Exhibit 99.1 Investor Presentation April 4, 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, 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 statements except as required by law. 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 historic 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 Growing Inventory ~870 total gross drilling locations across core play in Midland Basin Upside from additional benches in the Spraberry and Wolfcamp Conservative balance sheet with low leverage Prudent Financial Traditional reserve-based credit facility with standard covenants Management Significant liquidity Favorable hedge position Visible Production Midland Basin wells-in-progress provide ability to ramp up production Growth & Drilling Majority of acreage in key areas is HBP Program with Substantial Optionality Minimal obligation drilling in 2019 and 2020 Four prior successful public 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 Q2 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 2018 1997-2001 Texoil, Inc. (“TXLI”) 2005-2007 2014 Earthstone Q4 2018 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 10,454 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) 16,000 120 12,000 10,454 99 9,937 80 7,869 80 8,000 93 4,002 40 4,000 7,999 8,789 73 4,696 12 0 1,180 0 FY16A FY17A FY18A 4Q'18A FY16A FY17A FY18A 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) Unhedged Debt-Adjusted CFPS(3) $120.0 $2.40 2Q'16-4Q'18 CAGR 3.0x Maintained leverage below 1.5x since 2016 $96.2 45.7% $90.0 4Q’17: ESTE Sale of Bakken $2.00 $2.00 2.5x $60.6 2Q’17: ESTE Acquires assets for $27 million $60.0 20,900 Net Acres from $1.74 Total /Debt LQA EBITDA(X) Bold Energy $1.60 $1.50 2.0x $30.0 $18.7 2Q’16: ESTE Acquires Lynden Energy $1.16 $1.26 $1.19 $0.0 $1.20 $1.08 1.5x FY16A FY17A FY18A $0.94 1.2x 1.3x $0.85 1.0x $0.80 0.8x 1.0x Unhedged CFPS / Debt-Adjusted / Share CFPSDebt-Adjusted Unhedged 0.8x (1) 0.7x Lease Operating Expenses ($/Boe) $0.56 0.5x $0.33 $12.00 $0.40 0.3x 0.5x $10.29 0.3x 0.3x 0.3x $9.00 $0.00 0.0x $6.84 $5.66 $6.00 ESTE Leverage $3.00 $0.00 FY16A FY17A FY18A Track record of growing debt-adjusted cash flow per share while maintaining a low leverage profile drives greater overall (2) Cash G&A ($/Boe) shareholder returns $9.00 $7.13 $6.43 $5.81 $6.00 $3.00 $0.00 FY16A FY17A FY18A (1) Includes workovers and ad valorem taxes (2) Excludes stock-based compensation (3) CFPS represents annualized quarterly debt-adjusted cash flow per share 6
Company Overview The Woodlands, Texas based E&P company focused on development and production of oil and natural gas with current operations in the Midland Basin Asset Overview Midland Basin (~30,200 core net acres) and the Eagle Ford (~14,300 core net acres) Strategy of growing through the drill bit, organic leasing, and attractive asset acquisitions and business combinations (1) 2018 FY production of 9,937 Boe/d (65% oil, 83% liquids) Market Statistics(2) ($ in millions, except share price) Class A Common Stock (MM) 28.7 Class B Common Stock (MM) 35.5 Total Common Stock Oustanding (MM) 64.2 Stock Price (as of 4/2/19) $7.03 Market Capitalization $451.1 Plus: Total Debt $78.8 Less: Cash (0.4) Enterprise Value $529.6 Production Summary(1) Q4’18 Net Sales Volumes: 10,454 Boe/d Eagle Ford, 1,665 Midland Basin, 8,789 (1) Reflects reported sales volumes (2) Class A and Class B Common Stock outstanding as of March 8, 2019. Total debt and cash balances as of December 31, 2018 7
Earthstone by the Numbers: Increased Size, Scale and Core Inventory Midland Basin Net Acres 30,200 Midland Basin Locations (Gross / Net) 866 / 496 Operated Midland Basin Locations (Gross / Net) 500 / 398 Eagle Ford Net Acres 14,300 Operations Eagle Ford Locations (Gross / Net) 68 / 17 Q4 2018 Production (Boe/d)(1) 10,454 Q4 2018 Production (% Oil / % Liquids)(1) 70% / 87% PD Reserves (Mmboe) 23.6 (2) PD PV-10 ($mm) $436 1P Reserves (Mmboe) 98.8 1P PV-10 ($mm) $1,009 12/31/18 Reserves 12/31/18 1P % Oil / % Liquids 60% / 81% FY 2018 Revenue ($mm) $165.4 FY 2018 Adjusted EBITDAX ($mm)(3) $96.2 FY 2018 LOE ($/boe)(4) $5.66 FY 2018 G&A ($/boe)(5) $5.81 FY 2018 Financial 2018 FY Borrowing Base ($mm) $275 (1) Represents reported sales volumes (2) Reserve quantities based on SEC pricing. See appendix for SEC reserves, non-GAAP reconciliation and a constant price case at $55 Oil / $2.75 Gas (3) See “Reconciliation of Non-GAAP Financial Measure” on page 23 (4) Includes workovers and ad valorem taxes 8 (5) Excludes non-cash stock-based compensation
Areas of Operations Total (1) Midland Basin (1) 1P Reserves 98.8 1P Reserves 93.4 % PD 24% % PD 21% % Oil 60% % Oil 58% PV-10 ($mm) $1,009 PV-10 ($mm) $904 Q4 2018 Net Production (Boe/d)(2) 10,454 Q4 2018 Net Production (Boe/d)(2) 8,789 Gross Producing Wells 304 Gross Producing Wells 192 Core Net Acres 44,500 Core Net Acres 30,200 Core Gross Drilling Locations 934 Core Gross Drilling Locations 866 Eagle Ford (1) 1P Reserves 5.4 % PD 71% % Oil 84% PV-10 ($mm) $104 Q4 2018 Net Production (Boe/d)(2) 1,665 Gross Producing Wells 112 Core Net Acres 14,300 Core Gross Drilling Locations 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 9 (2) Represents reported sales volumes
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 $1,800 8 ― D&C / lateral foot flat despite inflationary 7 environment in the last 12 months; however, current $1,500 service costs are trending down $1,252 6 $1,200 5 # of Wells . Continue to see improvement in completion efficiencies $1,077 5 4 $924 $900 $835 4 ― Over the last 12 months, improved completions $774 $928 $ / Lateral Foot $ / Lateral efficiency from 5 stages per day to 9 stages per day 3 $600 3 . Larger inventory of extended lateral locations also 2 expected to drive improved efficiencies $300 2 2 1 1 . Earthstone’s completion evolution is setting the stage for $0 0 Q3' 17 Q4' 17 Q1' 18 Q2' 18 Q3' 18 Q4' 18 further well performance improvement Wells Spud to Rig Release Days (1)(2) ― Use of in-basin sand to help drive down costs while not affecting well performance 3.5 11,206 12,000 ― Continue to evaluate new completion techniques to 3.0 2.9 10,000 8,888 cost effectively enhance well performance 8,627 8,204 2.4 2.5 Length Lateral Average 2.3 8,000 2.0 2.0 7,585 1.8 6,000 6,237 Track record of driving down costs through improved 1.5 1.4 operational efficiencies to drive returns 4,000 1.0 Days per 1000 Lateral Lateral Foot 1000 per Days 2,000 0.5 0.0 0 Q3' 17 Q4' 17 Q1' 18 Q2' 18 Q3' 18 Q4' 18 Average Lateral Length (1) Excludes wells that required additional casing string or pilot well test (2) Spud to rig release days = average spud to rig release days / (average lateral foot/1000) 10
Asset Overview 11
Significant Position in the Midland Basin 30,200 Total Net Acres in Core of Midland Basin Midland Basin Overview 866 gross locations Significant Operated Position in Midland Basin(1) 23,300 net acres, 94% average working interest, 500 gross locations Q4 2018 Net Production of 8,789 Boe/d(2) (67% oil, 86% liquids) Wells in progress drive immediate production growth Attractive Rates of Returns (“ROR”)(3) Single well RORs 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 Completion Evolution Sets Stage for Further Well Performance Improvement (1) Does not include non-operated position (2) Represents reported sales volumes for both operated and non-operated properties 12 (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
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 C ― Average 80% Liquids, 20% Gas . 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 Cline ― Target TVDs are between 7,300-8,500’ Primary ESTE Landing Targets Development Focus Interval 13
Recent Southern Midland Basin Results Southern Midland Basin Activity Map Recent Well Results Well Name Operator IPW2 (Boe/d) IP/1000' (Boe) % Oil Industry Well 1 Torpedo 1048 B #5HA Apache 1,410 153 82% Earthstone Well 2 University 3-310 PU #9H Pioneer 1,242 127 84% Earthstone Operated Acreage 3 University 35-19 40 #104HA Hunt 1,030 101 91% Earthstone Non-Operated Acreage 4 Eaglehead C A4 #36AH Callon 1,306 179 83% 5 Cope 107-108 #31HS Sable 1,002 106 92% 6 Morgan A 25-26A-A #4201H Parsley 1,626 157 86% 7 Ratliff 9-7 B #2BU Earthstone 1,603 153 94% 8 Torpedo 1048 A #2HU Apache 1,944 211 89% 5 9 Fantasy #717WB Henry 1,075 177 89% 10 Sequoia #1H Driftwood 1,114 107 91% 14 6 15 11 Dogwood #1H Driftwood 1,449 144 87% 17 16 22 12 WTG 5-233 #1BU Earthstone 1,280 102 84% 4 13 1 8 23 13 Rocker B #137H Pioneer 1,491 155 91% 19 7 24 14 Sugg C #1915SM Laredo 2,070 232 72% 9 18 20 15 Aldwell 0544 #12HU Apache 1,726 226 85% 2 25 3 16 Lucy Lindsay 1-36-H #4315 Parsley 1,281 169 87% 10 17 Morgan A 25-26A-A #4401H Parsley 1,270 122 85% 18 Ratliff 9-7 A #1BL Earthstone 1,283 125 92% 11 19 Torpedo 1048 B #11HM Apache 3,011 328 93% 21 12 20 Benedum 3-6 #1BL Earthstone 1,828 245 88% 21 WTG 4-232 A #2BL Earthstone 1,746 169 88% 22 North Creek B #431CN Discovery 1,052 106 86% 23 Lucy Lindsay 1-36-H #4415 Parsley 888 115 86% 24 Torpedo 1048 A #8HL Apache 2,179 221 83% 25 University 2-20 #76H Pioneer 2,998 308 82% 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 14
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 13 wells in 2019 with an average working Midland Basin Locations by Op / Non-Op interest of 86% and an average lateral length of ~9,600 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 – 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 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 15
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) 2019 Midland &Upton Co Avg. (2 wells) 120 150 125 90 100 60 75 50 30 7,500' Norm CUMULATIVE PRODUCTION, MBOE (2 STREAM) 7,500' Norm CUMULATIVE PRODUCTION, MBOE (2 STREAM) 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 wells completed in 2017 and 2018 in Reagan County; production data adjusted for downtime (2) Reflects average cumulative production of wells completed in 2017 and 2018 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 16 quality differential. Assumes 3 month delay from spud to first sales
Acreage Trade – Central Reagan County Acreage Trade Highlights Pre-Trade Post-Trade In October 2018, ESTE traded non-operated working interests in Glasscock County and paid $27.8 million in cash for operated working interests in Reagan County with an offset operator Added 3,899 operated net acres to Reagan County position (~100% working interest) Includes 14 PDP wells (8 horizontal, 6 vertical) Net increase of 350 Boe/d and 2,677 acres Additionally, ESTE expects to finalize an additional lease acquisition which will add ~760 net acres in Reagan County With these acreage transactions, ESTE’s total net acreage in the Midland Basin has increased to ~30,200 acres, of which ~23,300 acres are operated ― ~14,000 contiguous net acres with 85% working interest in Central Reagan County ESTE Trade Added Pending Acreage Acreage Acreage Acquisition 17
Eagle Ford Asset Overview Karnes, Gonzales, and Fayette Counties, Texas . Operated Karnes, Gonzales, and Fayette Counties Tr av is Lee Washington Hays – 29,000 gross / 14,100 net leasehold acres Bastrop Austin Fa yet te – Working interests range from 17% to 67% Caldwell – 86% held-by-production Colorado Guadalupe . 112 gross / 47.9 net producing wells (106 operated / 6 non-op) Gonzales Lavaca . 68 identified gross Eagle Ford drilling locations Wilson Wharton Earthstone Acreage Gas Condensate Oil Window . Other Potential: Upper Eagle Ford, Austin Chalk, DeWitt Volatile Oil Jackson Buda, Wilcox, and Edwards Karnes Wet Gas Victoria 01020 . Recent increased offset activity suggests additional Goliad Miles upside Earthstone Lonestar Penn Virginia – Updated frac designs and longer laterals in the Bastrop Eagle Ford – Test of lower Austin Chalk Fayette s t n e t . Expect to drill 7 gross (1.5 net) wells in 2019 on the n x E o s a il t W a D Pen Ranch Unit in Southern Gonzales County ic m is e S D - 3 Gonzales t it W G e o D K n a z rn a e le s s Lavaca Offset operators include EOG, Encana and Marathon 18
Financial Overview 19
Capital Budget, Guidance and Liquidity ESTE 2019 Capital Budget(1) 2019 FY Guidance(1) (3) Gross / Net Well Count 2019 Average Daily Production (Boepd) 11,000 - 12,000 ($ in millions) Wells Spudded On-Line % Oil 65% Drilling and Completion: % Gas 16% Operated Midland Basin (1 Rig) $118 16 / 13.5 13 / 11.2 % NGL 19% Non-Operated Midland Basin $47 20 / 5 19 / 5.6 Operating Costs: Operated Eagle Ford $10 7 / 1.5 7 / 1.5 Lease Operating and Workover ($/Boe) $5.25 - $5.75 Land / Infrastructure $15 Production Taxes (% of Revenue) 5.0% - 5.3% Total $190 (2) Cash G&A ($/Boe) $5.00 - $5.50 2019 Capex by Project Area(1) Liquidity (12/31/2018) ($mm) 12/31/2018 8% 6% Cash $0.4 5% Revolver Borrowings 78.8 25% Total Debt $78.8 62% Revolver Borrowing Base 275.0 94% Less: Revolver Borrowings (78.8) Operated Midland Basin (1 Rig) Midland Basin Eagle Ford Plus: Cash 0.4 Non-Operated Midland Basin Operated Eagle Ford Liquidity $196.5 Land / Infrastructure (1) Assumes a 1-rig program for the operated Midland Basin acreage (2) Management estimates that approximately $50 million of the Company’s total capital budget is applicable to production growth for 2020 rather than 2019 20 (3) Based on 2019 Guidance provided on 1/16/2019, which is subject to numerous assumptions and risks
Hedge Book Summary Oil Production Hedged Gas Production Hedged Period Volume (Bbls) Volume (Bbls/d) $/Bbl Period Volume (MMBtu) Volume (MMBtu/d) $/MMBtu Q1 2019 523,000 5,811 $65.92 Q1 2019 945,000 10,500 $2.857 Q2 2019 591,500 6,500 $65.53 Q2 2019 955,500 10,500 $2.857 Q3 2019 598,000 6,500 $65.53 Q3 2019 920,000 10,000 $2.856 Q4 2019 579,600 6,300 $65.74 Q4 2019 920,000 10,000 $2.856 FY 2019 2,292,100 6,280 $65.67 FY 2019 3,740,500 10,248 $2.856 FY 2020 1,464,000 4,000 $65.87 FY 2020 2,562,000 7,000 $2.850 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 Q1 2019 495,000 5,500 ($5.56) Q1 2019 945,000 10,500 ($1.138) Q2 2019 500,500 5,500 ($5.29) Q2 2019 955,500 10,500 ($1.138) Q3 2019 506,000 5,500 ($5.29) Q3 2019 920,000 10,000 ($1.141) Q4 2019 506,000 5,500 ($5.29) Q4 2019 920,000 10,000 ($1.141) FY 2019 2,007,500 5,500 ($5.36) FY 2019 3,740,500 10,248 ($1.139) FY 2020 1,464,000 4,000 ($2.74) FY 2020 2,562,000 7,000 ($1.065) LLS Argus Crude Oil Basis Swaps Period Volume (Bbls) Volume (Bbls/d) $/Bbl (Differential) Q1 2019 90,000 1,000 $4.50 Q2 2019 91,000 1,000 $4.50 Q3 2019 92,000 1,000 $4.50 Q4 2019 92,000 1,000 $4.50 FY 2019 365,000 1,000 $4.50 Oil Production Hedged(1) Gas Production Hedged (Volumes in Bbls) Oil ~84% Hedged (Volumes in MMBtu) Gas ~93% Hedged 4,000,000 of FY19 Guidance (2) 6,000,000 of FY19 Guidance (2) 3,740,500 3,740,500 3,000,000 2,292,100 2,372,500 4,500,000 2,562,000 2,562,000 2,000,000 1,464,000 1,464,000 3,000,000 1,000,000 1,500,000 0 0 FY19 FY20 FY19 FY20 Oil Swaps Crude Basis Swaps Gas Swaps WAHA Basis Swaps (1) Crude basis swaps reflect Midland Argus and LLS Argus crude basis swaps for FY19 and FY20 21 (2) Based on midpoint of current guidance (11,000 – 12,000 boepd; 65% oil, 16% gas)
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 David Beard / 631-725-8810 / beard@cokerpalmer.com Imperial Capital Jason Wangler / 713-892-5603 / jwangler@imperialcapital.com Johnson Rice Ron Mills / 504-584-1217 / rmills@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 John Aschenbeck / 713-658-6343 / jaschenbeck@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 22
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 23
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 (loss) plus, when applicable, loss (gain) on sale of oil and gas properties; accretion; impairment expense; depletion, depreciation and amortization; transaction costs; interest expense, net; exploration expense; unrealized loss (gain) on mark-to-market of hedges; non-cash stock based compensation; and income tax (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 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 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: 4Q’18 Adjusted EBITDAX ($ in 000s) FY 2018 Adjusted EBITDAX ($ in 000s) 4Q'18 FY 2018 Net income (loss) $80,986 Net income (loss) (1) $95,213 Accretion of asset retirement obligations 41 Accretion of asset retirement obligations 169 Impairment expense 3,748 Impairment expense 4,581 Depletion, depreciation and amortization 14,206 Depletion, depreciation and amortization 47,568 Interest expense, net 1,110 Interest expense, net 2,898 Transaction costs 12,632 Transaction costs 13,524 Loss/(Gain) on sale of oil and gas properties 2,689 Loss/(Gain) on sale of oil and gas properties (1,919) Exploration expense 630 Exploration expense 630 Unrealized loss (gain) on derivative contracts (96,001) Unrealized loss (gain) on derivative contracts (76,038) Stock based compensation (non-cash)(2) 1,536 Stock based compensation (non-cash)(2) 7,071 Income tax (benefit) 2,351 Income tax (benefit) 2,470 Adjusted EBITDAX $23,929 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 24 (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” 25
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 properties to the Standardized Measure (in thousands): 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 26
