RBC Capital Markets Global Energy & Power Conference June 7, 2017
Cautionary Statement Regarding Forward-Looking Statements This presentation includes certain forward-looking statements and projections of 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, the volatility of, and sustained low oil, natural gas, and NGL prices; the supply and demand for oil, natural gas and NGLs; changes in commodity prices and basis differentials for oil and natural gas; 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; credit and performance risks of EP Energy s lenders, trading counterparties, customers, vendors, suppliers, and third party operators; 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 oil and natural gas demand; the uncertainties associated with governmental regulation, including any potential changes in federal and state tax laws and regulation; competition; and other factors described in EP Energy s 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. EP Energy assumes no 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. This presentation presents certain production and reserves-related information on an "equivalency" basis. Equivalent volumes are computed with natural gas converted to barrels at a ratio of six Mcf to one Bbl. These conversions are based on energy equivalency conversion methods primarily applicable at the burner tip and do not represent value equivalencies at the wellhead. Although these conversion factors are industry accepted norms, they are not reflective of price or market value differentials between product types. This presentation refers to certain non-gaap financial measures such as Adjusted Cash Operating Costs, Adjusted General and Administrative Expenses, Adjusted EBITDAX and Average LOE Unit Cost, excluding Haynesville assets. Definitions of these measures and reconciliation between U.S GAAP and non-gaap financial measures are included in the First Quarter 2017 Financial and Operational Reporting Package at epenergy.com. 2
EP Energy Corporation Overview Large contiguous positions in three basins Wolfcamp ~178,000 NET ACRES 1 ~452,000 total net acres 1 5,156 drilling locations 1 Q1 17 Results >80% of inventory economic <$40/BBL Adj. EBITDAX: $172MM Eagle Ford ~93,000 NET ACRES 1 Altamont ~181,000 NET ACRES 1 Oil Production: 46.9 MBbls/d Total Production: 82.5 MBoe/d CAPEX: $152MM UT 1 As of 12/31/16 3
Investment Thesis Operational excellence Efficient business with low cost structure Ample financial flexibility to manage through volatility Quality assets not fully reflected in current equity value Eagle Ford & Altamont valued at maintenance capital levels Wolfcamp low cost option Multiple levers available to further improve balance sheet 4
High Quality Inventory 5,156 Total Drilling Locations¹ Break-even <$40 BBl Wolfcamp: 2,682 Eagle Ford: 650 Altamont: 918 Total 4,250 Break-even $40-$55 Bbl 2 Up from previous total of 4,098 Break-even >$55 Bbl 3 >80% of drilling inventory economic below $40/Bbl 1 As of 12/31/16 2 Locations include: 325 Altamont, 255 Wolfcamp and 244 Eagle Ford 3 Locations include 82 Altamont 5
Continued Oil Growth Oil Production (MBbls/d) 2017 activities 50.8 45.1 45.0 45.7 46.9 1H 17: Increased Eagle Ford, moderate Wolfcamp 32.4 27.3 24.0 22.2 23.9 2H 17: Increase Wolfcamp, moderate Eagle Ford Full Year 2017 7.0 6.8 9.3 11.4 11.1 Eagle Ford and Altamont at maintenance levels 11.4 11.0 11.7 12.1 11.9 1Q'16 2Q'16 3Q'16 4Q'16 1Q'17 Altamont Wolfcamp Eagle Ford Excess cash flow shifted to Wolfcamp growth 6
Execution Efficiency Altamont Eagle Ford Wolfcamp $6.2 $7.2 $5.8 $4.2 $4.0 FY'14 FY'15 FY'16 2017E $5.2 Gross Well Cost 1 ($MM) $5.3 $4.6 $4.9 FY'14 FY'15 FY'16 2017E $4.1 $4.1 $4.3 Longer laterals $16.35 Increased efficiencies Deeper wells Adjusted Cash Operating Costs ($/Boe) $2.78 $3.28 $4.20 $2.61 $3.19 $3.99 $6.10 $5.37 2017 Guidance Mid-point 1Q'17 LOE Transportation and commodity purchases Adjusted G&A Taxes, other than income taxes $15.16 FY'14 FY'15 FY'16 2017E Note: See the First Quarter 2017 Financial and Operational Reporting Package, available at epenergy.com, for the Company s non-gaap reconciliations and definitions. 1 Includes drilling, completing and well site facilities 7
Top Tier Operating Costs $10.00 $8.00 Average LOE unit costs (1Q'15-4Q'16) Excludes Haynesville assets ($/Boe) $6.00 $4.00 $2.00 $- Peer A Peer B EPE Peer C Peer D Peer E Peer F Peer G Peer H Peer I Note: Peers include EOG, AREX, MTDR, LPI, RSPP, FANG, PXD, CXO, and CRZO Source: Company reports 8
Current Financial Profile $2,000 Maturity Profile ($MM) As of 12/31/15 $4.9 billion Reduced total debt by ~$1billion since YE 2015 $1,500 $1,000 $2,000 Significantly extended maturities Retired or extended $2 billion of debt maturing before 2020 Multiple options to address 2020 maturity $500 $0 $2,000 $1,500 $497 $1,222 $350 Maturity Profile ($MM) As of 3/31/17 $3.9 billion $800 2017 2018 2019 2020 2021 2022 2023 2024 2025 ~$1.2 billion of liquidity at 3/31/17 $1,000 $500 $1,326 $1,000 $0 $551 $500 $21 $273 $250 2017 2018 2019 2020 2021 2022 2023 2024 2025 9
Increased Financial Flexibility Extended ~$940MM of 2019-2021 maturities to 2025 Refinanced higher interest secured and unsecured notes with 8% secured debt Successfully completed semi-annual borrowing base redetermination Reaffirmed RBL borrowing base of $1.44B Extended 1 st Lien debt to EBITDAX ratio covenant through 1Q 19, and lowered the ratio from 3.5x to 3.0x Increased liquidity to ~$1.2 billion at 3/31/17 10
Hedge Program Summary Hedge Summary 2017 2018 Oil volumes (MMBbls)¹ 7.7 8.9 Average floor price ($/Bbl) $ 60.52 $ 60.00 Natural Gas volumes (TBtu) 26.1 18.3 Average floor price ($/MMBtu) $ 3.28 $ 3.07 Added 2018 price support 2017: Oil: ~63%² estimated oil floored at $60.52 (retain additional upside) Natural Gas: ~76%² estimated natural gas floored at $3.28 2018: Oil: ~52%² estimated oil floored at $60.00 (retain additional upside) Natural Gas: ~44%² estimated natural gas floored at $3.07 Note: Hedge positions are as of May 2, 2017 (Contract months: April 2017 Forward). For further details on the Company s derivative program, see EP Energy Corporation s Form 10-Q for the quarter ended March 31, 2017 ¹ Includes 2017 WTI three way collars of 6.7 MMBbls and 2018 WTI three way collars of 8.9 MMBbls ² Percent hedged based on midpoint of 2017 guidance 11
Solid Execution Across Asset Portfolio Wolfcamp Step-change improvements in well production Significant inventory of future opportunities Eagle Ford Increased efficiencies in high return program Improved performance with enhanced completions Altamont Strong results from recompletion program Improved returns: drilling JV, improved realized oil pricing 12
Wolfcamp: Significant Upside Value Increased type curve EUR to 750 Mboe Up from 400 MBoe in 2014 Drilling JV enhances IRR to >80% at $55 WTI 18 month pay-back period Increased pace of development Potentially complete 1,500-2,000 Wolfcamp wells in next decade Broader development across acreage At least one landing zone per A, B and C bench Across Reagan and Crockett Counties $4 $8 per share of additional upside value 13
Wolfcamp: Significant Scale Since 2010: Total capital spent ~ $2.4 billion Total footage drilled: 898 miles Total proppant pumped: 3.25 Billion lbs Total fluid volume: 63.5 Million Bbls or 2.67 Billion gallons Total compression: 19,291 HP (82.6 MMScf/d capacity) Total fluid that can be processed (CPF) daily:~250,000 bbls Total miles of - pipe in the ground:~220 miles, roads ~128 miles, electrical ~50 miles 300 Reported Wells (2014-2017 YTD) *PXD 575 reported wells 250 200 150 100 50 0 SM RSPP Discovery Broad Oak CVX CPE OXY AREX FANG ECA COG PE XTO FDL Energy Permian Res. EGN EPE LPI APA PXD Note: Horizontal wells in the Wolfcamp formation as reported top the State of Texas 2014 March 29, 2017 14
Wolfcamp: Significant Performance Improvement 7.0 6.8 Oil Production (MBbls/d) 9.3 11.4 11.1 Averaged 2 JV rigs and 2 frac crews Results supported by: Latest generation wells beating 750 Mboe type curve Improved base production 1Q'16 2Q'16 3Q'16 4Q'16 1Q'17 Completions 5 5 13 21 11 Maintained production volumes despite: Half the number of completions (4Q 16 to 1Q 17) Initial JV wells on-line (50% WI) Lower NRI tied to sliding scale royalty agreement Well positioned for growth in 2H 17 Increasing completions each quarter throughout 2017 15
Investing in Wolfcamp Growth Capital program Manage Eagle Ford & Altamont and maintenance capital levels Wolfcamp Oil Production (MBbls/d) Invest free cash in Wolfcamp growth Wolfcamp Highest program returns Currently two JV rigs active 8.6 8.6 Expect to add 3 rd rig mid-year 2017 Largest drilling inventory with 2,900+ locations 2016 2017E 2018E 16
Wolfcamp: Recent Success 140,000 Improved well performance Increased returns Higher NPV per well Reduced capital and operating costs University Lands (UL) sliding scale royalty agreement Increased activities Production growth 150-well drilling joint venture Cumulative Oil Production, Bbl 120,000 100,000 80,000 60,000 40,000 20,000 0 1 45 89 133 177 221 265 309 353 397 441 485 529 573 617 661 705 749 Previous Days 600 MBOE TC TC 750 MBOE TC Current Wells (41 wells) Type Curves Gross EUR (MBoe) 750 550 Average lateral length (feet) 8,500 8,500 Gross well costs ($MM) $4.5 $4.4 Break-even pricing ($/Bbl) 1 $25.75 $38.00 Gross drilling locations 2 1,096 1,586 Assuming $55 (WTI)/$3.00 (HH) Pre-tax IRR 3 57% 22% Pre-Tax NPV ($MM) $4.9 $1.5 Assuming $65 (WTI)/$3.50 (HH) Pre-Tax IRR 3 72% 29% Pre-Tax NPV ($MM) $5.9 $2.2 1 Break-even oil price (WTI) required to generate a 10 percent pre-tax IRR and $3.00 Henry Hub (HH), before impact of joint venture 2 In addition the company s drilling inventory includes 255 drilling locations with 4,500 laterals 3 Before impact of joint venture 17
Wolfcamp: JV Increases Program Value Enhances program economics (single well IRRs from 57% to 80%) (1) EPE Improved Returns on Capital 90% Increases near term cash flow and production ($75MM total carry) Further illuminates acreage value of approximately $20,000 per acre Accelerates development in a balance sheet friendly manner Expands operations in Reagan and Crockett counties BTAX IRR 80% 70% 60% 50% 40% 30% 20% 10% $45.00 $50.00 $55.00 $60.00 NYMEX WTI Wolfcamp - Including Type Curve Update and DrillCo JV Wolfcamp - Type Curve Update Only Wolfcamp - Type Curve 600 Mboe Includes only ~5% of existing inventory in Wolfcamp EPE Wolfcamp Acreage ~50 miles 1 Assumes flat oil price of $55/Bbl (WTI). 18
Wolfcamp: Continuous Cost and Execution Improvement Gross Well Cost ($MM) Gross Well Cost Per Foot $/ft. 1 $6.2 $5.3 $4.6 $407 $357 $3.8 $296 $246 2014 2015 2016 Best 2016 Well Unit LOE $/BOE 2014 2015 2016 Best 2016 Well Drilling Days Spud to Rig Release $7.71 $6.31 11.0 $4.70 8.1 6.2 4.3 2014 2015 2016 2014 2015 2016 Best 2016 Well Efficient operations drive lower cost 1 Based on total measured well depth. 19
Wolfcamp: Favorable Cost Compared to Permian Peers 533 Capex per Lateral Foot for Type Well ($/lateral ft.) 640 667 673 733 840 976 Avg. $723 EPE Peer A Peer B Peer C Peer D Peer E Peer F Gross Capital to EUR for Type Well 1 ($/Boe) 6.47 6.67 5.94 6.06 5.33 5.05 7.41 Avg. $6.13 Peer B Peer A Peer C EPE Peer D Peer F Peer E Average 2016 LOE unit costs ($/Boe) 6.88 4.15 4.70 4.93 5.23 5.29 $5.35 Avg. $5.22 Peer E EPE Peer D Peer B Peer A Peer F Peer C 1 Gross capital to estimated ultimate resource (EUR) is based on a single well type curve. The measure is drilling and completion capital invested to develop a well divided by EURs associated with such well. The peer companies listed may calculate this measure differently based on their publicly available type curve information. Data as of 12/31/16 and peers include: CPE, EGN, FANG, LPI, PXD, RSPP Source: Company presentation and Wall Street research Note: Peers A, B, C and D type curves based on 7,500 Midland Lower Spraberry, Peer E type curve based on 7,500 Midland Upper Wolfcamp. Peer F type curve based on 8,200 Midland Wolfcamp B. EP Energy type curve based on Midland Wolfcamp 750 Mboe type curve. 20
Wolfcamp: Attributes in Southern Midland Basin North Midland County GR Resis STOOIP 55 Miles South Reagan County GR Resis STOOIP South 600 Gross 1,000 Gross N S Greater thickness and oil in place Larger number of landing zones 21
Refining Drilling Design Dean Top Wolfcamp Full Development 7 wells per bench 21 per section Potential for additional landing zones -- ~770 -- --- ~1,540 --- 3-D seismic covering entire acreage position Identifies highest potential pay-zones Assist with drilling geo-steering Minimizes offset flooding Provides development flexibility 22
Wolfcamp: Improved Results With Increased Subsurface Knowledge Define sub-surface using Earth Model Reservoir and petrophysical properties EPE Well EUR 1,237 MBOE Good completion example Mechanical properties 3D Seismic and 650 wells for control pts. High Low Direct Offset EUR 167 MBOE Poor completion example Identify optimal landing zone Highest oil in place Wellbore stability High Low Hazard avoidance Results in: Efficiently geosteer lateral Maintain +/- 10 window Faster drilling times Lower costs Enhanced well performance Optimize completion design Improved returns 23
Wolfcamp: Enhanced Completions Increase Production Rates 275 529 478 Oil Rate (BOPD) 446 382 380 221 315 332 300 298 272 242 188 166 150 Proppant Loading (Lb/lat-ft) 2095 1620 1281 IP30 IP60 IP90 IP120 IP 150 Stage Spacing (Ft) 246 216 193 Fluid Volumes (Bbl/ft) 38 29 26 Generation 1 Generation 2 Generation 3 Improved results with changes to proppant loading, fluid design and stage spacing 24
Wolfcamp: Improved Drilling Efficiencies Proven drilling performance 16 > 9,000 9,500 2017E capex per foot: $297 Best wells Spud to RR 4.1 days Most footage in 24 hrs. 7,483 Fastest drilling rate 284 ft./hr. Rig Days (Spud to Rig Release) 14 12 10 8 6 11.0 7,700 7,900 8.1 8,900 6.2 6.4 Average Lateral Length (Ft.) 9,000 8,500 8,000 7,500 7,000 How Real-time monitoring capability enables quick decisions at the wellsite 4 2014 2015 2016 2017E 6,500 Real-time geosteering means more lateral in target window Wellsite images enable deeper understanding of efficiency opportunities Performance measurement and tracking aids in understanding opportunities 25
Wolfcamp: Improved Frac Crew Efficiencies Improved efficiency Less time between stages 20.0 18.0 Frac Crew Performance 19.0 20.0 18.0 More stages per day More pumping hours per day 16.0 14.0 12.0 13.2 16.0 14.0 12.0 Key elements to improved efficiency Sand silos Hours 10.0 8.0 6.0 6.0 9.5 10.0 8.0 6.0 Stages/day Automatic fueling systems Frac pump reliability Real time monitoring 4.0 2.0 0.0 1.8 0.5 2.2 2.0 2016 2017 E Stage Pump Time Between Time 4.0 2.0 0.0 Pumping Hours/day STG/Day 26
Wolfcamp: Marketing Advantages Production operations southeast of Midland hub Attractive quality crude oil production with < 45 API gravity Major Permian Basin Oil Pipelines 90% of crude oil production on pipeline Colorado City Direct access to Gulf Coast pipelines Majority of Permian takeaway pipes originate in the Southern Midland Basin Only ~1 MM Bbls/d of capacity connecting Delaware Basin to Midland Basin EPE acreage EPE acreage benefits from net back pricing advantages 27
Eagle Ford: Capital Efficient Program 40 30 Oil (MBbls/d) 20 10 0 Efficient Capital Drives Oil Growth 32.4 27.3 24.0 22.2 23.9 $92 $75 $32 $43 $25 1Q'16 2Q'16 3Q'16 4Q'16 1Q'17 250 225 200 Capex ($MM) 175 150 125 100 75 50 25 - Averaged 1 rig and 2 frac crews Resumed production growth Significant increase in well completions Accelerated DUC development Current cost advantage Most completions since 2Q 15 Base production beating expectations Increased completion efficiencies Favorable results from longer laterals and increased proppant loading 28
Altamont: Consistent Results Oil Production (MBbls/d) Averaged 1 JV rig and picked up 2 nd rig in late Feb. along with 1 frac crew 11.4 11.0 11.7 12.1 11.9 3 new well completions 16 recompletions 1Q'16 2Q'16 3Q'16 4Q'16 1Q'17 Strong program returns Completions 2 2 7 4 3 On-going drilling JV Successful recompletion program Significantly improved realized prices 29
New Altamont Drilling JV EPE Impact Enhances program economics Capital carry increases capex allocation options Includes <5% of existing inventory in Altamont program Implied acreage value of ~$10,000 to ~$20,000 per acre Summary Terms 60 well program TSO earns 50% of EPE s working interest EPE operates all wells EPE s share of capital $64mm First wells online July 17 Altamont Acreage 30
2017 Outlook 2017 Oil production (MBbls/d) 45 49 Total production (MBoe/d) 75 82 Oil & gas capital ($MM) 1 Wolfcamp $245 325 Eagle Ford 260 270 Altamont 125 135 Total capital program ($MM) $630 $730 Oil production growth from 2H 16 Favorable cost performance below low end of guidance range Includes two Wolfcamp rigs FY 17 and a third rig mid-year Gross well completions Wolfcamp 2 90 105 Eagle Ford ~60 Altamont ~25 Total 175-190 Lease operating expense ($/Boe) $5.85 $6.35 Adjusted general and administration expenses ($/Boe) 3 $3.15 $3.40 Transportation and commodity purchases ($/Boe) $3.90 $4.50 Taxes, other than income ($/Boe) $2.70 $2.85 Multiple options available to fund Wolfcamp capital growth Expect to maintain Eagle Ford and Altamont production at 2H 16 levels Expect significant Wolfcamp oil volume growth DD&A ($/Boe) $16 $17 1 Includes 20 25 percent non-drill capital 2 Includes completions which are within the DrillCo joint venture with 40 percent of total well cost to EP Energy. 3 See the First Quarter 2017 Financial and Operational Reporting Package, available at epenergy.com, for the Company s non- GAAP reconciliations and definitions. 31
Updated Type Well Economics Drilling locations with <$40/Bbl break-even prices Wolfcamp Eagle Ford Altamont Average lateral length 8,500 8,500 5,700 N/A Well spacing (acres) 150 150 40 60 80-160 Distance between wells (feet) 770 770 330 500 IP 30 (Boe/d) 722 639 1,068 408 IP 30 (Bo/d) 534 475 772 335 Gross EUR (MBoe) 750 550 505 500 % Liquids 80% 72% 78% 75% Gross well costs ($MM) $4.5 $4.4 $4.0 $4.2 Break-even pricing ($/Bbl) 1 $25.75 $38.00 $34.75 $35.00 Average WI % 100% 97% 85% 70% Average NRI 2 75% 73% 63% 59% Gross drilling locations 1,096 1,586 650 918 Assuming $55 (WTI) / $3.00 (HH) Pre-Tax IRR 57% 22% 58% 30% Pre-tax NPV ($MM) 4.9 1.5 $2.3 $2.0 Assuming $65 (WTI) / $3.50 (HH) Pre-Tax IRR 72% 29% 99% 44% Pre-tax NPV ($MM) 5.9 2.2 $3.6 $3.1 1 Break-even oil price (WTI) required to generate a 10 percent pre-tax IRR using latest well costs and $3.00 per MMBtu (HH). 2 Wolfcamp NRI does not include royalty relief according to sliding scale agreement; whereas economics do include royalty relief. 32
RBC Capital Markets Global Energy & Power Conference June 7, 2017