Investor Update. June 2015

Transcription

1 Investor Update June 2015

2 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 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 risk of EP Energy s lenders, trading counterparties, customers, vendors and suppliers; 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; 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 forwardlooking 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 EBITDAX, Adjusted EBITDAX, Adjusted EBITDAX Margin Per Unit, Adjusted Cash Operating Costs. Definition of these measures and reconciliation between U.S. GAAP and non-gaap financial measures are included in the First Quarter 2015 Financial and Operational Reporting Package available at 2

3 EP Energy EAGLE FORD SHALE Net Acres: ~ 82,000 1Q 15 Net Daily Production (MBoe/d): 54.7 Gross Drilling Locations: 872 ALTAMONT Net Acres: ~177,000 1Q 15 Net Daily Production (MBoe/d): 17.1 Gross Drilling Locations: 1,304 WASATCH DIMMIT WEBB SUMMIT DUCHESNE LA SALLE DAGGETT Note: Acreage and gross drilling locations as of 12/31/14. UINTAH EP Energy Acreage Net Acres: ~ 180,000 1Q 15 Net Daily Production (MBoe/d): 17.9 Gross Drilling Locations: 3,300 UPTON HAYNESVILLE SHALE Net Acres: ~38,000 1Q 15 Net Daily Production (MMcf/d): 76 Gross Drilling Locations: 197 PANOLA SHELBY CADDO WOLFCAMP SHALE CROCKETT REAGAN DE SOTO IRION BOSSIER RED RIVER Oil-focused growth company with four core asset areas Leading operations Low cost Top-tier well results Increasing efficiency Strategic positions in resourcerich basins ~477,000 net acres ~5,700 risked drilling locations, 30+ years Delivering results Improved production rates and costs Growing oil production Leading hedge position 3

4 Investment Thesis Large Portfolio of High Quality E&P Assets Efficient Operations Strategic position in leading U.S. resource plays with growing reserve base High return assets with breakeven costs below $45/bbl across portfolio Significant drilling inventory of low-cost plays; +30 years at 2015 drilling levels Large contiguous acreage positions in top oil and gas resource plays Repeatable drilling and completions activities High margin, low cost operator with liquids comprising 67% of YE 2014 reserves Continuous Improvement Strong Financial Position Successfully transitioned to high growth, 100% onshore, low-risk operations Completion optimization leading to higher IP rates while lowering cycle times Lower well costs (avg. well cost down 17% 12 to 14) Disciplined 2015 capital program to balance cash flow and capital spending Significant liquidity supported by growing reserve base 96%/82% of oil prod. hedged in 15/ 16 at avg. floor prices of $91.16/$ Significant Upside Potential 1 Hedging percentages based on the midpoint of 2015 production guidance. Well positioned to further improve returns Upside potential through efficient operations cost structure, well performance Significant untapped resource potential in Wolfcamp Compelling relative multiples compared with peer group 4

5 Continuous Improvement Gross Well Cost 1 ($MM) Total Well Cost per Foot 1 ($/ft.) Rig Days (Spud to Rig Release) Stimulation (Stages per day) Eagle Ford $8.3 $7.4 $7.2 $6.1 $569 $498 $489 $ Best Recent Well Best Recent Well Best Recent Well Best Recent Well 11.4 Altamont Wolfcamp $7.7 $5.9 $5.6 $6.2 $5.4 $5.2 $ Best Recent Well $3.8 $534 $472 $374 $407 $441 $425 $ Best Recent Well $ Best Recent Well Best Recent Well Best Recent Well Note: Best recent well performance reflect 1Q 15 actual results. 1 Includes drilling, completing and well site facilities Best Recent Well Best Recent Well Best Recent Well 5

6 Managing Efficient Operations Average LOE (1Q 13 1Q 15) $/Boe $7.44 $7.64 $7.89 $8.01 $8.19 $5.19 $5.57 $5.61 $5.98 $6.29 $3.79 Peer A EPE Peer B Peer C Peer D Peer E Peer F Peer G Peer H Peer I Peer J Note: Based on quarterly weighted average lease operating expenses for the period 1Q 13 through 1Q 15 as reported by peer companies; AREX, APC, CRZO, CLR, CXO, EOG, FANG, LPI, PXD and RSPP. 6

7 Delivering Strong Cash Margins $50 Cash Margin per BOE (2015E at assumed $65/Bbl WTI) $45 $40 $35 $/Boe $30 $25 $20 $15 $10 $5 $0 EPE CLR WLL RSPP CXO OAS APC EOG NBL PXD APA TLM EGN NFX EQT SM DVN XEC ECA WPX ECR CHK GPOR RRC SWN AR MHR COG Note: Base case volume expectations are hedged Source: Deutsche Bank 7

8 Increased Reserves and Inventory Proved Oil & Gas Reserves (MMBoe)¹ ² Proved Oil and Gas Reserves 18 percent increase from MMBoe in additions 66 percent in Eagle Ford $16.93 per Boe reserve replacement cost³ 343 percent reserve replacement ratio³ Future Drilling Locations 5,673 5, Core Program Drilling Inventory Added 500+ drilling locations from 2013 Eagle Ford 40-acre spacing Wolfcamp acquisition Altamont 80-acre spacing 30 year drilling inventory at 2015 activity levels 1 Based on the first day 12-month average prices of $96.94 per Bbl and $3.67 per MMBtu in 2013 and $94.99 per Bbl and $4.34 per MMBtu in Excludes 21 MMBoe from South Louisiana Wilcox and Greater Holly assets sold in May Includes price revisions and excludes acquisitions. 8

9 Asset Growth Potential YE 2013 YE % Oil Production 36.2 MBoe/d 54.8 MBoe/d 20% Total Production 81.2 MBoe/d 97.7 MBoe/d 18% Proved Reserves 526 MMBoe MMBoe 10% Drilling Locations 5,169 5,673 36% Adj. EBITDAX $1,139 million $1,547 million Adj. EBITDAX Margin Per Unit 13% $38.47 /MBoe $43.37 /MBoe 8% Net Acreage ~440 thousand ~477 thousand 1 Excludes 21 MMBoe from South Louisiana Wilcox and Greater Holly assets sold in May

10 Core Asset Overview Eagle Ford Wolfcamp Altamont Haynesville High-quality, highly concentrated asset portfolio 10

11 2015 Capital Program Financial discipline balance cash flows and capital Oil & Gas Capital Driving down capex per well in 2015 Wolfcamp 15% Altamont 11% Average 6 to 7 drilling rigs 160 to 190 well completions Eagle Ford 66% Haynesville 8% 10 percent oil volume growth 2015E: $ billion 11

12 Eagle Ford: Franchise Oil Program DIMMIT LA SALLE 1Q Highlights Highest-return program with significant growth Five rigs and four stimulation crews 38 wells completed Improved performance ¹ Break-even oil price (WTI) required to generate a 10% pre-tax IRR using most current well costs and current type curve and $3.50 per MMBtu (HH). Increased target landing zone accuracy Drilling cycle time improvements 40-acre development improving cost efficiencies increasing reserve recoveries per section Completion optimization resulting in higher IP rates Break-even oil price¹ of $40 per Bbl 2015 Outlook Similar number of completion activities as 2014 in cornerstone asset Leveraging recent drilling and completion success along with lower costs 12

13 Eagle Ford: Completion Optimization Results 1000 IP 30 (BOPD) % Oil Production, BOPD Cumulative Production, MBO FY (89 wells at current design) Current Type Curve 1Q' Producing Days Most Recent 39 Wells Current Type Curve Enhanced completions drive continued improvements Note: As of April 30,

14 Wolfcamp: Rapidly Improving Program UPTON CROCKETT REAGAN IRION Largest company resource base rapidly improving Two rigs and one stimulation crews 10 wells completed Technical advancements improved recent results Increased sub-surface knowledge Improved performance 1Q Highlights Increased target landing zone accuracy Identified multiple landing zones per bench Reduced cycle time ¹ Break-even oil price (WTI) required to generate a 10% pre-tax IRR using most current well costs and current type curve incorporating the improved early time performance while holding EUR s flat and $3.50 per MMBtu (HH). Continued completion optimization Break-even oil price¹ of ~$44 per Bbl 2015 Outlook New completion design improving production performance High grading drilling program most knowledge Driving down capital and operating costs 14

15 Wolfcamp: Drilling Optimization Increased subsurface knowledge ~1000 square miles of 3-D seismic identifies highest potential pay-zones Assist with drilling geo-steering Improved lateral landing zone identification Land in highest organic content Minimize limestone impact EPE Acreage 3-D Seismic Data WOLFCAMP A Landing zones A 0 A 1 A 2 B 0 WOLFCAMP B B 1 WOLFCAMP C C 1 C 2 C 3 C 4 15

16 Wolfcamp: Positive Rate of Change 600 Wolfcamp B&C IP 30 Results (BOPD) Oil Production, BOPD Type Curve IP 30 (369 BOPD) Cumulative Production, MBO % Wells Crockett Co. (4Q'14) Crockett Co. (1Q'15) Producing Days Most Recent 18 Wells Current Type Curve Note: As of April 30,

17 Wolfcamp: Optimizing Development Pattern Currently developing with mini-chevron pattern Wells spaced 770 apart in A, B, C benches with 1,540 between wells in same landing zones Minimizes offset frac interference Alters rock stresses which improves frac complexity Improves reserve recovery Enhances opportunity for future downspacing Dean Top Wolfcamp Full Development 7 wells per bench 21 wells per section --~ ~ ~1,

18 Altamont: Steady Growth With Solid Returns 11.0 Total Equivalent Volumes (MBoe/d) Q Highlights Continued improvement in legacy asset Two rigs and one stimulation crew 9 wells completed Approved for 80-acre well spacing Improved terms on oil sales contracts Break-even oil price 1 of ~$39 per Bbl 1Q'13 2Q'13 3Q'13 4Q'13 1Q'14 2Q'14 3Q'14 4Q'14 1Q' Outlook High grading drilling program Focus on highest-return wells in shallower, southwest area Leveraging success and learnings from 2014 all-time best wells Reducing activities compared with 2014 Continuing capital and operating cost reduction Narrowing basis differentials ¹ Break-even oil price (WTI) required to generate a 10% pre-tax IRR using most current well costs and current type curve and $3.50 per MMBtu (HH). 18

19 Haynesville: Resume Drilling in High Return Program Peak Month Gas (Mcf/d) EPE acreage 10,000+ 7,500 to 9,999 5,000 to 7,499 0 to 4,999 Highlights Premier acreage in core of the play Strategic location near Gulf Coast and growing Southeastern markets Top-tier drilling and production performance when last active Break-even gas price 1 of $2.35 per Mcf 2015 Outlook Restarting program at measured pace 1H 2015 Completion enhancements driving higher EURs and higher returns Multi-pad drilling with longer laterals Piloting re-frac program ¹ Break-even gas price (Henry Hub) required to generate a 10% pre-tax IRR using most current well costs and current type curve and $65.00/Bbl (WTI). 19

20 Type Well Economics 5 Year Inventory ( ) Long Short Vertical Holly Non Holly Pre-Tax IRR 1 52% 25% 37% 46% Breakeven Pricing ($/BBl or $/Mcf) 2 : At 20% Deflation $40.00 $47.00* $38.98 $2.35 At 30% Deflation $36.00 $42.50 $34.84 $2.14 At 40% Deflation $32.00 $38.00 $30.70 $1.93 * Recent improvements in Wolfcamp well performance have lowered the breakeven price to ~$44.00/BBl incorporating the improved early time performance while holding EUR s flat Full Inventory ( ) Eagle Ford Wolfcamp Altamont Haynesville Lateral Length (feet) 5,300 7,500 4,500 NA 4,500 4,500 Well Spacing(acres) Distance between wells (feet) IP 30 (Boe/d) ,667 1,333 Gross EUR (MBoe) , % Liquids 77% 77% 77% 75% - - Gross Well Costs ($MM) $5.8 $4.9 $3.8 $5.4 $7.3 $7.3 Net F&D Costs ($/Boe) $13.49 $14.27 $16.49 $15.27 $7.56 $11.86 Average WI % 89% 97% 97% 75% 77% 88% Average NRI % 67% 73% 73% 62% 62% 69% Pre-Tax IRR 1 50% 21% 15% 28% 46% 11% Gross Undrilled Locations (12/31/14) 872 2, , ¹ Assumes $65 per Bbl (WTI) oil and $3.50 per MMBtu (HH) 2 Break-even oil price (WTI) required to generate a 10% pre-tax IRR using 5 year ( ) inventory type well economics. 20

21 Solid Hedge Program Provides Multi-Year Price Protection Oil Fixed Price Hedges Fixed Price Swap Oil volumes (MMBbls) Average floor price ($/Bbl) $ $ $ Percent hedged based on midpoint of 2015 guidance 96% 82% 18% Natural Gas Fixed Price Hedges Natural Gas volumes (TBtu) Average floor price ($/MMBtu) $ 4.26 $ Percent hedged based on midpoint of 2015 guidance 95% 11% - Sector-leading hedge program Note: Hedge positions are as of April 24, 2015 (Contract months: April 2015 Forward) ¹ The table includes 2015 Brent three way collars of 0.8 MMBbls. For further details on the Company s derivative program, see EP Energy Corporation s Form 10-Q for the quarter ended March 31,

22 Successful First Step in Liability Management Program Replaced $750MM secured notes with lower cost unsecured notes Secured debt to EBITDAX (LTM) reduced from 1.5x to 1.0x Improved credit rating on unsecured debt Extended maturities of RBL and new Notes $1.7 billion of liquidity¹ $3,000 $2,500 Note Pro forma 3/31/15 ($ in millions) Interest Rate Principal (6/30/09) $ 9 $ 259 $ 688 Maturity $2.75B RBL $975 Libor + May 2019 Rating Moody s / S&P $750M Term Loan $496 Libor + May 2018 Ba2 / B+ $400M Term Loan $150 Libor + April 2019 Ba2 / B+ $2B Unsecured Notes Maturity Profile ($MM) $350M Unsecured Notes $800M Unsecured Notes $2, % May 2020 B1 / B $ % Sept B1 / B $ % June 2023 B1 / B $2,000 $1,775 $1,500 $1,000 $500 $0 $2,000 $496 $1,125 $350 $ Note: All notes and loans are at EP Energy LLC, a subsidiary of EP Energy Corporation, and as of May 28, 2015, the $750M Senior Secured Notes due 2019 were redeemed via tender offer and maturity call notice. 1 As of March 31,

23 Updated 2015 Outlook Original Guidance Updated Guidance Year/Year Change From 2014 Oil production (MBbls/d) Up 10% 1 Total production (MBoe/d) Up 4% 1 Capital program ($ billion) $1.2 $1.3 $1.2 $1.25 Down >40% Average drilling rigs Eagle Ford 3 4 Wolfcamp 1 Altamont 1 Haynesville 1 Wells completed Eagle Ford Wolfcamp Altamont Haynesville 5 10 Total Per-unit adjusted cash cost (per Boe) $10.50 $13.50 $10.50 $12.00 Down 15% Transportation cost (per Boe) $2.90 $3.35 $2.95 $3.15 DD&A rate (per Boe) $25.00 $ Growth rate compares mid-point of 2015 estimated production range with 2014 actual results from continuing operations. 23

24 Maintain focus on cost and capital discipline Improved 2015 outlook Advantaged low-cost operator Additional improvements in well performance Ongoing completion enhancements Increased target landing zone accuracy Improve financial position On track to be cash flow neutral for full year Well positioned for the future Looking Ahead 24

25 Investor Update June 2015