Investor Presentation

Transcription

1 Energy Corporation Investor Presentation March

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, operating results and shareholder returns; future liquidity and availability of capital; estimated earnout payments; 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, 2017, 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 1. As of December 31, Core development area in Appaloosa, Bronco and Mustang million shares outstanding as of February 28, 2018 and March 9, 2018 share price of $ Enterprise value includes $62.5 million face value convertible preferred. Company overview Delaware Basin pure play Premier Delaware Basin position 1 27,100 gross (21,100 net) acres, ~90% in derisked core of Basin ~90% of core acreage held by production Strong execution Consistently delivering strong returns on capital Top quartile ROCE Extensive derisked inventory 429 gross (375 net) operated Wolfcamp A and Upper B locations 1 Ten year drilling inventory with three rigs Testing Wolfcamp Lower B and Upper C potential to initially add more than 160 locations Reeves County, Texas Market data ($ million) 2 Ticker symbol REN Market cap $802 Total debt $555 Enterprise value $1,420 Page 3

4 2017 highlights Positioned for significant value creation Page 4 Spud 28 wells and placed 27 wells on production, exceeding original 22 well plan through drilling efficiencies Permian Basin production grew by 151% year-over-year. Exceeded high end of guidance for 4Q17. Expanded the Company s core Delaware Basin acreage footprint by 28% $ Sold Utah and New Mexico properties dramatically improving cost structure, 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 2017 operational achievements Page 5 Drilling Completion Production 25 wells drilled with three drilling over year-end Company drilling records of 14 days in Mustang and 17 days in Appaloosa Successful testing of the lower Wolfcamp B and Wolfcamp C 27 horizontal wells brought online Upper Wolfcamp average peak 24-hour rates of between 2,400 and 2,800 Boe per day Initiated transition to batch completion 4Q17 Permian Basin production growth of 89% year-over-year Full year Permian Basin production growth of 151%

6 Consistent production growth, improving cost structure Permian production growth (MBoe per day) Page 6 Grew production 8.5x Cash costs per Boe 60% reduction in costs

7 1. Non-GAAP measure; see reconciliation in the Appendix 2. As of December 31, 2017 Strong financial profile Page 7 Permian Basin operating margins Adjusted EBITDA 1 100% 50% 0% Debt maturity and availability 2 $30 million outstanding at year-end 2017 Active hedging program 7,000 Bbl of oil per day Approximately 70% of anticipated 1H18 production Average floor price of ~$50 per Bbl upside exposure in collar structures

8 Continued strong results from Upper Wolfcamp Page average 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

9 WCA wells tracking type curve Page 9 Five wells, all of which have at least 360 days of production Average exceeds type curve when adjusted for frac hits and downtime Appaloosa Type curve adjusted for frac hits and downtime Mustang Five wells, all of which have at least 360 days of production Cumulative production matches type curve when adjusted for interference and operational overprint Type curve adjusted for frac hits and downtime 1. Represents three stream gross production

10 WCC LWCB Positive results in Lower Wolfcamp Well Peak rates (Boe per day) 24 hr. 30 day 60 day S. Elephant B307SL 2,254 2,099 1,968 N. Elephant B301SL Drilling S. Elephant C207SL 2,294 1,930 1,695 Uinta C101H 3, Th. Canyon C107SL Completing Ranger C205SL WOC Thunder Canyon C107SL N. Elephant B301SL S. Elephant B307SL S. Elephant C207SL Ranger C205SL Page 10 Uinta C101H LWCB and UWCC drilling could add 160+ gross locations with upside 1 Producing WOC 1. Zone abbreviation legend: LWCB Lower Wolfcamp B; UWCC Upper Wolfcamp C

11 Upside Testing Development Ten year development inventory with extensive upside Wolfcamp zone Wells per zone Gross well inventory Upper A/Y Lower A Upper B Development total 429 Lower B 4 82 Upper C 4 79 Testing total 161 Downspaced LWCB Downspaced UWCC Lower C Upside total Total inventory Additional upside in Wolfcamp X and D 120+ gross locations on 160 acre spacing 1. Zone abbreviation legend: LWCB Lower Wolfcamp B; UWCC Upper Wolfcamp C Inventory spacing schematic Development Testing: 160 acre Upside: 80 acre mile Page 11

12 1. Companies included are AXAS, DNR, ECR, HK, MCF, PVAC, REN, SBOW, SN and SRCI (alphabetical order). Source: Johnson Rice & Company L.L.C 2. Companies included are CLR, CRC, CXO, DNR, EPE, FANG, JAG, LPI, OAS, PDCE, PE, PXD, REN, RSPP, WLL and XOG (alphabetical order). Source: Goldman Sachs Premier Delaware Basin operator Top tier production growth 2017E v 2016A 1 Page 12 Class leading capital efficiency Growth in cash flow per share 2017 ROCE 2 27% increase year-over-year

13 Sandlot Expanding development program in approach 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 13 UWCA LWCA UWCB Appaloosa 19 long laterals 12 WCA, 7 UWCB Focus area Mustang 23 mid-length laterals 15 WCA, 8 UWCB

14 Optimizing well performance through pad drilling Page 14 Nine-well pad expected to initially track TC Second set of 9 wells completed some level of interference expected Full section development Results in: Unaffected well, expected to perform at TC Wells drilled offsetting existing producers, some reduction relative to TC Wells experiencing interference from offset completions temporary deferral of production

15 Maximizing program performance Ranger/Mitre 10K WCA Ranger/Mitre 10K WCB Page 15 29% of 2018 program 16% of 2018 program Program average IRR more than 100% Program average IRR more than 35% Sandlot 6.5K WCA Sandlot 6.5K 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

16 1. Based on 2018 program average type curves and assumes $55 per Bbl and $3.00 per Mcf 2. Before COPAS 2018 program expected to deliver strong returns Ranger/Mitre 10K WCA 1 Ranger/Mitre 10K WCB 1 Page % capital recovered 62% capital recovered 2 2 Sandlot 6.5K WCA 1 Sandlot 6.5K WCB 1 57% capital recovered 53% capital recovered 2 2

17 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 17 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

18 +50% year-over-year Permian production growth Permian Basin average expected full year production of 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 18 Actual and estimated production (MBoe per day) Permian actual Low High Average 2018

19 Note: Assumes 2018 plan and $55 per Bbl and $3.00 per MMBtu. Three rigs in 2019 with flat pricing. Per share metrics assume 26.4 million fully diluted shares and February 15, 2018 closing price of $35.62 per share development driving strong financial performance Production Expect Permian Basin full year production growth of more than 50% compared to 2017 Page 19 Capital expenditures Approximately 56% of capital expenditures will be funded from internal cash flow with balance sheet flexibility to fund remainder Per share performance Anticipate growth in debt-adjusted per share cash flow of 40%-55% and production of 5-15% Leverage Anticipate exiting the year with a debt-to-adjusted EBITDA ratio of between 2.80x and 2.95x Free cash flow Anticipate positive free cash flow in 4Q18 and FY19

20 Positioned for significant value creation Page 20 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

21 Appendix

22 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

23 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

24 Drilling activity Since October 1, 2017 Page 24 Drilling activity Well name Area Zone Lateral length Spud to TD Status TD date (heel - toe) (days) Thunder Canyon C107SL M WCC 8,071 Completing 10/10/ Ranger C205SL A WCC 10,875 WOC 10/18/ Uinta C101H M WCC 8,066 Producing 10/29/ Ranger U06SL A UWCA 9,700 WOC 11/1/ Ranger L05H A LWCA 9,702 WOC 11/1/ Ranger L03H A LWCA 9,864 WOC 1/27/ Ranger L01H A LWCA 9,749 WOC 2/10/ Ranger U04H A UWCA 9,826 WOC 2/11/ Ranger U02H A UWCA 9,722 WOC 2/26/ Ranger B104SL A UWCB 9,731 WOC 3/1/ North Elephant B301SL A LWCB 10,000 Drilling - - Ranger B102SL A UWCB 10,000 Drilling - - Sandlot State L02H M LWCA 6,500 Drilling - - Sandlot State B101SL M UWCB 6,500 Drilling - - Sandlot State U01H M UWCA 6,500 Drilling - - Sandlot State L04H M LWCA 6,500 Drilling - - For wells that are currently drilling the lateral length is what is planned

25 Completion activity Since October 1, 2017 Page 25 Completions activity Well name Area Zone Lateral length First Proppant per Frac stages (perf - perf) production foot (lbs) Ace L06H M LWCA 7,699 10/3/ ,804 South Elephant C207SL A WCC 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 WCC 7,819 1/26/ ,809 Ranger U06SL A UWCA Ranger L05H A LWCA Ranger C205SL A WCC Thunder Canyon C107SL M WCC Ranger U04H A UWCA Ranger L03H A LWCA Ranger B104SL A UWCB Ranger U02H A UWCA Ranger L01H A LWCA WOC WOC WOC Completing WOC WOC WOC WOC WOC

26 Production activity As of March 8, 2018 Page 26 Production activity Well name Area Zone Lateral length Peak rates (Boe per day) (perf - perf) 24 hour 30 day 60 day 90 day North Goat B101SL A UWCB 10,062 2,362 2,284 2,176 2,013 Ace L06H M LWCA 7,699 2,735 2,622 2,508 2,341 South Elephant C207SL A WCC 9,403 2,294 1,930 1,695 1,544 South Elephant B307SL A LWCB 9,567 2,254 2,099 1,968 1,840 Long Yuengling L03H M LWCA 7,615 3,262 2,991 2,667 2,358 Long Yuengling U04H M UWCA 7,724 2,559 2,293 2,215 2,109 Uinta C101H M WCC 7,819 3,

27 Quarterly prices and volume Page 27 Prices and volume Average prices: 2016 Q1 Q2 Q3 Q4 FY Q1 Q2 Q3 Q4 YTD Oil ($ per Bbl) $ $ $ $ $ $ $ $ $ $ NGL ($ per Bbl) Gas ($ per Mcf) Production volumes: Oil (MBbl) ,072 1,238 3,821 1,213 1,400 1,554 1,331 5,499 NGL (MBbl) ,641 Gas (MMcf) ,436 1,903 4,811 1,922 2,881 3,562 3,735 12,101 MBoe 820 1,080 1,480 1,802 5,182 1,773 2,216 2,628 2,539 9,156

28 Note: See appendix for EBITDA reconciliation 1. Includes workover and excludes non-cash charges 2. Net of Copas reimbursements. Excludes non-cash charges 3. Excludes non-cash accruals; represents time- and performance-based incentive cash paid out Margin and cost structure Page 28 Summary ($ in millions, except as noted) Q1 Q Q3 Q4 FY Q1 Q Q3 Q4 YTD Sales volume Total MBoe 820 1,080 1,480 1,802 5,182 1,773 2,216 2,628 2,539 9,156 Revenue $ 19.0 $ 35.4 $ 47.4 $ 62.6 $ $ 64.6 $ 70.2 $ 79.4 $ 89.3 $ Realized derivative gains (losses) (0.3) Adjusted revenue $ 46.8 $ 55.9 $ 68.7 $ 81.0 $ $ 64.3 $ 71.9 $ 81.8 $ 89.3 $ Expenses Operating expenses Taxes G&A Cash-settled SARs awards Other expense - - (0.1) (0.2) (0.3) Total expenses Adjusted EBITDA $ 23.2 $ 29.9 $ 41.7 $ 51.8 $ $ 32.5 $ 38.7 $ 43.0 $ 58.6 $ Capital expenditures Non-CO 2 capital $ 27.7 $ 33.4 $ 34.0 $ 36.1 $ $ 54.9 $ 96.2 $ $ 63.8 $ CO 2 purchases Total Acquisitions Divestitures (0.2) 0.2 (35.3) (3.6) (38.9) (19.2) (10.6) (6.3) (172.4) (208.5) Total capital expenditures $ 29.1 $ 35.3 $ 0.3 $ $ $ 36.7 $ $ 95.8 $ (108.3) $ 272.2

29 Note: See appendix for EBITDA reconciliation 1. Includes workover and excludes non-cash charges 2. Net of Copas reimbursements. Excludes non-cash charges 3. Excludes non-cash accruals; represents time- and performance-based incentive cash paid out Margin and cost structure per Boe Page 29 Margins ($ per Boe) Q1 Q2 Q3 Q4 FY Q1 Q2 Q3 Q4 YTD Revenue $ $ $ $ $ $ $ $ $ $ Realized derivative gains (losses) (0.14) (0.01) 0.41 Adjusted revenue $ $ $ $ $ $ $ $ $ $ Expenses Operating expenses Taxes G&A Cash-settled SARs awards Other expense (0.01) (0.01) (0.08) (0.12) (0.07) 0.03 (0.06) 0.00 (0.01) (0.01) Total expenses Adjusted EBITDA $ $ $ $ $ $ $ $ $ $ 18.85

30 Non-GAAP reconciliations Page 30 Adjusted EBITDA 2016 ($ in millions) Q1 Q2 Q3 Q4 FY Q1 Q2 Q3 Q4 YTD Net income (loss) $ (85.3) $ (36.9) $ (18.9) $ (20.6) $ (161.7) $ 1.5 $ 13.2 $ (14.6) $ (1.3) $ (1.2) Adjustments: Interest $ 13.1 $ 13.0 $ 13.3 $ 11.3 $ 50.7 $ 17.7 $ 8.8 $ 8.5 $ 8.4 $ 43.4 Taxes (0.3) (0.3) Contingent consideration gain (loss) (3.5) (3.5) Depletion, depreciation and amortization Ceiling test impairment Stock-based compensation Aneth transaction costs Cash-settled incentive awards accrued (1.4) Cash-settled incentive awards paid (1.4) (0.6) (0.1) (2.1) Mark-to-market loss (gain) on derivatives (11.1) (5.8) Total adjustments $ $ 66.8 $ 60.6 $ 72.4 $ $ 31.0 $ 25.5 $ 57.6 $ 59.9 $ Adjusted EBITDA $ 23.2 $ 29.9 $ 41.7 $ 51.8 $ $ 32.5 $ 38.7 $ 43.0 $ 58.6 $