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| 8-K - 8-K - EARTHSTONE ENERGY INC | form8-kxinvestorpresentati.htm |
Investor Presentation June 4, 2018 1
Disclaimer Forward-Looking Statements This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Statements that are not strictly historical statements constitute forward-looking statements and may often, but not always, be identified by the use of such words such as “expects,” “believes,” “intends,” “anticipates,” “plans,” “estimates,” “guidance,” “potential,” “possible,” or “probable” or statements that certain actions, events or results “may,” “will,” “should,” or “could” be taken, occur or be achieved. The forward-looking statements include statements about the expected future reserves, production, financial position, business strategy, revenues, earnings, costs, capital expenditures and debt levels of the Company, and plans and objectives of management for future operations. Forward-looking statements are based on current expectations and assumptions and analyses made by Earthstone and its management in light of experience and perception of historical trends, current conditions and expected future developments, as well as other factors appropriate under the circumstances. However, whether actual results and developments will conform to expectations is subject to a number of material risks and uncertainties, including but not limited to: risks relating to any unforeseen liabilities; further declines in oil, natural gas liquids or natural gas prices; the level of success in exploration, development and production activities; adverse weather conditions that may negatively impact development or production activities; the timing of exploration and development expenditures; inaccuracies of reserve estimates or assumptions underlying them; revisions to reserve estimates as a result of changes in commodity prices; impacts to financial statements as a result of impairment write-downs; risks related to level of indebtedness and periodic redeterminations of the borrowing base under the Company’s credit agreement; Earthstone’s ability to generate sufficient cash flows from operations to meet the internally funded portion of its capital expenditures budget; Earthstone’s ability to obtain external capital to finance exploration and development operations and acquisitions; the ability to successfully complete any potential asset acquisitions and the risks related thereto; the impacts of hedging on results of operations; uninsured or underinsured losses resulting from oil and natural gas operations; Earthstone’s ability to replace oil and natural gas reserves; and any loss of senior managementor key technical personnel. Earthstone’s 2017 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, recent current reports on Form 8-K and any amendments of such filings, and other Securities and Exchange Commission (“SEC”) filings discuss some of the important risk factors identified that may affect Earthstone’s business, results of operations, and financial condition. Earthstone undertakes no obligation to revise or update publicly any forward-looking statements except as required by law. Industry and Market Data This presentation has been prepared by Earthstone and includes market data and other statistical information from third-party sources, including independent industry publications, government publications or other published independent sources. Although Earthstone believes these third-party sources are reliable as of their respective dates, Earthstone has not independently verified the accuracy or completeness of this information. Some data are also based on Earthstone’s good faith estimates, which are derived from its review of internal sources as well as the third-party sources described above. 2
Disclaimer Oil and Gas Reserves The SEC generally permits oil and gas companies, in filings made with the SEC, to disclose estimated proved reserves, which are estimates of reserve quantities that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, and certain probable and possible reserves that meet the SEC’s definitions for such terms. Earthstone discloses only estimated proved reserves in its filings with the SEC. Earthstone’s estimated proved reserves as of December 31, 2017 contained in this presentation were prepared by Cawley, Gillespie & Associates, Inc., an independent engineering firm (“CG&A”), and comply with definitions promulgated by the SEC. Additional information on Earthstone’s estimated proved reserves is contained in Earthstone’s filings with the SEC. This presentation also contains Earthstone’s internal estimates of its potential drilling locations, which may prove to be incorrect in a number of material ways. The actual number of locations that may be drilled may differ substantially. Certain estimates of proved reserves contained herein were independently prepared by CG&A utilizing NYMEX 5-year strip prices (future prices) for oil, natural gas and NGL’s as of December 31, 2017. Management believes that utilizing an alternate pricing case better represents the value of the reserves and are better aligned with fair value of reserves. Management also believes the alternate pricing case is useful to investors because it uses future prices and not historical prices in its planning and strategic decision making. In addition to using NYMEX 5-year strip prices, future plugging and abandonment costs net of salvage value have been excluded from the NYMEX 5-year strip price reserves case. 3
Investment Highlights Actively growing in the Midland Basin Growth through drill bit, acquisitions and significant business Midland Basin Focused Company combinations with Growing Inventory ~950 total gross drilling locations across core play in Midland Basin Upside from down-spacing and added benches Liquidity of $206 million(1), adequate to fund near-term capital expenses Prudently Managed Balance Sheet Conservative capital structure with low leverage Traditional reserve-based credit facility with standard covenants Midland Basin and Eagle Ford wells-in-progress provide ability to Visible Production Growth & Drilling ramp up production quickly Program with Substantial Optionality Majority of acreage in key areas is HBP Four prior successful public entities Operational excellence Proven Management Team Repeat institutional investors Market recognition from investors and sellside research analysts (1) Liquidity estimated as of March 31, 2018 based on $30mm drawn on revolving credit facility, $11mm of cash on hand and a borrowing base of $225mm. 4
Track Record • Management team has consistently created shareholder value ‐ Repeated success with multiple entities over 25 years 2005 – 2007 Southern Bay Energy, LLC ‐ Results have created long-term and recurring shareholders (Private) Gulf Coast, Permian Basin Extensive industry and financial relationships ‐ Initial investors – 40% IRR ‐ Technical and operational excellence . Multi-basin experience . Resource & conventional expertise 2001 – 2004 AROC, Inc. (Private) . Complex drilling & horizontal resource proficiency Gulf Coast, Permian Basin, Mid-Con. . Efficient and low-cost operator Preferred investors – 17% IRR Initial investors – 4x return . Proven acquisition and exploitation results 1997 – 2001 Texoil, Inc. (“TXLI”) Gulf Coast, Permian Basin 2007 – 2012 GeoResources, Inc. (“GEOI”) Preferred investors – 2.5x return Eagle Ford, Bakken / Three Forks, Gulf Coast Follow-on investors – 3x return Initial investors – 35% IRR Initial investors – 10x return Initial investors – 4.8x return 1992 – 1996 Hampton Resources Corp. (“HPTR”) Initial Southern Bay investors achieved a combined 7.4x ROI upon Gulf Coast the merger with GeoResources and subsequent sale in 2012 Preferred investors – 30% IRR Initial investors – 7x return Note: “Initial investors” refers to (i) in the case of private entities, investors that participated in the initial capitalization or recapitalization of the entity at the time a change in management occurred, or (ii) in the case of public entities, public shareholders existing at the date the transaction was announced to the public. Past performance is not necessarily indicative of future results. 5
Management . Strong management and technical team with demonstrated ability and prior success . Equity ownership - interests are clearly aligned with shareholders Years Years of Working Responsibility Experience Together Frank Lodzinski 45 29 CEO Robert Anderson 30 14 President Mark Lumpkin 20 1 CFO Steve Collins 28 21 Operations Tim Merrifield 37 18 Geology and Geophysics Francis Mury 42 29 Drilling and Development Ray Singleton 38 4 Operations and A&D Tony Oviedo 37 1 Accounting and Administration Lane McKinney 20 4 Land Lenny Wood 16 1 Exploration and Development Scott Thelander 11 1 Finance 6
Earthstone – A Platform for Steady Growth . Since December 2014, Earthstone has evolved from a micro cap, non-op Bakken / Three Forks company to a small cap operator that is primarily focused in the Midland Basin (2) Production (Boe/d) November 2014 9,664 Q1 2018 Midland Basin Eagle Ford Bakken/Other 7,567 Midland Basin Bakken / Three Forks Eagle Ford 662 Boe/d(1) (1) (3) 662 2,097 9,664 Boe/d(2) Q3 2014 Q1 2018 Resource Expansion December 2014 December 2014 Q2 2016 Q2 2017 Q2/Q3 2015 Strategic Private Sellers Combination Midland Basin Midland Basin Eagle Ford Operator Eagle Ford 5,883 Net Acres 20,900 Net Acres Karnes, Gonzales, Howard, Glasscock Reagan, Upton, Fayette Counties, TX Counties, TX Midland Counties, TX (1) Daily production for the three month period ended September 30, 2014. (2) Represents reported sales volumes. 7 (3) Eagle Ford production includes 2 Boe/d from other non-core assets that were divested in Q1 2018.
Company Overview • The Woodlands, Texas based E&P company focused on development and (3) production of oil and natural gas with current operations in the Midland Basin 12/31/2017 Proved Reserves (~26,700 core net acres) and the Eagle Ford (~16,000 core net acres) ‐ Closed sale of Bakken assets in December 2017 • Strategy of growing through the drill bit, organic leasing, and attractive asset Oil Gas NGL Total PV-10 acquisitions and business combinations Category (MMBbls) (MMMcf) (MMBbls) (MMBoe) ($mm) (1) • Q1 2018 production of 9,664 Boe/d (63% oil, 80% liquids) PDP 10.9 21.4 3.8 18.2 $274 • On May 9, 2017, Earthstone closed a business combination with Bold Energy III LLC PNP 1.1 1.9 0.4 1.8 $23 – 20,900 net acres(2) predominantly in Reagan, Upton, and Midland Counties PUD 35.5 68.1 13.4 60.3 $344 – 500+ gross locations; 99% operated; average 87% working interest(2) • In May 2016, Earthstone closed its business combination with Lynden Energy 1P 47.5 91.4 17.5 80.3 $641 Corp. and established its initial presence in the Midland Basin ‐ 5,883(2) net acres in Howard, Glasscock, Midland, and Martin Counties ‐ 177 gross locations; average 40% working interest(2) Production Summary Market Statistics(5) Q1 2018 Net Production: 9,664 Boe/d ($mm, Except Share Price) Class A Common Stock (mm) 27.9 (4) Class B Common Stock (mm) 35.9 Eagle Ford, 2,097 Total Common Stock Outstanding (mm) 63.7 Stock Price (5/31/18) $8.84 Market Capitalization $563.4 Plus: Total Debt $30.0 Midland Basin, 7,567 Less: Cash ($11.1) Enterprise Value $582.3 (1) Represents reported sales volumes. (2) Acreage, locations and working interests as of the transaction date. (3) Reserve quantities and values were independently estimated by CG&A utilizing NYMEX 5-year strip prices as of December 31, 2017 (Oil – $59.55, $56.19, $53.76, $52.29, $51.67 / Gas - $2.84, $2.81, $2.82, $2.85, $2.89). See “Non-GAAP Financial Measure – PV-10”. 8 (4) Eagle Ford production includes 2 Boe/d from other non-core assets that were divested in Q1 2018. (5) Class A and Class B Common Stock outstanding as of April 26, 2018. Total debt and cash balances as of March 31, 2018.
Earthstone by the Numbers: Increased Size, Scale and Core Inventory Midland Basin Net Acres 26,700 Net Midland Basin Locations 500 % Operated in Midland Basin 77% Operations Q1 2018 Production (Mboe/d)(1) 9.7 Q1 2018 Production (% Oil / % Liquids) 63% / 80% 12/31/2017 Proved Reserves (MMboe)(2) 80.3 12/31/2017 PV-10 ($mm)(2) $641 Reserves % Oil / % Liquids 59% / 81% Q1 2018 Revenue ($mm) $41 Q1 2018 Adjusted EBITDAX ($mm)(3) $25 Q1 2018 LOE ($/boe)(4) $5.35 Q1 Financial Q1 Q1 2018 G&A ($/boe)(5) $5.33 Borrowing Base ($mm) $225 (1) Represents reported sales volumes. (2) Reserve quantities and values were independently estimated by CG&A utilizing NYMEX 5-year strip prices as of December 31, 2017 (Oil – $59.55, $56.19, $53.76, $52.29, $51.67 / Gas - $2.84, $2.81, $2.82, $2.85, $2.89). See “Non-GAAP Financial Measure – PV-10”. (3) Excludes transaction costs. See “Reconciliation of Non-GAAP Financial Measure – Adjusted EBITDAX”. (4) Includes re-engineering, workovers and ad valorem taxes. 9 (5) Excludes transaction costs and non-cash stock-based compensation.
Robust Growth with a Focus on Operations and Balance Sheet Average Daily Production (Boe/d)(1) Adj. EBITDAX ($mm)(3) 16,000 $120.0 (4) $101.2 (2) 12,250 12,000 $90.0 9,664 7,869 $60.6 8,000 $60.0 4,002 3,936 ($mm) EBITDAX $26.5 4,000 $30.0 $18.7 Average Daily Production (Boe/d) 0 $0.0 Lease Operating Expense ($/Boe)(5) Net Debt / LTM EBITDAX $12.00 $10.95 2.0x $10.29 $9.00 1.5x $6.84 (2) $6.00 $5.35 $5.00 1.0x $3.00 0.5x LOE per Boe ($/Boe) 0.2x 0.2x Net Debt / LTM EBITDAX (x) 0.0x $0.00 0.0x (1) Represents reported sales volumes. (2) Reflects midpoint of 2018 FY Guidance. (3) Excludes transaction costs. See “Reconciliation of Non-GAAP Financial Measure – Adjusted EBITDAX”. 10 (4) Based Q1 2018 Adjusted EBITDAX of $25.3mm on an annualized basis. (5) Includes re-engineering, workovers and ad valorem taxes.
Areas of Operations Eagle Ford 1P Reserves (MMBoe) 6.5 % PD 73% % Oil 62% PV-10 ($mm) 82.1 Q1 2018 Net Production (Boe/d)(1,2) 2,097 Midland Basin Gross Producing Wells 165 1P Reserves (MMBoe) 73.7 Core Net Acres 16,000 % PD 21% Core Gross Drilling Locations 161 % Oil 59% PV-10 ($mm) 559.1 Q1 2018 Net Production (Boe/d)(1) 7,567 Total Gross Producing Wells 195 1P Reserves (MMBoe) 80.3 Core Net Acres 26,700 % PD 25% Core Gross Drilling Locations 943 % Oil 59% PV-10 ($mm) 641.2 Q1 2018 Net Production (Boe/d)(1) 9,664 Gross Producing Wells 361 Core Net Acres 42,700 Core Gross Drilling Locations 1,104 Notes: Reserve quantities and values were independently estimated by CG&A utilizing NYMEX 5-year strip prices as of December 31, 2017 (Oil – $59.55, $56.19, $53.76, $52.29, $51.67 / Gas - $2.84, $2.81, $2.82, $2.85, $2.89). PV-10 is a non-GAAP financial measure. See “Non-GAAP Financial Measure – PV-10”. (1) Represents reported sales volumes. 11 (2) Eagle Ford production includes 2 Boe/d from other non-core assets that were divested in Q1 2018.
Asset Overview 12
Significant Position in the Midland Basin 26,700 Total Net Acres in Core of Midland Basin 943 gross locations identified in only 4 benches Significant Operated Position in Midland Basin(1) 20,500 net acres, 87% working interest, 526 gross locations identified in only 4 benches Q1 2018 Net Production of 7,567 Boe/d(2) (60% oil, 78% liquids) Wells in progress drive immediate production growth Attractive Rates of Returns (“ROR”)(3) Single well RORs of 80% - +100% Position Delineated In Multiple Benches Strong offset results in the Wolfcamp A and B, Lower Spraberry, Significant Wolfcamp C potential Completion Evolution Sets Stage for Further Well Acreage Legend Performance Improvement Operated Non-Operated (1) Does not include non-operated position. (2) Represents reported sales volumes for both operated and non-operated properties. (3) Single well rates of return based on flat price deck of Oil – $60.00/Bbl, Gas - $3.00/Mcf before deductions for transportation, gathering and quality differential. 13
Consistent Thickness in Place Across the Operated Position . Reagan County Wolfcamp Wolfcamp Formation Isopach (Midland Basin)(1) ‐ Thickest Wolfcamp shale section in Midland Basin . Current Reagan inventory ‐ 1 Wolfcamp A target ‐ 2 Wolfcamp B targets ‐ 1 Wolfcamp C target . 7 viable target benches tested or developed by industry ‐ 2 Wolfcamp A targets ‐ 3 Wolfcamp B targets ‐ 1 Wolfcamp C target ‐ 1 Wolfcamp D target . Offset operators have developed five benches in a stacked “wine rack” pattern ‐ 2 Wolfcamp A targets ‐ 3 Wolfcamp B targets . Thermal maturity places ESTE’s acreage in oil window with low gas/oil ratios (“GOR”) ‐ Average 80% Liquids, 20% Gas . Shallower true vertical depth (“TVD”) than northern end of Midland Basin ‐ D&C costs are lower Source: University of Texas Bureau of Economic Geology. 14 (1) Does not include Wolfcamp A in the Wolfcamp Isopach.
High Quality Pay Across Multiple Zones Reagan County Type Section Reagan Co. Resource Greater than Midland Co. North Midland Central Reagan Dean Dean Wolfcamp A Wolfcamp A Wolfcamp Wolfcamp B Upper B Wolfcamp A Thickness increases 50-100’ from Midland to Reagan County. Wolfcamp Lower B Wolfcamp B Wolfcamp C Thickness increases 250-300’ Wolfcamp from Midland to Reagan County. C Wolfcamp C Bench is much thicker in Reagan County. Wolfcamp D Wolfcamp D Primary Targets Prospective Targets(1) (1) Prospective targets tested in offset wells by other operators. 15
Significant Acreage Position in Midland Basin Core at an Attractive Price Selected Midland Basin Transactions RSPP/Adventure – 7/2014 Oxy/Vanguard – 3/2017 Purchase price: $259mm Purchase price: $105 mm Production, net: 1,100 boe/d Production, net: 203 boe/d Acreage: 6,652 Acreage: 3,048 Adj. $/acre: $30,667 Adj. $/acre: $32,118 Parsley/PCORE – 12/2015 Purchase price: $149mm Production, net: 1,000 boe/d Acreage: 5,274 Adj. $/acre: $21,521 Parsley/Riverbend – 4/2016 Purchase price: $215mm Production, net: 1,100 boe/d Acreage: 8,700 Adj. $/acre: $20,893 Parsley/Cimarex – 8/2014 Purchase price: $252mm Production, net: 1,800 boe/d Acreage: 5,472 Adj. $/acre: 29,605 AEP/Tall City– 10/2014 AEP/Enduring – 6/2014 Purchase price: $726mm Purchase price: $2,500mm Production, net: 1,400 boe/d Production, net: 16,000 boe/d Acreage: 27,000 Acreage: 63,000 Adj. $/acre: $24,296 Adj. $/acre: $26,984 ESTE Operated ESTE Non-Op Compelling Bold purchase price of ~$12,000(1) per undeveloped net acre compares favorably to recent Midland Basin acquisitions Source: Company filings and 1Derrick. Note: Includes transactions with purchase prices greater than or equal to $100mm at announcement in Reagan, Glasscock and Upton counties for which transaction price and PDP is publicly available. Transaction value excludes PDP value of: $50,000/boe/d for transactions in 2014, $35,000/boe/d for transactions in 2015, $30,000/boe/d in 1H 2016 and $35,000/boe/d thereafter. 16 (1) Based on announced transaction value of ~$324mm on 11/8/2016 and PDP value of $35,000/boe/d.
Recent Southern Midland Basin Results 1 Pioneer 9 SEM XBC Giddings Est. 434C #3H University 9 #2913WC Wolfcamp B Lower Wolfcamp B Lower IPW2: 1698 Boe/d (87% oil) IPW2: 1190 Boe/d (90% oil) 2 Pioneer 10 Earthstone (Bold) XBC Giddings Est. 434D #4H WTG 4-232 #1H Wolfcamp B Lower Wolfcamp B Upper 16 IPW2: 1447 Boe/d (88% oil) IPW2: 942 Boe/d (93% oil) 3 11 Discovery 1 Pioneer XBC Giddings Est. 434G #7H Hickman E #2085SH 2 3 5 Wolfcamp B Lower Wolfcamp B Upper IPW2: 1320 Boe/d (90% oil) 4 IPW2: 1945 Boe/d (81% oil) 15 4 Pioneer 12 Earthstone (Bold) Brook A-5B #2H WTG 5-234 B #3HM Wolfcamp B Lower Wolfcamp B Upper IPW2: 1401 Boe/d (87% oil) IPW2: 1981 Boe/d (83% oil) 5 Parsley 13 Tracker Kathryn 44-5 #4215 Barnhart 76N78 #1LU 6 7 13 Wolfcamp A Wolfcamp B Upper 14 9 IPW2: 1602 Boe/d (85% oil) IPW2: 1319 Boe/d (92% oil) 11 6 Hunt Oil 14 Earthstone (Bold) 10 12 University 3-35 #101HB RCR RE 1 180 #7HA Wolfcamp B Upper Wolfcamp B Upper 8 IPW2: 1497 Boe/d (91% oil) IPW2: 1893 Boe/d (86% oil) 7 Hunt Oil 15 Sable Earthstone Acreage University 3-35 #105HB Hughes West #112HA Wolfcamp B Upper Wolfcamp B Upper IPW2: 1320 Boe/d (92% oil) IPW2: 1070 Boe/d (87% oil) 8 PT Petroleum 16 Parsley University Orange #6091C Greg Maddux 31-32 #4301H Industry Well ESTE Well ESTE Planned 2018 Wolfcamp C Wolfcamp B Upper IPW2: 1101 Boe/d (93% oil) IPW2: 1655 Boe/d (83% oil) Source: Company filings and investor presentations. 17 Note: Well completions filed since Oct. 2017. IP tests are 24 hour tests.
Recent Wolfcamp C Activity in Southern Midland Basin 1 PE Taylor 45-33 #4601H 2 PE Paige 13A & 12A #4810H 6 IPW2: 2465 BO, 4495 MCFG IPW2: 1351 BO, 2856 MCFG 5 Cum: 290 MBO in 8 months (1) IP60 of 1600 Boe/d (~56% oil) (1) 13 15 3 Parsley 4 Parsley Char Hughes 28-2 #4803H Victor 1223 #4804H 2 IP24: 1,000+ BO/d (2) IP24: 445 BO, 573 MCF (11/17) 12 9 5 Laredo 6 Laredo 1 Lane Trust E 43-32 #1NL Lane Trust E 43-42 #5NL 16 IPW2: 607 BO, 933 MCF (12/17) IPW2: 491 BO, 1446 MCF (12/17) 14 17 10 7 PT Petroleum 8 Callon University Orange #6091C Eaglehead C A3 #26CH (2) 11 19 IPW2: 1026 BO,452 MCF (1/18) IP: 1,000+ Boe/d (85%-90% oil) 8 9 Parsley 10 Parsley 20 Oliver 39-34 #4807 Bast 34 & 39 #4809H 3 Completed Permitted May 2017 18 4 11 Parsley 12 Parsley Brynlee 9 & 8 #4809H Devin 25-24 #4801H Permitted May 2017 Permitted May 2017 13 Parsley 14 Parsley Nunn 5-44 #4803H Kathryn 43 & 42 #4803H Permitted October 2017 Permitted October 2017 7 15 Parsley 16 Parsley Paige 13C-12H #4815H Dallas Keuchel 37-36-C #4805H Permitted December 2017 Permitted December 2017 17 Parsley 18 Earthstone (Bold) Taylor 45 & 33 #4807H West Hartgrove 1 #2C Permitted January 2018 Permitted January 2018 ESTE Leasehold Wolfcamp C Well or Permit 19 Sable 20 Parsley Hughes East 7-22 #47HD Lucy Lindsay 1-36-H #4815H Permitted January 2018 Permitted January 2018 Note: Reflects Wolfcamp C permits filed since July 2016. (1) From November Press Release. 18 (2) From Company Press Releases. Wells are flowing back and may not have reached peak rates.
Differentiated, Balanced Inventory in Midland Basin Midland Basin Overview Gross Locations by Lateral Length and Target . Contiguous acreage positions provide significant Gross Locations by Lateral Length development advantage Target 5,000' - 6,250' 6,250' - 8,750' 8,750' - 10,000' Total % Total Lower Spraberry 1 46 40 87 9% . Long lateral development increases capital efficiency Wolfcamp A 9 112 160 281 30% . Over 95% of Midland horizontal locations have laterals of ~6,250 feet or greater Upper Wolfcamp B 9 98 159 266 28% – Over 50% of horizontal locations 8,750 feet or greater Lower Wolfcamp B 7 81 119 207 22% . Additional upside from: Wolfcamp C6554110211% – Middle Spraberry Total Gross Locations 32 392 519 943 100% – Jo Mill Total Net Locations 500 – Additional Lower Spraberry % Total (Gross) 3% 42% 55% 100% – Additional benches in Wolfcamp B – Wolfcamp D . Actively pursuing acreage and acquisition bolt-on opportunities to increase lateral lengths and ownership . Near-term drilling focused in the Wolfcamp A and the Wolfcamp B based on positive offset results, but are optimistic about the upside potential in other zones 19
Well Performance Update . All areas outperforming initial expectations . All areas and target horizons generating attractive returns at strip prices with cost inflation . Increased early time production profile while maintaining EUR – Improved rate of return (“ROR”) due to initial production outperforming previous type curves Reagan County Results(1) Midland and Upton County Results(2) 250 250 1,000 MBOE 2017 Reagan Co Avg. (16 wells) 200 200 Midland and Upton Co Avg. (7 wells) 2016 Reagan Co Avg. (2 wells) 850 MBOE 150 150 100 100 50 50 7,500' Norm CUMULATIVE PRODUCTION, MBOE (2 STREAM) 7,500' Norm CUMULATIVE PRODUCTION, MBOE (2 STREAM) 0 0 036912036912 TIME, MONTHS TIME, MONTHS Type Curve Summary (100% WI, 75% NRI 7,500' Laterals) DC & E(3) EUR Oil NGL ROR ( %) (4) County ($m) (MBoe) (%) (%) $50/$3 $60/$3 Midland / Upton $7,000 1,000 67% 20% >100% >100% Reagan $6,800 850 59% 22% 47% 88% (1) Reflects average cumulative production of wells completed in 2016 and 2017 in Reagan County. Average does not include wells once shut in for offset frac activity. (2) Reflects average cumulative production of wells completed in 2016 and 2017 in Upton and Midland Counties. (3) Reflects estimated 2018 drilling, completions and equipment costs, including production facilities. 20 (4) Single well rates of return assumes 3-stream economics on flat price deck of Oil – $50.00 and $60.00/Bbl, Gas - $3.00/Mcf before deductions for transportation, gathering and quality differential.
Blocking Up Acreage – East Central Upton County Pre Acreage Trade Acreage Trade Highlights Completed trade with offset operator to block up acreage for longer laterals Earthstone now has 2,650 net acres in the Benedum prospect with average 95% WI (80% NRI) Trade gives Earthstone 75 gross potential drilling locations in the Wolfcamp A, Upper B, and Lower B Average lateral length ~ 6,650’ 2 wells planned for 2018 Post Acreage Trade 21
Blocking Up Acreage – Southeast Reagan County Pre Acreage Trade Acreage Trade Highlights Completed trade with offset operator and became operator of the RCR RE 180 well and unit 480 net acres in the RCR Unit with 100% WI (76% NRI) Ability to drill future wells with 7,500 ft laterals Retained 2.5% ORRI in offsetting 640 acre standup unit RCR RE 180 well online in December 2017 Continuing to pursue other adjacent acreage Post Acreage Trade acquisitions/trades to increase lateral lengths 2.5% ORRI 22
Eagle Ford Asset Overview Karnes, Gonzales, and Fayette Counties, Texas . Operated Karnes, Gonzales, and Fayette Counties – 33,600 gross / 16,000 net leasehold acres – Working interests range from 17% to 50% – 60% held-by-production . 104 gross / 44.8 net producing wells (98 operated / 6 non-op) . 161 identified gross Eagle Ford drilling locations . Majority of acreage covered by 173 square mile 3-D seismic shoot – Avoid faulting for steering Eagle Ford wells – Indicate natural fractures Earthstone Lonestar Penn Virginia – Delineate other prospective opportunities . Other Potential: Upper Eagle Ford, Austin Chalk, Buda, Wilcox, and Edwards . Non-operated La Salle County – 61 gross producing wells – 25,100 gross / 2,900 net leasehold acres – Working interests range from 10% to 15% Offset operators include EOG, Encana and Marathon 23
Recent Eagle Ford Activity . 11 gross wells drilled in southwestern Gonzales County and completed in late 2017 and early 2018 Pilgrim and – 2 wells in Davis Unit (~5,300 foot lateral); 17% Davis Units working interest – 3 wells in Pilgrim Unit (~7,300 foot lateral); 19% working interest – 6 wells in Crosby Unit (~4,900 foot lateral); 25% working interest . Joint Development Agreements (“JDA”) with IOG Capital to fund a majority of Earthstone’s capital expenditures for a 50% interest in 13 wells in the Eagle Ford (11 drilled in 2017 and completed in 2017 and beginning of 2018) – JDAs in the Pilgrim, Davis and Crosby Units Crosby Unit – Operated interests previously included 33% in Davis Unit, 38% in Pilgrim Unit and 50% in Crosby Unit – Reduced estimated 2017 budget by $17 million . Offsetting successful Earthstone Boggs Unit Boggs Unit – 4 wells completed in October 2016 – Cumulative production of 596 MBoe (93% oil) through January 2018 – Average lateral length of ~6,260 feet – Average proppant of ~2,260 lbs/ft . 2018 drilling and completion plans to offset the Davis and Crosby Units – 10 well drilling program began in March 2018 24
Financial Overview 25
2018 Capital Budget, Guidance and Liquidity 2018 Capital Budget(1) 2018 FY Guidance(1)(2) Gross / Net Well Count 2018 Average Production (Boe/d) 12,000 – 12,500 $mm Spudded On-Line % Oil 64% Drilling and Completion: % Gas 17% Operated Midland Basin 130 20 / 19 22 / 19.6 % NGL 19% Non-Operated Midland Basin 14 5 / 2 5 / 2 Operating Costs: Operated Eagle Ford 12 10 / 2.1 16 / 3.6 Lease Operating and Workover ($/Boe) $4.75 – $5.25 Land / Infrastructure 14 Production Taxes (% of Revenue) 5.0% – 5.3% Total $170 G&A ($/Boe) $5.00 – $5.50 2018 Capex by Project Area(1) Liquidity (3/31/18)(3) Total Capex D&C Capex ($mm) 3/31/2018 8% 8% Cash 11.1 7% Revolver Borrowings 30.0 8% Total Debt $30.0 Revolver Borrowing Base(4) 225.0 77% Less: Revolver Borrowings (30.0) 92% Plus: Cash 11.1 Operated Midland Basin Non-Operated Midland Basin Midland Basin Eagle Ford Liquidity $206.1 Operated Eagle Ford Land / Infrastructure Notes: (1) Assumes a 1-rig program for the operated Midland Basin acreage. (2) G&A excludes transaction costs and non-cash stock-based compensation. Guidance is forward-looking information that is subject to a number of risks and uncertainties, many of which are beyond Earthstone’s control. 26 (3) Revolver balance of $30mm and cash balance of $11.1mm as of March 31, 2018. (4) Borrowing Base of $185mm as of 3/31/2018 that was increased to $225mm on 5/23/2018.
Hedging Summary Oil Production Hedged Gas Production Hedged Period Volume (Bbls) $/Bbl Period Volume (MMBtu) $/MMBtu Q2 2018 387,350 $51.72 Q2 2018 605,000 $2.947 Q3 2018 367,700 $51.27 Q3 2018 610,000 $2.947 Q4 2018 321,700 $50.16 Q4 2018 610,000 $2.947 Q1 2019 270,000 $55.42 Q2 2019 273,000 $55.42 Q3 2019 276,000 $55.42 Q4 2019 257,600 $55.18 Midland Cushing Basis Differential Oil Swaps: . Q2 – Q4 2018 Midland Cushing Basis Swap of 453,750 Bbls (1,650 Bbl/day) at -$0.15 per Bbl . 2019 – 2020 Midland Cushing Basis Swap of 731,000 Bbls (1,000 Bbl/day) at -$5.95 per Bbl 27
Analyst Coverage Firm Analyst Contact Info Baird Joseph Allman / 646-557-3209 / jdallman@rwbaird.com Euro Pacific Joel Musante / 800-727-7922 ext: 144 / jmusante@europac.net Imperial Capital Jason Wangler / 713-892-5603 / jwangler@imperialcapital.com Johnson Rice Ron Mills / 504-584-1217 / rmills@jrco.com KLR Brad Morris / 713-255-5063 / bm@klrgroup.com Northland Jeff Grampp / 949-600-4150 / jgrampp@northlandcapitalmarkets.com Roth John White / 949-720-7115 / jwhite@roth.com Mike Kelly, CFA / 713-658-6302 / mkelly@seaportglobal.com Seaport Global John Aschenbeck / 713-658-6343 / jaschenbeck@seaportglobal.com Stephens Ben Wyatt / 817-900-5714 / ben.wyatt@stephens.com SunTrust Neal Dingmann / 713-247-9000 / neal.dingmann@suntrust.com Wells Fargo Gordon Douthat / 303-863-6880 / gordon.douthat@wellsfargo.com 28
Contact Information Mark Lumpkin, Jr. EVP, Chief Financial Officer Scott Thelander Director of Finance Corporate Offices Houston 1400 Woodloch Forest Drive | Suite 300 | The Woodlands, TX 77380 | (281) 298-4246 Midland 600 N. Marienfeld | Suite 1000 | Midland, TX 79701 | (432) 686-1100 Website www.earthstoneenergy.com 29
Reconciliation of Non-GAAP Financial Measure – Adjusted EBITDAX Adjusted EBITDAX (as defined below) is presented herein and reconciled from the GAAP measure of net income because of its wide acceptance by the investment community as a financial indicator. We define “Adjusted EBITDAX” as net income plus, when applicable, accretion of asset retirement obligations; depletion, depreciation and amortization; interest expense, net; transaction costs; (gain) on sale of oil and gas properties; unrealized loss (gain) on derivatives; stock-based compensation; and income tax expense (benefit). Our Adjusted EBITDAX measure provides additional information that may be used to better understand our operations. Adjusted EBITDAX is one of several metrics that we use as a supplemental financial measurement in the evaluation of our business and should not be considered as an alternative to, or more meaningful than, net income as an indicator of operating performance. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic cost of depreciable and depletable assets. Adjusted EBITDAX, as used by us, may not be comparable to similarly titled measures reported by other companies. We believe that Adjusted EBITDAX is a widely followed measure of operating performance and is one of many metrics used by our management team and by other users of our consolidated financial statements. For example, Adjusted EBITDAX can be used to assess our operating performance and return on capital in comparison to other independent exploration and production companies without regard to financial or capital structure and to assess the financial performance of our assets and our Company without regard to capital structure or historical cost basis. The following table provides a reconciliation of Net income to Adjusted EBITDAX for the period indicated: ($000's) Q1 2018 Net income $12,191 Accretion of asset retirement obligations 41 Depletion, depreciation and amortization 9,708 Interest expense, net 613 (Gain) on sale of oil and gas properties (449) Unrealized loss (gain) on derivative contracts 1,000 Stock‐based compensation (non‐cash) 1,940 Income tax expense (benefit) 249 Adjusted EBITDAX $25,293 30
Non-GAAP Financial Measure – PV-10 PV-10 is derived from the Standardized Measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the Standardized Measure on a pre-tax basis. PV-10 is equal to the Standardized Measure at the applicable date, before deducting future income taxes, discounted at 10%. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the Standardized Measure. Our PV-10 measure and the Standardized Measure do not purport to present the fair value of our oil and natural gas reserves. Earthstone’s proved reserves as of December 31, 2017 were independently estimated by CG&A utilizing NYMEX 5-year strip prices as of December 31, 2017 (Oil – $59.55, $56.19, $53.76, $52.29, $51.67 / Gas - $2.84, $2.81, $2.82, $2.85, $2.89). 31