2015 Results and 2016 Outlook February 19, 2016

Transcription

1 Results and 2016 Outlook February 19, 2016

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 volatility of and current 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 EPS, Adjusted EBITDAX, Adjusted EBITDAX Margin Per Unit, Adjusted Cash Operating Costs, PV-10, and Discretionary Cash Flow Per Share. Definitions of these measures and reconciliation between U.S. GAAP and non-gaap financial measures are included in the Fourth Quarter Financial and Operational Reporting Package at epenergy.com. In this presentation, data for the quarter and year ended December 31, 2014, does not include information and activity related to assets that were sold in

3 Solid Execution Delivered on goals New well completions in-line with planned activity levels Reduced capital and cash costs beat expectations Grew production from 2014 oil up 10%, equivalents up 12% Improved asset quality lowered break-even prices Achieved operational break-throughs Wolfcamp step change improvement in well performance Haynesville improved completion designs Improved financial flexibility Maintained strong liquidity of $1.6 billion at year-end Extended RBL maturity and re-affirmed borrowing base Re-financed secured debt to unsecured and extended maturity Cash flow positive in 2H 15 3

4 Delivered On FY Expectations Original Guidance Updated Guidance Results Total production (MBoe/d) Oil production (MBbls/d) Capital program ($ billion) 1 $1.2 $1.3 $1.2 $1.25 $1.2 Average drilling rigs s completed Adjusted cash cost (per Boe) $10.50 $13.50 $10.25 $11.25 $9.89 Transportation cost (per Boe) $2.90 $3.35 $2.60 $2.90 $2.88 DD&A rate (per Boe) $25.00 $27.00 $24.50 $26.50 $ Excludes approximately $111 million of acquisition capital. 4

5 4Q Operations Summary Program 1Q Q1 3Q Q3 Average Completed s Completed s Equivalent Production (MBoe/d) Oil (MBbls/d) NGLs (MBbls/d) Natural Gas (MMcf/d) Eagle Ford Wolfcamp Eagle Ford $102 Wolfcamp $33 Altamont $31 ($MM) Altamont Haynesville/Other Total Company Haynesville/Other $15 4Q 15 Total Capital¹ $181MM 1Q 15 3Q 15 Avg: $344MM¹ Lower activity levels in 4Q ¹ Excludes acquisition capital 5

6 Rapidly Improving Cost Structure Gross Cost 1 ($MM) Total Company LOE ($/Boe) Eagle Ford $7.2 $5.8 $4.9 FY'14 FY'15 Best $5.39 $4.53 Altamont Wolfcamp $6.2 $5.2 $5.3 $4.1 Note: Best well results reflect wells that are representative of type wells. 1 Includes drilling, completing and well site facilities. $4.6 FY'14 FY'15 Best $3.4 FY'14 FY'15 Best 4Q' Q'14 4Q'15 Total Company Production (MBoe/d) Q'15 6

7 Reserves and Inventory Proved oil and gas reserves 546 MMBoe in proved reserves 12% decrease from 14 ~6% increase prior to impacts from price and the 5-year development plan rule revisions ~69 MMBoe of reserve additions primarily in three oil programs Acquisition adds of ~11 MMBoe $2.0 billion PV-10 at 12/31/15 1 Excludes ~$800 million of hedge value $18.32/Boe reserve replacement cost 1,2 164% reserve replacement ratio 1,2 Drilling inventory Maintained future inventory of ~5,700 drilling locations Total consistent with 2014 Eagle Ford acquisition added locations 30 years drilling inventory at activity levels High-quality assets with low break-even costs 1 Based on the average first day of the month spot price for the preceding 12-month period of $50.28 per Bbl (WTI) and $2.59 per MMBtu (Henry Hub). 2 Excluding acquisitions, the effect of price revisions, and the impact of the SEC s five-year development rule after our reductions in estimated capital in our long-range development plan based on the lower price environment. 7

8 Type Economics Eagle Ford Wolfcamp 60% 50% Cost: ~ $4.7MM Lateral Length: 5,700 ft Break-even Price: ~$39 per Bbl 50% 40% Cost: ~ $4.2MM Lateral Length: 7,500 ft Break-even Price: ~$39 per Bbl BTAX IRR BTAX IRR 40% 30% 20% 10% 0% 50% 40% 30% 20% $40.00 $50.00 $60.00 NYMEX WTI Altamont Cost: ~ $4.2MM Vertical Depth: ~13,000 ft Break-even Price: ~$37 per Bbl BTAX IRR BTAX IRR 30% 20% 10% 0% 120% 100% 80% 60% 40% $40.00 $50.00 $60.00 NYMEX WTI Haynesville Cost: ~ $10.2MM Lateral Length: 7,500 ft Break-even Price: ~1.60 per Mcf 10% 20% 0% $40.00 $50.00 $60.00 NYMEX WTI 0% $2.50 $3.00 $3.50 NYMEX HH Note: Break-even oil price (WTI) required to generate a 10 percent pre-tax IRR using estimated 2016 well costs and latest Eagle Ford, Wolfcamp, and Altamont type curves, and $2.50 per MMBtu (Henry Hub) for 2016 to 2020 planning period. 8

9 Financial Results 9

10 Financial Highlights 4Q 15 results $425MM Adjusted EBITDAX up 5% from 4Q 14 $0.22 Adjusted EPS and $1.42 Discretionary Cash Flow Per Share $8.87 Adjusted unit cash operating costs down 26% from 4Q 14 Maintained strong unit cash margins of ~$41 per barrel Non-cash impairment charge due to lower commodity prices Financial discipline Free cash flow positive in 4Q 4Q 15 net debt down ~$60MM from 3Q 15 Maintaining strong liquidity $1.6 billion liquidity at 12/31/ No near-term debt maturities Opportunities for asset divestitures and additional drilling carries Improving balance sheet a top priority in 2016 Note: See the Fourth Quarter Financial and Operational Reporting Package, available at epenergy.com for the Company s non-gaap reconciliations and definitions. 10

11 Continued Lower Cash Costs $/Boe Margin / Cost 4Q Q Variance Adjusted Cash Operating Costs Per Unit Unit revenue $58.17 $ % unfavorable LOE ($5.39) ($4.53) 16% favorable Adjusted net G&A ($3.43) ($2.80) 18% favorable Production taxes ($2.71) ($1.39) 49% favorable Rig Termination Fees ($0.34) ($0.04) 88% favorable Other taxes ($0.13) ($0.11) 15% favorable Adj. cash operating costs per unit sub-total ($12.00) ($8.87) 26% favorable Transportation ($3.06) ($3.19) 4% unfavorable Adj. EBITDAX margin per unit $43.11 $ % unfavorable $12.00 $0.34 $11.44 $0.20 $10.74 $3.43 $8.72 $8.87 $3.71 $3.73 $0.04 $2.71 $2.13 $2.58 $2.80 $2.05 $1.81 $1.39 $5.39 $5.12 $4.72 $4.25 $4.53 $0.13 $0.28 $0.24 $0.08 $0.11 Total adjusted cash operating costs $114MM $91MM 20% favorable 4Q'14 1Q'15 2Q'15 3Q'15 4Q'15 Other Taxes LOE Production Taxes Adjusted Net G&A Rig Termination & Other Efficient business with favorable cost trends Note: See the Fourth Quarter Financial and Operational Reporting Package, available at epenergy.com for the Company s non-gaap reconciliations and definitions. 11

12 Oil Fixed Price Hedges Hedge Program Provides Cash Flow Stability Fixed Price Swap Oil volumes (MMBbls) Average floor price ($/Bbl) $ $ Natural Gas Fixed Price Hedges Natural Gas volumes (TBtu) Average floor price ($/MMBtu) $ $942MM from settlements realized on financial derivatives in MTM of hedge book ~$800MM at 12/31/ oil positions 100% swaps High-quality, diversified counterparties 2016 oil production effectively hedged at ~$80/Bbl Note: Hedge positions are as of December 31, (Contract months: January 2016 Forward) ¹ The table includes 2017 WTI three way collars of 1.1 MMBbls. For further details on the Company s derivative program, see EP Energy Corporation s Form 10-K for the year ended December 31,. 12

13 2016 Outlook 2016 Oil production (MBbls/d) Total production (MBoe/d) Capital program ($MM) $500 $900 completions Adjusted cash cost (per Boe) $9.50 $10.50 Transportation cost (per Boe) $3.40 $3.65 Remain cash flow positive Disciplined capital allocation Capital and completion activity back-end loaded 1H 16-1/3 2H 16-2/3 Significant flexibility in timing and allocation of capital 13

14 Program Update 14

15 Eagle Ford: Efficient Oil Program Oil Production (MBbls/d) Q Highlights 14 wells completed (3 wells in late December) 3 rigs and 1 stimulation crew 4Q production impacts Significantly less completions Increased frac interference 4Q'13 1Q'14 2Q'14 3Q'14 4Q'14 1Q'15 2Q'15 3Q'15 4Q'15 Successfully integrated acquisition 2016 Outlook IP 30 (BOPD) Reduce to 1 rig in 1H 16 Focus on highest quality acreage and lease commitments Maintain operational efficiencies Continue to stagger landing zones on adjacent wells Continue to focus on base optimization and cost reductions (capital and LOE) 15

16 Wolfcamp: Break-through Results While Driving Down Costs 5.5 4Q' Q' Q'14 Oil Production (MBbls/d) Q'14 4Q'14 1Q' Q' Q' Q'15 4Q Highlights Improved well returns in Higher production rates Reduced well costs Reduced LOE costs Completed one well late in 4Q Improved well performance Optimized landing zones Enhanced completion designs 2016 Outlook Wolfcamp B&C IP 30 (BOPD) No rig currently running released rig in January Positioning for increased activity in 2H 16 Expanding knowledge with broader development Increase Reagan County activity Additional A bench tests Testing longer laterals Continue to focus on base optimization and cost reductions (capital and LOE) 16

17 Altamont: Steady Oil Performance Oil Production Q Highlights (MBbls/d) Consistent high-end well performance Completed 2 wells Reduced LOE costs Increased recompletion activity Improved price differentials 4Q'13 1Q'14 2Q'14 3Q'14 4Q'14 1Q'15 2Q'15 3Q'15 4Q' Outlook New drilling partnership with capital carry Altamont IP 30 (BOPD) 1 rig program Attractive returns at current prices On-going recompletion program Improve realized pricing relative to WTI Continue to focus on base optimization and cost reductions (capital and LOE)

18 Haynesville: Program Enhancements Gas Production (MMcf/d) Outstanding results from first two 7,500 laterals 4Q Highlights Average IP 90 of ~20 MMcf/d Existing wells benefitted from offset wells fracture stimulation Completed 4 wells and 4 refracs in 4Q'13 1Q'14 2Q'14 3Q'14 4Q'14 1Q'15 2Q'15 3Q'15 4Q'15 Grew production volumes to a level not seen since 1Q Outlook No new drilling activity planned at current commodity prices All acreage HBP Continue to focus on base optimization and cost reductions (capital and LOE) 18

19 Managing Through Volatility Solid Execution Solid financial and operational results Continued to improve asset programs Reduced costs Improved financial flexibility 2016 Outlook Maintain financial discipline Focus on asset improvements and efficiencies Improve balance sheet Positioned for success in volatile markets 19

20 Results and 2016 Outlook February 19, 2016

21 Appendix 21

22 Top Tier Capital Cost and Efficiency Gross Cost 1 ($MM) Total Cost per Foot 1 ($/ft.) Rig Days (Spud to Rig Release) Stimulation (Stages per day) Eagle Ford $8.3 $7.4 $7.2 $5.8 $4.9 $569 $498 $489 $379 $ Altamont Wolfcamp $7.7 $5.9 $5.6 $6.2 $5.4 $5.2 $5.3 $4.1 $4.6 $3.4 $534 $472 $374 $407 $441 $425 $357 $344 $310 $ Note: Best well results reflect wells that are representative of type wells. 1 Includes drilling, completing and well site facilities. 22

23 Completed s By Quarter Program 1Q 2Q 3Q 4Q FY Eagle Ford Wolfcamp Altamont Haynesville Total company