Investor Update. June 2014

Transcription

1 Investor Update June 2014

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; 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; 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 oil and natural gas demand; the uncertainties associated with governmental regulation, including any potential changes in federal and state tax laws and regulation; political and currency risks associated with international operations of EP Energy; 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 EBITDAX and Adjusted Cash Operating Costs Per Unit. Definitions of these measures and reconciliation between U.S. GAAP and non-gaap financial measures are included in the Appendix and EP Energy s First Quarter 2014 Financial and Operational Reporting Package at epenergy.com. 2

3 EP Energy Today Oil-focused growth company with four core assets in leading U.S basins ~477,000 total net acres 1 ~5,644 risked drilling locations 1 1Q 14 Results 49.1 MBbls/d oil production 94.7 MBoe/d total production $357 MM Adjusted EBITDAX 13 rig average 66 completed wells EAGLE FORD SHALE Net Acres: 91,675 1Q 2014 Net Daily Production (MBoe/d): 46.5 Gross Drilling Locations: 946 TX ALTAMONT Net Acres: 173,110 1Q 2014 Net Daily Production (MBoe/d): 13.4 Gross Drilling Locations: 1,126 EP Energy Acreage 1 Pro forma for April 2014 acquisition. Notes: See Appendix and 1Q 14 Financial and Operational Reporting Package, available at epenergy.com for the company s non-gaap reconciliation and definitions. Acreage and gross drilling locations as 12/31/13. UT WOLFCAMP SHALE Net Acres: 175, Q 2014 Net Daily Production (MBoe/d): 11.9 Gross Drilling Locations: 3,375 1 EPE acreage TX Acquired acreage HAYNESVILLE SHALE Net Acres: 36,865 1Q 2014 Net Daily Production (MMcfe/d): Gross Drilling Locations: 197 3

4 Proven Management Team Name Position Industry Yrs. EP/EPE Yrs. Brent Smolik Chairman, President & CEO 29 7 Clay Carrell EVP & COO 25 6 Dane Whitehead EVP & CFO 29 7 Marguerite Woung-Chapman SVP, General Counsel Experience Energy Joan Gallagher SVP, HR & Admin. Services 20 8 Frank Falleri SVP, Central Greg Givens VP, Eagle Ford Richard Little VP, Southern Scott Anderson VP, Business Development 29 3 Kyle McCuen VP, Planning & Treasury Dennis Price VP, Marketing Frank Olmsted VP, Controller Delaney Bellinger VP, Info. Tech

5 Performance Highlights Execution Concentrated asset base with high degree of operating control Record well completions 66 wells in 1Q 14 Expect in FY 14 All programs performed above type curve Solid multi-year hedges Significant liquidity Growth Accelerating oil and equivalent production growth Expect YOY oil volumes up > 45% Expect YOY equivalent volumes up 19% year of drilling inventory now ~5,644 risked drilling locations Continued EBITDAX growth Higher unit margins Focused execution delivering high-return growth 1 Note: Year-over-year All amounts growth pro rate forma 2013 for continuing completed production and pending volumes asset compared sales. with 2014 continuing production volumes. 5

6 Significant Oil Production Growth MBbls/d Total Company Altamont 9.8 1Q Q Q Q Wolfcamp 7.2 Eagle Ford Q Q Q Q 2014 Note: Q continuing production volumes compared with Q continuing production volumes. Operational enhancements & higher activity drive growth 6

7 High-Quality, Concentrated Asset Portfolio Eagle Ford Wolfcamp Altamont Haynesville A Leading Operator in Each Basin 7

8 Eagle Ford: Franchise Program Continued growth and improvement in high-return assets Six rigs running Improved run time and reducing unit lifting cost Record quarterly production in 1Q 14 of 46.5 MBoe/d (31.6 MBbls/d of oil) Oil Production (MBbls/d) well completions ( 14E) 35 wells completed in 1Q Further upside Additional efficiencies gains Testing 40-acre spacing Testing shorter stage spacing and higher proppant volumes Significant high-quality oil volume growth 8

9 EUR (Gross MBoe) Eagle Ford: Continuous Improvement Improved performance Multi-year EUR progression Success drivers Refining lateral placement Improving stimulation design and execution Resin-coated sand, gel loading, frac stages and spacing, perf clusters, cycletime reduction Facility additions and optimizing production practices Expect additional efficiency gains EUR Progression (MBoe) Current Type Curve Current Type Curve 2013 Eagle Ford Central Gross Well Cost ($MM) NPV ($MM) $7.2 $6.9 $ $7.0 $7.3 $ $7.7 $8.0 $ $8.4 $8.7 $9.0 Note: NPV calculated pre-tax at 10 percent discount rate. Assumes $90.00 (WTI) and $4.50 (HH) price deck. 9

10 Wolfcamp: Rapidly Growing Oil Asset Quarterly Production Volumes Q'13 2Q'13 3Q'13 4Q'13 1Q'14 Liquids (MBbls/d) Reagan Crockett Gas (MBboe/d) Acquired acreage, April Thickest part of basin - Highest oil in place - Wolfcamp A, B and C all present Irion Significant production growth Fourth rig added in late March Record quarterly production in 1Q 14 of 11.9 Boe/d (7.2 MBbls/d of oil) well completions ( 14E) 20 wells completed in 1Q 14 Combined Wolfcamp B and C development Initiating Wolfcamp A program zone with highest oil in place Industry active in Cline and Spraberry formations around EPE Improving returns as program matures 10

11 Wolfcamp: Current Development Concept Expanding development across acreage position 2014 primarily combined B/C development Adding A wells 770' between wells in each zone Completing all wells on a pad prior to producing 11

12 Gross EUR (MBoe) Cumulative Production, MBOE Wolfcamp: Improving Results 23 Development plan focused on combined B/C development Well results above type curve Average initial 30-day production rates: Equiv: 549 Boe/d vs. 367 Boe/d type curve Oil: 351 Bbls/d vs. 240 Bbls/d type curve Wolfcamp Long Gross Well Cost ($MM) NPV ($MM) $5.8 $5.3 $ B/C Development Wells Cumulative Production (Mboe) Current Type Curve Well Average (up to 29) Individual Wells Current Type Curve EUR: 400 Mboe 400 $2.8 $3.2 $ $3.3 $3.8 $ $3.8 $4.3 $ Number of wells online for: 30 days days days 15 Note: NPV calculated pre-tax at 10% discount rate. Assumes $90.00 (WTI) and $4.50 (HH) price deck Days 29-well average includes EP Energy production data for wells utilizing current completion design of combined Wolfcamp B and C completions. Wells H, H, H, 40EP25-01H, 40EP 25-03H, 40EP25-04H, 40EP25-05H, 40EP25-06H, HH, IH, JH, PH, KH, LH, MH, JH, KH, NH, OH, RH, SH,44-12-VH, WH, HH, IH, JH, KH, LH, MH. 12 Page 12

13 Wolfcamp: Expanding Development 2013 Wells WCB 61 WCC 5 Total = Wells A Bench ~5 B Bench C Bench Total = Wells 2014 Wells 2014 Wolfcamp A bench wells Recently Acquired Acreage Region derisked by industry activity and tests 1,300+ horizontal wells in four county area 1 ~220 A and C Bench wells offsetting EPE acreage Expanding our development in 2014 while maintaining efficiencies ~3,375 drilling locations 2 1 Wells drilled below 5,000 in Crockett, Reagan, Irion, and Upton counties between January 2009 and March As of December 31, 2013 pro forma for 475 drilling locations from the April 2014 acquisition. 13 Page 13

14 Altamont: Consistent Growth Steady production growth from advantaged position in Uinta Basin Three rigs now running Record quarterly production in Q1 14 of 13.4 Boe/d (9.8 MBbls/d of oil) well completions ( 14E) 11 wells completed in 1Q 14 Improved execution with higher initial production rates Up-side opportunities from infill drilling Significant resource base provides consistent growth and future upside 14

15 Haynesville Premier Shale Gas Resource Haynesville: Premier Shale Gas Resource ~37,000 net acres in core of De Soto Parish in NE Louisiana Acreage 100% HBP No current drilling activity Peak Month Gas (Mcf/d) EPE acreage 10,000+ 7,500 to 9,999 5,000 to 7,499 0 to 4,999 Fairway 197 drilling locations 1 Able to quickly commence program with commodity price improvement Attractive economics with gas prices of $4.00 $4.50, yielding single-well IRRs of 33% 47% 2 Access to growing Gulf Coast markets Source: DI Desktop and EP Energy estimates 1 As of 12/31/ Type well economics for Holly area wells 15

16 Financial Execution Strong financial performance from core assets Higher oil volumes improve unit margins and returns Solid hedge positions in support cash flows Ample financial capacity Reaffirmed $2.5 billion borrowing base $2.3 billion of liquidity at 3/31/14 1 ~$450 million net debt reduction in 1Q 14 Well positioned for future growth 1 Based on available revolver capacity and cash on hand, pro forma for IPO proceeds. 16

17 Efficient Capital 6 well completions 7 well completions Altamont $49 Wolfcamp $ well Other $4 Other $3 completions Eagle Ford $ well completions 20 well completions Wolfcamp $132 Altamont $64 Eagle Ford $ well completions 1Q 13 Total: $ completions 1Q 14 Total: $ Completions 2014E Capital: $2.0 Billion Project level IRR > 45% 1 1 IRRs based on $90.00/Bbl (WTI) and $4.50/MMBtu (Henry Hub) price deck. Weighted average well level IRR weighted by 2014E capital. 17

18 Exciting 2014 Growth Outlook Continued production growth 1 $2 billion capital program Improve operational efficiency Programs well positioned for growth 45+ percent increase in oil volumes now 19 percent increase in total equivalent production now 2 $1.73 billion drilling and completion capital 87 percent drill-bit focused Directed entirely to Eagle Ford, Wolfcamp and Altamont 45%+ avg. well level IRR 3 Growing cash flows narrow capex funding gap Focused on execution and operational improvements Improving LOE per barrel in core oil programs Significant EBITDAX margin expansion Enhancing drilling inventory Eagle Ford down spacing Wolfcamp A program initiated Altamont infill wells Successful acquisition and divestiture enhanced portfolio 1 Pro forma for completed and pending divestitures. 2 Year-over-year growth rate 2013 continuing production volumes compared with 2014 continuing production volumes 3 18 IRR represents before tax rate of return per internal estimates. IRR based on $90.00/Bbl (WTI) and $4.50/MMBtu (Henry Hub) price deck. Weighted average well level IRR weighed by 2014E capital. 18

19 Investor Update June 2014

20 Non-GAAP Disclosures Disclosure of Non-GAAP Financial Measures The Securities and Exchange Commission 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 company uses the terms EBITDAX, Adjusted EBITDAX and adjusted cash operating costs per unit. EBITDAX is defined as income (loss) from continuing operations plus interest and debt expense, income taxes, depreciation, depletion and amortization and exploration expense. Adjusted EBITDAX is defined as EBITDAX, adjusted as applicable in the relevant period, for the net change in the fair value of derivatives (mark to market effects of financial derivatives, cash settlements and premiums paid or received related to these derivatives), impairment charges, equity earnings from our investment in Four Star (sold in September 2013), non-cash compensation expense, transition and restructuring costs, losses on extinguishment of debt, fees paid to our Sponsors, and costs associated with our initial public offering. The company believes that the presentation of EBITDAX and Adjusted EBITDAX is important to provide management and investors with (i) additional information to evaluate our ability to service debt, adjusting for items required or permitted in calculating covenant compliance under our debt agreements, (ii) an important supplemental indicator of the operational performance of our business, (iii) an additional criterion for evaluating our performance relative to our peers, (iv) additional information to measure our liquidity (before cash capital requirements and working capital needs) (v) and supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. EBITDAX and Adjusted EBITDAX have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our results as reported under U.S. GAAP or as an alternative to net income, income (loss) from continuing operations, operating income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. For example, our presentation of EBITDAX may not be comparable to similarly titled measures used by other companies in our industry. We monitor cash operating costs required to produce our oil and natural gas. Cash operating costs is a non-gaap measure calculated on a per Boe basis and includes total operating expenses less depreciation, depletion and amortization expense, transportation costs, exploration expense, natural gas purchases, impairment charges and other expenses. Adjusted cash operating costs is a non-gaap measure and is defined as cash operating costs less transition and restructuring costs, management, transaction and other fees paid to the Sponsors, non-cash compensation expense, and costs associated with our initial public offering. We believe cash operating costs and adjusted cash operating costs per unit are valuable measures of operating performance and efficiency; however, these measures may not be comparable to similarly titled measures used by other companies and are subject to several of the same limitations as analytical tools as noted in the paragraphs above. 20

21 Raising 2014 Production Growth Original 2/10/14 Year/Year Growth Rate Updated 5/7/14 Year/Year Growth Rate Oil production (MBbls/d) % % Total production (MBoe/d) % % 2 Capital program ($ billion) Drilling and completion $1.73 $1.73 Facilities, lease and seismic $0.20 $0.20 G&A, interest and other $0.07 $0.07 Total 3 $2.00 $2.00 Average drilling rigs Eagle Ford Wolfcamp Altamont Wells completed Eagle Ford Wolfcamp Altamont Total Per-unit adjusted cash cost (per Boe) $ $14.25 $ $14.25 Transportation cost (per Boe) $ $3.50 $ $3.50 DD&A rate (per Boe) $ $26.00 $ $ The equivalent volume estimate and growth rate includes the impact of the Q divestiture of non-core gas assets, which will be treated as discontinued operations beginning in Q As a result, full year 2014 annual average production of approximately 3.5 Mboe/d (85 percent gas) from these assets will be excluded from reported volumes and guidance, and full year 2013 reported volumes will be reduced by approximately 4.9 Mboe/d. The impact on reported oil production from discontinued operations is expected to be minimal. ² Growth rate compares mid-point of 2014 estimated production range with 2013 actual results from continuing operations Excludes $150 million capital for April 30, 2014 acquisition.

22 Gross EUR (Mboe) Gross EUR (Mboe) Gross EUR (Mboe) Gross EUR (Bcfe) Type Well Economics Eagle Ford Wolfcamp Altamont Haynesville Central North Long Short Vertical ¹ Horizontal Holly Non-Holly Lateral Length (ft) 5,600 5,600 7,500 4,500 N/A 3,960 4,500 4,500 Well Spacing ² (Distance between wells) 60 acres (500 ft) 60 acres (500 ft) 140 acres (770 ft) 90 acres (770 ft) 160 acres 160 acres 107 acres (880 ft) 107 acres (880 ft) Gross EUR (Mboe) % Liquids 77% 96% 75% 75% 73% 68% 0% 0% Gross Well Costs ($MM) $7.2 $6.7 $5.8 $4.5 $6.3 $7.1 $7.9 $7.9 Net F&D Costs ($/Boe) $14.59 $28.78 $19.19 $24.91 $18.90 $27.97 $10.02 $14.83 Average WI % 89% 93% 95% 99% 73% 71% 81% 76% Average NRI % 67% 70% 71% 74% 61% 58% 66% 58% NRI Pre-Tax NPV - 10% ($MM) $7.0 $2.7 $2.8 $1.3 $3.6 $1.4 $3.8 $1.0 Break-Even Oil Price ($/Bbl or $/MCF) ³ $37.50 $65.00 $56.30 $69.80 $52.85 $71.68 $2.95 $3.88 Pre-Tax IRR 58% 26% 30% 21% 36% 24% 47% 21% Gross Undrilled Locations (12/31/2013) ⁴ , Single-Well Sensitivities ⁵ Eagle Ford Central Wolfcamp Long Altamont Vertical Gross Well Cost ($MM) Gross Well Cost ($MM) Gross Well Cost ($MM) NPV $7.2 $6.9 $6.6 NPV $5.8 $5.3 $4.8 NPV $6.3 $5.7 $5.1 Haynesville Holly Gross Well Cost ($MM) NPV $7.9 $7.4 $ $7.0 $7.3 $ $2.8 $3.2 $ $3.6 $4.0 $ $3.8 $4.2 $ $7.7 $8.0 $ $3.3 $3.8 $ $4.0 $4.4 $ $4.5 $4.9 $ $8.4 $8.7 $ $3.8 $4.3 $ $4.5 $4.9 $ $5.2 $5.6 $6.0 Note: IRR and NPV metrics per internal EPE estimates and assume $90.00/$4.50 price deck. NPV calculated at 10% discount rate, before income tax, and stated in ($MM). 1 13,320 total vertical depth. ² Wolfcamp Long based 1.5 sections (960 acres) due to 7,500 laterals. 3 Break-even oil price is price required to generate a 10% pre-tax IRR. Break-even prices on Eagle Ford, Wolfcamp and Altamont assume $4.50/MMBtu (Henry Hub). 4 As of December 31, 2013 pro forma for 475 drilling locations from the April 2014 acquisition. 5 The gross EUR estimates are more speculative than estimates of proved reserves and are thus subject to substantially greater risk of being recovered by EP Energy. In addition, lower gross EUR estimates and /or higher gross well costs will result in lower NPV estimates than those presented. 22

23 Eagle Ford: High-quality Oil Production Average API Gravity No gravity adjustments for oil with gravity of 45 degrees or below Month Percent Monthly Sales Volumes by Product Oil Gas NGL 1 Based on monthly pipeline delivered sales Month 23

24 Recent Wolfcamp Acquisition: Successful Strategy in Action Immediate upgrade to asset portfolio Divesting non-core South Louisiana Wilcox and non-haynesville Arklatex tight-gas assets for $150 million Acquired ~37,000 acres in Southern Midland Basin immediately offsetting current acreage for $153 million (~$2,700 per undeveloped acre) Transactions build on EP Energy strategy Monetizes non-core assets at more than seven times estimated 2014 EBITDA Significant addition of high-quality Wolfcamp acreage at a compelling value Adds scale and operational efficiencies in a core area Pro forma core assets increased Pro forma core inventory +10% unproved resources (143 MMBoe) 20+ year drilling inventory +9% drilling inventory (475 locations) 5,644 risked locations +8% net acres (~37,000 acres) 1.5 billion Boe of resource 24

25 Successful Wolfcamp Offset Activity Sources: Texas RRC, HIS, and EP Energy Sources: Texas RRC, IHS, EP Energy 25

26 Solid Hedge Program Fixed Price Hedges 1 Oil volumes (MMBbls) Average floor price ($/Bbl) $ $ $ Percent hedged based on updated 2014 guidance ~100% +100% ~60% Natural Gas (TBtu) Average floor price ($/MMBtu) $ 4.02 $ 4.26 $ 4.20 Percent hedged based on updated 2014 guidance ~100% ~85% ~10% Eagle Ford Hedges 2 Oil volumes (MMBbls) Effective floor price ($/Bbl) $ $ $ Note: Positions are as of March 31, 2014 (Contract months: April 2014 Forward). 1 Oil fixed price hedges include WTI, Brent and LLS fixed price swaps and floors 2 Reflects combination of oil fixed prices and basis hedges that effectively floor Eagle Ford oil prices. Floor prices do not include customary refinery and contract deductions. 26