Attached files
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| 8-K - 8-K - EARTHSTONE ENERGY INC | este-20210420.htm |
| EX-99.1 - EX-99.1 - EARTHSTONE ENERGY INC | ex991-bbredeterminationpre.htm |
| EX-10.1 - EX-10.1 - EARTHSTONE ENERGY INC | ex101thirdamendmenttocredi.htm |
1 Investor Presentation April 20, 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,” “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 benefits of the proposed acquisition (the “Transaction”) of certain assets from Tracker Resource Development III, LLC (“Tracker”) and Sequel Energy Group, LLC (“Sequel”) by Earthstone Energy, Inc. (“Earthstone” or the “Company”) and its stockholders, the anticipated completion of the proposed Transaction or the timing thereof, 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: the ability to complete the proposed Transaction on anticipated terms and timetable; Earthstone’s ability to integrate the assets of Tracker and Sequel successfully after the Transaction and achieve anticipated benefits from it; the possibility that various closing conditions for the Transaction may not be satisfied or waived; risks relating to any unforeseen liabilities of Earthstone or the assets to be acquired in the Transaction; declines in oil, natural gas liquids or natural gas prices; the level of success in exploration, development and production activities; adverse weather conditions that may negatively impact development or production activities; the timing of exploration and development expenditures; inaccuracies of reserve estimates or assumptions underlying them; revisions to reserve estimates as a result of changes in commodity prices; impacts to financial statements as a result of impairment write-downs; risks related to level of indebtedness and periodic redeterminations of the borrowing base under the Company’s Credit Facility; Earthstone’s ability to generate sufficient cash flows from operations to fund all or portions of its future capital expenditures budget; Earthstone’s ability to obtain external capital to finance exploration and development operations and acquisitions; the ability to successfully complete any potential asset dispositions 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 technical personnel; and the direct and indirect impact on most or all of the foregoing on the evolving COVID-19 pandemic. Earthstone’s annual report on Form 10-K for the year ended December 31, 2020, 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 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 for hydrocarbons 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 2020 Form 10-K, subsequent 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 the data to reflect events or circumstances after the date of this presentation. Therefore, you are cautioned not to place undue reliance on the information in this presentation. 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 of IRM and pending Tracker Acquisition Low Leverage Supported by Free Cash Flow ✓ 1.2x pro forma leverage for 2020 (0.8x standalone) (1) supported by substantial free cash flow(2) Strong Liquidity ✓ >$250 million pro forma liquidity (cash + undrawn availability) as of 3/31/21(3) as adjusted for borrowing base increase to $475 million High Commodity Price Protection ✓ ~88% of 2021 oil production hedged (4) High Margin, Low Cost Production ✓ Leading cash margins & low cost structure with $11.08 per BOE of all- in cash costs(5) in FY 2020 Commitment & Focus ✓ “Do the right thing” commitment to stakeholders, employees and environment (1) Leverage reflects 12/31/20 total debt / 2020 Adjusted EBITDAX; pro forma leverage represents Earthstone leverage at 12/31/20 as adjusted for the closing of the IRM acquisition on 1/7/21 (2) Free cash flow defined as Adjusted EBITDAX less interest expense less capital expenditures (3) Liquidity based on estimated 3/31/21 ESTE debt and cash balance with borrowing base as adjusted for April 2021 increase to $475MM (4) Based on midpoint of 2021 production guidance, which does not include expected impact of Tracker on 2H2021 production (5) All-in cash costs measured includes lease operating expenses, ad valorem and production taxes, cash G&A expense and interest expense. Excludes impact of income taxes
4 Proven Leadership and Track Record of Value Creation Operating team has extensive experience operating across various basins and in different operating environments Track Record of Value Creation 2007 2014 2017200520011992 1997 1992-1996 Hampton Resources Corp. (“HPTR”) Gulf Coast Initial investors – 7x return 2Q 2017 Earthstone Acquired 20,900 Net Acres from Bold Energy III LLC in Midland Basin 2005-2007 Southern Bay Energy, LLC (Private) Gulf Coast, Permian Basin Initial Investors – 40% IRR 2014 Earthstone Bakken (662 Boe/d) Acquired Eagle Ford interests from Oak Valley Resources 1997-2001 Texoil, Inc. (“TXLI”) Gulf Coast, Permian Basin Initial investors – 10x return 2001-2004 AROC, Inc. (Private) Gulf Coast, Permian Basin, Mid-Con. Initial investors – 4x return 2007-2012 GeoResources, Inc. (“GEOI”) Eagle Ford, Bakken / Three Forks, Gulf Coast, Austin Chalk Initial investors – 4.8x return 2021 Leadership Team Years of Experience Years Working Together Title Frank Lodzinski 49 25 Executive Chairman Robert Anderson 34 17 President and CEO Steve Collins 33 25 Operations Mark Lumpkin 24 4 CFO Tim Merrifield 45 20 Geology and Geophysics Tony Oviedo 40 4 Accounting and Administration 1Q 2021 Earthstone Acquired Independence Resources in Midland Basin 2Q 2021 Earthstone Announced acquisition of Tracker Resource Development III, LLC (expected close early 3Q21)
5 IRM Tracker Combined Announced Date 12/18/2020 4/1/2021 Closing Date 1/7/2021 Early 3Q 2021 1-Day Stock Price Impact +17.7% +25.3% Acquisition Price ($mm)(1) $186 $126 $312 PDP PV10 ($mm)(2) $173 $153 $326 Production (Boepd)(3) 8,800 7,800 16,600 % Liquids 85% 59% 73% Net Acreage 43,400 20,300 63,700 Drilling Locations(4) 70 49 119 Over $300 million in aggregate YTD acquisitions of Independence Resources Management, LLC (closed 1/7/2021(1)) and Tracker Resource Development (announced 4/1/2021, pending closing) (1) IRM acquisition price of $182MM based on $50.8MM of equity consideration (approximately 12.7MM shares and ESTE share price of $3.99 on 12/16/20) and cash consideration of $131.2MM. Tracker acquisition price of $126MM based on $44.2MM of equity consideration (approximately 6.2MM shares and ESTE share price of $7.24 on 3/30/21) and cash consideration of $81.6MM. Includes assets from Tracker Resource Development III, LLC and an affiliate and from affiliates of Sequel Energy (2) Based on ESTE estimates; PV10 as of 12/1/20 based on NYMEX strip pricing as of 11/30/20 for IRM and as of 3/1/21 based on NYMEX strip pricing as of 3/29/21 for Tracker (3) Estimated 3Q 2020 production for IRM and estimated March 2021 production for Tracker (4) ESTE estimated drilling locations exceeding ESTE rate of return threshold based on 11/30/20 NYMEX strip pricing for IRM and $50/bbl flat oil pricing for Tracker 2021: Increasing Scale and Efficiency Through Consolidation
6 Recent Acquisitions Meet Key Earthstone Criteria Earthstone Objectives Commentary IRM / Tracker Acquisitions Increase Scale at Favorable Valuations ~75% increase in ESTE base production volumes PDP-focused purchase price valuation ✓ High Quality Basin & Acreage Position Complementary Midland Basin acreage footprint Adds ~120 high-graded drilling locations ✓ Increase Free Cash Flow Capacity Increased cash flow base positions ESTE for continued organic growth within free cash flow ✓ Maintain Balance Sheet Strength ESTE targeting sub-1.25x leverage at YE21 (1) >50% undrawn borrowing base (2) ✓ Maintain Leading Cost Structure & Margins Maintains low cost, high margin operating metrics Eliminate ~95% of IRM/Tracker G&A ✓ (1) Pro forma for pending Tracker Acquisition; leverage defined as total debt to Adjusted EBITDAX (2) Based on Credit Facility balance as of 3/31/21, as adjusted for increase in borrowing base to $475MM in April 2021
7 ($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 Feb-21 -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 4/19/2021 -23% -160%
8 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; excludes acquisitions (3) Liquidity defined as revolver availability + cash; Liquidity % defined as (revolver availability + cash) / borrowing base. Liquidity in 4Q20 pro forma for IRM acquisition 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 $27MM May 2020 Voluntarily curtailed ~60% of production 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 1Q19 2Q19 3Q19 4Q19 1Q20 2Q20 3Q20 4Q20 EBITDAX ($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 $30 Capex ($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 $20 Total Debt / LQA EBITDAX 0.5x 0.3x 0.4x 0.6x 1.4x 0.8x 1.3x 0.5x 0.7x 1.2x 1.0x 0.3x 0.3x 0.3x 0.3x 0.8x 0.9x 0.8x 1.0x 0.9x 1.0x 1.1x 0.9x 1.0x Liquidity ($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 $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% 32% 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 14,809 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)
9 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 (~32,800 core net acres(1)) — Additional 38,500 net acres in the Midland Basin and 12,500 net acres in the Eagle Ford — Pending additional ~20,300 net acres in the Midland Basin from Tracker Strategy of growing through the drill bit, organic leasing, and attractive asset acquisitions and business combinations 2020 4Q production of 22,128 Boe/d (53% oil, 76% liquids)(2) Market Statistics(3) (1) Includes ~4,900 core net acres from acquisition of IRM. Total Midland Basin ~71,300 net acres (2) Reflects 4Q20 Earthstone sales volumes and estimated IRM 4Q20 three-stream sales volumes (3) Class A and Class B Common Stock outstanding as of 3/4/21. Total ESTE debt and cash as of 3/31/21 (excludes impact of pending Tracker acquisition) Production Summary(2) 4Q20 Net Sales Volumes: 22,128 Boe/d ESTE Operated ESTE Non-Operated ESTE (Legacy) 14,809 IRM 7,318 5,800 – 6,000 boepd estimated production 2H 2021 Tracker + Tracker (pending acquisition) ($ in millions, except share price) Class A Common Stock (MM) 43.6 Class B Common Stock (MM) 34.4 Total Common Stock Outstanding (MM) 78.1 Stock Price (as of 4/19/21) $7.00 Market Capitalization $546.6 Plus: Total Debt (as of 3/31/21) $223.4 Less: Cash (as of 3/31/21) (1.4) Enterprise Value $768.6
10 Earthstone Overview
11 0.9x 0.4x 0.8x 1.2x 0.8x 1.2x YE16A YE17A YE18A YE19A YE20A PF FY20A $10.29 $6.84 $5.66 $5.85 $5.21 $6.43 $7.13 $5.81 $3.87 $3.25 $16.72 $13.97 $11.47 $9.72 $8.46 FY16A FY17A FY18A FY19A FY20A Lease Operating Expenses ($/Boe) Cash G&A ($/Boe) (1) Pro forma for acquisition of IRM (2) Excludes stock-based compensation Average Daily Production (Boe/d) Adjusted EBITDAX ($MM) Lease Operating Expense and Cash G&A(2) ($/Boe) Debt / Adjusted LTM EBITDAX 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 Midland Basin Growth Story (1) 1,180 4,696 7,999 11,846 13,681 22,128 4,002 7,869 9,937 13,429 15,276 22,128 FY16A FY17A FY18A FY19A FY20A PF 4Q20A Midland Basin Other (1) (1) $18.7 $60.6 $97.0 $146.3 $144.2 $223.0 FY16A FY17A FY18A FY19A FY20A PF FY20A
12 $24.81 $17.13 $17.99 $7.92 $8.35 $9.47 $11.94 $13.49 $13.90 $17.95 $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 $11.08 $9.34 $10.12 $9.31 $10.56 $13.79 $13.85 $14.57 $15.54 $21.59 $21.72 $0.00 $10.00 $20.00 $30.00 $40.00 ESTE Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 LOE (incl Workovers) Ad Val. & Prod. Taxes Transportation Cash G&A Interest Expense FY20 All-in Cash Margin ($/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: $9.73 SMid-Cap(2) Avg: $15.12 ESTE: $11.08 Low Cost Production Generates Leading Cash Margins FY20 All-in Cash Costs ($/Boe)(1) Large-Cap(2) Avg: $17.56 SMid-Cap(2) Avg: $12.98 ESTE: $24.81
13 3.3x 4.6x 5.0x 2.8x 3.5x 4.2x 4.7x 4.8x 5.2x 5.3x – 3.0x 6.0x 9.0x 12.0x ESTE Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 0.8x 1.2x 1.4x 2.9x 2.3x 2.3x 2.3x 2.5x 3.5x 3.6x 4.0x 4.2x – 2.0x 4.0x 6.0x 8.0x ESTE Pro Forma 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 YE20 Total Debt / FY20 EBITDAX Large-Cap(2) Avg: 2.2x SMid-Cap(2) Avg: 3.1x ESTE / PF IRM(1): 0.8x / 1.2x Enterprise Value to 2022E EBITDAX Large-Cap(3)(4) Avg: 4.8x SMid-Cap(3) Avg: 4.4x ESTE(2): 3.3x Source: Factset, Wall Street research. Market Data as of 4/19/21 (1) Pro forma for acquisition of IRM (2) Pro forma for acquisition of IRM and Tracker (3) Large-Cap includes: FANG and PXD. SMid-Cap includes: BATL, CDEV, CPE, LPI, MTDR, REI, SM and XEC (BATL excluded in bottom chart due to lack of research coverage) (4) Reflects PXD pro forma for its acquisition of PE and FANG pro forma for its announced acquisitions of QEP and Guidon (1)
14 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
15 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% to 42% in 2020 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
16 Executive Compensation Fully Aligned with Shareholders (1) Peers include all U.S. public upstream operators with market capitalization from $250MM to $1.0BN as of 1/29/2021: BRY, BCEI, CPE, CDEV, MCF, LPI, OAS, PVAC, QEP, TALO, WTI, WLL. Data based on 2020 SEC proxy filings (2) Absolute shareholder return includes change in stock price plus impact of dividends paid (3) Based on 2021 long term equity incentive plan awards 3-Year Total Shareholder Return(3) Payout (% of target)(3) <25% 0% 25% - 50% 50-100% 50% - 75% 100-200% >75% 200% 75% of Equity Compensation based on 3-year Absolute Shareholder Return(2) Leading executive compensation practices ― Consistent with investor demands ― Focused on share price and corporate performance ― Designed to incentivize management for performance Lower cash, higher equity weighted compensation structure ― Meaningful compensation but below peers(1) ― Annual cash incentive is 100% at risk and target below peers(1) ― Equity compensation aligned with shareholders and dependent upon stock performance • 75% of shares at-risk based solely on shareholder return (see right side of page) • 25% of shares vest over 3-year period Majority of executive compensation is based directly on shareholder gains
17 Areas of Operations (1) Based on ESTE management estimates of reserves as of 12/31/20 assuming Oil - $50/Bbl, Gas - $2.50/Mcf. Excludes impact of pending Tracker acquisition (2) Represents estimated sales volumes (3) ESTE estimates as of 3/1/21 based on NYMEX strip pricing as of 3/29/21 (4) Estimated March 2021 three-stream sales volumes (5) ESTE estimated upside locations and IRRs assuming 4 wells per section and costs based on current management estimates at a $50 WTI flat price deck Total (excludes Tracker)(1) Total Proved Developed (Mmboe) 56.0 Total PD PV-10 ($mm) $653 4Q20 Net Production (Boe/d)(2) 22,128 4Q20 Net Production - % Oil(2) 53% 4Q20 Net Production - % Liquids(2) 76% Gross Producing Wells 1,101 Net Acres 83,800 Gross Drilling Locations 632 ESTE Midland Basin(1) Total Proved Developed (Mmboe) 52.3 Total PD PV-10 ($mm) $598 4Q20 Net Production (Boe/d) 20,762 4Q20 Net Production - % Oil 51% 4Q20 Net Production - % Liquids 75% Gross Producing Wells 980 Net Acres 71,300 Gross Drilling Locations 632 Eagle Ford(1) Total Proved Developed (Mmboe) 3.7 Total PD PV-10 ($mm) $54 4Q20 Net Production (Boe/d) 1,366 4Q20 Net Production - % Oil 82% 4Q20 Net Production - % Liquids 94% Gross Producing Wells 121 Net Acres 12,500 Gross Drilling Locations 0 Tracker PDP Reserves (Mmboe)(3) 19.8 PDP PV-10 ($mm)(3) $153 Mar21 Net Production (Boe/d)(4) ~7,800 Mar21 Net Production - % Oil(4) 21% Mar21 Net Production - % Liquids(4) 59% Gross Producing Wells 71 Net Acres ~20,300 Gross Drilling Locations(5) 49
18 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 The Midland Basin (Excludes Impact of Pending Tracker Acquisition) 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 - $2.50/Mcf and includes locations from acquisition of IRM
19 Financial Overview
20 ($mm) 3/31/2021 Cash $1.4 Revolver Borrowings 223.4 Total Debt $223.4 Revolver Borrowing Base 475.0 Less: Revolver Borrowings (223.4) Plus: Cash 1.4 Liquidity $253.0 Capital Budget, Guidance and Liquidity (Excludes Impact of Pending Tracker Acquisition) ESTE 2021 Capital Budget Liquidity (3/31/21)(2) 2021 FY Guidance 2021 Capital Budget Breakdown(1) Note: Guidance is forward-looking information that is subject to considerable change and numerous risks and uncertainties, many of which are beyond Earthstone’s control. See “Forward-Looking Statements”. Cash G&A is defined as general and administrative expenses excluding stock-based compensation (1) Reflects midpoint of FY2021E Guidance (2) Excludes impact of pending Tracker acquisition ($ 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
21 Oil and Gas Hedges Summary – 100% Swaps Oil Production Swaps Gas Production Swaps (Volumes in Bbls/d) (Volumes in MMBtu/d) 18,937 5,000 18,937 5,000 0 5,000 10,000 15,000 20,000 FY21 1Q22 Gas Swaps WAHA Basis Swaps Note: Hedgebook as of 4/9/21; excludes impact of pending Tracker acquisition (1) Based on midpoint of FY2021 guidance (19,500 – 21,000 Boe/d; 52% - 54% oil, 21% - 23% gas) ~88% of Guidance(1) ~71% of Guidance(1) 9,429 4,746 8,144 4,500 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 1,412,000 15,689 $2.784 2Q 2021 811,260 8,915 $48.26 2Q 2021 1,820,000 20,000 $2.813 3Q 2021 843,925 9,173 $48.91 3Q 2021 1,840,000 20,000 $2.813 4Q 2021 849,475 9,233 $49.29 4Q 2021 1,840,000 20,000 $2.813 FY 2021 3,441,500 9,429 $48.34 FY 2021 6,912,000 18,937 $2.807 FY 2022 1,732,250 4,746 $53.64 1Q 2022 450,000 5,000 $2.971 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 1,412,000 15,689 ($0.402) 2Q 2021 720,260 7,915 $0.78 2Q 2021 1,820,000 20,000 ($0.366) 3Q 2021 751,925 8,173 $0.79 3Q 2021 1,840,000 20,000 ($0.366) 4Q 2021 757,475 8,233 $0.80 4Q 2021 1,840,000 20,000 ($0.366) FY 2021 2,972,500 8,144 $0.79 FY 2021 6,912,000 18,937 ($0.373) FY 2022 1,642,500 4,500 $0.74 1Q 2022 450,000 5,000 ($0.228) 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)
22 Analyst Coverage Firm Analyst Contact Info Alliance Global Partners Andrew Bond / 203-577-5427 / abond@allianceg.com Johnson Rice Charles Meade / 504-584-1274 / cmeade@jrco.com Northland Subash Chandra / 212-405-8098 / schandra@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
23 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
24 Appendix
25 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 measure not prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) 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
26 Reserves Summary – Alternative 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) Based on internal estimates utilizing $50 oil and $2.50 gas effective as of 3/1/21 (2) The present value of estimated future revenues, discounted at 10% annually, to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to (i) non-property related expenses such as general and administrative expenses, debt service and future income tax expense, or (ii) depreciation, depletion and amortization ESTE IRM Tracker(1) COMBINED Reserve Category Proved Developed Proved Undeveloped Total Proved Developed Proved Undeveloped Total Proved Developed Proved Developed Proved Undeveloped Total Oil (MBbls) 19,547 21,530 41,077 9,551 8,570 18,121 3,336 32,434 30,100 62,534 Gas (MMcf) 57,891 56,580 114,471 17,789 5,125 22,914 50,836 126,516 61,705 188,221 NGL (MBbls) 10,502 10,316 20,818 3,834 1,105 4,939 8,022 22,358 11,421 33,779 Total (MBoe) 39,698 41,276 80,974 16,350 10,529 26,879 19,831 75,879 51,805 127,684 PV-10(2) ($ in thousands) $452,780 $265,499 $718,279 $199,960 $104,331 $304,291 $141,353 $794,093 $369,830 $1,163,923
27 Reconciliation of Non-GAAP Financial Measure – Adjusted EBITDAX Earthstone uses Adjusted EBITDAX, a financial measure that is not presented in accordance with 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)FY 2020 Adjusted EBITDAX ($ in 000s) 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 Rig termination expense $0 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 FY 20 Net (loss) income ($29,434) Accretion of asset retirement obligations $307 Depreciation, depletion and amortization $96,414 Impairment expense $64,498 Interest expense, net $5,232 Transaction costs $622 Rig termination expense $426 Loss (gain) on sale of oil and gas properties ($204) Exploration expense $298 Unrealized loss (gain) on derivative contracts ($3,855) Stock based compensation (non-cash)(1) $10,054 Income tax expense (benefit) ($112) Adjusted EBITDAX $144,246
28 Reconciliation of Non-GAAP Financial Measure – Adjusted EBITDAX (1) Included in Earthstone’s General and administrative expense in the Consolidated Statements of Operations Combined FY 2020 Adjusted EBITDAX ($ in 000s) ESTE IRM Combined Net (loss) income ($29,434) $18,154 ($11,280) Accretion of asset retirement obligations $307 $1,277 $1,584 Depreciation, depletion and amortization $96,414 $46,230 $142,644 Impairment expense $64,498 $0 $64,498 Interest expense, net $5,232 $9,845 $15,077 Transaction costs $622 $0 $622 Rig termination expense $426 ($24) $402 Loss (gain) on sale of oil and gas properties ($204) $0 ($204) Exploration expense $298 $0 $298 Unrealized loss (gain) on derivative contracts ($3,855) $1,109 ($2,746) Stock based compensation (non-cash)(1) $10,054 $1,799 $11,853 Income tax expense (benefit) ($112) $362 $250 Adjusted EBITDAX $144,246 $78,752 $222,998 The following table provides a reconciliation of Earthstone’s and IRM’s Net (loss) income to Adjusted EBITDAX for: