Exhibit 99.A

EP Energy Operations Update March 28, 2012

2 Cautionary Statement Regarding Forward-Looking Statements This presentation includes certain forward-looking statements and projections of affiliates of El Paso Corporation (collectively, “EP Energy”). EP Energy 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, including, without limitation, changes in unaudited and/or unreviewed financial information; volatility in, and access to, the capital markets; the effects of any changes in accounting rules and guidance; EP Energy’s ability to meet production volume targets; 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 future exploration and production operations; the success of drilling programs with regard to proved undeveloped reserves and unproved resources; EP Energy’s ability to comply with the covenants in various financing documents; EP Energy’s ability to obtain necessary governmental approvals for proposed E&P projects and to successfully construct and operate such projects; actions by the credit rating agencies; the successful close of the sale of EP Energy to EPE Acquisition, LLC; credit and performance risk of EP Energy’s lenders, trading counterparties, customers, vendors and suppliers; changes in commodity prices and basis differentials for oil and natural gas; general economic and weather conditions in geographic regions or markets served by EP Energy, or where operations of EP Energy 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 EP Energy; competition; and other factors described in El Paso Corporation’s (and its affiliates') Securities and Exchange Commission filings. While EP Energy makes these statements and projections in good faith, neither EP Energy 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. Neither EP Energy nor El Paso Corporation assumes any obligation to publicly update or revise any forward-looking statements made herein or any other forward-looking statements made by EP Energy, whether as a result of new information, future events, or otherwise. Certain of the production information in this presentation includes the production attributable to EP Energy’s 48.8 percent interest in Four Star Oil and Gas Company (“Four Star”). El Paso Corporation’s Supplemental Oil and Natural Gas disclosures, which are included in its Annual Report on Form 10-K, reflect EP Energy’s 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 Corporation and not those of Four Star. The SEC permits oil and gas companies, in their filings with the SEC, to disclose only estimated proved, probable and possible reserves that meet the SEC's definitions of such terms. El Paso Corporation discloses only estimated proved reserves in its filings with the SEC. El Paso Corporation's estimated proved reserves as of December 31, 2011 contained in this presentation were estimated by El Paso Corporation's internal staff of engineers and comply with the rules and definitions promulgated by the SEC. El Paso Corporation engaged independent reserve engineers to audit a substantial portion of its estimated proved reserves. The reserve audit procedures followed by the independent reserve engineers on behalf of El Paso Corporation are described in El Paso Corporation's Annual Report on Form 10-K. For the year ended December 31, 2011, El Paso Corporation engaged Ryder Scott Company, L.P., an independent petroleum engineering firm, to perform reserve audit services with respect to its estimated proved reserves.

Cautionary Statement Regarding Forward Looking Forward-Statements In this presentation, EP Energy has disclosed its proved reserves using the SEC's definition of proved reserves under rules effective December 31, 2009. Proved reserves are estimated quantities of hydrocarbons that geological and engineering data demonstrate with reasonable certainty to be recoverable in the future from known reservoirs under the assumed economic conditions. Although the SEC now allows companies to report probable and possible reserves, El Paso Corporation has elected not to report on such basis in its filings with the p p p p , p p g SEC. In this presentation, EP Energy has provided estimates of its “net risked resources,” “unproved resources” or “inventory” which are different than probable and possible reserves as defined by the SEC. Note that El Paso Corporation is not permitted to include or refer to EP Energy’s net risked resources, unproved resources or inventory on such a basis in any SEC filings, and these estimates of net risked resources, unproved resources or inventory should not be construed as comparable to El Paso Corporation’s disclosures of EP Energy’s proved reserves. Net risked resources, unproved resources or inventory are estimates of potential reserves that are made using accepted geological and engineering analytical techniques. Investors are urged to closely consider the disclosures and risk factors in El Paso Corporation’s Forms 10-K and 10-Q, available from El Paso Corporation’s offices or from its website at http://www.elpaso.com, including th i h t t i ti i ti ti titi f d the inherent uncertainties in estimating quantities of proved reserves. This presentation presents certain production and reserves-related information on an "equivalency" basis. Equivalent volumes are computed with oil and natural gas liquid quantities converted to Mcf at a ratio of one Bbl to six Mcf, and natural gas converted to barrels at a ratio of six Mcf to one Bbl. A Boe conversion ratio of six Mcf of natural gas to one Bbl, and a Mcfe conversion ratio of one Bbl of crude oil or NGLs to six Mcf, is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Although these conversion factors are industry accepted norms, they are not reflective of price or market types value differentials between product types. This presentation refers to certain non-GAAP financial measures such as “Reserve Replacement Cost (“RRC”),” “Reserve Replacement Ratio,” "PV-10," “Segment Adjusted EBITDA" and “Segment EBIT." Definitions of these measures and reconciliations between U.S. GAAP and non-GAAP financial measures are included in the body of this presentation or in the Appendix to this presentation. 3

4 Performance Update

5 Large, Diverse, High-Quality Asset Base ALTAMONT WOLFCAMP EAGLE FORD HAYNESVILLE 2011 Proved Reserves Note: Includes EP Energy’s proportionate share of Four Star reserves and production 1 PV-10 value assumes 2011 Pre-Tax SEC pricing. The PDPs represent~55%. of the value S. LOUISIANA WILCOX Total: 4.0 Tcfe 12/31/2011 PV-10: ~$7.0 billion1 Total: 880 MMcfe/d Altamont 14% Other Assets 42% Wolfcamp 4% Wilcox 1% Eagle Ford 16% Haynesville 23% 4Q 2011 Production Altamont 7% Other Assets 48% Wolfcamp 1% Wilcox 1% Eagle Ford 8% Haynesville 35% Western 2011 Reserves (Bcfe): 1,110 4Q 211 Production (MMcfe/d): 153 Central 2011 Reserves (Bcfe): 1,492 4Q 211 Production (MMcfe/d): 443 Southern 2011 Reserves (Bcfe): 1,116 4Q 211 Production (MMcfe/d): 187 Brazil/Egypt/FSOG 2011 Reserves (Bcfe): 269 4Q 211 Production (MMcfe/d): 97

6 Low-Risk 90% 97% 100% Drilling Inventory Growth Liquids 6:1 34% 48% 59% Domestic 82% 90% 99% Core Prog1 46% 61% 78% 2009 2010 1Core programs include Altamont, Eagle Ford, Haynesville (includes Middle Bossier), Wolfcamp and South Louisiana Wilcox Note: Inventory includes unproved resources and proved undeveloped reserves; All inventory is risked, net to EP Energy’s interest Net Risked Resources Excluding PDP and PDNP (Tcfe) Significant oil and natural gas inventory with high ownership and control 2011 0.9 1.3 1.9 2.5 4.2 6.2 2.0 2.2 1.6 0.6 0.2 0.0 2009 YE 2010 YE 2011 YE PUD Unconventional Conventional Lower Risk Conventional Higher Risk 6.0 8.0 9.7 27% CAGR

Core Programs Provide Multi-Year Drilling Opportunity HAYNESVILLE EAGLE FORD (Northern/Central) WOLFCAMP ALTAMONT WILCOX 1As of 12/31/11 (includes PUD locations and is shown on a risked basis) CORE PROGRAMS DRILLING LOCATIONS1 Haynesville 673 Eagle Ford 1,246 Wolfcamp 983 Altamont 1,336 Wilcox 260 Total 4,498 Oil Resources Gas Resources 7

8 Drilling Inventory—Low Breakeven Prices $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 0 500 1,000 1,480 1,980 2,480 2,980 ($/M MBTU) (Bcfe) Gas Directed Drilling Inventory $0 $10 $20 $30 $40 $50 $60 $70 $80 $90 $100 0 200 399 599 799 999 ($/BBL) (MMBoe) Oil Directed Drilling Inventory 500 1,000 1,500 2,000 2,500 3,000 0 0 200 400 600 800 1,000 ~90% of 9.7 TCFE of Inventory economic below $5.00/MMBTU* and $60/BBL* * Based on NYMEX pricing for Henry Hub and WTI 10% IRR After-tax Return Threshold

9 Proven Track Record 2011 performance shows sustained top-tier metrics Total RRC ($/Mcfe)1 Domestic RRC ($/Mcfe)2 Production (MMcfe/d) 3 2009 2011 Reserve Replacement Ratio R/P (Years) 10 12 13 1 Total including acquisitions and price-related revisions 2 Domestic before acquisitions and price-related revisions. 2010 domestic RRC includes ~$265MM of leasehold capital, or $0.39/Mcfe. 2009 domestic RRC includes ~$85MM of leasehold capital, or $0.18/Mcfe 3 Includes EP Energy’s proportionate share of Four Star production 2010 09–11 Chg. .30% .11% . 89% .10% .30% 763 782 838 212% 347% 400% $1.59 $1.58 $1.41 $2.04 $1.40 $1.43 16% 22% 30% 84% 78% 70% 2009 2010 2011 Liquids Gas 2,750 3,362 3,987 Total Estimate Proved Reserves (Bcfe) 20%CAGR

10 Relatively Large Reserve Base .49% Proved Undeveloped1 . ~60% of proved value is liquids2 .Reserves up 57% from YE 2008 to YE 2011 1 Includes EP Energy’s proportionate share of Four Star reserves 2 Based on YE2011 PV-10, which assumes 2011 SEC pricing 3 2011 reserves as of 12/31/11 using 2011 SEC pricing 2011 Year-End Proved Reserves (Tcfe) 0 1 2 3 4 5 6 7 XCO FST PXP KWK SD LINE QEP NFX RRC WPX PXD 4.03

11 Better Growth at Lower Cost Total Reserve Replacement Cost Note: RRC calculation represents Total Costs Incurred / (Purchases + Extensions & Discoveries + Revisions + Improved Recovery) 3-Year Average RRC as of 12/31/2011 ($/Mcfe) $0 $1 $2 $3 $4 RRC QEP KWK LINE PXD WPX NFX SD FST XCO PXP 1.55

12 52 38 66 35 21 47 27 14 23 Haynesville Eagle Ford Altamont First 3 Wells Average 2011 Best Well 2011 Delivering Improved Capital Performance 2Exclusive of time between drilling and stimulation events 1 Includes all development wells spud, completed, and to sales in 2011 10.8 9.7 6.6 8.9 9.5 6.9 7.7 6.8 4.6 First 3 Wells Average 2011 Best Well 2011 CAPITAL COSTS ($ MM) CYCLE TIME Spud to Rig Release + Stimulation2 1 1

13 Reducing Operating Costs . 28% reduction in unit lifting costs . Reduced subsurface, compression and disposal costs . Divested high cost production . Mitigating impact of oil transition 245 237 175 156 176 2007 2008 2009 2010 2011 Total Cost ($MM) 0.86 0.89 0.70 0.62 0.65 2007 2008 2009 2010 2011 Unit Cost ($/Mcfe) Total Domestic

14 Oil Impact is Growing 1 Includes our proportionate share of Four Star production 2 Excludes the impact of financial derivatives Oil Volumes grew 24% in 2011 9% 11% 11% 11% 10% 11% 12% 15% 5% 4% 4% 4% 4% 3% 3% 3% 86% 84% 85% 85% 86% 86% 84% 82% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 Liquids as % of Total Production1 % Oil % NGL % Gas 20% 27% 25% 30% 29% 33% 33% 44% 5% 5% 4% 4% 4% 3% 4% 3% 76% 68% 72% 66% 67% 64% 64% 53% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 Liquids as % of Total Revenue2 % Oil % NGL % Gas

15 Premium Pricing in Key Resource Areas * Based on pricing as of March 2012 Access to attractive markets and pricing EAGLE FORD ALTAMONT WOLFCAMP WILCOX HAYNESVILLE Natural Gas South Texas Indices NW Rocky Mountains WAHA and EPNG Permian Henry Hub Henry Hub NGLs Mt. Belvieu Mt. Belvieu and Conway Mt. Belvieu Mt. Belvieu - Realized Price ($/Mcf)* ~$2.50 above NYMEX HH Residue returned to field; excess yields minimal value ~$2.50 above NYMEX HH ~$2.50 above NYMEX HH NYMEX HH minus basis differentials Oil Refinery Postings and LLS Index Refinery Postings WTI minus Midland Diff. LLS Indexed - Realized Price ($/bbl)* NYMEX WTI plus $1-$10/bbl NYMEX WTI minus $13-$15/bbl NYMEX WTI minus $1-$3/bbl NYMEX WTI plus $12-19/bbl -

Robust Hedge Position Natural Gas Hedges 2013 2012 2014 Crude Oil (TBTU) Volume Average Price(1) Volume Average Price(1) Volume Average Price(1) Economic - EPEP Avg Floor 181 $4.68 79 $3.58 52 $3.92 Hedges (Mbl) Volume Average Price(1) Volume Average Price(1) Volume Average Price(1) Volume Average Price(1) Crude Oil Fixed Price Swaps 1,531 $105.14 7,430 $104.83 8,760 $98.64 6,114 $95.48 2014 2015 2012 2013 Three-Way Collars - Ceiling 5,764 $114.16 1,552 $128.34 Three-Way Collars - Floor2 5,764 $92.54 1,552 $100.00 Avg Floor 7,295 $95.18 8,982 $103.99 8,760 $98.64 6,114 $95.48 Written Calls - Ceiling 1,460 $95.00 2,920 $96.87 1,095 $100.00 1,095 $100.00 d f l fl h d l f h d d f db l d bl f d Floors currently represent approximately 74%, 43% and 34% of production 2012, 2013 and 2014, in respectively respectively3 g 16 Note: Hedge Profile reflects hedges in place as of March 26, 2012; Hedge positions indemnified by EPE Acquisition, LLC include 939 MBbl of 2013 crude, 28.8 Bcf of 2013 gas, and all hedges in 2014 and beyond 1 Prices presented are per MMBtu of natural gas and per Bbl of oil 2 If market prices settle at or below $67.54 and $75.00 for the years 2012 and 2013, respectively, our three-way collars-floors effectively “lock-in” a cash settlement of the market price plus $25.00 per Bbl for 2012 and 2013 3 Percentage based on 2011 actual volumes include our proportionate share of Four Star

17 Historical Financials

18 Summary Historical Financials Note: Production volumes include our proportionate share of Four Star ($ in millions, unless otherwise stated) FY 2009 FY 2010 FY 2011 Production Natural Gas (MMcfe) 238,101 242,776 257,964 Oil/Condensate (MBbls) 4,497 5,111 6,340 NGL (MBbls) 2,248 1,996 1,624 Combined production (MMcfe) 278,571 285,418 305,748 Average combined daily production (MMcfe/d) 763 782 838 Average Realized Sales Prices Natural Gas ($/Mcf) $ 3.80 $ 4.32 $ 4.04 Oil ($/Bbl) 52.48 72.83 91.40 NGL ($/Bbl) 33.75 42.38 53.50 Realized Sales Prices, Including Average Financial Derivative Statements Natural Gas ($/Mcf) $ 7.62 $ 5.67 $ 5.44 Oil ($/Bbl) 95.57 71.13 90.23 Total Operating Revenues $ 1,828 $ 1,789 $ 1,867 Total Operating Expenses $ 3,145 $ 1,058 $ 1,364 Segment Adjusted EBITDA $ 1,539 $ 1,137 $ 1,305 Capital Expenditures $ 1,129 $ 1,318 $ 1,644

19 Segment Adjusted EBITDA Reconciliation Note: Production volumes include our proportionate share of Four Star ($ in millions) FY 2009 FY 2010 FY 2011 Reported Net (Loss) Income $ (911) $ 443 $ 262 Income tax (benefit) expense $ (462) $ 263 $ 220 Interest expense 24 21 12 Segment EBIT $(1,349) $ 727 $ 494 Net impact of E&P financial derivatives $ 323 $ (92) $ 47 Ceiling test charges 2,123 25 152 Restructuring costs 2 – – DD&A 440 477 612 Segment Adjusted EBITDA $ 1,539 $ 1,137 $ 1,305

20 Asset Overview

21 Asset Overview 2011 Proved Reserves Total: 4.0 Tcfe 12/31/2011 PV-10: ~$7.0 billion1 Total: 880 MMcfe/d Altamont 14% Other Assets 42% Wolfcamp 4% Wilcox 1% Eagle Ford 16% Haynesville 23% 4Q 2011 Production Altamont 7% Other Assets 48% Wolfcamp 1% Wilcox 1% Eagle Ford 8% Haynesville 35% Note: Includes EP Energy’s proportionate share of Four Star reserves and production 1 PV-10 value assumes 2011 Pre-Tax SEC pricing. The PDPs represent ~55%. of the value

22 Planned Capital Allocation 1 Present Value Ratio = (Total Capital + NPV)/Total Capital 2 Includes $110 million of capitalized G&A and interest . Founded on deep and diverse inventory . All projects compared on the same basis .Hurdle rate PVR1 1.15 with conservative commodity price deck and 12% discount rate . Rigorous look-back process 2012 $1.5 Billion Capital Program2 ($ in millions) $899 $97 $183 $155 $126 $77 Eagle Ford Haynesville Wolfcamp Altamont South Louisiana Wilcox Other Assets

23 Eagle Ford Shale Highlights . Highest value asset in portfolio . Premier acreage position in oil / volatile oil portion of play . 4–5 rigs per year through 2014 in Central Eagle Ford holds acreage . Over 400 MMBoe of resources and over 1,200 potential drilling locations in LaSalle and Atascosa counties in inventory . Midstream infrastructure in place . Program in full development mode . Strong production rates and well performance . Recent IP rates exceeding type curve . Reducing cycle times . Oil production growing rapidly . South area provides gas option

24 Eagle Ford Shale Overview 2012 Program Map of Operations Resource Profile Avg. Net Production Growth 1Net Acres consists of ~66,000 net acres of dry gas and ~91,000 net acres of oil (85% Central / 15% North) 2 Inventory includes potential unproved resources and proved undeveloped reserves; All inventory is risked, net to EP Energy’s interest 3Average working interest and net revenue interest for future drilling inventory wells As of 12/31/2011 Total Proved Reserves (MMBoe) 107 Net Acres1 157,000 Operated Producing Wells 64 Future Inventory Resources2 (MMBoe) /% Liquids 403 / 91% Future Drilling Locations / Operated Locations 1,246 / 1,236 Average WI2,3 / Average NRI2,3 84% / 63% . 2012 Capital—$899 million . 88 gross wells expected to spud in 2012 . Operating 4 rigs, will pick up 5th later this year . 2 spacing pilots completed (100 & 80 acres), 3 more underway (90, 70, & 60 acres) Represents EP Energy acreage 0.0 5.0 10.0 15.0 20.0 MBoe/d Gas NGL Oil

25 Eagle Ford IP Improvement Recent wells yielding exceptional 24-hour IP rates 10 wells 10 wells 5 wells 13 wells 18 wells 11 wells 0 200 400 600 800 1,000 1,200 1,400 2010 1Q 2011 2Q 2011 3Q 2011 4Q 2011 1Q 2012 Daily Production (Boe/d) EAGLE FORD CENTRAL AREA Avg. IP (Boe/d) * *Through February 2012

26 24 14 13 12 12 11 12 8 2Q 2010 3Q 2010 4Q 2010 1Q 2011 2Q 2011 3Q 2011 4Q 2011 Best Well DRILLING DAYS (Spud to Total Depth) 2.2 1.1 2.7 2.7 3.1 3.0 4.4 6.4 2Q 2010 3Q 2010 4Q 2010 1Q 2011 2Q 2011 3Q 2011 4Q 2011 Best Well STIMULATION (Stages/Day) Eagle Ford Operational Efficiency Eagle Ford Operational Success Rig line now drills ~20 wells per year Higher efficiency lowers total well cost Best Well: Ritchie Farms No. 14H rig released 1/25/2012 Best Well: Maltsberger No. 11H completed 1/11/2012 . Leveraged experience from Haynesville shale to establish baseline . Employ different technology and designs—bits, mud, directional services, pad drilling . Establish consistent supplies and services . Optimize completion design to maximize value and recovery . Eliminate non-productive time relentlessly

27 Eagle Ford Oil & Gas Infrastructure DIMMIT LA SALLE OIL VOLATILE OIL WET GAS DRY GAS EP acreage Gas line Gas interconnects Oil line Oil interconnects Oil terminal Gardendale Rail Facility Enterprise Kinder/Copano ETC Regency Hilcorp Gardendale Hilcorp Cotulla DIMMIT In-field Gathering . Owned and operated by EP Energy . Wellhead gathering to 8 central batteries currently; additional batteries under construction Camino Real Gathering System* . Natural gas system capacity of 150–170 MMcf/d . Oil system capacity of 90,000 Bbls/d, with blending capability . Additional connections to new lines under construction in area would substantially increase capacity Takeaway . Sufficient downstream processing and transportation capacity to accommodate aggressive gas volume growth . Long-term oil sales agreements with premium pricing to WTI Began oil deliveries to downstream markets via pipeline 1Q 2012 *Camino Real is owned and operated by El Paso Midstream

28 Eagle Ford Economics Northern Acreage (Oil) Central Acreage (Oil) Southern Acreage (Dry Gas) Operational Metrics Depth (ft) 6,000 – 7,000 7,000 – 9,800 10,000 – 13,000 Lateral Length (ft) 4,500 – 6,500 4,500 – 6,500 4,500 – 6,500 Capital Costs ($MM) $6.0 – 7.0 $8.0 – 8.4 $7.8 – $9.8 EUR (Gross MBoe) 204 500 – 600 5.4 (Bcfe) IP (Boe/d) 165 750 – 900 7 (MMcfe/d) IP (30) (Boe/d) 155 600 – 800 6 (MMcfe/d) Financial Metrics ($3.50/ $90) IRR 10% – 15% 45% – 65% 0% – 1% PVR 0.97 – 1.07 1.50 – 1.70 0.71 – 0.80 Net F&D Costs ($/Boe) $41 – $48 $20 – $23 $2.13 – $2.67 ($/Mcfe) Note: Capital, Production and EUR are gross numbers and do not account for royalties. Based on internal engineering estimates

29 Eagle Ford Decline Profiles 0 2 4 6 8 0 6 12 18 24 30 36 42 48 54 60 MMcfe/d Month TYPE CURVE—SOUTH AREA (DRY GAS) 0 100 200 300 400 500 600 700 800 0 6 12 18 24 30 36 42 48 54 60 Boe/d Month TYPE CURVE—CENTRAL AREA (~75% Oil) 0 50 100 150 200 0 6 12 18 24 30 36 42 48 54 60 Boe/d Month TYPE CURVE—NORTH AREA (~90% Oil) Note: Based on internal engineering estimates

30 Altamont Highlights . Applying new technologies . Multi-billion barrel oilfield located within the Uinta basin (approximately 10% recovered to-date) . Continuing to improve drilling and vertical well completion efficiencies . Significant net risked resources tied to future drilling inventory . Over 1,300 drilling locations . Multiple vertical growth opportunities ranging from the conventional tight sands to unconventional shales . Considerable short cycle oil production opportunities tied to low cost recompletions and pump upgrades . Large lease position in proven oil field with significant cost efficient production growth opportunities . Land position is predominantly held by production (HBP) . Excellent economic returns at current oil prices

31 Altamont Overview 2012 Program Map of Operations Resource Profile Avg. Net Production Growth . 2012 Capital—$155 million . 21 gross wells expected to spud in 2012 . Plan to maintain active oil drilling program with 2 rigs . Resources and future locations based on 160 acre spacing, but additional upside exists related to further down-spacing As of 12/31/2011 Total Proved Reserves (MMBoe) 92 Net Acres 176,000 Operated Producing Wells 331 Future Inventory Resources1 (MMBoe) / % Liquids 276 / 71% Future Drilling Locations1 / Operated Locations 1,336 / 1,030 Average WI2 / Average NRI2 60% / 50% 1 Inventory includes unproved resources and proved undeveloped reserves; All inventory is risked, net to EP Energy’s interest. 2Average working interest and net revenue interest for future drilling inventory wells 0.0 2.0 4.0 6.0 8.0 10.0 2006 2007 2008 2009 2010 2011 M Boe/d Gas Oil

32 Altamont Operational Efficiency . Focused drilling delivering lower costs . Simplified design and execution . Enhanced site supervision . Centralized engineering in Houston to leverage best practices . Established strategic supplier relationships Altamont Operational Success 76 35 39 36 27 17 4Q 2010 1Q 2011 2Q 2011 3Q 2011 4Q 2011 Best Well DRILLING DAYS (Spud to Total Depth) 339 276 401 378 405 496 602 3Q 2010 4Q 2010 1Q 2011 2Q 2011 3Q 2011 4Q 2011 Best Well DRILLING ROP (Feet Per Day) Best Well: Hill 3-24C6 rig released 6/22/2011 Best Well: Hill 3-24C6 rig released 6/22/2011

33 Altamont Program Statistics Economics Operational Metrics Depth (ft) 9,000 – 16,500 Capital Costs ($MM) $4.6 – $7.7 EUR (Gross MBoe) 300 – 450 IP (Boe/d) 400 – 600 IP (30) (Boe/d) 330 – 500 Financial Metrics ($3.50 / $90) IRR 20% – 40% PVR 1.25 – 1.45 F&D Costs ($/Boe) $15 – $21 0 100 200 300 400 500 0 6 12 18 24 30 36 42 48 54 60 Boe/d Month Note: Economics include benefit from future up-hole zone recompletions. Based on internal engineering estimates. TYPE CURVE DEEP/SHALLOW AVERAGE

34 Wolfcamp Shale Highlights . Early mover with excellent position in highly competitive oil play . High level of industry activity surrounding EP units . Thickest section with superior porosity and organic content . High oil in place . 138,000 net acres . Single landowner, University Land System . 6 of 7-year lease term remaining on majority of acreage . 100% operated . Longer laterals and higher stages yielding exceptional production results . Technically evaluating the Lower Wolfcamp and secondary objectives for additional upside . Rapidly moving to development phase . Optimizing for Upper Wolfcamp drilling and completion techniques . Improving recovery factor

35 Wolfcamp Shale Overview Map of Operations Resource Profile (Upper Wolfcamp) 2012 Program As of 12/31/2011 Total Proved Reserves (Mmboe) 25 Net Acres 138,000 Operated Producing Wells 14 Future Inventory Resources1 (MMBoe) / % Liquids 329 / 89% Future Drilling Locations1 / Operated Locations 983 / 983 Average WI1,2 / Average NRI1,2 100% / 75% . 2012 Capital—$183 million . 13 gross wells expected to spud in 2012 . Plan to operate 1 rig for remainder of 2012 . Resources and future locations related to 90 acre spacing Avg. Net Production Growth REAGAN IRION CROCKETT Wells Drilled El Paso +7000' Laterals El Paso 2000'– 4500' Laterals Competitor Lateral Wells Drilled EP Energy +7000’ Laterals EP Energy 2000’-4500’ Laterals Competitor Lateral 0.0 0.2 0.4 0.6 0.8 1.0 1Q 2011 2Q 2011 3Q 2011 4Q2011 MBoe/d 1 Inventory includes unproved resources and proved undeveloped reserves; All inventory is risked, net to EP Energy’s interest 2Average working interest and net revenue interest for future drilling inventory wells

36 Wolfcamp Activity Heating Up REAGAN IRION CROCKETT Wells Drilled El Paso +7000' Laterals El Paso 2000'– 4500' Laterals Competitor Lateral Petrohawk EOG EOG/Devon EOG/ Devon Approach ConocoPhillips EOG/ Devon Forest Oil Samson Highmount Pioneer EOG Apache Source: University Lands’ website

37 0 100 200 300 400 500 600 700 800 900 Q32010 Q42010 Q12011 Q22011 Q32011 Q42011 (Average IP24 (Boe/d) Upper Wolfcamp IP Improvement . Core, log, drilling and performance analysis has led to clear target in Upper Wolfcamp . Long and short lateral completions increasing IP’s over time . Fracture stimulation designed to maximize stimulated rock volume and near wellbore conductivity . Micro-seismic shows good complexity with better than average prop’d half lengths when compared to industry . Best well in EPE area IP24 over 1,300 Boe/d (in 3Q 2011) .EPE type curve holding when compared to actual production 3Q 2010 4Q 2010 1Q 2011 2Q 2011 3Q 2011 4Q 2011

38 Wolfcamp Operational Efficiency . Leveraged best practices from Haynesville and Eagle Ford . Early problems with hole stability have been addressed . Stimulation relationship delivering improved performance . Reducing total well costs . Expect continued improvement as play advances into full scale development Wolfcamp Operational Success 24 26 12 8 2Q 2011 3Q 2011 4Q 2011 Best Well DRILLING DAYS (Spud to Total Depth) 2.7 2.5 4.0 5.3 2Q 2011 3Q 2011 4Q 2011 Best Well STIMULATION (Stages/Day) Best Well: University 43-24 #1 rig released 12/3/2011 Best Well: University 43-23 #2 completed 1/18/2012

39 Wolfcamp Program Statistics Economics Operational Metrics Depth (ft) 5,000 – 8,000 Lateral Length (ft) 7,000 – 8,000 Capital Costs ($MM) $8.0 – $8.4 EUR (Gross MBoe) 465 – 510 IP (Boe/d) 575 – 675 IP (30) (Boe/d) 400 – 500 Financial Metrics ($3.50 / $90) IRR 20% – 30% PVR 1.20 – 1.35 Net F&D Costs ($/Boe) $21 – $24 0 100 200 300 400 500 600 0 6 12 18 24 30 36 42 48 54 60 Boe/d Month Type Curve Note: Based on internal engineering estimates

40 South Louisiana Wilcox Highlights . Leveraged Texas Wilcox experience in South Louisiana . Tight sands on conventional oily structures . ~177,000 acres leased or optioned, premier position in Beauregard Parish . ~1/3 leased either in primary term, or held by production or operations . ~2/3 under lease options, once exercised will provide 3 year window to develop . Significant acreage position with substantial growth potential . Over 1,000 square miles of 3-D seismic, about a third proprietary . Program does not compete for resource-play-type services . Access to LLS crude pricing and Gulf Coast NGL pricing

41 South Louisiana Wilcox Overview 2012 Program Map of Operations Resource Profile Avg. Net Production Growth Wilcox Deltaic Sands TX LA NEWTON SABINE ORANGE JASPER TYLER HARDI N JEFFERSON LIBERTY ANGELINA SAN AUGUSTINE RUSK NACOGDOC HES SHELBY POLK CALCASIEU BEAUREGARD ALLEN JEFFERSON DAVIS ACADIA RAPIDES VERNON SABINE NATCHITOCHES WINN GRANT DE SOTO CAMERON Lake Charles As of 12/31/2011 Total Proved Reserves (MMBoe) 6 Net Acres ~177,000 Operated Producing Wells 14 Future Inventory Resources1 (MMBoe) / % Liquids 56 / 59% Future Drilling Locations1 / Operated Locations 260 / 260 Average WI1,2 / Average NRI1,2 92% / 69% 1 Inventory includes unproved resources and proved undeveloped reserves; All inventory is risked, net to EP Energy’s interest 2Average working interest and net revenue interest for future drilling inventory wells 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 3Q 10 4Q 10 1Q 11 2Q 11 3Q 11 4Q 11 2012 E MBoe/d Gas Oil . 2012 Capital—$126 million . 12 gross wells expected to spud in 2012 . Plan to operate 1 rig for remainder of 2012

42 South Louisiana Wilcox Operational Efficiency . Rapidly improved drilling performance . Improved petrophysics reducing number of completions . Lower total costs delivering improved value Wilcox Operational Success 22 20 21 15 6 1Q 2011 2Q 2011 3Q 2011 4Q 2011 Best Well DRILLING DAYS (Spud to Total Depth) 667 735 672 1,107 2,194 1Q 2011 2Q 2011 3Q 2011 4Q 2011 Best Well DRILLING ROP (Feet Per Day) Best Well: Anita Midkiff 33 #1 rig released 10/4/2011 Best Well: Anita Midkiff 33 #1 rig released 10/4/2011

43 South Louisiana Wilcox Program Statistics Economics Operational Metrics Depth (ft) 13,000'– 15,000' Capital Costs ($MM) $6.0 – 7.0 EUR (Gross MBoe) 320–440 IP (Boe/d) 500–900 IP (30) (Boe/d) 400–800 Financial Metrics Per Well ($3.50 / $90) IRR 30%–70% PVR 1.30–1.60 F&D Costs ($/Boe) $19.75–27.25 0 100 200 300 400 500 600 700 0 12 24 36 48 60 Boe/d Months TYPE CURVE Note: Based on internal engineering estimates

44 . Premier acreage position in the heart of the play, predominantly HBP . Significant production growth, 4Q 2011 rate over 300 MMcfe/d net . Drilling results among the best in industry . Efficient plan of development (multi-well pads, batch drill and complete) . Continuous improvement has led to enhanced well performance . High capital efficiency . Low development cost . Low lease operating expense ($0.06/Mcf) Haynesville Shale Highlights Demonstrates EP Strategy and Approach to Business

45 Haynesville Shale Overview 2012 Program Map of Operations Resource Profile (Bcfe) Avg. Net Production Growth As of 12/31/2011 Haynesville Bossier Total Proved Reserves (Bcfe) 886 17 Net Acres 41,000 24,500 Operated Producing Wells 106 1 Future Inventory Resources1 (Bcfe) 717 534 Future Drilling Locations1 434 239 Average WI1,2 44% 77% Average NRI1,2 36% 64% . 2012 Capital—$97 million . 4 gross wells spud in 2012 . Expected to complete 12 wells in 2012 . 107-acre spacing (6 per section in Holly) . Drilling program suspended due to low gas prices EP Energy acreage 1 Inventory includes unproved resources and proved undeveloped reserves; All inventory is risked, net to EP Energy’s interest. 2Average working interest and net revenue interest for future drilling inventory wells 0 50 100 150 200 250 300 350 MMcfe/d

46 Haynesville Operational Efficiency Haynesville Operational Success . Industry leading execution . Consistent program aligned with strategic suppliers . Rapid transfer of knowledge to other shale programs . Retain critical skills to restart with higher gas prices 28 26 26 25 24 25 28 26 19 1Q 2010 2Q 2010 3Q 2010 4Q 2010 1Q 2011 2Q 2011 3Q 2011 4Q 2011 Best Well DRILLING DAYS (Spud to Total Depth) 2.9 3.3 3.4 3.9 4.1 3.6 3.6 3.9 5.4 1Q 2010 2Q 2010 3Q 2010 4Q 2010 1Q 2011 2Q 2011 3Q 2011 4Q 2011 Best Well STIMULATION (Stages/Day) Best Well: Pegues Etal 36H #2 rig released 8/21/2011 Best Well: Gamble Est. 13H #3 completed 1/18/2012

47 Haynesville Program Statistics Holly Non-Holly Middle Bossier Operational Metrics Depth (ft) 11,000 – 12,500 11,000 – 12,500 10,700 – 12,200 Lateral Length (ft) 4,300 – 4,600 4,300 – 4,600 4,300 – 4,600 Capital Costs ($MM) $7.9 – 8.3 $7.9 – 8.3 $7.9 – 8.3 EUR (Gross Bcfe) 5.4 – 7.1 4.3 – 5.3 3.0 – 4.0 IP (MMcfe/d) 15 – 19 8 – 13 7 – 9 IP (30) (MMcfe/d) 12 – 16 7 – 11 6 – 8 Financial Metrics ($3.50 / $90) IRR 12% – 29% 0% – 6% 0% – 2% PVR 1.04 – 1.27 0.77 – 0.91 0.71 – 0.81 F&D Costs ($/Mcfe) $1.43 – $1.88 $1.91 – $2.35 $2.53 – $3.38 Note: Based on internal engineering estimates

48 Haynesville Decline Profiles 0 2 4 6 8 10 12 14 16 0 6 12 18 24 30 36 42 48 54 60 MMcfe/d Month TYPE CURVE—HOLLY 0 2 4 6 8 10 12 14 16 0 6 12 18 24 30 36 42 48 54 60 MMcfe/d Month TYPE CURVE—NON-HOLLY 0 2 4 6 8 10 12 14 16 0 6 12 18 24 30 36 42 48 54 60 MMcfe/d Month TYPE CURVE - MIDDLE BOSSIER Note: Based on internal engineering estimates

49 Appendix

50 Reserve Metrics 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 price 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 are derived directly from the table presented in Item 8, Financial Statements and Supplementary Data, Supplemental Oil and Natural Gas Operations in El Paso’s 2011 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 are derived directly from the table presented in Item 8, Financial Statements and Supplementary Data, Supplemental Oil and Natural Gas Operations in El Paso’s 2011 Annual Report on Form 10-K We show the calculation of domestic reserve replacement costs excluding the impact of acquisitions 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 developing future production of new reserves, it cannot be used as a measure of value creation. The exploration for and the acquisition and development of oil and natural gas reserves is inherently uncertain as further discussed in the El Paso’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.

51 METRICS PVR (PRESENT VALUE RATIO) . Present Value Ratio = (Total Discounted Capital + NPV)/ Total Discounted 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 F&D (FINDING AND DEVELOPMENT COSTS) . New well cost divided by net EUR

52 Unproved Resources . 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 primarily of conventional resources in the Altamont Field, SLA Wilcox, other Rockies programs, south Texas, and Brazil development programs. It also includes tight-sand drilling in the ArkLaTex area. . Conventional, higher-risk: This primarily includes higher-risk exploration in the Gulf of Mexico, Texas Gulf Coast, and undrilled international exploration prospects in Brazil and Egypt.

53 Additional Non-GAAP Information EP Energy uses the non-GAAP financial measure of Segment EBIT. Segment EBIT is defined as net income (loss) adjusted for interest and debt expense and income taxes. We believe that Segment EBIT is useful to investors because it allows them to use the same performance measure analyzed internally by El Paso and our management to evaluate the performance of our business and investments without regard to the manner in which they are financed or our capital structure. We also use the non-GAAP financial measure of Segment Adjusted EBITDA. Segment Adjusted EBITDA is defined as Segment EBIT adjusted as applicable in the relevant period for the impact of financial derivatives, ceiling test charges, restructuring costs and excludes depreciation, depletion and amortization. We believe that Segment Adjusted EBITDA is useful to investors as many analysts use it as a measure of operating performance, and this measure allows them to understand how certain significant items impact the comparability of our results. This measure, however, should not be used as a substitute for operating cash flows. We also use the non-GAAP measure of PV-10. PV-10 is considered a non-GAAP measure as it is derived from the standardized measure of discounted future net cash flows. PV-10 is defined as discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future income taxes, discounted at 10%. We believe that the presentation of PV-10 is relevant and useful to investors because it allows them to evaluate the relative monetary significance of our oil and natural gas properties regardless of our tax structure. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the standardized measure of discounted future net cash flows. Our PV-10 measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of our oil, natural gas and NGL reserves. Below is a reconciliation of PV-10 to the standardized measure (in millions). $ 7,016 PV-10 (1,816) Income taxes, discounted at 10% 210 Discounting difference (1) $ 5,410 Standardized measure of discounted future net cash flows (1) The discounting difference relates to differences in the manner in which discounted cash flows are determined for reserve calculations (monthly) versus the discount calculation for purposes of calculating the standardized measure (annually)