2016 Results and 2017 Outlook

Transcription

1 2016 Results and 2017 Outlook March 2, 2017

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 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 Cash Operating Costs, Adjusted General and Administrative Expenses and Adjusted EBITDAX. Definitions of these measures and reconciliation between U.S GAAP and non-gaap financial measures are included in the Fourth Quarter 2016 Financial and Operational Reporting Package at epenergy.com. In addition, this presentation refers to the non-gaap measure PV-10. Presentation of and reconciliation to the most comparable GAAP financial measure to PV- 10 is included in the Appendix to this presentation. 2

3 Solid Execution Operational Success Generated 4Q 16 sequential production growth Improved well returns and asset value in all programs Lowered cash operating costs Returned Wolfcamp to growth $255MM of Adjusted EBITDAX in 4Q 16 Financial Results Adjusted cash operating costs down 7% from 4Q 15 1 $0.12 Adjusted EPS in 4Q 16 $1.1 billion of liquidity at YE 16 Recent Achievements Increased financial flexibility - Nov 16 & Feb 17 refinancings Increased Wolfcamp type curve EUR Wolfcamp drilling JV and expanded development Note: See the Fourth Quarter 2016 Financial and Operational Reporting Package, available at epenergy.com, for the Company s non-gaap reconciliations and definitions. ¹ Excludes the impact of the sale of the Haynesville Shale asset which closed on May 3,

4 Delivered on 2016 Expectations 2016 Guidance 2016 Results Total production (MBoe/d) Oil production (MBbls/d) Capital program ($MM) ~$495 $488 Wells completed ~95 98 Adjusted cash operating costs ($/Boe) $13.80 $14.10 $

5 Improved Financial Profile $2,000 Maturity Profile ($MM) As of 12/31/15 $4.9 billion Reduced total debt by ~$1billion since YE 15 $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 2/6/17 1 $3.9 billion $ ~$1.1 billion of liquidity at YE 16 $1,000 $500 $1,326 $1,000 $0 $551 $500 $21 $278 $ Pro forma as of 12/31/16 to include February 2017 notes offering. 5

6 Reserves and Inventory Proved oil and gas reserves Drilling inventory 432 MMBoe in proved reserves ~5,200 drilling locations Down ~20% from 2015, driven by Haynesville sale, impact of the SEC s five-year development rule and lower prices >2,900 in Wolfcamp >80% premier locations 3 Up 7% from 2015, adjusted for impacts from Haynesville sale, impact of the SEC s five-year development rule and lower prices 1 ~30 years drilling inventory at 2017 activity levels ~64 MMBoe of reserve additions $3.4 billion 2 of PV 10 at current strip Deep high-quality asset inventory 1 The adjustments include 34MMBoe for the sale of Haynesville, 98MMBoe for the 5-year SEC development rule, and 18MMBoe for prices. 2 Based on proved reserve amounts as of December 31, 2016 run at NYMEX strip prices as of February 17, PV-10 also includes adjustments to align with the collateral valuation methodologies used for the RBL Facility borrowing base including PUDs that were previously booked and lost due to the 5-year SEC rule, expected benefit from the Wolfcamp JV, current capital and operating costs and the value of future hedge settlements. 3 Based on locations with break-even prices below $40 per barrel (WTI) 6

7 4Q 16 Operations Summary Program Completed Wells Equivalent Production (MBoe/d) Oil (MBbls/d) NGLs (MBbls/d) Natural Gas (MMcf/d) Eagle Ford Wolfcamp $72 ($MM) Wolfcamp Eagle Ford $25 Altamont $19 Altamont Total Company Q 16 Total Capital $116MM 4Q 16 sequential production growth for all products 7

8 Efficient Cost Structure Gross Well Cost 1 ($MM) Altamont Eagle Ford Wolfcamp $6.2 $7.2 $5.8 $4.2 $3.7 FY'14 FY'15 FY'16 Best 2H'16 Well $5.2 $5.3 $4.6 $4.1 $4.1 $3.8 FY'14 FY'15 FY'16 Best 2H'16 Well $3.3 Adjusted Cash Operating Costs, Excluding Haynesville 2 ($MM) $119 $14 $45 $42 $28 $33 $32 $29 4Q'15 $111 $7 4Q'16 Transport & Commodity Purchases Adj. Net G&A LOE Taxes Other Than Income FY'14 FY'15 FY'16 Best 2H'16 Well Note: Best 2016 well results reflect wells that are representative of type wells 1 Includes drilling, completing and well site facilities ² Excludes the impact of the sale of the Haynesville Shale asset which closed on May 3,

9 Leading Hedge Program Hedge Summary Oil volumes (MMBbls)¹ Average floor price ($/Bbl) $ $ Natural Gas volumes (TBtu) Average floor price ($/MMBtu) $ 3.28 $ : Oil: ~75%² estimated oil floored at $61.66 (retain additional upside) Gas: ~76%² estimated natural gas swapped at $ : Oil: ~19%² estimated oil floored at $60.00 (retain additional upside) Gas: ~26%² estimated natural gas swapped at $3.11 $639MM realized from settlements of financial derivatives in 2016 Note: Hedge positions are as of February 27, 2017 (Contract months: January 2017 Forward). For further details on the Company s derivative program, see EP Energy Corporation s Form 10-K for the year ended December 31, 2016 ¹ Includes 2017 WTI three way collars of 8.8 MMBbls and 2018 WTI three way collars of 3.3 MMBbls ² Percent hedged based on midpoint of 2017 guidance 9

10 2017 Outlook 2017 Oil production (MBbls/d) Total production (MBoe/d) Oil & gas capital ($MM) 1 Wolfcamp $ Eagle Ford Altamont Total capital program ($MM) $630 $730 Oil production growth from 2H 16 Includes two Wolfcamp rigs FY 17 and a third rig mid-year Gross well completions Wolfcamp Eagle Ford ~60 Altamont ~25 Total Lease operating expense ($/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 $2.85 Expect to maintain Eagle Ford and Altamont production at 2H 16 levels Expect 40% CAGR oil volume growth in the Wolfcamp ( 16 18) DD&A ($/Boe) $16 $17 1 Includes 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 Fourth Quarter 2016 Financial and Operational Reporting Package, available at epenergy.com, for the Company s non- GAAP reconciliations and definitions. 10

11 Asset Portfolio Delivers Results Wolfcamp Oil production growth volumes up 37% from 4Q 15 Improved well performance, upgraded type curve One drilling rig in 2016 and completed 44 wells Eagle Ford Increased efficiencies in high return program Generated excess cash flow One drilling rig in 2016 and completed 39 wells Altamont Strong performance from recompletion program Improved returns due to drilling JV and better realized oil pricing One JV drilling rig in 2016 and completed 15 wells 11

12 Wolfcamp: Recent Success 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 140, , ,000 80,000 60,000 40,000 20, Days Previous 600 MBOE TC TC 750 MBOE TC Current Wells (41 wells) New Type Curves 8.3 Oil Production (MBbls/d) Q'15 1Q'16 2Q'16 3Q'16 4Q'16 Gross EUR (MBoe) 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 12

13 Wolfcamp: JV Key Terms EPE Wolfcamp JV Key Terms 150 well program (two 75 well tranches) First wells online in Jan 17 Wellbore only interest ~9,000 laterals Primary objectives: Increases returns Accelerates activities Illuminates acreage value Investor: Wolfcamp DrillCo Funds ~$450MM for 60% of D&C cost EPE Wolfcamp Acreage Earns 50% Working Interest (WI) in completed interval WI reverts to 15% after investor achieves a 12% IRR EP Energy Operates all wells Benefits from ~$75MM carry 13

14 Wolfcamp: JV Increases Program Value EPE Improved Returns on Capital Enhances program economics (single well IRRs from 57% to 80%) (1) Increases near term cash flow and production ($75MM total carry) BTAX IRR 90% 80% 70% 60% 50% 40% 30% 20% 10% $45.00 $50.00 $55.00 $60.00 NYMEX WTI Further illuminates acreage value of approximately $20,000 per acre Wolfcamp - Including Type Curve Update and DrillCo JV Wolfcamp - Type Curve Update Only Wolfcamp - Type Curve 600 Mboe Accelerates development in a balance sheet friendly manner Expands operations in Reagan and Crockett counties Includes only ~5% of existing inventory in Wolfcamp 1 Assumes flat oil price of $55/Bbl (WTI). 14

15 2016 Results and 2017 Outlook March 2, 2017

16 Appendix 16

17 2016 Completed Wells By Quarter Program 1Q 2Q 3Q 4Q FY Eagle Ford Wolfcamp Altamont Total Company

18 Updated Type Well Economics Drilling locations with <$40/Bbl break-even prices Wolfcamp Eagle Ford Altamont Average lateral length 8,500 8,500 5,700 N/A Well spacing (acres) Distance between wells (feet) IP 30 (Boe/d) , IP 30 (Bo/d) Gross EUR (MBoe) % Liquids 80% 72% 78% 75% Gross well costs ($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, Assuming $55 (WTI) / $3.00 (HH) Pre-Tax IRR 57% 22% 58% 30% Pre-tax NPV ($MM) $2.3 $2.0 Assuming $65 (WTI) / $3.50 (HH) Pre-Tax IRR 72% 29% 99% 44% Pre-tax NPV ($MM) $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. 18

19 YE 2016 PV-10 and PV-10 Reconciliation In this presentation, we calculate the PV-10 of oil and gas reserves. The PV-10 of oil and gas reserves is defined as the value of our proved reserve amounts at December 31, 2016, calculated using NYMEX strip prices as of February 17, 2017, plus adjustments for PUDs that were previously booked and lost due to the 5-year SEC rule, the expected benefit from the Wolfcamp joint venture and other contractual arrangements, current capital and operating costs and the value of future hedge settlements, also valued at NYMEX strip prices at February 17, 2017, all then discounted using a 10 percent discount rate. Our calculation of PV-10 is consistent with the collateral valuation methodology we use for determining our borrowing base under the RBL Facility. The PV-10 is derived from the standardized measure of discounted future net cash flows of our oil and natural gas properties, which is the most directly comparable GAAP financial measure. We believe that the presentation of PV-10 is useful to investors because it presents (i) the relative monetary significance of our oil and natural gas properties using current prices and information, regardless of tax structure and (ii) the relative value of our reserves to other companies. The PV-10 and the standardized measure of discounted future net cash flows do not purport to present the fair value of our oil, natural gas and NGLs reserves, nor should they be considered in isolation or as a substitute for the comparable GAAP measure. Additionally, this measure may not be comparable to similarly titled measures used by other companies. The following tables provide a reconciliation of PV-10 to the standardized measure of discounted future net cash flows (in millions): `` 12/31/16 PV-10 ($MM) Proved Developed $2,249 Proved Undeveloped 1,067 PV-10 of Oil, Gas and NGL Reserves $3,316 PV-10 of Hedge Settlements 102 PV-10 of Oil and Gas Reserves plus MTM of Hedges $3,418 As of PV-10 of Oil, Gas and NGL Reserves- Dec. 31, 2016 $3,316 Less: Assumption differences 1 2,264 PV-10 of Oil, Gas and NGL Reserves - Dec. 31, 2016 at SEC prices 2 $1,052 Less: Income taxes, discounted at 10% 25 Standardized measure of discounted future net cash flows at Dec. 31, 2016 $1,027 1 Assumption difference relate to those adjustments made to the SEC proved reserves as of December 31, 2016 as described above. 2 The first day 12-month average price used to estimate our proved reserves at December 31, 2016 was $42.75 per barrel of oil (WTI) and $2.48 per MMBtu for natural gas (HH). 19