Investor Presentation March 15, 2018 Exhibit 99.1

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 management or key technical personnel. Earthstone’s 2017 Annual Report on Form 10-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.

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.

Prudently Managed Balance Sheet Liquidity of $183 million(1), adequate to fund near-term capital expenses Conservative capital structure with low leverage Traditional reserve-based credit facility with standard covenants Proven Management Team Four prior successful public entities Operational excellence Repeat institutional investors Market recognition from investors and sellside research analysts Midland Basin Focused Company with Growing Inventory Actively growing in the Midland Basin Growth through drill bit, acquisitions and significant business combinations ~950 total gross drilling locations across core play in Midland Basin Upside from down-spacing and added benches Visible Production Growth & Drilling Program with Substantial Optionality Midland Basin and Eagle Ford wells-in-progress provide ability to ramp up production quickly Majority of acreage in key areas is HBP Investment Highlights (1)Liquidity estimated as of December 31, 2017 based on $25mm drawn on revolving credit facility and $23mm of cash on hand. Borrowing base was increased to $185mm in Q4 2017.

Track Record 2001 – 2004 AROC, Inc. (Private) Gulf Coast, Permian Basin, Mid-Con. Preferred investors – 17% IRR Initial investors – 4x return 2005 – 2007 Southern Bay Energy, LLC (Private) Gulf Coast, Permian Basin Initial investors – 40% IRR 1997 – 2001 Texoil, Inc. (“TXLI”) Gulf Coast, Permian Basin Preferred investors – 2.5x return Follow-on investors – 3x return Initial investors – 10x return 1992 – 1996 Hampton Resources Corp. (“HPTR”) Gulf Coast Preferred investors – 30% IRR Initial investors – 7x return Management team has consistently created shareholder value Repeated success with multiple entities over 25 years Results have created long-term and recurring shareholders Extensive industry and financial relationships Technical and operational excellence Multi-basin experience Resource & conventional expertise Complex drilling & horizontal resource proficiency Efficient and low-cost operator Proven acquisition and exploitation results 2007 – 2012 GeoResources, Inc. (“GEOI”) Eagle Ford, Bakken / Three Forks, Gulf Coast Initial investors – 35% IRR Initial investors – 4.8x return Initial Southern Bay investors achieved a combined 7.4x ROI upon the merger with GeoResources and subsequent sale in 2012 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.

Management Strong management and technical team with demonstrated ability and prior success Equity ownership - interests are clearly aligned with shareholders Years of Experience Years Working Together Responsibility Frank Lodzinski 45 29 President and CEO Robert Anderson 30 14 Corporate Development and Engineering Mark Lumpkin 20 1 CFO Steve Collins 28 21 Completions and 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 Scott Thelander 11 1 Finance

Earthstone – A Platform for Steady Growth December 2014 Q2/Q3 2015 Private Sellers Eagle Ford Karnes, Gonzales, Fayette Counties, TX December 2014 Strategic Combination Eagle Ford Operator Q2 2016 Midland Basin 5,883 Net Acres Howard, Glasscock Counties, TX Resource Expansion November 2014 Bakken / Three Forks 662 Boe/d(1) Q4 2017 Midland Basin Eagle Ford Bakken / Three Forks 9,071 Boe/d(2) Q2 2017 Midland Basin 20,900 Net Acres Reagan, Upton, Midland Counties, TX Daily production for the three month period ended September 30, 2014. Represents reported sales volumes. 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 (1)

Company Overview 12/31/2017 Proved Reserves(2) The Woodlands, Texas based E&P company focused on development and production of oil and natural gas with current operations in the Midland Basin (~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 acquisitions and business combinations Q4 2017 production of 9,071 Boe/d (63% oil, 81% liquids)(1) On May 9, 2017, Earthstone closed a business combination with Bold Energy III LLC 20,900 net acres predominantly in Reagan, Upton, and Midland Counties 500+ gross locations; 99% operated; average 87% working interest In May 2016, Earthstone closed its business combination with Lynden Energy Corp. and established its initial presence in the Midland Basin 5,883 net acres in Howard, Glasscock, Midland, and Martin Counties 177 gross locations; average 40% working interest Production Summary Q4 2017 Net Production: 9,071 Boe/d Represents reported sales volumes. 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, $2.89). See “Non-GAAP Financial Measure – PV-10”. Bakken and other non-core assets were divested in Q4 2017. Class A and Class B Common Stock outstanding as of March 5, 2018. Total debt and cash balances as of December 31, 2017. Market Statistics(4) (3) Category Oil (MMBbls) Gas (MMMcf) NGL (MMBbls) Total (MMBoe) PV-10 ($mm) PDP 10.9 21.4 3.8 18.2 $274 PNP 1.1 1.9 0.4 1.8 $23 PUD 35.5 68.1 13.4 60.3 $344 1P 47.5 91.4 17.5 80.3 $641

Represents reported sales volumes. 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, $2.89). See “Non-GAAP Financial Measure – PV-10”. Excludes transaction costs. See “Reconciliation of Non-GAAP Financial Measure – Adjusted EBITDAX”. Includes re-engineering, workovers and ad valorem taxes. Excludes transaction costs and non-cash stock-based compensation. Borrowing Base ($mm) $185 Q4 2017 Revenue ($mm) $36 Q4 2017 LOE ($/boe)(4) $5.59 Q4 2017 G&A ($/boe)(5) $6.75 Q4 2017 Adjusted EBITDAX ($mm)(3) $22 Q4 Financial 12/31/2017 Proved Reserves (MMboe)(2) 80.3 % Oil / % Liquids 59% / 81% Reserves Operations Midland Basin Net Acres 26,700 Net Midland Basin Locations 500 Q4 2017 Production (Mboe/d)(1) 9.1 Q4 2017 Production (% Oil / % Liquids) 63% / 81% % Operated in Midland Basin 77% Earthstone by the Numbers: Increased Size, Scale and Core Inventory 12/31/2017 PV-10 ($mm)(2) $641

Represents reported sales volumes. Reflects midpoint of 2018 FY Guidance. Excludes transaction costs. See “Reconciliation of Non-GAAP Financial Measure – Adjusted EBITDAX”. Q4 2017 Adjusted EBITDAX = $22.1mm on an annualized basis. Includes re-engineering, workovers and ad valorem taxes. Robust Growth with a Focus on Operations and Balance Sheet Average Daily Production (Boe/d)(1) Adj. EBITDAX ($mm)(3) Net Debt ($mm) Lease Operating Expense ($/Boe)(5) (2) (4) (2)

Total 1P Reserves (MMBoe)80.3 % PD25% % Oil59% PV-10 ($mm)641.2 Q4 2017 Net Production (Boe/d)(1,2)9,071 Gross Producing Wells361 Core Net Acres42,700 Core Gross Drilling Locations1,104 Eagle Ford 1P Reserves (MMBoe)6.5 % PD73% % Oil62% PV-10 ($mm)82.1 Q4 2017 Net Production (Boe/d)(1)1,773 Gross Producing Wells165 Core Net Acres16,000 Core Gross Drilling Locations161 Midland Basin 1P Reserves (MMBoe)73.7 % PD21% % Oil59% PV-10 ($mm)559.1 Q4 2017 Net Production (Boe/d)(1) 6,393 Gross Producing Wells195 Core Net Acres26,700 Core Gross Drilling Locations943 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”. Represents reported sales volumes. Includes Bakken and other non-core production that was divested in Q4 2017. Areas of Operations

Asset Overview

Significant Operated Position in Midland Basin(1) 20,500 net acres, 87% working interest, 526 gross locations identified in only 4 benches Q4 2017 Net Production of 6,393 Boe/d(2) (63% oil, 81% 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 Performance Improvement Does not include non-operated position. Represents reported sales volumes. 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. Significant Position in the Midland Basin Acreage Legend Operated Non-Operated 26,700 Total Net Acres in Core of Midland Basin 943 gross locations identified in only 4 benches

Reagan County Wolfcamp 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. (1)Does not include Wolfcamp A in the Wolfcamp Isopach. Consistent Thickness in Place Across the Operated Position Wolfcamp Formation Isopach (Midland Basin)(1)

Reagan County Type Section Dean Wolfcamp Upper B Wolfcamp Lower B Wolfcamp A Wolfcamp C Wolfcamp D Primary Targets Prospective Targets(1) North Midland Central Reagan Dean Wolfcamp A Wolfcamp B Wolfcamp C Wolfcamp D Reagan Co. Resource Greater than Midland Co. Wolfcamp A Thickness increases 50-100’ from Midland to Reagan County. Wolfcamp B Thickness increases 250-300’ from Midland to Reagan County. Wolfcamp C Bench is much thicker in Reagan County. (1)Prospective targets tested in offset wells by other operators. High Quality Pay Across Multiple Zones

Selected Midland Basin Transactions AEP/Tall City– 10/2014 Purchase price: $726mm Production, net: 1,400 boe/d Acreage: 27,000 Adj. $/acre: $24,296 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/Enduring – 6/2014 Purchase price: $2,500mm Production, net: 16,000 boe/d Acreage: 63,000 Adj. $/acre: $26,984 Oxy/Vanguard – 3/2017 Purchase price: $105 mm Production, net: 203 boe/d Acreage: 3,048 Adj. $/acre: $32,118 RSPP/Adventure – 7/2014 Purchase price: $259mm Production, net: 1,100 boe/d Acreage: 6,652 Adj. $/acre: $30,667 Parsley/PCORE – 12/2015 Purchase price: $149mm Production, net: 1,000 boe/d Acreage: 5,274 Adj. $/acre: $21,521 ESTE Operated ESTE Non-Op 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. (1) Based on announced transaction value of ~$324mm on 11/8/2016 and PDP value of $35,000/boe/d. Significant Acreage Position in Midland Basin Core at an Attractive Price Compelling Bold purchase price of ~$12,000(1) per undeveloped net acre compares favorably to recent Midland Basin acquisitions

PT Petroleum University Orange #6091C Wolfcamp C IPW2: 1101 Boe/d (93% oil) Hunt Oil University 3-35 #105HB Wolfcamp B Upper IPW2: 1320 Boe/d (92% oil) Hunt Oil University 3-35 #101HB Wolfcamp B Upper IPW2: 1497 Boe/d (91% oil) Parsley Kathryn 44-5 #4215 Wolfcamp A IPW2: 1602 Boe/d (85% oil) Pioneer Brook A-5B #2H Wolfcamp B Lower IPW2: 1401 Boe/d (87% oil) Pioneer XBC Giddings Est. 434G #7H Wolfcamp B Lower IPW2: 1945 Boe/d (81% oil) Pioneer XBC Giddings Est. 434D #4H Wolfcamp B Lower IPW2: 1447 Boe/d (88% oil) Recent Southern Midland Basin Results Pioneer XBC Giddings Est. 434C #3H Wolfcamp B Lower IPW2: 1698 Boe/d (87% oil) Parsley Greg Maddux 31-32 #4301H Wolfcamp B Upper IPW2: 1655 Boe/d (83% oil) 16 1 14 Earthstone (Bold) WTG 4-232 #1H Wolfcamp B Upper IPW2: 942 Boe/d (93% oil) Earthstone (Bold) WTG 5-234 B #3HM Wolfcamp B Upper IPW2: 1981 Boe/d (83% oil) Tracker Barnhart 76N78 #1LU Wolfcamp B Upper IPW2: 1319 Boe/d (92% oil) Earthstone (Bold) RCR RE 1 180 #7HA Wolfcamp B Upper IPW2: 1893 Boe/d (86% oil) Sable Hughes West #112HA Wolfcamp B Upper IPW2: 1070 Boe/d (87% oil) Discovery Hickman E #2085SH Wolfcamp B Upper IPW2: 1320 Boe/d (90% oil) SEM University 9 #2913WC Wolfcamp B Lower IPW2: 1190 Boe/d (90% oil) 2 3 4 5 Earthstone Well Industry Well 2 1 3 6 6 7 7 9 8 8 9 10 12 11 11 10 12 16 15 13 14 13 15 5 4 Earthstone Acreage ESTE Planned 2018 Source: Company filings and investor presentations. Note: Well completions filed since Oct. 2017. IP tests are 24 hour tests.

ESTE Leasehold Wolfcamp C Well or Permit 1 17 2 3 4 5 6 7 8 9 10 11 12 13 16 14 15 PE Taylor 45-33 #4601H IPW2: 2465 BO, 4495 MCFG Cum: 290 MBO in 8 months (1) 1 PE Paige 13A & 12A #4810H IPW2: 1351 BO, 2856 MCFG IP60 of 1600 Boe/d (~56% oil) (1) 2 Parsley Char Hughes 28-2 #4803H IP24: 1,000+ BO/d (2) 3 Parsley Victor 1223 #4804H IP24: 445 BO, 573 MCF (11/17) 4 Laredo Lane Trust E 43-32 #1NL IPW2: 607 BO, 933 MCF (12/17) 5 Laredo Lane Trust E 43-42 #5NL IPW2: 491 BO, 1446 MCF (12/17) 6 PT Petroleum University Orange #6091C IPW2: 1026 BO,452 MCF (1/18) 7 Callon Eaglehead C A3 #26CH IP: 1,000+ Boe/d (85%-90% oil) (2) 8 Parsley Oliver 39-34 #4807 Completed 9 Parsley Bast 34 & 39 #4809H Permitted May 2017 10 Parsley Brynlee 9 & 8 #4809H Permitted May 2017 11 Parsley Devin 25-24 #4801H Permitted May 2017 12 Parsley Nunn 5-44 #4803H Permitted October 2017 13 Parsley Kathryn 43 & 42 #4803H Permitted October 2017 14 Parsley Paige 13C-12H #4815H Permitted December 2017 15 Parsley Dallas Keuchel 37-36-C #4805H Permitted December 2017 16 Parsley Taylor 45 & 33 #4807H Permitted January 2018 17 Earthstone (Bold) West Hartgrove 1 #2C Permitted January 2018 18 Sable Hughes East 7-22 #47HD Permitted January 2018 19 Parsley Lucy Lindsay 1-36-H #4815H Permitted January 2018 20 20 19 Note: Reflects Wolfcamp C permits filed since July 2016. From November Press Release. From Company Press Releases. Wells are flowing back and may not have reached peak rates. Recent Wolfcamp C Activity in Southern Midland Basin 18

Gross Locations by Lateral Length and Target Contiguous acreage positions provide significant development advantage Long lateral development increases capital efficiency Over 95% of Midland horizontal locations have laterals of ~6,250 feet or greater Over 50% of horizontal locations 8,750 feet or greater Additional upside from: Middle Spraberry Jo Mill Additional Lower Spraberry 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 Midland Basin Overview Differentiated, Balanced Inventory in Midland Basin

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) 1,000 MBOE Well Performance Update 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. Reflects average cumulative production of wells completed in 2016 and 2017 in Upton and Midland Counties. Reflects estimated 2018 drilling, completions and equipment costs, including production facilities. 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. 850 MBOE

Blocking Up Acreage – East Central Upton County Post Acreage Trade Pre Acreage Trade 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 Acreage Trade Highlights

Blocking Up Acreage – Southeast Reagan County 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 acquisitions/trades to increase lateral lengths Post Acreage Trade Pre Acreage Trade 2.5% ORRI

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 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% Karnes, Gonzales, and Fayette Counties, Texas Earthstone Lonestar Penn Virginia Offset operators include EOG, Encana and Marathon Eagle Ford Asset Overview

11 gross wells drilled in southwestern Gonzales County and completed in late 2017 and early 2018 2 wells in Davis Unit (~5,300 foot lateral); 17% 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 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 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 Recent Eagle Ford Activity Crosby Unit Pilgrim and Davis Units Boggs Unit

Financial Overview

$mm Gross / Net Well Count Spudded On-Line Drilling and Completion: Operated Midland Basin 130 20 / 19 22 / 19.6 Non-Operated Midland Basin 14 5 / 2 5 / 2 Operated Eagle Ford 12 10 / 2.1 16 / 3.6 Land / Infrastructure 14 Total $170 2018 Capex by Project Area(1) 2018 Capital Budget(1) Notes: (1)Assumes a 1-rig program for the operated Midland Basin acreage. 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. Revolver balance of $25mm and cash balance of $23mm as of December 31, 2017. 2018 FY Guidance(1)(2) Current Liquidity (12/31/17)(3) 2018 Average Production (Boe/d) 12,000 – 12,500 % Oil 64% % Gas 17% % NGL 19% Operating Costs: Lease Operating and Workover ($/Boe) $4.75 – $5.25 Production Taxes (% of Revenue) 5.0% – 5.3% G&A ($/Boe) $5.00 – $5.50 Total Capex D&C Capex 2018 Capital Budget, Guidance and Current Liquidity

Hedging Summary Note: Does not include 2018 Midland basis swap of 602,250 bbls @ -$0.15.

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 Seaport Global Mike Kelly, CFA / 713-658-6302 / mkelly@seaportglobal.com 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

Frank Lodzinski President and CEO Robert Anderson EVP, Corporate Development and Engineering 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 Contact Information

Reconciliation of Non-GAAP Financial Measure – Adjusted EBITDAX The non-GAAP financial measure of Adjusted EBITDAX, as calculated by us below, is intended to provide readers with meaningful information that supplements our financial statements prepared in accordance with GAAP (Accounting Principles Generally Accepted in the U.S.). This disclosure may not be comparable to similarly titled measures used by other companies. Further, this non-GAAP measure should only be considered in conjunction with financial statements and disclosures prepared in accordance with GAAP and should not be considered in isolation or as a substitute for GAAP measures, such as net income or loss, operating income or loss, or any other GAAP measure of financial position or results of operations. Adjusted EBITDAX is used as a supplemental financial measure by our management and by external users of our financial statements, such as investors, commercial banks and others, to assess our operating performance compared to that of other companies in our industry, without regard to financing methods, capital structure or historical costs basis. We define “Adjusted EBITDAX” as net income (loss) plus, when applicable, accretion; impairment expense; depletion, depreciation and amortization; interest expense, net; transaction costs; (gain) on sale of oil and gas properties; exploration expense; rig idle expense; unrealized (gain) loss on derivatives; stock based compensation; and income tax (benefit). Our Adjusted EBITDAX should not be considered an alternative to net income (loss), operating income (loss), cash flow provided by (used in) operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDAX may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDAX in the same manner. The following table provides a reconciliation of Net income (loss) to Adjusted EBITDAX for the periods indicated:

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).