: 520 Bcfe Risked resource potential3: 520 Bcfe Spacing: 107 acre (6 wells/section) 1As of 12/31/10 2Average working interest and net revenue interest for operated wells only 3Future locations and resource potential as of 12/31/10, future locations shown on an unrisked basis and include PUD locations 20,000 net acres

Program Statistics Operated producing wells1: 15 Average WI2: 70 % Average NRI2: 52 % Future drilling locations3: 147 Operated: 90 PUD reserves: 67 Bcfe Unrisked resource potential3: 280 Bcfe Risked resource potential3: 280 Bcfe Spacing: 160 acre (4 wells/section) 1As of 12/31/10 2Average working interest and net revenue interest for operated wells only 3Future locations and resource potential as of 12/31/10, future locations shown on an unrisked basis and include PUD locations 20,000 net acres

Overview Objective: Haynesville Shale Depth: 11,000'-12,500' Lateral length: 4,300'- 4,600' Capital costs: $8.7-$9.3 MM EUR (Gross): 6.0-7.0 Bcfe Initial prod: 15-25 MMcfe/d IP(30): 12-20 MMcfe/d Metrics ($4.00/MMBtu, $80/Bbl) IRR: 20%-30% PVR: 1.10-1.20 F&D costs: $1.55-$1.95/Mcfe Overview Objective: Haynesville Shale Depth: 11,000'-12,500' Lateral length: 4,300'- 4,600' Capital costs: $8.7-$9.3 MM EUR (Gross): 5.0-6.0 Bcfe Initial prod: 9-19 MMcfe/d IP(30): 6-15 MMcfe/d Metrics ($4.00/MMBtu, $80/Bbl) IRR: 5%-15% PVR: 0.9 - 1.0 F&D costs: $1.80-$2.35/Mcfe HOLLY AREA NON-HOLLY

TX Edwards Reef DIMMIT WEBB DUVAL LA SALLE MC MULLEN FRIO ZAVALA MAVERICK MEXICO Sligo Reef Dry Gas Oil ATASCOSA Wet Gas Volatile Oil PROGRAM STATISTICS Operated producing wells1: 9 Average WI2: 93 % Average NRI2: 70 % Future drilling locations3: 1,145 100% operated PUD reserves: 25 MMBOE Unrisked resource potential3: 550 MMBOE Risked resource potential3: 395 MMBOE Spacing: North 120 acre Central 120 acre South 160 acre South 160 acre South 160 acre South 160 acre South 160 acre South 160 acre South 160 acre South 160 acre South 160 acre South 160 acre South 160 acre South 160 acre South 160 acre South 160 acre South 160 acre 170,000 net acres 65,000 net acres dry gas 105,000 net acres oil 74,000 central 31,000 north 1As of 12/31/10 2Average working interest and net revenue interest for operated wells only 3Future locations and resource potential as of 12/31/10, future locations shown on an unrisked basis and include PUD locations

Overview Objective Eagle Ford Shale Eagle Ford Shale Eagle Ford Shale Depth 6,000'-7,000' 7,000'-10,000' 9,000'-14,000' Lateral Length: 4,500'-5,500' 4,500'-5,500' 4,500'-5,500' Capital costs: $5.0-$7.5 MM $7.0-$9.0 MM $7.0-$12.0 MM EUR (Gross): 400-550 MBOE 400-900 MBOE 4.0-8.0 Bcfe Initial prod: 400-800 BOED 600-1,100 BOED 5-15 MMcfe/d IP (30): 300-600 BOED 400-900 BOED 4-12 MMcfe/d Metrics ($4.00/MMBtu, $80/Bbl) IRR: 25%-45% 25%->50% 0%-15% PVR: 1.20-1.40 1.20-1.50 0.85-1.0 F&D costs: $14-$22 ($/BOE) $12-$20 ($/BOE) $1.50-$3.50 ($/Mcfe) NORTHERN ACREAGE (Oil) CENTRAL ACREAGE (Oil) SOUTHERN ACREAGE (Dry Gas) Note: Capital, Production and EUR are gross numbers and do not account for royalties

Program Statistics Operated producing wells1: 256 Average WI2: 70 % Average NRI2: 55 % Future drilling locations3: 840 Operated: 740 PUD reserves : 55 MMBOE Unrisked resource potential3: 130 MMBOE Risked resource potential3: 125 MMBOE Spacing: 160 acre 190,000 net acres El Paso Acreage 1As of 12/31/10 2Average working interest and net revenue interest for operated wells only 3Future locations and resource potential as of 12/31/10, future locations shown on an unrisked basis and include PUD locations

OVERVIEW Objective: Wasatch Green River Depth: 9,000'-16,500' Capital costs: $4.0-$7.0 MM EUR (Gross): 300-400 MBOE Initial prod: 400-600 BOED IP(30): 330-500 BOED METRICS ($80/Bbl) IRR: 25%-45% PVR: 1.25-1.45 F&D costs: $17-$21/Bbl

PROGRAM STATISTICS Operated producing wells1: 0 Average WI2: 100 % Average NRI2: 75 % Future drilling locations3: 860 100% operated PUD reserves: 6 MMBOE Unrisked resource potential3,4: 220 MMBOE Risked resource potential3,4: 155 MMBOE Spacing: 160 acre current 138,000 net acres El Paso Acreage 1As of 12/31/10 2Average working interest and net revenue interest for operated wells only 3Future locations and resource potential as of 12/31/10, future locations shown on an unrisked basis and include PUD locations 4Risked and unrisked resource potential only includes upper Wolfcamp

OVERVIEW Objective: Upper Wolfcamp Shale Depth: 5,000'-8,000' Lateral Length: 4,000'-6,000' Capital costs: $4.0-$6.0 MM EUR (Gross): 300-380 MBOE Initial prod: 300-400 BOE/d IP(30): 250-350 BOE/d METRICS ($80/Bbl) IRR: 25%-35% PVR: 1.25-1.35 F&D costs: $17-$25/Bbl

PROGRAM STATISTICS Operated producing wells1: 943 Average WI2: 100 % Average NRI2: 93 % Future drilling locations3: 840 - 100% Operated PUD reserves : 190 Bcfe Unrisked resource potential3: 350 Bcfe Risked resource potential3: 325 Bcfe Spacing: 160 acre initial / 80 acre down-spacing El Paso owns 605,000 acres of minerals Taos Colfax NM CO El Paso Acreage 1As of 12/31/10 2Average working interest and net revenue interest for operated wells only 3Future locations and resource potential as of 12/31/10, future locations shown on an unrisked basis and include PUD locations

OVERVIEW Objective: Raton CBM Depth: 2,500' Capital costs: $400K-$600K EUR (Gross): 1.0-1.3 Bcfe Initial prod: 30-50 Mcfe/d IP(30): 30-50 Mcfe/d METRICS ($4.00/MMBtu) IRR: 20% - 30% PVR: 1.40 - 1.50 F&D costs: $0.30-$0.60/Mcfe

PROGRAM STATISTICS Operated producing wells: 1,171 Average WI1: 86 % Average NRI1: 69 % Future drilling locations2: 270 - 100% Operated PUD reserves : 25 Bcfe Unrisked resource potential2: 60 Bcfe Risked resource potential2: 60 Bcfe Spacing: 160 acre initial / 80 acre down-spacing 110,000 net acres 1Average working interest and net revenue interest for operated wells only 2Future locations and resource potential as of 12/31/10, future locations shown on an unrisked basis and include PUD locations

OVERVIEW Objective: Black Warrior CBM Depth: 700' - 2,500' Capital costs: $350K - $400K EUR (Gross): 0.3 - 0.6 Bcf Initial prod: 30-50 Mcf/d IP(30): 40-60 Mcf/d METRICS ($4.00/MMbtu) IRR: 5%-15% PVR: 0.75-1.1 F&D costs: $1.00 - $1.65/Mcfe

PROGRAM STATISTICS Operated producing wells: 1,134 Average WI1: 81 % Average NRI1: 66 % Future drilling locations2: 575 - 100% Operated PUD reserves: 85 Bcfe Unrisked resource potential2: 410 Bcfe Risked resource potential2: 410 Bcfe Spacing: 160 acre 117,000 net acres3 1Average working interest and net revenue interest for operated wells only 2Future locations and resource potential as of 12/31/10, future locations shown on an unrisked basis and include PUD locations 3Inclusive of Haynesville acreage

PROGRAM STATISTICS Operating wells: 42 Average WI1: 65 % Average NRI1: 48 % Future drilling locations2: 65 - Operated: 64 PUD reserves : 0 Bcfe Unrisked resource potential2: 895 Bcfe Risked resource potential2: 505 Bcfe 63 blocks El Paso Acreage 1Average working interest and net revenue interest for operated wells only 2Future locations and resource potential as of 12/31/10, future locations shown on an unrisked basis and include PUD locations

Undrilled Locations1: 2,010 PUD Reserves: 75 Bcfe Unrisked Resource Potential1: 3,830 Bcfe Risked Resource Potential1: 1,795 Bcfe 1Future locations and resource potential as of 12/31/10, future locations shown on an unrisked basis and include PUD locations

Present Value Ratio = (Total Capital + NPV)/Total Capital NPV & total capital discounted at 12% Minimum ratio is 1.15: Every $1.00 invested returns $1.15 on an after-tax, discounted basis over the life of the project Total capital includes drilling, completion, & wellhead facility costs. Does not include sunk costs or infrastructure

We calculate two primary metrics, (i) a reserve replacement ratio and (ii) reserve replacement costs, to measure our ability to establish a long-term trend of adding reserves at a reasonable cost in our core asset areas. The reserve replacement ratio is an indicator of our ability to replenish annual production volumes and grow our reserves. It is important for us to economically find and develop new reserves that will more than offset produced volumes and provide for future production given the inherent decline of hydrocarbon reserves. In addition, we calculate reserve replacement costs to assess the cost of adding reserves which is ultimately included in depreciation, depletion and amortization expense. We believe the ability to develop a competitive advantage over other natural gas and oil companies is dependent on adding reserves in our asset areas at lower costs than our competition. We calculate these metrics as follows: Reserve replacement ratio Sum of reserve additions1 Actual production for the corresponding period Reserve replacement costs/Mcfe Total oil and gas capital costs2 Sum of reserve additions1 1Reserve additions include proved reserves and reflect reserve revisions for prices and performance, extensions, discoveries and other additions and acquisitions and do not include unproved reserve quantities or proved reserve additions attributable to investments accounted for using the equity method. All amounts except for 2011 estimates are derived directly from the table presented in Item 8, Financial Statements and Supplementary Data, Supplemental Natural Gas and Oil Operations in the company's 2010 Annual Report on Form 10-K. 2Total oil and gas capital costs include the costs of development, exploration and proved property acquisition activities conducted to add reserves and exclude asset retirement obligations. All amounts except for 2011 estimates are derived directly from the table presented in Item 8, Financial Statements and Supplementary Data, Supplemental Natural Gas and Oil Operations in the company's 2010 Annual Report on Form 10-K. We show the calculation of domestic reserve replacement costs excluding the impact of acquisitions, performance and price-related revisions on reserves to demonstrate the effectiveness of our domestic drilling program exclusive of economic factors (such as price) outside of our control. The reserve replacement ratio and reserve replacement costs per unit are statistical indicators that have limitations, including their predictive and comparative value. As an annual measure, the reserve replacement ratio is limited because it typically varies widely based on the extent and timing of new discoveries, project sanctioning and property acquisitions. In addition, since the reserve replacement ratio does not consider the cost or timing of future production of new reserves, it cannot be used as a measure of value creation. The exploration for and the acquisition and development of natural gas and oil reserves is inherently uncertain as further discussed in the Company's SEC filings. One of these risks and uncertainties is our ability to spend sufficient capital to increase our reserves. While we currently expect to spend such amounts in the future, there are no assurances as to the timing and magnitude of these expenditures or the classification of the proved reserves as developed or undeveloped.

Unconventional: Unconventional resources primarily consist of the company's Haynesville, Eagle Ford, and Wolfcamp shale plays and coal bed methane operations in the Raton, Black Warrior and Arkoma Basins. Conventional, low-risk: This consists of conventional resources in the Altamont Field, other Rockies programs, south Texas, and Brazil development programs. It also includes tight-sand drilling in the ArkLaTex area. Conventional, higher-risk: This includes higher-risk exploration in the Gulf of Mexico, Texas Gulf Coast, and undrilled international exploration prospects in Brazil and Egypt.