ex992esteinvpres20191106

Exhibit 99.2 Investor Presentation November 6, 2019 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,” “target,” “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: further and substantial declines in oil, natural gas liquids or natural gas prices; risks relating to any unforeseen liabilities; 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 levels 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 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 2018 Annual Report on Form 10-K, quarterly reports on Form 10-Q, recent current reports on Form 8-K 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 statementsexceptasrequiredbylaw. This presentation contains Earthstone’s 2019 production, capital expenditure and operating expense guidance. The actual levels of production, capital expenditures and operating expenses may be higher or lower than these estimates due to, among other things, uncertainty in drilling schedules, changes in market demand and unanticipated delays in production. These estimates are based on numerous assumptions. All or any of these assumptions may not prove to be accurate, which could result in actual results differing materially from estimates. No assurance can be made that any new wells will produce in line with historical performance, or that existing wells will continue to produce in line with expectations. For additional discussion of the factors that may cause us not to achieve our production estimates, see Earthstone’s filings with the SEC, including its Form 10-K and any amendments thereto. We do not undertake any obligation to release publicly the results of any future revisions we may make to this prospective data or to update this prospective data to reflect events or circumstances after the date of this presentation. Therefore, you are cautioned not to place undue reliance on this information. 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. Estimated Ultimate Recovery and Locations Management’s use of the term estimated ultimate recovery (“EUR”) in this presentation describes estimates of potentially recoverable hydrocarbons that the SEC rules prohibit from being included in filings with the SEC. These are more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized, particularly in areas or zones where there has been limited or no drilling history. We include EUR to demonstrate what we believe to be the potential for future drilling and production by Earthstone. Actual quantities that may be ultimately recovered may differ substantially from estimates. Factors affecting ultimate recovery include the scope of the operators' ongoing drilling programs, which will be directly affected by the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors, and actual drilling results, including geological and mechanical factors affecting recovery rates. Estimates of potential resources may also change significantly as the development of the properties underlying Earthstone's mineral interests provides additional data. 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. 2

Investment Highlights  Actively growing in the Midland Basin Midland Basin Focused  Growth through drill bit, acquisitions and significant business combinations Company with Leading Cost Structure  ~870 total gross drilling locations across core play in Midland Basin  Peer leading finding costs and cash margins  Conservative balance sheet with low leverage Prudent Financial  Traditional reserve-based credit facility with standard covenants Management  Significant liquidity  Favorable hedge position  Wells-in-progress provide ability to ramp up production Visible Production Growth & Drilling  Majority of acreage in key areas is HBP Program with  Minimal future drilling obligations Substantial Optionality  2019 Wellbore Development Agreement provides for enhanced economics  Prior successful entities Proven Management  Operational excellence Team  Repeat institutional investors  Management recognition from investors and sellside research analysts 3

Proven Leadership and Track Record of Value Creation Operating team has extensive experience running multi-rig development programs across various basins Leadership Team Years of Experience Years Working Together Title Frank Lodzinski 47 31 CEO Robert Anderson 32 15 President Steve Collins 31 23 Operations Mark Lumpkin 22 2 CFO Tim Merrifield 43 18 Geology and Geophysics Francis Mury 45 31 Drilling and Development Tony Oviedo 38 2 Accounting and Administration Track Record of Value Creation 1992-1996 2001-2004 2007-2012 2Q 2017 Hampton Resources Corp. (“HPTR”) AROC, Inc. (Private) GeoResources, Inc. (“GEOI”) Earthstone Acquired 20,900 Net Gulf Coast Gulf Coast, Permian Basin, Mid-Con. Eagle Ford, Bakken / Three Forks, Gulf Acres from Bold Energy III LLC in Initial investors – 7x return Initial investors – 4x return Coast, Austin Chalk Midland Basin Initial investors – 4.8x return 1992 1997 2001 2005 2007 2014 2017 2019 1997-2001 Texoil, Inc. (“TXLI”) 2005-2007 2014 Earthstone 3Q 2019 Gulf Coast, Permian Basin Southern Bay Energy, LLC (Private) Bakken (662 Boe/d) Earthstone Initial investors – 10x return Gulf Coast, Permian Basin Acquired Eagle Ford interests from Oak Midland Basin, Eagle Ford 12,181 Boe/d Initial Investors – 40% IRR Valley Resources 4

Midland Basin Growth Story . Since entering the Midland Basin in 2016, Earthstone has substantially increased production, proved reserves and core acreage while maintaining low leverage and preserving financial flexibility . The Company has meaningfully derisked its current position through the drill bit while significantly increasing its operated production Average Daily Production (Boe/d)(1) Total Proved Reserves (MMBoe)(2) 17,500 15,000 120 15,000 99 12,033 12,500 14,000 80 9,937 80 10,000 7,869 7,500 93 5,000 4,002 10,690 40 73 7,999 2,500 4,696 12 0 1,180 0 FY16A FY17A FY18A 9mos '19A 2019E FY16A FY17A FY18A Exit Rate Midland Basin Other Midland Basin Other Midland Basin Net Acres 1P PV-10 Growth ($MM)(2) 40,000 $1,200 $1,009 30,200 30,000 26,665 $900 $599 20,000 $600 $904 23,500 10,000 5,900 20,498 $300 $524 $86 0 $0 FY16A FY17A FY18A FY16A FY17A FY18A Operated Non‐Operated Midland Basin Other (1) Represents reported sales volumes (2) Reserve reports based on SEC pricing prepared by Cawley, Gillespie & Associates 5

Consistent Growth and Margin Expansion While Maintaining a Strong Balance Sheet Adjusted EBITDAX ($MM) Lease Operating Expenses ($/Boe)(1) $150.0 $12.00 $127.7 $10.29 $120.0 $96.2 $9.00 $90.0 $6.84 $6.86 $6.50 $5.66 $60.6 $6.00 $60.0 $3.00 $30.0 $18.7 $0.0 $0.00 (2) FY16A FY17A FY18A 9mos '19A FY16A FY17A FY18A 9mos Ended FY19 Annualized 3Q19A Guidance Debt / EBITDAX Cash G&A ($/Boe)(3) 1.2x $9.00 1.0x 1.0x $7.13 0.9x $6.43 0.8x $5.81 0.8x $6.00 $4.75 0.6x $4.22 0.4x 0.4x $3.00 0.2x – $0.00 (2) FY16A FY17A FY18A 9mos '19A FY16A FY17A FY18A 9mos Ended FY19 Annualized 3Q19A Guidance (1) Includes workovers and ad valorem taxes (2) Reflects midpoint of FY2019 guidance (3) Excludes stock-based compensation 6

Leading Finding Costs and Low Leverage vs. Permian Peer Groups FY 2018 F&D – All Sources ($/Boe) (1) $60.00 ESTE: Large-Cap (2) Avg: Mid-Cap (2) Avg: Small-Cap (2) Avg: $7.79 $17.56 $12.73 $22.66 $45.00 $42.56 $30.00 $22.59 $18.39 $18.60 $16.38 $15.89 $14.27 $15.11 $13.60 $15.00 $11.71 $9.97 $11.33 $11.39 $11.61 $11.75 $7.79 $0.00 ESTE Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 2Q19 Total Debt / LQA EBITDAX 6.0x ESTE: Large-Cap (2) Avg: Mid-Cap (2) Avg: Small-Cap (2) Avg: 5.0x 0.8x 1.2x 1.8x 2.2x 4.0x 3.0x 2.6x 2.6x 2.7x 2.2x 2.4x 1.9x 2.0x 1.5x 1.5x 1.6x 1.6x 1.7x 1.4x 1.3x 1.3x 0.8x 1.0x 0.7x – ESTE Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 (1) Calculated as: (Total Costs Incurred / (Reserve Revisions + Extensions & Discoveries + Purchases)) (2) Large-Cap (market capitalization >$10 billion) includes: CXO, FANG, PXD. Mid-Cap (market capitalization $1-10 billion) includes: CDEV, CPE, JAG, MTDR, SM, PE, WPX, XEC. Small-Cap (market capitalization <$1 billion) includes: AXAS, LPI, ROSE, REI 7

Leading Cash Margins But Undervalued Equity Trading Metrics 1H19 All-in Cash Margin ($/Boe) (1) $60.00 ESTE: Large-Cap (2) Avg: Mid-Cap (2) Avg: Small-Cap (2) Avg: $29.07 $25.21 $20.66 $21.16 $45.00 $29.07 $28.25 $30.00 $27.39 $26.24 $25.35 $23.96 $25.01 $22.89 $21.31 $21.56 $19.51 $20.42 $18.58 $16.27 $16.24 $15.00 $12.60 $0.00 ESTE Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Enterprise Value to 2020E EBITDAX (3) 12.0x ESTE: Large-Cap (2) Avg: Mid-Cap (2)(4) Avg: Small-Cap (2) Avg: 9.0x 2.5x 5.5x 4.0x 2.9x 6.0x 5.5x 6.0x 5.2x 4.9x 4.2x 4.3x 3.7x 3.7x 3.7x 3.9x 3.5x 3.1x 2.6x 2.9x 3.0x 2.5x 2.5x – ESTE Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Source: Factset, Wall Street research. Market Data as of 11/4/19 (1) All-in cash margin calculated on a per Boe basis as revenues after realized hedge impact less LOE, ad valorem and production taxes, transportation expense, cash G&A expense and interest expense. Excludes impact of income taxes. Cash G&A and interest expense includes expensing of capitalized cash G&A and capitalized interest expense, respectively. Companies that capitalized a portion of their cash G&A and/or interest expense include CDEV, CPE, CXO, FANG, and MTDR (2) Large-Cap (market capitalization >$10 billion) includes: CXO, FANG, PXD. Mid-Cap (market capitalization $1-10 billion) includes: CDEV, CPE, JAG, MTDR, SM, PE, WPX, XEC. Small-Cap (market capitalization <$1 billion) includes: AXAS, LPI, ROSE, REI (3) Enterprise Value based on 2Q19 company financials 8 (4) CPE’s enterprise value is adjusted for its recently announced acquisition of CRZO

Company Overview  The Woodlands, Texas based E&P company focused on development and production of oil and natural gas with current operations in the Midland Basin Asset Overview Midland Basin (~30,200 core net acres) and the Eagle Ford (~14,300 core net acres)  Strategy of growing through the drill bit, organic leasing, and attractive asset acquisitions and business combinations (1)  2019 3Q production of 12,181 Boe/d (58% oil, 81% liquids) Market Statistics(2) ($ in millions, except share price) Class A Common Stock (MM) 29.3 Class B Common Stock (MM) 35.3 Total Common Stock Oustanding (MM) 64.6 Stock Price (as of 11/4/19) $4.51 Market Capitalization $291.2 Plus: Total Debt $125.0 Less: Cash (9.8) Enterprise Value $406.4 Production Summary(1) 3Q19 Net Sales Volumes: 12,181 Boe/d Eagle Ford , 1,222 ESTE Operated ESTE Non-Operated Midland Basin, 10,959 (1) Reflects reported sales volumes (2) Class A and Class B Common Stock outstanding as of 11/1/19. Total debt and cash balances as of 9/30/19 9

Earthstone by the Numbers: Increased Size, Scale and Core Inventory Midland Basin Net Acres(1) 30,200 Midland Basin Locations (Gross / Net)(1) 866 / 496 Operated Midland Basin Locations (Gross / Net)(1) 500 / 398 Eagle Ford Net Acres(1) 14,300 Operations Eagle Ford Locations (Gross / Net)(1) 68 / 17 3Q 2019 Production (Boe/d)(2) 12,181 3Q 2019 Production (% Oil / % Liquids)(2) 58% / 81% PD Reserves (Mmboe) 23.6 (3) PD PV-10 ($mm) $436 1P Reserves (Mmboe) 98.8 1P PV-10 ($mm) $1,009 12/31/18 Reserves 12/31/18 1P % Oil / % Liquids 60% / 81% 3Q 2019 Revenue ($mm) $39.2 3Q 2019 Adjusted EBITDAX ($mm)(4) $29.8 3Q 2019 LOE ($/boe)(5) $6.48 3Q 2019 G&A ($/boe)(6) $3.59 3Q 2019 Financial 3Q Borrowing Base / Liquidity ($mm) $325 / $210 (1) Acreage and location count as of 12/31/18 (2) Represents reported sales volumes (3) Reserve quantities based on SEC pricing. See appendix for SEC reserves, non-GAAP reconciliation and a constant price case at $55 Oil / $2.75 Gas (4) See “Reconciliation of Non-GAAP Financial Measure” on page 28 (5) Includes workovers and ad valorem taxes 10 (6) Excludes non-cash stock-based compensation

Areas of Operations (1) Total Midland Basin (1) 1P Reserves (Mmboe) 98.8 1P Reserves (Mmboe) 93.4 % PD 24% % PD 21% % Oil 60% % Oil 58% PV-10 ($mm) $1,009 PV-10 ($mm) $904 (2) 3Q 2019 Net Production (Boe/d)(2) 12,181 3Q 2019 Net Production (Boe/d) 10,959 (3) Gross Producing Wells(3) 342 Gross Producing Wells 228 (4) Core Net Acres(4) 44,500 Core Net Acres 30,200 (4) Core Gross Drilling Locations(4) 934 Core Gross Drilling Locations 866 Eagle Ford (1) 1P Reserves (Mmboe) 5.4 % PD 71% % Oil 84% PV-10 ($mm) $104 3Q 2019 Net Production (Boe/d)(2) 1,222 Gross Producing Wells(3) 114 Core Net Acres(4) 14,300 Core Gross Drilling Locations(4) 68 (1) Reserve quantities based on SEC pricing. See appendix for SEC reserves, non-GAAP reconciliation and a constant price case at $55 Oil / $2.75 Gas (2) Represents reported sales volumes (3) As of 10/1/19 11 (4) Acreage and location count as of 12/31/18

Continuous Focus on Operational Improvement . Meaningful improvements in drilling days and prudent Actual Drilling, Completions & Equipment Cost / Foot (1) service cost management over past year $1,500 15 . Continue to see improvement in completion efficiencies $1,200 12 ― Improved completions efficiencies with 10-12 frac $1,008 stages per day $926 # of Wells $865 $900 $825 9 . Larger inventory of extended lateral locations also expected to drive improved efficiencies Foot $ / Lateral $600 6 . Earthstone’s completion evolution is setting the stage for further well performance improvement $300 3 ― Use of in-basin sand to help drive down costs while not $0 0 affecting well performance 2H17 FY18 YTD19 Target (2) Wells ― Continue to evaluate new completion techniques to (1)(3) cost effectively enhance well performance Spud to Rig Release Days 3.0 12,000 10,402 2.6 10,000 2.5 10,000 8,354 7,894 2.0 2.0 8,000 Average LateralLength 2.0 1.5 1.5 6,000 Track record of driving down costs through improved 1.0 4,000 operational efficiencies to drive returns per 1,000Days lateral Foot 0.5 2,000 0.0 0 2H17 FY18 YTD19 Target (2) Average Lateral Length (1) Excludes wells that required additional casing string or pilot well test. Includes operated Midland Basin wells only (2) Based on management targets (3) Spud to rig release days = average spud to rig release days / (average completed lateral foot/1000) 12

Drilling and Completion Efficiencies Lead to Increased IRRs . A continued focus on driving down costs and increased IRR Improvements with Decreased D&C Costs(1) efficiencies 120% ― Reduced drilling days as a result of improved 104% drilling efficiencies and the implementation of a 100% new high-spec rig 80% 74% ― Frac costs reductions through the use of in-basin sand and improved operations 60% 54% 40% . Reduced drilling times and frac costs lead to an Type Curve IRR % 40% overall reduction in capex which enhances economics 20% ― Reagan County economics increase by 35% ― Midland/Upton County economics increase by 41% 0% Reagan Midland/Upton $960 per Ft $825 per Ft All-in Frac Costs per Stage $125,000 Significantly increasing wellhead economics $100,000 $80,854 $77,167 $75,000 $59,276 $50,000 All-In Frac Costsper Stage ($) $25,000 $0 1H18 2H18 YTD19 (1) IRRs calculated assuming drilling, completions and equipment costs of $960 per lateral foot (current corporate type curve assumptions) and $825 per lateral foot (management’s target). Assumes pricing of $50 oil / $2.50 gas 13

Asset Overview 14

Significant Position in the Midland Basin 30,200 Total Net Acres in Core of Midland Basin Midland Basin Overview 866 gross locations(1) Significant Operated Position in Midland Basin(2) 23,300 net acres, 94% average working interest, 500 gross locations(1) 3Q 2019 Net Production of 10,959 Boe/d(3) (55% oil, 80% liquids) Wells in progress drive immediate production growth Attractive Rates of Returns (“IRR”)(4) Single well IRRs of 60% to +100% Position Delineated In Multiple Benches Strong offset results in the Wolfcamp A and B, Lower Spraberry, Additional Spraberry and Wolfcamp Benches ESTE Operated Completion Evolution Sets Stage for Further Well ESTE Non-Operated Performance Improvement (1) Acreage and location count as of 12/31/18 (2) Does not include non-operated position (3) Represents reported sales volumes for both operated and non-operated properties (4) Single well IRRs based on flat price deck of Oil – $60.00/Bbl, Gas - $3.00/Mcf before deductions for transportation, gathering and quality differential 15

High Quality Pay Across Multiple Zones Reagan County Type Section Proven Multi-Zone Development . Current Reagan inventory ― 1 Wolfcamp A target Dean ― 2 Wolfcamp B targets ― 1 Wolfcamp C target Wolfcamp . 8 targets across 5 benches tested by industry A . ESTE development focused on Wolfcamp A, BU, and BL . Effectively co-developing all three focus zones where returns in Wolfcamp each bench are attractive B Upper ― New 3 well Sinclair pad co-developed in A, BU, and BL on lease with existing BU and BL parent wells Wolfcamp B Lower Quality Geology Across Thick Interval . Reagan County Wolfcamp ― Thickest Wolfcamp shale section in Midland Basin . Thermal maturity in oil window with low gas/oil ratios (“GOR”) ― Tmax values 440-450 across ESTE acreage Wolfcamp ― Average 80% Liquids, 20% Gas C . Significant Oil in Place ― Wolfcamp A to Wolfcamp B Lower contains 90-120 Mmbo/sec . Shallower true vertical depth (“TVD”) than northern end of Midland Basin ― D&C costs are lower Wolfcamp D ― Target TVDs are between 7,300-8,500’ Primary ESTE Landing Targets Development Focus Interval 16

Recent Southern Midland Basin Results Southern Midland Basin Activity Map Recent Well Results Well Name Operator IPW2 (Boe/d) IP/1000' (Boe) % Oil 1 Jordan N 23-24 #2814H Double Eagle 1,395 133 88% 2 Torpedo 1048 B #5HA Apache 1,410 153 82% 3 University 3-310 PU #9H Pioneer 1,242 127 84% 4 Eaglehead C A4 #36AH Callon 1,306 179 83% 5 Jordan NN 23-24 #4314H Double Eagle 1,801 171 84% 18 6 Adely #34WB Summit 1,895 189 84% 7 Ratliff 9-7 B #2BU Earthstone 1,603 158 94% 8 Torpedo 1048 A #2HU Apache 1,944 211 89% 9 Sequoia #1H Driftwood 1,114 107 91% 17 5 10 Hartgrove #3H Hibernia 1,178 125 88% 6 1 11 University 9C #1212WB Sequitur 1,506 145 90% 4 12 16 12 Watkins Burkett #6H Pioneer 2,267 310 84% 2 8 10 7 24 23 20 13 13 Weatherby 1225-1226 #37 Sable 1,483 161 86% 19 11 21 14 Dogwood #1H Driftwood 1,449 144 87% 3 25 9 15 WTG 5-233 #1BU Earthstone 1,280 102 84% 16 Rocker B #137H Pioneer 1,491 155 91% 14 17 Sugg C #1915SM Laredo 2,070 232 72% Industry Well 18 Sugg B 163-162 #N032MC Laredo 1,387 140 85% Earthstone Well 22 15 19 Ratliff 9-7 A #1BL Earthstone 1,283 125 92% Earthstone Operated Acreage 20 Torpedo 1048 B #11HM Apache 3,011 328 93% Earthstone Non-Operated Acreage 21 Benedum 3-6 #1BL Earthstone 1,828 245 88% 22 WTG 4-232 A #2BL Earthstone 1,746 169 88% 23 Watkins Burkett #7H Pioneer 1,488 199 85% 24 Torpedo 1048 A #8HL Apache 2,179 221 83% 25 University 2-20 #76H Pioneer 2,998 308 82% L. Spraberry Wolfcamp A Wolfcamp BU Wolfcamp BL Wolfcamp C Wolfcamp D Source: Company filings, Investor presentations, DrillingInfo, RRC Note: Well completions filed since Jan 2018; IP tests are 24 hour tests from RRC W2 17

Differentiated, Balanced Inventory in Midland Basin Midland Basin Overview Gross Locations by Lateral Length and Target . Contiguous acreage positions provide significant development Gross Locations by Lateral Length advantage Target 5,000' - 6,250' 6,250' - 8,750' 8,750' - 10,000'+ Total % Total Wolfcamp A 9 109 138 256 30% . Long lateral development increases capital efficiency Wolfcamp B Upper 16 95 123 234 27% Wolfcamp B Lower 15 86 95 196 23% All Other Targets – 88 92 180 21% . Over 95% of Midland horizontal locations have laterals of ~6,250 feet Total Gross Locations 40 378 448 866 100% or greater Total Net Locations 28 226 242 496 % Total (Gross) 5% 44% 52% 100% – Over 50% of horizontal locations 8,750 feet or greater . Expect to complete 17 wells in 2019 with an average working Midland Basin Locations by Op / Non-Op interest of ~74% and an average lateral length of ~10,600 ft Gross Net Average Average % of Gross Locations Locations LL WI Locations in WC A+B – Increasing average completed lateral length from ~8,000 ft and Operated 500 398 8,930 80% 92% ~7,900 ft in 2017 and 2018, respectively Non-Operated 366 97 8,884 27% 63% Total 866 496 8,910 57% 79% . Additional upside from: – Middle Spraberry Midland Basin Average Lateral Length Evolution (Feet) – Jo Mill 12,000 10,600 – Additional Lower Spraberry 9,000 8,000 7,900 – Additional benches in Wolfcamp B 6,000 – Wolfcamp D 3,000 . Actively pursuing acreage and acquisition bolt-on opportunities to 0 increase lateral lengths and ownership 2017 2018 2019 . Near-term drilling focused in the Wolfcamp A and the Wolfcamp B based on positive offset results, but we are optimistic about the upside potential in other zones Note: Gross location count includes only economic locations in 12/31/18 CGA reserve report 18

Midland Basin Performance Review  Outperforming initial expectations and generating attractive returns at strip prices  Improved internal rate of return (“IRR”) due to initial production outperforming previous type curves Reagan County Results(1) Midland and Upton County Results(2) 150 200 Reagan TC Midland/Upton TC 2017 Reagan Co Avg. (16 wells) 2017 Midland & Upton Co Avg. (6 wells) 2018 Reagan Co Avg. (13 wells) 175 2018 Midland & Upton Co Avg. (3 wells) 2019 Reagan Co Avg. (4 wells) 120 2019 Upton Co Avg. (2 wells) 150 2019 Midland Co Avg. (5 wells) 125 90 100 60 75 50 30 2019 Upton County wells: 7,500' Norm CUMULATIVE PRODUCTION, MBOE (2 STREAM) 7,500' Norm CUMULATIVE PRODUCTION, MBOE (2 STREAM) ~850 Mboe EUR and 48% IRR(6) 25 0 0 0123456 0123456 TIME, MONTHS TIME, MONTHS Type Curve Summary (100% WI, 75% NRI 7,500' Laterals) (3) (4) (4) (5) Lateral Length DC & E EUR Oil NGL IRR Type Curve Area (ft) ($M) (MBoe) (%) (%) $50/$2.50 $60/$2.50 Midland / Upton 7,500 $7,200 1,000 67% 20% 74% >100% Reagan 7,500 $7,200 850 59% 22% 40% 58% Source: ESTE management, investor presentations (1) Reflects average cumulative production of operated wells completed in 2017, 2018 and 2019 in Reagan County; production data adjusted for downtime (2) Reflects average cumulative production of operated wells completed in 2017, 2018 and 2019 in Upton and Midland Counties (3) EUR calculated on a 2-stream basis (4) Percent oil and NGL calculated on a 3-stream basis (5) Single well rates of return assumes 3-stream economics on flat price deck of Oil - $50.00 and $60.00/Bbl, Gas - $2.50/Mcf before deductions for transportation, gathering, and quality differential. Assumes 3 month delay from spud to first sales 19 (6) EUR calculated on a 2-stream basis and assumes 3-stream economics on flat price deck of Oil - $50.00 and Gas - $2.50/Mcf

ESTE Current Non-operated Activity Overview Midland Basin Tubb . 3 gross / 1.2 net new wells online Aug/Sept 2019 . Targeting WC A and WC D (10k Foot Laterals) . ~$13mm net capex (35-40% WI) . ~2,430 net acres . WC A peak IP30 of 2,381 boepd (88% oil) and average rate of 2,159 boepd (87% oil) (90 days) . 2 WC D wells average peak IP30 = 969 boepd (86% oil) Toe Nail . 15 gross / 3.1 net new wells by 2Q 2020 . Targeting JM, LSS, WC A and WC B (10k Foot Laterals) . ~$30mm net capex (~21% WI) . Completion capital spent in 2020 . ~270 net acres Mid-States . 2 gross / 0.7 net new wells online October 2019 . Targeting WC A and WC B (10k Foot Laterals) ESTE Operated . ~$6.4mm net capex (35% WI) ESTE Non-Operated . ~230 net acres . 2 wells online with an average 3rd Party Acreage rate per well of 1,161 boepd (87% oil) through 32 days, and have not reached peak IP30 20

Blocking Up Acreage – Upton County (Benedum Project) Benedum Project Overview Midland Basin Overview . ESTE continues to focus on blocking up its acreage footprint to increase lateral length . The Benedum Project is a good example of how trades can enhance location economics . Completed first acreage trade at the Benedum Project in August 2017 . Executed second acreage trade at the Benedum Project in September 2019 – Enhanced capital efficiency by increasing lateral length – Increased acreage footprint by ~50 gross acres – Traded away ~6,200 ft laterals for ~10,000 ft laterals – Incrementally increased lateral footage by 25,000 ft ESTE Operated ESTE Non- ― Effectively 2.5 wells at 10,000 ft laterals Operated Benedum Project – May 2017 Benedum Project – August 2017 Benedum Project – September 2019 21

Eagle Ford Asset Overview Eagle Ford Overview Eagle Ford Position: Karnes, Gonzales and Fayette Counties . Operated Karnes, Gonzales, and Fayette Tr av is Lee Washington Hays Counties Bastrop Austin Fa yet te – 29,000 gross / 14,100 net leasehold acres Caldwell – Working interests range from 17% to 67% Colorado Guadalupe – 86% held-by-production Gonzales . 114 gross / 47.4 net producing wells (106 Lavaca operated / 8 non-op) Wilson Wharton Earthstone Acreage Gas Condensate . 68 identified gross Eagle Ford drilling locations Oil Window DeWitt Volatile Oil Jackson Karnes Wet Gas . Other Potential: Upper Eagle Ford, Austin Chalk, Victoria 01020 Buda, Wilcox, and Edwards Goliad Miles . Recent increased offset activity suggests Earthstone Lonestar Penn Virginia additional upside Bastrop – Updated frac designs and longer laterals in the Eagle Ford Fayette s – Test of lower Austin Chalk t n e t x n E o s a il t W a D ic m is e S D . 2019 capital program consists of drilling and - 3 completing 10 gross / 5.1 net wells in 2H 2019: Gonzales t it W G e o D K n a z rn a e le – 7 gross (3.1 net) wells on the Pen Ranch Unit s s in Southern Gonzales County (Producing) Lavaca – 3 gross (2.0 net) wells on the Davis Unit in Southern Gonzales County (Fracing) Offset operators include EOG, Encana and Marathon 22

Financial Overview 23

Capital Budget, Guidance and Liquidity ESTE 2019 Capital Budget(1) 2019 FY Guidance(1) Gross / Net Well Count 2019 Average Daily Production (Boe/d) 11,250 - 12,250 ($ in millions) Wells Spudded On-Line % Oil 65% Drilling and Completion: % Gas 16% Operated Midland Basin $135 19 / 14.7 17 / 12.6 % NGL 19% Non-Operated Midland Basin $25 20 / 5 5 / 2 2019 Year-end Exit Rate (Boe/d) 14,000 - 15,000 Operated Eagle Ford $30 10 / 5.1 10 / 5.1 Operating Costs: Land / Infrastructure $15 Lease Operating and Workover ($/Boe) $6.25 - $6.75 (2) Total $205 (2) Production Taxes (% of Revenue) 5.0% - 5.3% Cash G&A ($/Boe) $4.50 - $5.00 2019 Capex by Project Area(1) Liquidity (9/30/2019) ($mm) 9/30/2019 7% 16% Cash $9.8 15% Revolver Borrowings 125.0 12% Total Debt $125.0 66% Revolver Borrowing Base 325.0 84% Less: Revolver Borrowings (125.0) Operated Midland Basin (1 Rig) Midland Basin Eagle Ford Plus: Cash 9.8 Non-Operated Midland Basin Operated Eagle Ford Liquidity $209.8 Land / Infrastructure (1) Updated guidance reflects a temporary 2nd rig in the Midland Basin. Subject to numerous assumptions and risks (2) Management estimates that approximately $50 million of the Company’s total capital budget will result in production growth for 2020 rather than 2019 24

Hedge Book Summary Oil Production Hedged Gas Production Hedged Period Volume (Bbls) Volume (Bbls/d) $/Bbl Period Volume (MMBtu) Volume (MMBtu/d) $/MMBtu 4Q 2019 671,600 7,300 $64.31 4Q 2019 782,000 8,500 $2.854 FY 2020 2,562,000 7,000 $61.26 FY 2020 2,562,000 7,000 $2.850 FY 2021 730,000 2,000 $55.00 WTI Midland Argus Crude Basis Swaps WAHA Differential Basis Swaps Period Volume (Bbls) Volume (Bbls/d) $/Bbl (Differential) Period Volume (MMBtu) Volume (MMBtu/d) $/MMBtu 4Q 2019 506,000 5,500 ($5.29) 4Q 2019 782,000 8,500 ($1.155) FY 2020 2,562,000 7,000 ($1.40) FY 2020 2,562,000 7,000 ($1.065) FY 2021 730,000 2,000 $0.85 LLS Argus Crude Oil Basis Swaps Period Volume (Bbls) Volume (Bbls/d) $/Bbl (Differential) 4Q 2019 92,000 1,000 $4.50 Oil Production Hedged(1) Gas Production Hedged (Volumes in Bbls/d) Oil ~86% Hedged (Volumes in MMBtu/d) Gas ~83% Hedged of FY19 Guidance (2) of FY19 Guidance (2) 10,000 12,000 7,300 7,000 7,000 8,500 8,500 7,500 6,500 9,000 7,000 7,000 5,000 6,000 2,500 3,000 0 0 4Q19 FY20 4Q19 FY20 Oil Swaps Crude Basis Swaps Gas Swaps WAHA Basis Swaps (1) Crude basis swaps reflect Midland Argus and LLS Argus crude basis swaps (2) Based on midpoint of revised guidance (11,250 – 12,250 Boe/d; 65% oil, 16% gas) 25

Analyst Coverage Firm Analyst Contact Info Alliance Global Partners Joel Musante / 203-349-4782 / jmusante@allianceg.com Baird Joseph Allman / 646-557-3209 / jdallman@rwbaird.com Coker Palmer Noel Parks / 215-913-7320 / parks@cokerpalmer.com Imperial Capital Jason Wangler / 713-892-5603 / jwangler@imperialcapital.com Johnson Rice Dun McIntosh / 504-584-1217 / dun@jrco.com Northland Jeff Grampp / 949-600-4150 / jgrampp@northlandcapitalmarkets.com RBC Brad Heffern / 512-708-6311 / brad.heffern@rbccm.com Roth John White / 949-720-7115 / jwhite@roth.com Seaport Global Mike Kelly / 713-658-6302 / mkelly@seaportglobal.com Stephens Gail Nicholson / 301-904-7466 / gail.nicholson@stephens.com SunTrust Neal Dingmann / 713-247-9000 / neal.dingmann@suntrust.com Wells Fargo Gordon Douthat / 303-863-6880 / gordon.douthat@wellsfargo.com 26

Contact Information Mark Lumpkin, Jr. EVP, Chief Financial Officer Scott Thelander Vice President 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 27

Reconciliation of Non-GAAP Financial Measure Earthstone uses Adjusted EBITDAX, a financial measure that is not presented in accordance with United States generally accepted accounting principles (“GAAP”). Adjusted EBITDAX is a supplemental non- GAAP financial measure that is used by Earthstone’s management team and external users of its financial statements, such as industry analysts, investors, lenders and rating agencies. Earthstone’s management team believes Adjusted EBITDAX is useful because it allows Earthstone to more effectively evaluate its operating performance and compare the results of its operations from period to period without regard to its financing methods or capital structure. Earthstone defines Adjusted EBITDAX as net income plus, when applicable, loss (gain) on sale of oil and gas properties; accretion of asset retirement obligations; impairment expense; depletion, depreciation and amortization; transaction costs; interest expense, net; exploration expense; unrealized loss (gain) on derivative contracts; stock based compensation (non-cash); and income tax expense (benefit). Earthstone excludes the foregoing items from net income (loss) in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within their industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as an indicator of Earthstone’s operating performance or liquidity. Certain items excludedfromAdjustedEBITDAXaresignificant 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 costs of depreciable assets, none of which are components of Adjusted EBITDAX. Earthstone’s computation of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies or to similar measures in Earthstone’s revolving credit facility. The following table provides a reconciliation of Net income to Adjusted EBITDAX for: 3Q19 Adjusted EBITDAX ($ in 000s) FY 2018 Adjusted EBITDAX ($ in 000s) 3Q 19 FY 18 Net income $26,127 Net income (1) $95,213 Accretion of asset retirement obligations $52 Accretion of asset retirement obligations $169 Impairment expense $0 Impairment expense $4,581 Depletion, depreciation and amortization $14,079 Depletion, depreciation and amortization $47,568 Interest expense, net $1,609 Interest expense, net $2,898 Transaction costs $42 Transaction costs $13,524 Loss (gain) on sale of oil and gas properties $120 Loss (gain) on sale of oil and gas properties ($1,919) Exploration expense $0 Exploration expense $630 Unrealized loss (gain) on derivative contracts ($15,021) Unrealized loss (gain) on derivative contracts ($76,038) Stock based compensation (non-cash) (2) $2,207 Stock based compensation (non-cash) (2) $7,071 Income tax expense $575 Income tax expense $2,470 Adjusted EBITDAX $29,790 Adjusted EBITDAX $96,167 (1) Net income includes a $4.8 million charge to expense accrual representing management’s estimate of a pending lawsuit settlement 28 (2) Included in General and administrative expense in the Consolidated Statements of Operations

Reserves Summary Earthstone’s proved reserves as of December 31, 2018 were independently estimated by Cawley, Gillespie & Associates, Inc. (“CGA”), independent petroleum engineers, utilizing SEC prescribed oil and gas prices of $65.56/bbl and $3.100/mmbtu, respectively, calculated for December 31, 2018. SEC prices net of differentials were $61.52/bbl and $2.16/Mcf for oil and gas, respectively. Earthstone is also providing an alternative summary of proved reserves, calculated in accordance with SEC rules, with the exception of using constant oil and gas prices of $55.00/bbl and $2.75/mmbtu, respectively, as shown in the table below. Year-End 2018 SEC Proved Reserves Oil Gas NGL Total PV-10 Reserves Category (Mbbls) (MMcf) (MBbls) (MBoe) ($ in thousands) Proved Developed 14,325 26,110 4,969 23,646 $435,736 Proved Undeveloped 44,709 87,107 15,974 75,201 572,764 Total 59,034 113,217 20,943 98,847 $1,008,500 Year-End 2018 Proved Reserves ($55.00 Oil / $2.75 Gas) Oil Gas NGL Total PV-10 Reserves Category (Mbbls) (MMcf) (MBbls) (MBoe) ($ in thousands) Proved Developed 13,957 25,393 4,830 23,019 $351,024 Proved Undeveloped 39,252 72,821 13,294 64,683 347,477 Total 53,209 98,214 18,124 87,702 $698,501 Note: PV-10 is a non-GAAP financial measure. See “Non-GAAP Financial Measure – PV-10” 29

Non-GAAP Financial Measure – PV-10 PV-10 is derived from the standardized measure of discounted future net cash flows (“Standardized Measure”), which is the most directly comparable financial measure under GAAP. 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. The following table provides a reconciliation of PV-10 of the Company’s estimated proved reserves to the Standardized Measure (in thousands) as of December 31, 2018: Reconciliation of PV-10 Present Value of estimated future net revenues (PV-10) $1,008,500 Future income taxes, discounted at 10% (49,048) Standardized measure of discounted future net cash flows $959,452 30

F&D Costs per Unit F&D costs per unit is a non-GAAP metric commonly used in the oil and gas exploration and production industry by companies, investors and analysts in order to measure a company’s ability of adding and developing reserves at a reasonable cost. F&D costs per unit is a statistical indicator that has limitations, including its predictive and comparative value. In addition, because F&D costs per unit do not consider the costs or timing of future production of new reserves, such measures may not be adequate measures of value creation. This reserve metric may not be comparable to similarly titled measurements used by other companies. The calculation for F&D costs per unit is based on estimated costs incurred in 2018. The calculation for F&D costs per unit does not include future development costs required for the development of proved undeveloped reserves. The following table provides a calculation of the F&D costs per unit. F&D Costs per Unit Costs Incurred ($ in thousands) 2018 Acquisition costs: Proved $41,569 Unproved 31,268 Exploration costs 630 Development costs 153,161 Total Costs Incurred $226,628 Reserve Additions (MBoe) 2018 Extensions and Discoveries 16,209 Purchases 6,810 Revisions 6,075 Total Reserves Added 29,094 F&D Cost Per Boe $7.79 31