2017 Operations Update and 2018 Guidance

Transcription

1 Energy Corporation 2017 Operations Update and 2018 Guidance February 26, 2018

2 Cautionary statements Statements in this presentation, other than statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of Words such as expect, estimate, project, budget, forecast, target, anticipate, intend, plan, may, will, could, should, poised, believes, predicts, potential, continue, and similar expressions are intended to identify such forward-looking statements; however the absence of these words does not mean the statements are not forward-looking. Such forward looking statements include statements regarding 2018 production, lease operating expense, corporate G&A and capital expenditure guidance; expected production growth from 2017 to 2018; future oil and liquids percentage and NGL yields; future leverage ratios; future drilling plans and activity, including production that may result from our 2018 program; future financial and operating results; future liquidity and availability of capital; future infrastructure and other capital projects, the anticipated costs thereof and the percentage of cash flow outspend; future production, reserve growth and decline rates; the impact of well interference and the effectiveness of drilling and completion adjustments in response thereto; the anticipated benefits of our 2018 development strategy; expected timing and location of drilling and completion of pad wells and the timing of the production contribution thereof; our plans and expectations regarding our future development activities including drilling and completing wells and the spacing of such wells; the number of such potential projects, locations and productive intervals; our projection of free cash flow in 4Q18 and 2019; the prospectivity of our properties and acreage; estimated ultimate recoveries of oil and gas (EURs); performance of wells against type curves; and anticipated rates of return (IRRs), net asset values and PV-10 values of our projects and properties. Resolute will evaluate its capital expenditures in relation to its liquidity and cash flow and may adjust its activity and capital spending levels based on acquisitions, changes in commodity prices, the cost of goods and services, production results and other considerations. Forward-looking statements in this presentation include matters that involve known and unknown risks, uncertainties and other factors that may cause actual results, levels of activity, performance or achievements to differ materially from results expressed or implied by this presentation. Such risk factors include, among others: uncertainties regarding future actions that may be taken by Monarch in furtherance of its intent to nominate director candidates for election at the Company s 2018 annual meeting of stockholders; potential operational disruption caused by Monarch s future actions; the Company s ability to successfully implement its strategy to create long-term stockholder value; depressed commodity prices; the volatility of oil and gas prices including the price realized by Resolute; inaccuracy in reserve estimates and expected production rates; potential write downs of the carrying value and volumes of reserves as a result of low commodity prices; the discovery, estimation, development and replacement by Resolute of oil and gas reserves; the future cash flow, liquidity and financial position of Resolute; Resolute s level of indebtedness and our ability to fulfill our obligations under the senior notes, our credit facility and any additional indebtedness that we may incur; potential borrowing base reductions under our revolving credit facility; the success of the business and financial strategy, hedging strategies and plans of Resolute; the amount, nature and timing of capital expenditures of Resolute, including future development costs; the availability of additional capital and financing, including the capital needed to pursue our drilling and development plans for our properties, on terms acceptable to us or at all; uncertainty surrounding timing of identifying drilling locations and necessary capital to drill such locations; the potential for downspacing, infill or multi-lateral drilling in the Permian Basin or obstacles thereto; the timing of issuance of permits and rights of way; the timing and amount of future production of oil and gas; availability of drilling, completion and production personnel, supplies and equipment; the completion and success of exploratory drilling on our properties; potential delays in the completion, commissioning and optimization schedule of Resolute s facilities construction projects or any potential breakdown of such facilities; operating costs and other expenses of Resolute; the success of prospect development and property acquisition of Resolute; Resolute s dependence on third parties for installation of gas gathering and processing infrastructure, oil gathering facilities and water disposal facilities and potential delays relating thereto; the success of Resolute in marketing oil and gas; competition in the oil and gas industry; the impact of weather and the occurrence of disasters, such as fires, floods and other events and natural disasters; environmental liabilities; potential power supply limitations or delays; operational problems or uninsured or underinsured losses affecting Resolute s operations or financial results; adverse changes in government regulation and taxation of the oil and gas industry, including the potential for increased regulation of underground injection, fracing operations and venting/flaring; potential climate related change regulations; risks and uncertainties associated with horizontal drilling and completion techniques; the availability of water and our ability to adequately treat and dispose of water during and after drilling and completing wells; changes in derivatives regulation; developments in oil-producing and gas-producing countries; and cyber security risks. Actual results may differ materially from those contained in the forward-looking statements in this presentation. Resolute undertakes no obligation and does not intend to update these forward-looking statements to reflect events or circumstances occurring after the date of this presentation. You are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this presentation. You are encouraged to review Item 1A. - Risk Factors and all other disclosures appearing in the Company s Form 10-K for the year ended December 31, 2016, subsequent quarterly reports on Form 10-Q and subsequent filings with the Securities and Exchange Commission (the "SEC") for further information on risks and uncertainties that could affect the Company s businesses, financial condition and results of operations. All forward-looking statements are qualified in their entirety by this cautionary statement. Furthermore, the SEC prohibits oil and gas companies, in their filings with the SEC, from disclosing estimates of oil or gas resources other than reserves, as that term is defined by the SEC. In this presentation, Resolute includes estimates of quantities of oil and gas using certain terms, such as resource, resource potential, EUR, oil in place, or other descriptions of volumes of reserves, which terms include quantities of oil and gas that may not meet the SEC definitions of proved, probable and possible reserves, and which the SEC guidelines strictly prohibit Resolute from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being recovered by Resolute. Finally, reserve estimates mentioned in this presentation were prepared internally using price and cost assumptions and methodologies that are different from what would be required if prepared in accordance with guidelines established by the SEC for the estimation of proved reserves, and such reserve estimates do not include probable and possible reserves. Such reserve estimates have not been audited by our independent reserves auditor. Production rates, including early time rates, 24 hour peak IP rates, 30, 60, 90, 120 and 150 day peak IP rates, for both our wells and for those wells that are located near to our properties are limited data points in each well s productive history and represent three stream gross production. These rates are sometimes actual rates and sometimes extrapolated or normalized rates. As such, the rates for a particular well may change as additional data becomes available. Peak production rates are not necessarily indicative or predictive of future production rates, EUR or economic rates of return from such wells and should not be relied upon for such purpose. Equally, the way we calculate and report peak IP rates and the methodologies employed by others may not be consistent, and thus the values reported may not be directly and meaningfully comparable. Lateral lengths described are indicative only. Actual completed lateral lengths depend on various considerations such as leaseline offsets. Standard length laterals, sometimes referred to as 5,000 foot laterals, are laterals with completed length generally between 4,000 feet and 5,500 feet. Mid length laterals, sometimes referred to as 7,500 foot laterals, are laterals with completed length generally between 6,000 feet and 8,000 feet. Long laterals, sometimes referred to as 10,000 foot laterals, are laterals with completed length generally longer than 8,000 feet. Non-GAAP financial measures: Resolute s presentations may include certain non-gaap financial measures. When applicable, a reconciliation of these measures to the most directly comparable GAAP measure is presented. Page 2

3 2017 operational results

4 2017 highlights Positioned for significant value creation Page 4 Spud 28 wells and placed 27 wells on production, drilled first three Ranger wells in initial nine-well group Exceeded high end of guidance for 4Q17. Permian Basin production grew by 151% year-over-year Acquired Bronco in 2Q17, increasing the Company s Delaware Basin footprint by 28% $ Sold Aneth Field resulting in dramatically improved cost structure; significantly improved leverage and liquidity Performed extensive technical work to lay foundation for shift to full field development mode Resolute positioned to unlock the full potential of its assets

5 Permian production growth Page 5 Quarterly production (MBoe per day) Grew production 8.5x Top tier production growth in the most productive shale play in North America

6 2017 Wolfcamp A (WCA) and Upper B (UWCB) results Page 6 Average peak rates (Boe per day) Zone WCA UWCB Appaloosa Wells hr. 2,845 2,408 Bronco 30 day 2,515 2, day 2,270 1,882 Mustang Wolfcamp A Wolfcamp B

7 WCC LWCB Lower Wolfcamp B (LWCB) and C (WCC) results Page 7 Well Peak rates (Boe per day) 24 hr. 30 day 60 day S. Elephant B307SL 2,254 2,099 1,968 N. Elephant B201SL Drilling S. Elephant C207SL 2,294 1,930 1,624 Uinta C101H 1 2, Th. Canyon C107SL WOC Ranger C205SL WOC Thunder Canyon C107SL N. Elephant B201SL S. Elephant B307SL S. Elephant C207SL Ranger C205SL Uinta C101H LWCB and WCC drilling could add 160+ gross locations with upside Producing WOC 1. Early-time rate, may not reflect final peak

8 Mustang 2016 and 2017 WCA average well performance 1 Page WCA wells Five wells all of which have at least 360 days of production Cumulative production adjusted for interference and operational overprint matches type curve Nine wells with production ranging from 120 to 310 days Cumulative production to date exceeding type curve even prior to adjusting for interference 2017 WCA wells 1. Represents three stream gross production Type curve 2016/ adjusted for frac hits and downtime

9 Appaloosa 2016 WCA average well performance Months 9 12 Five wells all of which have at least 360 days of production Page 9 Months 9 12 Type curve adjusted for frac hits and downtime Average exceeds type curve when adjusted for frac hits and downtime Frac hits and downtime resulted in approximately 5% less average cumulative production over 360 days Difference of ~90 Boe per day over the course of the year 1. Represents three stream gross production

10 Appaloosa 2017 average well performance 1 Page 10 Type curve Wolfcamp A 2017 Individual 2017 wells All 2017 Appaloosa wells were infill wells drilled adjacent to existing producers Several of these wells have underperformed the type curve due to frac hits and interference Well interference issues were most pronounced in the 2017 Appaloosa drilling program; 2018 plan is designed to minimize interference 1. Represents three stream gross production

11 Examples of recovery from frac hits Page 11 Appaloosa South Goat 2204H South Goat U01H frac hit Mustang Queen City 0302BH Renegade frac hit Pipeworks frac hit Daily production Frac hit event Pre-frac hit forecast Typically wells which experience interference from offset completions return to pre-interference trend

12 1. Present values presented are pre-tax. After tax effect would lower PV 10 to $433 million 2. Calculated as sum of purchases, extensions, discoveries and total revisions divided by production Year-end 2017 proved reserves Product mix 47% oil and 70% liquids Page 12 Preliminary reconciliation 1 PV 10 Proved reserves MMBoe ($ million) Year-end $ Denton divestiture (0.4) (4.3) Aneth divestiture (22.6) (94.9) 2017 Aneth and Denton production (1.8) (18.7) Pro forma YE16 Reeves County 35.4 $ Texas production (7.3) (69.5) Additions Bronco acquisition Revisions (6.6) Year-end $ Reeves County reserves grew 51% year-over-year 2017 reserve replacement was ~250% 2

13 2018 operational plan and capital budget

14 Sandlot 2018 development program Three rigs from February to mid-september, two rigs thereafter First nine-well group online in May Plan to drill 42 gross (40.8 net) wells 1 Appaloosa focus on Ranger/Mitre areas 19 long laterals, 12 WCA and 7 UWCB Mustang focus on Sandlot area 23 mid-length laterals, 15 WCA and 8 UWCB Appaloosa Page 14 Mustang 2018 program to generate strong production growth and superior return on capital 1. Drilled or drilling over year-end 2018

15 Field history leading to 2018 development strategy 2016 well 2017 results 2018 approach 2017 infill well Frac energy moves towards pressure sink Focus on drilling and contemporaneously completing groups of up to nine wells Benefits from this strategy include: Reduced frac hits Improved infill well performance Cost savings Page 15 Parent well pressure sink Inefficient stimulation and reduced production in both wells UWCA LWCA UWCB New drilling strategy expected to significantly improve well performance and reduce costs

16 5 wells 5 wells 8 well group 9 well group 9 well group 9 well group 1. Represents current operational plan. Actual wells drilled and drilling order subject to change. 2. Drilled or drilling over year-end operations timeline 1 Page 16 N. Elephant WCB Uinta C101H Appaloosa triple Appaloosa triple Appaloosa triple Mustang triple Mustang triple Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Appaloosa Mustang Drilling Completion Production Dec Mustang triple Appaloosa triple Appaloosa triple Appaloosa double Thunder Canyon C208H Mustang triple Mustang triple Mustang triple Appaloosa triple Appaloosa double Mustang triple Mustang double Area Drilled 2 On line Mustang Appaloosa Total 42 38

17 Cumulative production curves preface Solid black line represents the type curve for an unconstrained parent well. This curve has not been altered from previously provided information. The area between the type curve and the dashed black line represents a range of potential outcomes for wells to be drilled in 2018, some of which are expected to experience reduced performance relative to the parent well type curve The red line represents the expected average outcome for the program as laid out for This average will change in any given year based on the mix of wells to be drilled. Total Company production guidance for 2018 is further reduced for various assumed operating issues such as power outages, weather, well shut-ins and downstream gas constraints Black Grey Red Page 17

18 Cumulative production and IRRs Ranger/Mitre 10K WCA Ranger/Mitre 10K WCB Page 18 29% of 2018 program 16% of 2018 program Program average IRR more than 100% Program average IRR more than 35% Sandlot 7K WCA Sandlot 7K WCB 36% of 2018 program 19% of 2018 program Program average IRR ~40% Program average IRR more than 30% Parent well type curve Range of expected outcomes 2018 program average Economics assume $55 per Bbl and $3 per MMBtu flat pricing

19 2018 production targets Permian Basin average full year production grows more than 50% to MBoe per day in 2018 Production accelerates significantly through the year resulting in more than 90% increase in production from 1Q18 to 4Q18 4Q18 production rate of MBoe per day Page 19 Actual and estimated production (MBoe per day) Permian only Low High Average 2018

20 1. Based on actual sales volume and excluding non-cash items as well as one-time fees incurred in conjunction with the disposition of Aneth Field. 2. Based on mid-point of production and expense guidance 2018 expenses Page 20 Annual cash LOE of $60 million to $68 million Annual G&A expense of $30 million to $34 million LOE per Boe 1 G&A per Boe Significantly improved cost structure resulting from growing low cost production and divestiture of Aneth

21 2018 guidance Page guidance Range Low High Projected 2018 production Annual MBoe 10,950 12,045 Annual average Boe per day 30,000 33,000 4Q average Boe per day 42,000 44,000 On a volume-weighted basis: Oil Oil and NGL 52% 75% Projected 2018 costs ($ million): Lease operating expense $60 $68 General and administrative $30 $34 Projected 2018 net capital expenditures ($ million) $365 $395

22 2018 capital guidance detail Page capital guidance ($ million) Range Low High Projected 2018 net capital expenditures Drilling, completion and well facilities $350 $375 Field facilities and other Other corporate capital Total capital before earnout payments Less: anticipated earnout payments (27) (29) Total capital expenditures net of earnouts $365 $395

23 1. Assumes 26.4 million fully diluted shares and February 15, 2018 closing price of $35.62 per share; $55 per Bbl and $3.00 per MMBtu flat pricing 2. Assumes 2018 plan, three rigs in 2019 and $55 per Bbl and $3.00 per MMBtu 2018 plan metrics 1 Production Expect Permian Basin full year production growth of more than 50% compared to 2017 Page 23 Capital expenditures Approximately 56% of capital expenditures will be funded from internal cash flow with sufficient balance sheet flexibility to fund remainder Per share performance Anticipate growth in debt-adjusted per share cash flow (40%-55%) and production (5-15%) Leverage Anticipate exiting the year with a debt-to-ebitda ratio of between 2.80x and 2.95x Free cash flow Anticipate positive free cash flow in 4Q18 and

24 Key takeaways Positioned for significant value creation Page 24 Core of core acreage position, employing efficient full field development technology Significant production growth year-over-year Costs Dramatically improved cost structure $ Positioned to achieve free cash flow in 4Q18 and CF share Substantial growth in per share financial metrics expected to translate into stronger trading multiples Resolute positioned to unlock the full potential of its assets 1. Assumes 2018 plan, three rigs in 2019 and $55 per Bbl and $3.00 per MMBtu

25 Appendix

26 Drilling activity Since October 1, 2017 Page 26 Drilling activity Well name Area Zone Lateral length Spud to TD Status TD date (heel - toe) (days) Uinta C101H M UWCC 8,066 Producing 10/29/ Ranger U06SL A UWCA 9,700 WOC 11/1/ Thunder Canyon C107SL M UWCC 8,071 WOC 11/8/ Ranger L05H A LWCA 9,702 WOC 11/23/ Ranger C205SL A MWCC 10,875 WOC 12/11/ North Elephant WCB A LWCB 10,000 Drilling - - Ranger U04H A UWCA 10,000 Drilling - - Ranger B104SL A UWCB 10,000 Drilling - - Ranger B102SL A UWCB 10,000 Drilling - - For wells that are currently drilling the lateral length is what is planned

27 Completion activity Since October 1, 2017 Page 27 Completions activity Well name Area Zone Lateral length First (perf - perf) production Frac stages Proppant per foot (lbs) Ace L06H M LWCA 7,699 10/3/ ,804 South Elephant C207SL A MWCC 9,403 11/5/ ,809 South Elephant B307SL A LWCB 9,567 11/5/ ,801 Long Yuengling L03H M LWCA 7,615 11/21/ ,800 Long Yuengling U04H M UWCA 7,724 11/21/ ,799 Uinta C101H M UWCC 7,819 2/2/ ,809

28 Production activity As of February 23, 2017 Page 28 Production activity Well name Area Zone Lateral length Peak rates (Boe per day) (perf - perf) 24 hour 30 day 60 day 90 day Ace L06H M LWCA 7,699 2,735 2,622 2,508 2,341 South Elephant C207SL A MWCC 9,403 2,294 1,930 1,624 - South Elephant B307SL A LWCB 9,567 2,254 2,099 1,968 1,827 Long Yuengling L03H M LWCA 7,615 3,262 2,991 2,667 - Long Yuengling U04H M UWCA 7,724 2,559 2,293 2,215-1 Uinta C101H M UWCC 7,819 2, Early time rate, may not reflect final peak