1 Investor Presentation February 2, 2021 Exhibit 99.2
2 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,” “forecasts”, “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: substantial declines in oil, natural gas liquids or natural gas prices; exposure to financial counterparty credit risk related to our derivative transactions; 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 facility; 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; any loss of senior management or key technical personnel; and the direct and indirect impact on most or all of the foregoing on the evolving COVID-19 pandemic. Earthstone’s 2019 Annual Report on Form 10-K and subsequent, quarterly reports on Form 10-Q and 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 2021 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, oil and natural gas prices, 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 Earthstone’s expectations. Earthstone’s ability to fund its 2021 and future capital budgets is subject to numerous risks and uncertainties, including volatility in commodity prices and the potential for unanticipated increases in costs associated with drilling, production and transportation. 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 2019 Form 10-K, Form 10-Qs and Form 8-Ks. 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 from estimates.
3 Investment Highlights: Leading Small-Cap, Permian Focused Producer Top Investment Criteria Earthstone’s Qualifications Basin & Acreage Position ✓ High quality, Midland Basin acreage position enhanced by recent acquisition Low Leverage Supported by Free Cash Flow ✓ 1.1x pro forma leverage at 3Q20 (1) supported by substantial free cash flow Strong Liquidity ✓ $115 million pro forma liquidity (cash + undrawn availability) on borrowing base as of 12/31/20(2) High Commodity Price Protection ✓ 9,114 bopd of 2021 oil production hedged at $48.04 per barrel WTI price(3) High Margin, Low Cost Production ✓ Top quartile cash margins & leading cost structure with $9.18 per BOE of all-in cash costs(4) in 3Q 2020 Commitment & Focus ✓ “Do the right thing” commitment to stakeholders, employees and environment (1) Leverage reflects 3Q20 total debt / LTM Adjusted EBITDAX at 3Q20 pro forma for acquisition of Independence Resources Management, LLC (“IRM”), which closed on 1/7/21 (2) Liquidity based on 12/31/20 ESTE debt and cash balance with pro forma adjustments for acquisition of IRM (3) 2021 hedges include hedges novated from IRM to ESTE in connection with the acquisition of IRM (4) All-in cash costs measured includes lease operating expenses, ad valorem and production taxes, cash G&A expense and interest expense. Excludes impact of income taxes
4 Proven Leadership and Track Record of Value Creation Operating team has extensive experience operating across various basins and in different operating environments Track Record of Value Creation 2007 2014 2017200520011992 20201997 1992-1996 Hampton Resources Corp. (“HPTR”) Gulf Coast Initial investors – 7x return 2Q 2017 Earthstone Acquired 20,900 Net Acres from Bold Energy III LLC in Midland Basin 2005-2007 Southern Bay Energy, LLC (Private) Gulf Coast, Permian Basin Initial Investors – 40% IRR 2014 Earthstone Bakken (662 Boe/d) Acquired Eagle Ford interests from Oak Valley Resources 1997-2001 Texoil, Inc. (“TXLI”) Gulf Coast, Permian Basin Initial investors – 10x return 2001-2004 AROC, Inc. (Private) Gulf Coast, Permian Basin, Mid-Con. Initial investors – 4x return 2007-2012 GeoResources, Inc. (“GEOI”) Eagle Ford, Bakken / Three Forks, Gulf Coast, Austin Chalk Initial investors – 4.8x return 2021 Leadership Team Years of Experience Years Working Together Title Frank Lodzinski 49 25 Executive Chairman Robert Anderson 34 17 President and CEO Steve Collins 33 25 Operations Mark Lumpkin 24 4 CFO Tim Merrifield 45 20 Geology and Geophysics Tony Oviedo 40 4 Accounting and Administration 1Q 2021 Earthstone Acquired Independence Resources in Midland Basin
5 $56.99 $210.4 $5.85 $3.87 13,429 $146.3 1.2x $39.05 $67.5 $5.38 $3.07 15,382 $143.4 0.8x ($/bbl) ($mm) ($/boe) ($/boe) (boepd) ($mm) (x) 2019 2020 (1) EIA historical WTI spot price average for full year 2019 and 2020 (2) Actual results for 2019 and midpoint of ESTE 2020 guidance as updated on 11/4/2020 for 2020 (3) Actual reported sales volumes through 9/30/20 plus estimated sales volumes for the three months ended on 12/31/20 (4) Actual results for 2019 and EBITDAX as reported through 9/30/20 plus Wall Street analyst consensus estimates for 4Q20 as of 1/4/21 per FactSet for 2020 (5) Actual results for 2019 and total debt and trailing twelve months EBITDAX as of 9/30/20 for 2020 2020: Managing Oil Price Collapse and Delivering Results -31% -68% -2%-21% +15% WTI Oil Price(1) CAPEX(2) LOE(2) Cash G&A(2) Production (3) EBITDAX(4) -32% D/EBITDAX (5) -8% Uncontrollable, Mitigated via Hedging Controllable via Proactive Response Results
6 ($40) ($20) $0 $20 $40 $60 $80 $100 $120 $140 Feb-09 Feb-10 Feb-11 Feb-12 Feb-13 Feb-14 Feb-15 Feb-16 Feb-17 Feb-18 Feb-19 Feb-20 -25% -34% -29% -61% -47% -23%-37% -22% -43% -21% $110 $80 $70 $40 Post Financial Crisis – OPEC/Shale Standoff OPEC/Shale Standoff - Current Bear market every 17 months Bear market every 7 months WTI trading in range of $40-70 per barrel vs. $80-110 per barrel since OPEC / Shale standoff commenced in 2H 2014, but with periods above and below trading range, including a historic price drop to negative territory in April 2020 — Industry re-geared cost structure, production flexibilities and improved efficiencies to create sustainability / profitability Increased commodity cycle velocity: Bear market (-20% WTI price) has occurred every 7 months vs. every 17 months, including 4x since November 2018 Business strategy must account for lower oil price and higher volatility Oil Price Volatility Requires Focused Business Strategy WTI Crude Oil Spot Price Since 2009 Source: Factset data as of 2/1/2021 -23% -160%
7 3,849 4,517 4,646 3,872 3,576 3,759 3,979 4,685 4,735 7,932 9,671 9,071 9,664 8,845 10,766 10,454 11,209 12,699 12,181 17,571 15,767 13,555 16,959 15,232 0 4,000 8,000 12,000 16,000 20,000 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 1Q19 2Q19 3Q19 4Q19 1Q20 2Q20 3Q20 4Q20 T ot al D ai ly P ro du ct io n (B oe /d ) ($40) ($20) $0 $20 $40 $60 $80 W T I ($/Bbl) Managing Through Oil Price Volatility Source: ESTE management, FactSet, public filings (1) Adjusted 3Q’2018 EBITDAX of $26.4MM includes a one-time legal settlement expense of ~$4.8MM; Annualized 3Q’2018 adjusted EBITDAX calculated by multiplying the pre-legal settlement 3Q’2018 adjusted EBITDAX of $31.2MM by three and adding $26.4MM (2) Reflects additions to oil and gas properties (3) Liquidity defined as revolver availability + cash; Liquidity % defined as (revolver availability + cash) / borrowing base (4) Estimated sales volumes for 4Q20 May 2017 Acquired 20,900 Net Acres from Bold Energy, LLC in Midland Basin December 2015 Announces Acquisition of Lynden Energy Corp.; ESTE Enters the Midland Basin June 2016 $45MM Common Equity Offering October 2017 $40MM Common Equity Offering December 2017 Divested Bakken Assets for $27MM May 2020 Voluntarily curtailed ~60% of production 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 1Q19 2Q19 3Q19 4Q19 1Q20 2Q20 3Q20 EBITDAX ($MM)(1) $5 $9 $8 $4 $2 $5 $3 $7 $5 $15 $19 $22 $25 $21 $26 $24 $32 $34 $30 $50 $38 $40 $36 Capex ($MM)(2) $19 $29 $18 $3 $2 $4 $9 $13 $4 $6 $20 $39 $33 $35 $52 $30 $48 $31 $78 $58 $42 $3 $1 Total Debt / LQA EBITDAX 0.5x 0.3x 0.4x 0.6x 1.4x 0.8x 1.3x 0.5x 0.7x 1.2x 1.0x 0.3x 0.3x 0.3x 0.3x 0.8x 0.9x 0.8x 1.0x 0.9x 1.0x 1.1x 0.9x Liquidity ($MM)(3) $128 $113 $110 $92 $74 $84 $89 $80 $80 $97 $91 $183 $166 $207 $203 $197 $155 $221 $210 $169 $128 $108 $115 Liquidity %(3) 160% 142% 137% 115% 93% 112% 118% 100% 100% 64% 61% 99% 90% 92% 90% 71% 56% 68% 65% 52% 47% 39% 48% (4)
8 Company Overview Midland Basin Asset Overview The Woodlands, Texas based E&P company focused on development and production of oil and natural gas with current operations in the Midland Basin (~34,000 core net acres(1)) and the Eagle Ford (~14,500 core net acres) Strategy of growing through the drill bit, organic leasing, and attractive asset acquisitions and business combinations 2020 4Q production of 22,551 Boe/d (52% oil, 76% liquids)(2) Pro Forma Market Statistics(3) (1) Includes ~4,900 core net acres from acquisition of IRM. Total Midland Basin ~72,500 net acres (2) Reflects estimated 4Q20 Earthstone sales volumes and estimated IRM 4Q20 three-stream sales volumes (3) Class A and Class B Common Stock outstanding as of 10/29/20 pro forma for ~12.7mm Class A shares issued in connection with the acquisition of IRM. Total ESTE debt and cash as of 12/31/20 pro forma for acquisition of IRM Production Summary(2) 4Q20 Net Sales Volumes: 22,551 Boe/d ESTE Operated ESTE Non-Operated IRM ESTE (Legacy) 15,232 IRM 7,318 ($ in millions, except share price) Class A Common Stock (MM) 42.9 Class B Common Stock (MM) 35.0 Total Common Stock Outstanding (MM) 77.9 Stock Price (as of 2/1/21) $5.43 Market Capitalization $423.2 Plus: Total Debt (as of 12/31/20) $260.0 Less: Cash (as of 12/31/20) (15.3) Enterprise Value $667.9
9 Independence Resources Acquisition
10 $182 million acquisition(1) of Independence Resources Management, LLC underwritten on PDP value but provides attractive drilling inventory additions Increases ESTE size and scale with ~50% increase in production and Adjusted EBITDAX(2) Preserves conservative balance sheet with estimated pro forma 1.1x net leverage(3) at 9/30/20 Consistent with ESTE Permian Basin consolidation strategy and positions ESTE for further transactions Minimal incremental G&A results in targeted 25% reduction in go forward Cash G&A per Boe Accretive to all key financial metrics Independence Resources Acquisition Overview and Key Highlights (1) Acquisition price based on $50.8MM of equity consideration (approximately 12.7 million shares and ESTE share price of $3.99 on 12/16/20) and cash consideration of $131.2MM (2) Based on trailing twelve months ending 9/30/20 (3) Net leverage reflects 9/30/20 net debt (total debt less cash) / LTM Adjusted EBITDAX at 9/30/20 pro forma for acquisition of IRM
11 IRM Acquisition Details – Closed on 1/7/21 Consideration and Funding Earthstone acquired Independence Resources Management, LLC and certain related entities (“IRM”) on 1/7/2021 Cash and equity consideration of $182.0 million — Cash consideration of $131.2 million — ~12.7 million Class A shares of ESTE equity consideration totaling $50.8 million (based on ESTE closing share price of $3.99 on 12/16/2020) ESTE’s credit facility borrowing base was increased to $360 million in conjunction with the acquisition with borrowings under the credit facility and cash on hand utilized to fund the cash portion of the consideration ESTE shareholders retain 83.7% of the common equity in the pro forma company Leadership and Governance ESTE Board of Directors increased in size from eight to nine with the appointment of Mr. David S. Habachy to the Board No changes to ESTE management team
12 Strategic Acquisition Bolsters Existing Midland Basin Position IRM Asset Overview Combined Midland Basin Map ESTE Operated ESTE Non-Operated IRM IRM “Spanish Pearl” Core Acreage IRM Key Asset Statistics Daily Production for 3Q20 (Boepd)(1) 8,780 PDP Reserves(3) 16.3 MMBoe PDP PV 10 ($MM)(3) $173 Core Net Acres ~4,900 Total Net Acres ~43,400 % HBP / % Operated 100% / 99% Gross Locations(4) 70 (1) Estimated IRM 3Q20 three-stream sales volumes (2) Adjusted EBITDAX is a non-GAAP financial measure. See "Reconciliation of Non-GAAP Financial Measure - Adjusted EBITDAX" (3) ESTE estimates as of 12/1/20 based on NYMEX strip pricing as of 11/30/20 (4) ESTE estimate of Middle Spraberry, Lower Spraberry and Wolfcamp A locations assuming 880’ well spacing Complementary Midland Basin assets meaningfully increase ESTE size and scale 3Q20 production of 8,780 Boepd (66% oil)(1) $81.3MM of LTM Adjusted EBITDAX at 9/30/20(2) Purchase price supported by PDP reserves ~4,900 core net acres in Midland and Ector counties with 70 remaining locations with average IRR of 45% in the Middle Spraberry, Lower Spraberry and Wolfcamp A(3) — Additional upside in the Jo Mill, Wolfcamp B and Wolfcamp D
13 (1) Source: Enverus. Includes horizontal wells completed since January 2010 (2) ESTE estimate of Middle Spraberry, Lower Spraberry and Wolfcamp A locations assuming 880’ well spacing IRM “Spanish Pearl” and Offset Well Results(1)IRM Spanish Pearl Area Activity Middle Spraberry Lower Spraberry Wolfcamp A Well # Well Name Operator TLL (ft.) 6 Month Oil Cum / 1,000' (bo) Comp. Date 1 Whittenburg 9MS IRM 9,857 10,657 1/2018 2 Midkiff 3MS IRM 4,453 7,460 8/2018 3 Ratliff 4408MH Concho 9,965 7,041 2/2020 4 Gardendale 501LS FDL 9,585 8,487 7/2018 5 Whittenburg 9LS IRM 9,660 11,237 1/2019 6 Parks Bell 4028H Concho 7,502 9,747 3/2019 7 Haag 9LS IRM 9,966 9,458 6/2019 8 Pearl Jam 7-12 (6 well avg.) IRM 5,058 14,246 3/2020 9 Parks Bell 4030H Concho 7,657 11,416 3/2019 10 Haag 9WA IRM 10,060 9,754 6/2019 11 Gardendale 105WA FDL 9,394 10,209 6/2019 12 Ratliff 28 East 2802AH Concho 13,262 9,246 9/2019 Industry Well IRM Well IRM “Spanish Pearl” IRM “Spanish Pearl” Inventory and Resource Summary Acreage position well within the basin margin with thick and consistent Spraberry and Wolfcamp sections across the entirety of the position Surrounded by producing wells on all sides and further de-risked by significant development and multiple spacing configurations on the IRM acreage IRM has 48 PDP horizontal wells producing from 4 different zones (Middle Spraberry, Lower Spraberry, Wolfcamp A and Wolfcamp B) Majority of existing IRM wells co-developed in vertical patterns across multiple zones, leaving remaining acreage less impacted by cross zone depletion and parent/child 70 gross locations with average 45% IRR at strip pricing and 880’ remaining well spacing in Middle Spraberry, Lower Spraberry and Wolfcamp A(2); additional upside locations 1 4 2 3 5 7 8 6 9 10 11 12 IRM “Spanish Pearl” and Offset Operator Well Results
14 IRM Acquisition Meets Key Earthstone Criteria Earthstone Objectives Commentary IRM Acquisition Increase Scale at Favorable Valuations Increases ESTE size and scale by ~50% with minimal impact to leverage and shares outstanding Purchase price of $182.0 million underwritten on PDP value ✓ High Quality Basin & Acreage Position Complementary Midland Basin acreage position includes ~4,900 core net acres (100% HBP, 93% operated) in Midland and Ector counties High quality inventory addition with 70 gross locations with an average 45% IRR(1) ✓ Increase Free Cash Flow Capacity Substantially increases cash flow with minimal incremental G&A Added scale enhances pro forma development options within free cash flow ✓ Maintain Balance Sheet Strength Pro forma net leverage of 1.1x at 9/30/20 Pro forma liquidity of ~$115 million(2) at 12/31/20 (cash + undrawn credit facility availability) ✓ Maintain Leading Cost Structure & Margins Maintains low cost, high margin operating metrics, while reducing go forward per unit Cash G&A costs by ~25% ✓ (1) ESTE estimate of Middle Spraberry, Lower Spraberry and Wolfcamp A locations assuming 880’ well spacing. IRRs based on NYMEX strip pricing as of 11/30/20 (2) Liquidity based on cash + undrawn availability on borrowing base based on 12/31/20 ESTE debt and cash balance with pro forma adjustments for acquisition of IRM
15 16,959 25,740 Status Quo ESTE Pro Forma ESTE 65.2 77.9 Status Quo ESTE Pro Forma ESTE $164 $246 Status Quo ESTE Pro Forma ESTE Meaningful Improvement to Key Operational Metrics 3Q20 Net Production (Boe/d)(1) 9/30/20 LTM Adjusted EBITDAX ($MM)(2) 9/30/20 Net Leverage(3) 0.8x 1.1x Status Quo ESTE Pro Forma ESTE (1) Represents reported sales volumes; Pro Forma ESTE utilizes estimated IRM 3Q20 3-stream production (2) Adjusted EBITDAX is a non-GAAP financial measure. See "Reconciliation of Non-GAAP Financial Measure - Adjusted EBITDAX" (3) Net leverage reflects 9/30/20 net debt (total debt less cash) / LTM Adjusted EBITDAX at 9/30/20 Transaction increases production and Adjusted EBITDAX by ~50% with minimal impact to leverage and shares outstanding 9/30/20 Shares Outstanding (MM)
16 Transaction Improves Key Metrics Without Impacting Balance Sheet Metrics 2021 Net Production 2021 Adjusted EBITDAX 2021 Free Cash Flow ESTE expects to pick up an operated rig in late 1Q 2021 IRM’s Spanish Pearl asset is expected to compete for capital with existing ESTE assets in a 1-rig program Note: Both status quo and pro forma scenarios assume a 1-rig program beginning in 2H 2021 Status Quo ESTE – 1 Rig Pro Forma ESTE – 1 Rig
17 Earthstone Overview
18 1,180 4,696 7,999 11,846 13,866 22,551 4,002 7,869 9,937 13,429 15,232 22,551 FY16A FY17A FY18A FY19A FY20A PF 4Q20A Midland Basin Other (1) Represents estimated sales volumes (2) PF 3Q20A is pro forma for acquisition of IRM (3) Excludes stock-based compensation Average Daily Production (Boe/d) Adjusted EBITDAX ($MM)(2) Lease Operating Expense and Cash G&A(3) ($/Boe) Debt / LTM EBITDAX(2) Since entering the Midland Basin in 2016, Earthstone has substantially increased production and decreased operating expenses, which has resulted in increased Adjusted EBITDAX, while also maintaining low leverage and preserving financial flexibility Acquisition of IRM enhances scale and ability to generate top tier operational and financial results Completed 6 drilled but uncompleted wells in 4Q 2020 and will complete 5 drilled but uncompleted wells in 1Q 2021 Midland Basin Growth Story $18.7 $60.6 $97.0 $146.3 $114.4 $145.6 $245.6 FY16A FY17A FY18A FY19A YTD3Q20A 3Q20A Annual. PF LTM 3Q20A $10.29 $6.84 $5.66 $5.85 $6.51 $4.53 $4.51 $6.43 $7.13 $5.81 $3.87 $3.09 $3.34 $2.18 $16.72 $13.97 $11.47 $9.72 $9.60 $7.87 $6.69 FY16A FY17A FY18A FY19A 1Q20A 2Q20A 3Q20A Lease Operating Expenses ($/Boe) Cash G&A ($/Boe) 0.9x 0.4x 0.8x 1.2x 1.0x 1.1x 0.8x 1.1x YE16A YE17A YE18A YE19A 1Q20A 2Q20A 3Q20A PF 3Q20A (1)
19 $26.06 $17.58 $18.30 $6.93 $7.32 $10.59 $12.24 $13.00 $13.65 $17.30 $20.85 $0.00 $15.00 $30.00 $45.00 ESTE Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 $10.72 $9.23 $9.33 $9.65 $10.07 $13.56 $13.71 $14.95 $15.19 $21.72 $21.77 $0.00 $10.00 $20.00 $30.00 $40.00 ESTE Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 LOE (incl Workovers) Ad Val. & Prod. Taxes Transportation Cash G&A Interest Expense YTD 3Q20 All-in Cash Margin ($/Boe)(1) (1) All-in cash margin calculated on a per Boe basis as revenues after realized hedge impact less all-in cash costs, which consists of 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, FANG, MTDR and XEC (2) Large-Cap includes: FANG and PXD. SMid-Cap includes: BATL, CDEV, CPE, LPI, MTDR, REI, SM and XEC Large-Cap(2) Avg: $9.28 SMid-Cap(2) Avg: $15.08 ESTE: $10.72 Low Cost Production Generates Leading Cash Margins YTD 3Q20 All-in Cash Costs ($/Boe)(1) Large-Cap(2) Avg: $17.94 SMid-Cap(2) Avg: $12.73 ESTE: $26.06
20 4.0x 6.6x 7.3x 3.2x 3.4x 3.9x 4.7x 4.9x 5.1x 5.6x 6.1x – 3.0x 6.0x 9.0x 12.0x 15.0x ESTE Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 0.9x 1.5x 2.7x 2.2x 2.4x 2.4x 2.5x 3.7x 4.3x 4.4x 4.4x – 2.0x 4.0x 6.0x 8.0x ESTE Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 Leading Leverage Metrics but Undervalued Equity Trading 3Q20 Total Debt / YTD 3Q20 Annualized EBITDAX Large-Cap(1) Avg: 2.1x SMid-Cap(1) Avg: 3.3x ESTE: 0.9x Enterprise Value to 2021E EBITDAX Large-Cap(1)(3) Avg: 6.9x SMid-Cap(1) Avg: 4.6x ESTE(2): 4.0x Source: Factset, Wall Street research. Market Data as of 2/1/21 (1) Large-Cap includes: FANG and PXD. SMid-Cap includes: BATL, CDEV, CPE, LPI, MTDR, REI, SM and XEC (2) Pro forma for acquisition of IRM (3) Reflects PXD pro forma for its announced acquisition of PE and FANG pro forma for its announced acquisitions of QEP and Guidon
21 1.7 1.8 2.4 4.5 3.0 - 5.0 FY17 FY18 FY19 FY20 2021E $926 $1,008 $845 $767 $670 $650 - $700 2H17 FY18 FY19 1Q20 4Q20 2021E Spud to Rig Release Days per 1,000’(1)(3) Average Number of Wells Per Pad A continued focus on driving down costs and increased efficiencies achieved by developing larger pads and driving down drilling and completion days (1) Excludes wells that required additional casing string or pilot well test. Includes operated Midland Basin wells only (2) Estimate based on total drilling, completions and equipment costs for a 10,000 ft lateral (3) Spud to rig release days = average spud to rig release days / (average completed lateral foot/1000) Continuous Focus on Operational Improvement Actual Drilling, Completions & Equip. Cost ($/Lat Ft.)(1) All-in Frac Costs per Stage ($/Stage) 2.6 2.0 2.0 1.9 2H17 FY18 FY19 1Q20 (2) $80,854 $77,167 $61,884 $56,600 $50,308 $37,833 $40,000 1H18 2H18 1H19 2H19 1Q20 4Q20 2021E
22 Installation of Vapor Recovery Units (“VRUs”) in conjunction with tank battery construction minimizes air emissions Target Zero Flaring: Connect natural gas pipelines ahead of flowback and first production negates need for flaring Leak Detection & Repair (“LDAR”) program since 2019 to further minimize air emissions Target >60% of 2021 oil production in Midland Basin on Pipeline. Increased from 13% and 42% in 2019 and 2020, respectively Plan for 100% of water disposal on pipeline in the Midland Basin to reduce truck hauls, which, in turn, reduces CO2 emissions Highly Focused Environmental Stewardship At Earthstone, maintaining environmentally sustainable business practices is a top priority Key Environmental Priorities Focus on Responsible Operatorship
23 Areas of Operations (1) Based on ESTE management estimates of reserves as of 12/31/20 assuming Oil - $50/Bbl, Gas - $2.50/Mcf (2) Represents estimated sales volumes Total(1) Total Proved Developed (Mmboe) 56.0 Total PD PV-10 ($mm) $653 4Q20 Net Production (Boe/d)(2) 22,551 4Q20 Net Production - % Oil(2) 52% Gross Producing Wells 1,118 Net Acres 87,000 Gross Drilling Locations 632 Legacy Midland Basin(1) Total Proved Developed (Mmboe) 36.0 Total PD PV-10 ($mm) $399 4Q20 Net Production (Boe/d)(2) 13,866 4Q20 Net Production - % Oil(2) 44% Gross Producing Wells 246 Net Acres 29,100 Gross Drilling Locations 562 IRM(1) Total Proved Developed (Mmboe) 16.3 Total PD PV-10 ($mm) $200 4Q20 Net Production (Boe/d)(2) 7,318 4Q20 Net Production - % Oil(2) 61% Gross Producing Wells 748 Net Acres 43,400 Gross Drilling Locations 70 Eagle Ford(1) Total Proved Developed (Mmboe) 3.7 Total PD PV-10 ($mm) $54 4Q20 Net Production (Boe/d)(2) 1,366 4Q20 Net Production - % Oil(2) 82% Gross Producing Wells 124 Net Acres 14,500 Gross Drilling Locations 0
24 Reserves Summary (1) Earthstone’s proved reserves as of December 31, 2020 were independently estimated by Cawley, Gillespie & Associates, Inc. (“CGA”), independent petroleum engineers, utilizing SEC prescribed oil and gas prices of $39.57/bbl and $1.985/mmbtu, respectively, calculated for December 31, 2020. SEC prices net of differentials were $38.90/bbl and $0.97/Mcf for oil and gas, respectively (2) To illustrate the effects of commodity price fluctuations on estimated reserve quantities and present values and to illustrate the impact of the recent acquisition of IRM, which closed on January 7, 2021, Earthstone is also providing an alternative summary of estimated proved reserves. This alternative summary as shown in the table below has been prepared in accordance with Society of Petroleum Engineers’ 2018 Petroleum Resources Management System utilizing constant benchmark prices of $50.00 per barrel for oil and $2.50 per MMBtu for natural gas Year-End 2020 SEC Proved Reserves(1) Alternative Year-End 2020 Proved Reserves at $50/bbl and $2.50/MMBtu(2) Oil Gas NGL Total PV-10 Reserves Category (Mbbls) (MMcf) (Mbbls) (Mboe) ($ in thousands) Proved Developed 29,098 75,680 14,336 56,048 $652,740 Proved Undeveloped 30,100 61,705 11,421 51,805 $369,830 Total 59,198 137,385 25,757 107,853 $1,022,570 Oil Gas NGL Total PV-10 Reserves Category (Mbbls) (MMcf) (Mbbls) (Mboe) ($ in thousands) Proved Developed 18,878 55,764 10,125 38,298 $329,395 Proved Undeveloped 21,212 55,450 10,123 40,577 $144,047 Total 40,090 111,214 20,248 78,875 $473,442
25 Gross Locations by Lateral Length and Target(2) Long lateral development increases capital efficiency Over 85% of Midland horizontal locations have laterals of ~6,750 feet or greater Near-term drilling focused in the Lower Spraberry, Wolfcamp A and Wolfcamp B targets in Midland and Upton Counties Midland Basin Overview Substantial Economic Inventory in Midland Basin Midland Basin Locations by Op / Non-Op(2)Well Level Economics (10,000’ lateral @ $650/ft Costs)(1) Gross Locations by Lateral Length Target 5,000' - 6,750' 6,750' - 8,750' 8,750'+ Total % Total Lower Spraberry 19 22 35 76 12% Wolfcamp A & B 37 131 221 389 62% All Other Targets 27 53 87 167 26% Total Gross Locations 83 206 343 632 100% Total Net Locations 79 146 189 414 % Total (Gross) 13% 33% 54% 100% Average % of Gross Gross Net Lateral Average Locations in Locations Locations Length WI LSBY, WC A/B Operated 389 334 8,217 86% 78% Non-Operated 243 80 9,338 33% 67% Total 632 414 8,648 65% 74% IRR IRR 3-Stream EUR Oil Liquids $50 Oil / $40 Oil / Project Area (Mboe) (%) (%) $2.50 Gas $2.50 Gas Midland 1,250 60% 81% 93% 55% Upton 1,000 56% 79% 69% 39% Reagan 1,300 38% 70% 46% 27% (1) Single well rates of return (“IRR”) based on all-in drilling, completions and equipment costs of $650/foot for a 10,000 foot lateral. Assumes 3-stream economics on flat benchmark price deck of Oil - $50 and $40/Bbl, Gas - $2.50/Mcf before deductions for transportation, gathering, and quality differential. Assumes NGL differential realizations to be 30% of WTI (2) Gross location count includes only economic locations based on ESTE management estimates of reserves as of 12/31/20 assuming Oil - $50/Bbl, Gas - $2.50/Mcf and includes locations from acquisition of IRM
26 Financial Overview
27 Capital Budget, Guidance and Liquidity ESTE 2021 Capital Budget Liquidity (12/31/2020)(2) 2021 FY Guidance 2021 Capital Budget Breakdown(1) Note: Guidance is forward-looking information that is subject to considerable change and numerous risks and uncertainties, many of which are beyond Earthstone’s control. See “Forward-Looking Statements”. Cash G&A is defined as general and administrative expenses excluding stock-based compensation (1) Reflects midpoint of FY2021E Guidance (2) Liquidity presented at 12/31/20 on an ESTE standalone basis and at 12/31/20 pro forma for the acquisition of IRM ($mm) 12/31/20 PF 12/31/20 (2) Cash $1.5 $15.3 Revolver Borrowings 115.0 260.0 Total Debt $115.0 $260.0 Revolver Borrowing Base 240.0 360.0 Less: Revolver Borrowings (115.0) (260.0) Plus: Cash 1.5 15.3 Liquidity $126.5 $115.3 ($ in millions) Gross / Net Operated Wells Spudded Gross / Net Operated Wells On Line Net Non-Op Wells On Line Drilling and Completion $80 - $90 21 / 18.5 16 / 13.5 0.7 Land / Infrastructure $10 Total $90 - $100 89% 11% Drilling and Completion Land / Infrastructure 2021 Average Daily Production (Boepd) 19,500 - 21,000 % Oil 52% - 54% % Liquids 77% - 79% 2021 Operating Costs Lease Operating Expense ($/Boe) $6.00 - $6.50 Production and Ad Valorem Taxes (% of Revenue) 6.25% - 7.25% Cash G&A ($mm) $20.0 - $21.0
28 Oil and Gas Hedges Summary – 100% Swaps Oil Production Swaps Gas Production Swaps (Volumes in Bbls/d) (Volumes in MMBtu/d) 9,114 1,000 7,829 0 5,000 10,000 15,000 FY21 FY22 Oil Swaps Crude Basis Swaps Oil Production Hedges - 100% Swaps Gas Production Hedges - 100% Swaps Period Volume (Bbls) Volume (Bbls/d) $/Bbl Period Volume (MMBtu) Volume (MMBtu/d) $/MMBtu 1Q 2021 936,840 10,409 $47.04 1Q 2021 1,334,500 14,828 $2.772 2Q 2021 811,260 8,915 $48.26 2Q 2021 1,592,500 17,500 $2.786 3Q 2021 798,175 8,676 $48.44 3Q 2021 1,610,000 17,500 $2.786 4Q 2021 780,475 8,483 $48.59 4Q 2021 1,610,000 17,500 $2.786 FY 2021 3,326,750 9,114 $48.04 FY 2021 6,147,000 16,841 $2.783 FY 2022 365,000 1,000 $47.70 1Q 2022 225,000 2,500 $2.937 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 1Q 2021 742,840 8,254 $0.77 1Q 2021 1,334,500 14,828 ($0.413) 2Q 2021 720,260 7,915 $0.78 2Q 2021 1,592,500 17,500 ($0.386) 3Q 2021 706,175 7,676 $0.80 3Q 2021 1,610,000 17,500 ($0.386) 4Q 2021 688,475 7,483 $0.81 4Q 2021 1,610,000 17,500 ($0.386) FY 2021 2,857,750 7,829 $0.79 FY 2021 6,147,000 16,841 ($0.392) 1Q 2022 225,000 2,500 ($0.230) NYMEX CMA Roll Period Volume (Bbls) Volume (Bbls/d) $/Bbl (Differential) 1Q 2021 292,840 3,254 ($0.26) 2Q 2021 265,260 2,915 ($0.26) 3Q 2021 246,175 2,676 ($0.26) 4Q 2021 228,475 2,483 ($0.27) FY 2021 1,032,750 2,829 ($0.26) 16,841 2,500 16,841 2,500 0 5,000 10,000 15,000 20,000 FY21 1Q22 Gas Swaps WAHA Basis Swaps
29 Analyst Coverage Firm Analyst Contact Info Alliance Global Partners Andrew Bond / 203-577-5427 / abond@allianceg.com Johnson Rice Dun McIntosh / 504-584-1217 / dun@jrco.com Northland Jeff Grampp / 949-600-4150 / jgrampp@northlandcapitalmarkets.com RBC Scott Hanold / 512-708-6354 / scott.hanold@rbccm.com Roth John White / 949-720-7115 / jwhite@roth.com Stephens Gail Nicholson / 301-904-7466 / gail.nicholson@stephens.com Truist Neal Dingmann / 713-247-9000 / neal.dingmann@truist.com Wells Fargo Tom Hughes / 212-214-5022 / thomas.hughes@wellsfargo.com
30 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 Contact Information
31 Appendix
32 Reserves Summary – Alternative Pricing The information presented below includes the combination of the stand-alone reserve quantities and PV-10 for Earthstone and IRM as of December 31, 2020 prepared in accordance with Society of Petroleum Engineers’ 2018 Petroleum Resources Management System utilizing constant benchmark prices of $50.00 per barrel for oil and $2.50 per MMBtu for natural gas. Alternative Year-End 2020 Proved Reserves at $50/bbl and $2.50/MMBtu (1) The present value of estimated future revenues, discounted at 10% annually, to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to (i) non-property related expenses such as general and administrative expenses, debt service and future income tax expense, or (ii) depreciation, depletion and amortization ESTE IRM COMBINED Reserve Category Proved Developed Proved Undeveloped Total Proved Developed Proved Undeveloped Total Proved Developed Proved Undeveloped Total Oil (MBbls) 19,547 21,530 41,077 9,551 8,570 18,121 29,098 30,100 59,198 Gas (MMcf) 57,891 56,580 114,471 17,789 5,125 22,914 75,680 61,705 137,385 NGL (MBbls) 10,502 10,316 20,818 3,834 1,105 4,939 14,336 11,421 25,757 Total (MBoe) 39,698 41,276 80,974 16,350 10,529 26,879 56,048 51,805 107,853 PV-10(1) ($ in thousands) $452,780 $265,499 $718,279 $199,960 $104,331 $304,291 $652,740 $369,830 $1,022,570
33 Reconciliation of Non-GAAP Financial Measure – Adjusted EBITDAX Earthstone uses Adjusted EBITDAX, a financial measure that is not presented in accordance with accounting principles generally accepted in the United States (“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 (loss) income plus, when applicable, (gain) loss on sale of oil and gas properties, net; accretion of asset retirement obligations; impairment expense; depletion, depreciation and amortization; transaction costs; interest expense, net; rig termination expense; 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 (loss) income 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 (loss) income to Adjusted EBITDAX for: (1) Included in General and administrative expense in the Consolidated Statements of Operations FY 2019 Adjusted EBITDAX ($ in 000s)3Q 2020 Adjusted EBITDAX ($ in 000s) 3Q 20 Net (loss) income ($11,858) Accretion of asset retirement obligations $47 Depreciation, depletion and amortization $28,538 Impairment expense $2,115 Interest expense, net $1,186 Transaction costs ($705) Loss (gain) on sale of oil and gas properties $0 Exploration expense $0 Unrealized loss (gain) on derivative contracts $14,543 Stock based compensation (non-cash)(1) $2,403 Income tax expense (benefit) $130 Adjusted EBITDAX $36,399 FY 19 Net (loss) income $1,580 Accretion of asset retirement obligations $214 Depreciation, depletion and amortization $69,243 Impairment expense $0 Interest expense, net $6,566 Transaction costs $1,077 Loss (gain) on sale of oil and gas properties ($3,222) Exploration expense $653 Unrealized loss (gain) on derivative contracts $59,849 Stock based compensation (non-cash)(1) $8,648 Income tax expense (benefit) $1,665 Adjusted EBITDAX $146,273
34 Reconciliation of Non-GAAP Financial Measure – LTM Adjusted EBITDAX (1) Included in Earthstone’s General and administrative expense in the Consolidated Statements of Operations 9/30/20 LTM Adjusted EBITDAX ($ in 000s) (1) ESTE IRM Pro Forma Net (loss) income ($16,693) ($66,645) ($83,338) Accretion of asset retirement obligations 191 1,254 1,445 Depreciation, depletion and amortization 103,058 46,852 149,910 Impairment expense 62,548 56,600 119,148 Interest expense, net 6,038 11,281 17,319 Transaction costs (45) 0 (45) Loss (gain) on sale of oil and gas properties (3,866) 0 (3,866) Rig termination expense 426 1,998 2,424 Exploration expense 951 27,226 28,177 Unrealized loss (gain) on derivative contracts 1,051 346 1,397 Stock based compensation (non-cash)(1) 9,633 2,961 12,594 Income tax expense (benefit) 1,049 (575) 474 Adjusted EBITDAX $164,341 $81,298 $245,639
35 Reserves Summary and PV-10 (Non-GAAP Financial Measure) Earthstone’s proved reserves as of December 31, 2020 were independently estimated by Cawley, Gillespie & Associates, Inc. (“CGA”), independent petroleum engineers, utilizing SEC prescribed oil and gas prices of $39.57/bbl and $1.985/mmbtu, respectively, calculated for December 31, 2020. SEC prices net of differentials were $38.90/bbl and $0.97/Mcf for oil and gas, respectively. Year-End 2020 SEC Proved Reserves PV-10 is a non-GAAP measure that differs from a measure under GAAP known as “standardized measure of discounted future net cash flows” in that PV-10 is calculated without including future income taxes. Management believes that the presentation of the PV-10 value of our oil and natural gas properties is relevant and useful to investors because it presents the estimated discounted future net cash flows attributable to our estimated proved reserves independent of our income tax attributes, thereby isolating the intrinsic value of the estimated future cash flows attributable to our reserves. We believe the use of a pre-tax measure provides greater comparability of assets when evaluating companies because the timing and quantification of future income taxes is dependent on company-specific factors, many of which are difficult to determine. For these reasons, management uses and believes that the industry generally uses the PV-10 measure in evaluating and comparing acquisition candidates and assessing the potential rate of return on investments in oil and natural gas properties. PV-10 does not necessarily represent the fair market value of oil and natural gas properties. PV-10 is not a measure of financial or operational performance under GAAP, nor should it be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP. The table below provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows (in thousands): Reconciliation of PV-10 Present value of estimated future net revenues (PV-10) $473,442 Future income taxes, discounted at 10% ($12,589) Standardized measure of discounted future net cash flows $460,853 Oil Gas NGL Total PV-10 Reserves Category (Mbbls) (MMcf) (Mbbls) (Mboe) ($ in thousands) Proved Developed 18,878 55,764 10,125 38,298 $329,395 Proved Undeveloped 21,212 55,450 10,123 40,577 $144,047 Total 40,090 111,214 20,248 78,875 $473,442
36 Non-GAAP Financial Measure – Free Cash Flow Free Cash Flow is a non-GAAP financial measure that we use as an indicator of our ability to fund our development activities. We define Free Cash Flow as Adjusted EBITDAX (defined above), less interest expense, less accrual-based capital expenditures. Management believes that Free Cash Flow, which measures our ability to generate additional cash from our business operations, is an important financial measure for use in evaluating the Company's financial performance. Free Cash Flow should be considered in addition to, rather than as a substitute for, consolidated net income as a measure of our performance and net cash provided by operating activities as a measure of our liquidity. Reconciliation of Free Cash Flow ($ in 000s) 3Q20 Adjusted EBITDAX $36,399 Interest expense, net (1,186) Capital expenditures (accrual basis) (1,378) Free Cash Flow $33,835
